### THIS FILING IS
Item 1: An Initial (Original) Submission OR Resubmission No. ____ Form 1 Approved OMB No. 1902-0021 (Expires 2/29/2009) Form 1-F Approved OMB No. 1902-0029 (Expires 2/28/2009) Form 3-Q Approved OMB No. 1902-0205 (Expires 2/28/2009) X



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

These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and 18 CFR 141.1 and 141.400. Failure 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



### FERC FORM No.1/3-Q (REV. 02-04) Exact Legal Name of Respondent (Company) Year/Period of Report End of 2008/Q4 Oklahoma Gas and Electric Company

### INSTRUCTIONS FOR FILING FERC FORM NOS. 1 and 3-Q

GENERAL INFORMATION I. Purpose FERC Form No. 1 (FERC Form 1) is an annual regulatory requirement for Major electric utilities, licensees and others (18 C.F.R. § 141.1). FERC Form No. 3-Q ( FERC Form 3-Q)is a quarterly regulatory requirement which supplements the annual financial reporting requirement (18 C.F.R. § 141.400). These reports are designed to collect financial and operational information from electric utilities, licensees and others subject to the jurisdiction of the Federal Energy Regulatory Commission. These reports are also considered to be non-confidential public use forms.

II. Who Must Submit Each Major electric utility, licensee, or other, as classified in the Commission’s Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject To the Provisions of The Federal Power Act (18 C.F.R. Part 101), must submit FERC Form 1 (18 C.F.R. § 141.1), and FERC Form 3-Q (18 C.F.R. § 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).

III. What and Where to Submit (a) Submit FERC Forms 1 and 3-Q electronically through the forms submission software. Retain one copy of each report for your files. Any electronic submission must be created by using the forms submission software provided free by the Commission at its web site:

## http://www.ferc.gov/docs-filing/eforms/form-1/elec-subm-soft.asp. The software is used to submit the electronic filing to the Commission via the Internet. (b) The Corporate Officer Certification must be submitted electronically as part of the FERC Forms 1 and 3-Q filings. (c) Submit immediately upon publication, by either eFiling or mail, two (2) copies to the Secretary of the Commission, the latest Annual Report to Stockholders. Unless eFiling the Annual Report to Stockholders, mail the stockholders report to the Secretary of the Commission at: Secretary Federal Energy Regulatory Commission 888 First Street, NE Washington, DC 20426 (d) For the CPA Certification Statement, submit within 30 days after filing the FERC Form 1, a letter or report (not applicable to filers classified as Class C or Class D prior to January 1, 1984). The CPA Certification Statement can be either eFiled or mailed to the Secretary of the Commission at the address above.

FERC FORM 1 & 3-Q (ED. 03-07) i

### The CPA Certification Statement should: a) Attest to the conformity, in all material aspects, of the below listed (schedules and pages) with the Commission's applicable Uniform System of Accounts (including applicable notes relating thereto and the Chief Accountant's published accounting releases), and 

## b) 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 C.F.R. §§ 41.10-41.12 for specific qualifications.)

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 e) Thefollowing format must be used for the CPA Certification Statement unless unusual circumstances or conditions, explained in the letter or report, demand that it be varied. Insert parenthetical phrases only when exceptions are reported. “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 requirements of the Federal Energy Regulatory Commission 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 Regulatory Commission as set forth in its applicable Uniform System of Accounts and published accounting releases.” The letter or report must state which, if any, of the pages above do not conform to the Commission’s requirements. Describe the discrepancies that exist. (f) Filers are encouraged to file their Annual Report to Stockholders, and the CPA Certification Statement using eFiling. To further that effort, new selections, “Annual Report to Stockholders,” and “CPA Certification Statement” have been added to the dropdown “pick list” from which companies must choose when eFiling. Further instructions are found on the Commission’s website at

## http://www.ferc.gov/help/how-to.asp

. (g) Federal, State and Local Governments and other authorized users may obtain additional blank copies of FERC Form 1 and 3-Q free of charge from

## http://www.ferc.gov/docs-filing/eforms/form-1/form-1.pdfand 

## http://www.ferc.gov/docs-filing/eforms.asp#3Q-gas

. IV. When to Submit: FERC Forms 1 and 3-Q must be filed by the following schedule:

FERC FORM 1 & 3-Q (ED. 03-07) ii

### a)FERC Form 1 for each year ending December 31 must be filed by April 18thof the following year (18 CFR § 141.1), and b) FERC Form 3-Q for each calendar quarter must be filed within 60 days after the reporting quarter (18 C.F.R. § 141.400). V. Where to Send Comments on Public Reporting Burden. The public reporting burden for the FERC 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 reviewing the collection of information. The public reporting burden for the FERC Form 3-Q collection of information is estimated to average 150 hours per response. Send comments 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: Information Clearance Officer); and to the Office of Information and Regulatory Affairs, Office of Management and Budget, Washington, DC 20503 (Attention: Desk Officer for the Federal Energy Regulatory Commission). 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 1 & 3-Q (ED. 03-07) iii

### GENERAL INSTRUCTIONS I. Prepare this report in conformity with the Uniform System of Accounts (18 CFR Part 101) (USofA). Interpret all accounting words and phrases in accordance with the USofA. II. 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. III 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. VII For any resubmissions, submit the electronic filing using the form submission software only. Please explain the reason for the resubmission in a footnote to the data field. VIII. Do not make references to reports of previous periods/years or to other reports in lieu of required entries, except as specifically authorized. IX. Wherever (schedule) pages refer to figures from a previous period/year, the figures reported must be based upon those shown by the report of the previous period/year, or an appropriate explanation given as to why the different figures were used. Definitions for 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 not 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. "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 to remain reliable even under adverse conditions. "Point-to-Point Transmission Reservations" are described in Order No. 888 and the Open Access Transmission Tariff. For all transactions identified as LFP, provide in a footnote the

FERC FORM 1 & 3-Q (ED. 03-07) iv

### 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-Point Transmission Reservations. Use this classification for 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-mentioned classifications, such as all other service regardless of the length of the contract and service FERC 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 I. Commission Authorization (Comm. Auth.) -- The authorization 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 1 & 3-Q (ED. 03-07) v

### 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 with: (3) ’Corporation' means any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. It shall not include 'municipalities, as hereinafter defined; (4) 'Person' means an individual or a corporation; (5) 'Licensee, means any person, State, or municipality Licensed under the provisions of 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 and 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 fore bay reservoirs directly connected therewith, the primary line or lines transmitting power there from 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 appropriate 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 the 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 Commission in the -proper administration of this Act. The Commission may prescribe the manner and FERC Form in which such reports salt 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 reports shall be made under oath unless the Commission otherwise specifies*.10

FERC FORM 1 & 3-Q (ED. 03-07) vi

### "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 may find necessary or appropriate to carry out the provisions of this Act. Among other things, such rules and regulations may define accounting, technical, and trade terms used in this Act; and may prescribe the FERC Form or FERC 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 

# The Commission may assess up to $1 million per day per violation of its rules and regulations.See FPA § 316(a) (2005), 16 U.S.C. § 825o(a).

FERC FORM 1 & 3-Q (ED. 03-07) vii

### IDENTIFICATION 

## FERC FORM NO. 1/3-Q: REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER

Scott Forbes 

### 321 N. Harvey, Oklahoma City, OK 73101-0321 2008/Q4

321 N. Harvey, Oklahoma City, OK 73101-0321 01 Exact Legal Name of Respondent

(1) An Original (2) A Resubmission X 02 Year/Period of Report End of Oklahoma Gas and Electric Company 03 Previous Name and Date of Change (if name changed during year)

04 Address of Principal Office at End of Period(Street, City, State, Zip Code)

05 Name of Contact Person 06 Title of Contact Person

07 Address of Contact Person (Street, City, State, Zip Code)

08 Telephone of Contact Person,Including Area Code 09 This Report Is 10 Date of Report (Mo, Da, Yr)

01 Name

02 Title 03 Signature 04 Date Signed 

### (Mo, Da, Yr)

Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any false, fictitious or fraudulent statements as to any matter within its jurisdiction. 

### / /

Scott Forbes Controller and CAO

(405) 553-3491 / /

Scott Forbes

Controller and CAO 04/10/2009 ANNUAL CORPORATE OFFICER CERTIFICATION The undersigned officer certifies that: I have examined this report and to the best of my knowledge, information, and belief all statements 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.



## FERC FORM No.1/3-Q (REV. 02-04) Page 1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of LIST OF SCHEDULES (Electric Utility) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Title of Schedule Reference Page No. Remarks (c) (b) (a) 

### Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".

101 General Information 1 102 Control Over Respondent 2 103 Corporations Controlled by Respondent 3 104 Officers 4 105 Directors 5 108-109 Important Changes During the Year 6 110-113 Comparative Balance Sheet 7 114-117 Statement of Income for the Year 8 118-119 Statement of Retained Earnings for the Year 9 120-121 Statement of Cash Flows 10 122-123 Notes to Financial Statements 11 122(a)(b) Statement of Accum Comp Income, Comp Income, and Hedging Activities 12 200-201 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 13 N/A 202-203 Nuclear Fuel Materials 14 204-207 Electric Plant in Service 15 N/A 213 Electric Plant Leased to Others 16 214 Electric Plant Held for Future Use 17 216 Construction Work in Progress-Electric 18 219 Accumulated Provision for Depreciation of Electric Utility Plant 19 224-225 Investment of Subsidiary Companies 20 227 Materials and Supplies 21 N/A 228-229 Allowances 22 N/A 230 Extraordinary Property Losses 23 N/A 230 Unrecovered Plant and Regulatory Study Costs 24 None 231 Transmission Service and Generation Interconnection Study Costs 25 232 Other Regulatory Assets 26 233 Miscellaneous Deferred Debits 27 234 Accumulated Deferred Income Taxes 28 250-251 Capital Stock 29 253 Other Paid-in Capital 30 N/A 254 Capital Stock Expense 31 256-257 Long-Term Debt 32 261 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 33 262-263 Taxes Accrued, Prepaid and Charged During the Year 34 266-267 Accumulated Deferred Investment Tax Credits 35 269 Other Deferred Credits 36

FERC FORM NO. 1 (ED. 12-96) Page 2LIST OF SCHEDULES (Electric Utility) (continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Title of Schedule Reference Page No. Remarks (c) (b) (a) 

### Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".

N/A 272-273 Accumulated Deferred Income Taxes-Accelerated Amortization Property 37 274-275 Accumulated Deferred Income Taxes-Other Property 38 276-277 Accumulated Deferred Income Taxes-Other 39 278 Other Regulatory Liabilities 40 300-301 Electric Operating Revenues 41 304 Sales of Electricity by Rate Schedules 42 310-311 Sales for Resale 43 320-323 Electric Operation and Maintenance Expenses 44 326-327 Purchased Power 45 328-330 Transmission of Electricity for Others 46 N/A 331 Transmission of Electricity by ISO/RTOs 47 332 Transmission of Electricity by Others 48 335 Miscellaneous General Expenses-Electric 49 336-337 Depreciation and Amortization of Electric Plant 50 350-351 Regulatory Commission Expenses 51 352-353 Research, Development and Demonstration Activities 52 354-355 Distribution of Salaries and Wages 53 N/A 356 Common Utility Plant and Expenses 54 397 Amounts included in ISO/RTO Settlement Statements 55 398 Purchase and Sale of Ancillary Services 56 400 Monthly Transmission System Peak Load 57 N/A 400a Monthly ISO/RTO Transmission System Peak Load 58 401 Electric Energy Account 59 401 Monthly Peaks and Output 60 402-403 Steam Electric Generating Plant Statistics 61 N/A 406-407 Hydroelectric Generating Plant Statistics 62 N/A 408-409 Pumped Storage Generating Plant Statistics 63 N/A 410-411 Generating Plant Statistics Pages 64 422-423 Transmission Line Statistics Pages 65 424-425 Transmission Lines Added During the Year 66

FERC FORM NO. 1 (ED. 12-96) Page 3LIST OF SCHEDULES (Electric Utility) (continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Title of Schedule Reference Page No. Remarks (c) (b) (a) 

### Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".

426-427 Substations 67 450 Footnote Data 68 

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

FERC FORM NO. 1 (ED. 12-96) Page 4

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report

End of

GENERAL INFORMATION Oklahoma Gas and Electric Company 

### X / / 2008/Q4

State of Oklahoma (Formerly the Territory of Oklahoma) February 27, 1902 Scott Forbes, Controller and CAO 321 N. Harvey P.O. Box 321 Oklahoma City, OK 73101-0321 

### 1. Provide name and title of officer having custody of the general 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.

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.

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 possession, (c) the authority by which the receivership or trusteeship was created, and (d) date when possession by receiver or trustee ceased.

4. State the classes or utility and other services furnished by respondent during the year in each State in which the respondent operated.

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) Yes...Enter the date when such independent accountant was initially engaged: (2) No X Not Applicable

State of Oklahoma - Electric Utility Service Only State of Arkansas - Electric Utility Service Only

FERC FORM No.1 (ED. 12-87) PAGE101

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report

End of

CONTROL OVER RESPONDENT Oklahoma Gas and Electric Company 

### X / / 2008/Q4



### 1. If any corporation, business trust, or similar organization or a combination of such organizations jointly 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(s), state name of trustee(s), 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.

Page 102 FERC FORM NO. 1 (ED. 12-96)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

CORPORATIONS CONTROLLED BY RESPONDENT Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name of Company Controlled Kind of Business Percent Voting Stock Owned (c) (b) (a) Footnote Ref. (d) 

### 1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote. 2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming any intermediaries involved. 3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.

Definitions 1. See the Uniform System of Accounts for a definition of control. 2. Direct control is that which is exercised without interposition of an intermediary. 3. Indirect control is that which is exercised by the interposition of an intermediary which 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 voting 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 understanding between 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.

Owner and Lessor of 4.8% 1 The Arklahoma Corporation (a) Transmission facilities. 2 3 4 5 6 7 (a) Held Jointly with Entergy Arkansas Inc. 8 and AEP-Southwestern Electric Power 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27

FERC FORM NO. 1 (ED. 12-96) Page 103Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

OFFICERS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Title Name of Officer Salary for Year (c) (b) (a) 

### 1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. 2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.

Chairman of the Board, President and Chief 775,000 Peter B. Delaney 1 Executive Officer 2 3 Chief Operating Officer 510,000 Danny P. Harris 4 5 Senior Vice President and Chief Financial Officer (A) 207,187 James R. Hatfield 6 7 Vice President, Enterprise Information and 216,500 Reid V. Nuttall 8 Performance 9 10 Vice President Public Affairs 228,000 Paul L. Renfrow 11 12 Vice President and Treasurer 211,000 Deborah S. Fleming 13 14 Vice President Administration / Corporate Secretary 199,500 Carla D. Brockman 15 16 Vice President Utility Commercial Operations 202,000 Jesse B. Langston 17 18 Vice President Power Delivery 210,000 Melvin H. Perkins, Jr. 19 20 Vice President Regulatory Affairs 210,000 Howard W. Motley, Jr. 21 22 Vice President Internal Audit 183,000 Gary D. Huneryager 23 24 Controller / Chief Accounting Officer 229,500 H. Scott Forbes 25 26 Chief Risk Officer 207,000 Jerry A. Peace 27 28 Vice President Utility Operations 244,800 Jean Leger, Jr. 29 30 Vice President Corporate Strategy 232,000 S. Craig Johnston 31 and Marketing 32 33 Assistant Corporate Secretary / Compliance Officer 140,000 John D. Rhea 34 35 Vice President Power Supply 193,500 John Wendling Jr. 36 37 Vice President Human Resources (B) 37,601 Cary W. Martin 38 39 Vice President Human Resources (C) 91,875 Robert Grasty 40 41 Vice President Process & Perf Improvement (D) 76,667 Christina McQuistion 42 43 44

FERC FORM NO. 1 (ED. 12-96) Page 104Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

OFFICERS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Title Name of Officer Salary for Year (c) (b) (a) 

### 1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function (such as sales, administration or finance), and any other person who performs similar policy making functions. 2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous incumbent, and the date the change in incumbency was made.

(A) Resigned effective July 11th. Salary reported is 1 salary earned for 2008. 2 3 (B) Resigned effective March 6th. Salary reported is 4 salary earned for 2008. 5 6 (C) Employed as of August 19th. Annual salary is 7 $245,000. 8 9 (D) Employed as of September 2nd. Annual salary 10 is $230,000. 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44

FERC FORM NO. 1 (ED. 12-96) Page 104.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

DIRECTORS Oklahoma Gas and Electric Company X / / 2008/Q4

Line Name (and Title) of Director Principal Business Address (b) (a) No. 

### 1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated titles of the directors who are officers of the respondent. 2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.

Post Office Box 1066 Herbert H. Champlin 1 Enid, Oklahoma 73702 2 3 2956 Via Experanze Luke R. Corbett (B) 4 Edmond, Oklahoma 73013 5 6 Post Office Box 648 John D. Groendyke (B) (C) 7 Enid, Oklahoma 73702 8 9 1415 N. Hudson Kirk D. Humphreys (A) (B) 10 Oklahoma City, Oklahoma 73103 11 12 Post Office Box 1507 Robert Kelley (A) 13 Ardmore, Oklahoma 73402 14 15 3037 NW. 63 Suite 155W Linda Petree Lambert (A) (C) 16 Oklahoma City, Oklahoma 73116 17 18 500 Heritage Boulevard Robert O. Lorenz (A) (C) 19 Edmond, Oklahoma 73003 20 21 111 Willits Place-Suite 300 Leroy C. Richie (B) (C) 22 Birmingham, Michigan 48009 23 24 Post Office Box 23433 Wayne H. Brunetti (A) (B) 25 Silverthorne, CO 80498 26 27 1155 21st Street N.W. J. D. Williams (B) (C) 28 Washington D.C. 20036 29 30 1508 W. Wilshire Ronald H. White, M.D. 31 Oklahoma City, Oklahoma 73116 32 33 Post Office Box 321 Peter B. Delaney * 34 Oklahoma City, Oklahoma 73101-0321 Chairman of the Board, President and 35 Chief Executive Officer 36 37 (A) Member of Audit Committee 38 (B) Member of Compensation Committee 39 (C) Member of Nominating and Corporate Governance 40 Committee 41 42 * Mr. Delaney is a standing member of all committees 43 44 45 46 47 48

FERC FORM NO. 1 (ED. 12-95) Page 105

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report Year/Period of Report End of

IMPORTANT CHANGES DURING THE QUARTER/YEAR 

### Oklahoma Gas and Electric Company X / / 2008/Q4

PAGE 108 INTENTIONALLY LEFT BLANK SEE PAGE 109 FOR REQUIRED INFORMATION. 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 "NA" 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, development, 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. 8. 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 respondent 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 occurred 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 percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.

FERC FORM NO. 1 (ED. 12-96) Page 108

### 1) None 2) None 3) In September OG&E acquired a 51% interest in a 1,230 megawatt combined cycle plant that was placed in service in 2004. On September 16, 2008, the FERC issued an order approving the acquisition. Entries were submitted to the Commission on February 25, 2009, and amended and supplemented on March 6, 2009. Commission approval was granted on March 31, 2009. 4) None 5) None 6) In January the Company issued $200 milion of 6.45 Senior Notes, Series due February 1, 2038. On September 9, 2008 the Company issued $250 million of 6.35% Senior Notes due September 1, 2018. In December the Company issued $250 million of 8.25% Senior Notes, Series due January 15, 2019. 7) None 8) None 9) PROCEEDINGS CULMINATED DURING 2008 In the Matter of Resource Planning Guidelines for Electric Utilities and Consideration of Sec. 111(d)(12) of the Energy Policy Act of 2005, Docket No. 06-028-R, ARKANSAS PUBLIC SERVICE COMMISSION. In 2003, the "Electric Utility Regulatory Reform Act of 2003" was enacted. In order to meet the responsibilities of this Act, and to recognize changes in the electric industry, the Commission initiated this proceeding for the purpose of developing Resource Planning Guidelines to be followed by jurisdictional electric utilities. The Commission stated in the Order initiating this proceeding that "There is now a greater need for electric utilities to plan both generation and transmission investment on a regional basis, coordinate these investment decisions with multiple state and federal rules and policies, plan for new infrastructure in the context of new wholesale market opportunities, incorporate increased demand-side resources .... and anticipate and implement ways to mitigate the impact of rising costs of generation fuels. The Commission requested written comments on the attached draft Guidelines, to be filed no later than April 7, 2006. In April and May 2006, various parties filed Comments and Reply Comments. In July 2006, various parties, including OG&E, filed Fuel Usage Data Reports with the Commission. On January 4, 2007, the Commission issued Order No. 6 finding that the proposed Resource Planning Guidelines for Electric Utilities were in the public interest and should be adopted. In one section, the Commission indicated its intention to "retain a more general and flexible process in these Guidelines" and granted the utilities latitude to explore modeling techniques, but also stated that the Commission will require utilities to provide results of all tests used to evaluate promotional practices. The Commission also directed that the Staff conduct studies concerning the PURPA standard, to be considered in a future order. On May 24, 2007, the Commission sent letters to the Arkansas Secretary of State and other State offices notifying them of filing and approval of Rules. On July 20, Staff filed with the Commission a report titled "Arkansas Electric Generation Fuel Diversity: Implementation of EPAct 2005 Amendments to PURPA Section 111(d)," prepared for the APSC Staff by Synapse Energy Economics, Inc. On December 19, 2007, the Commission issued Order No. 7 regarding issues in Order No. 6 and directing jurisdictional utilities to file existing plans regarding fossil fuel efficiency plans within 45 days of this Order No. 7. In February 2008, parties filed responses to Order No. 7. OG&E's comments stated that they believe their current policies and practices comply with the purpose of the EPAct, and also that they are committed to the implementation of energy efficiency and conservation programs in Arkansas. OG&E believes the actions it has taken, in conjunction with the Commission's integrated resource planning guidelines, addresses the improvement of its fossil fuel generation fleet. Also, OG&E believes that it is unnecessary to adopt any additional guidelines, which may be unduly vague, and recommends against any such action. On April 29, 2008, the APSC Staff submitted its Comments and Recommendations stating that Staff does not recommend that the Commission adopt the Fossil Fuel Generation Efficiency Standard; that current Arkansas statutes, Commission Rules, and current policies and practices of the electric utilities adequately address fossil fuel generation efficiency and the goals of PURPA. On May 29, 2008, the Commission, having considered Staff's recommendations and discussion and the filings by the state's electric utilities, issued Order No. 8 determining that it is not in the public interest to adopt the Fossil Fuel Generation Efficiency Standard of Section 1251 of EPAct amending Section 111(d)(13) of PURPA, and that current Arkansas statutes, the Commission's Rules, and the current policies and practices of the electric utilities adequately address fossil fuel generation efficiency and the goals of PURPA. On June 27, 2008, the Commission, stating there is no further action to be taken in this Name of Respondent

Oklahoma Gas and Electric Company 

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### FERC FORM NO. 1 (ED. 12-96) Page 109.1

### matter at this time, issued Order No. 9 authorizing and directing the Secretary to close this docket. In the Matter of the Application of Oklahoma Gas and Electric Company for an Order of the Commission Granting Recovery of the Costs Associated with the Cancellation of the Red Rock Generating Facility, Cause No. PUD 200700447, OKLAHOMA CORPORATION COMMISSION. On December 7, 2007, OG&E filed this Application and supporting testimony requesting that after appropriate notice and hearing the Commission issue an Order authorizing (1) OG&E to accrue a regulatory asset in the amount of $14,734,521 representing the Oklahoma jurisdictional portion of its prudently expended, extraordinary costs associated with the Red Rock Generating Facility, (2) the suspension of the 90/10 sharing mechanism set forth in Commission Order No. 526426 so that OG&E may apply 100% of the proceeds from SO2allowance sales as a reduction to this regulatory asset until these extraordinary costs are recovered in full and (3) such other relief as the Commission deems appropriate. The Application stated that during the time period of July 2006 through October 2007, OG&E incurred costs and expenses directly attributable to the Red Rock Generating Facility. The expenditures incurred during the period July 2006 through October 2007 including those of the joint owners total $38,564,356. The major components of this amount include outside legal services in negotiating the COO and Engineering, Procurement and Construction Agreement (“EPC”), outside consultants including Sargent & Lundy, out-of-pocket expenses, filing fees at the Oklahoma Department of Environmental Quality to obtain an air permit and at the Southwest Power Pool for the transmission service request for the Red Rock Generating Facility, costs paid to Red Rock Power Constructors under the Letter of Intent which includes cancellation costs paid for cancellation of the steam turbine generator, boiler and air quality control system. The amount the Company is requesting in this proceeding represents certain incremental costs not currently being recovered in OG&E’s rates. Several parties requested and were granted intervention in this cause, and orders dated February 11, 2008 established a procedural schedule, setting hearing date of May 7, 2008, and granted Applicant's motion for a protective order. Discovery took place during February and March, and on March 24, 2008, responsive testimony was filed by intervening parties. On April 15, 2008, OG&E filed rebuttal testimony. On June 27, 2008, OG&E filed its Motion to Consolidate this cause with newly-filed OG&E Cause No. 200800215 (Application of Oklahoma Gas and Electric Company for an Order of the Commission Granting Recovery of the Storm Cost Regulatory Asset and Authorizing a Recovery Rider). Settlement negotiations in Cause No. 200700447 have included discussions regarding OG&E's recovery of storm damage costs, and the parties to both Causes anticipate filing a Joint Stipulation and Settlement Agreement providing for the settlement of both cases. On July 11, 2008, the Commission issued its Order granting the Motion to Consolidate. On July 24, 2008, the parties submitted a negotiated Joint Stipulation and Settlement Agreement to the Commission for its approval. On August 22, 2008, the Commission issued its Final Order approving the Joint Stipulation and Settlement Agreement. The Agreement allows OG&E to recoup part of the money it spent on the December 2007 ice storm and part of the money invested in the Company's plan to build the Red Rock coal-fired plant. The Company was allowed to recover approximately $7 million of the approximately $18 million spent on Red Rock and approximately $33 million on the ice storm. In the Matter of the Application of Oklahoma Gas and Electric Company for an Order of the Commission Granting Preapproval of the Purchase of the Redbud Generating Facility and Authorizing a Recovery Rider, Cause No. PUD 200800086, OKLAHOMA CORPORATION COMMISSION. On March 20, 2008, OG&E filed this Application and supporting testimony requesting: a determination from the Commission that OG&E’s decision to purchase a fifty-one (51%) interest in the Redbud Generating Facility for the agreed upon price is prudent; a determination from the Commission that the Redbud Generating Facility is used and useful upon the closing of the purchase transactions and beginning operation of the plant; that the Commission authorize the recovery of the annual revenue requirement associated with the Redbud Generating Facility through the Redbud Acquisition Recovery Rider from the time OG&E begins operating the plant until the conclusion of OG&E’s next rate case and implementation of new rates; and that the Commission authorize the inclusion of the full investment or purchase price, O&M expenses, depreciation and ad valorem taxes associated with the Redbud Generating Facility in OG&E’s cost of service in its next rate case. By the end of March, several parties had filed motions to intervene. On April 9, 2008, the Commission issued its Order directing that specific costs associated with the services of expert witnesses for the Attorney General's office in this cause be paid by OG&E, and authorizing OG&E to treat those costs as a regulatory asset, and further that those specific costs may be deemed to be recoverable, which determination shall be deferred until the next general rate case filed by OG&E. On May 14, 2008, the Commission issued its Order directing that specific costs associated with the services of expert witnesses for the Commission Staff in this cause be paid by OG&E, and authorizing OG&E to treat those costs as a regulatory asset, and further that those specific costs may be deemed to be recoverable, which determination shall be deferred until the next general rate case filed by OG&E. On June 25, 2008, the Commission issued its procedural schedule in this cause, scheduling hearings on the merits to begin on September 24, 2008. On July 30, 2008, the parties submitted a Joint Stipulation and Settlement Agreement to the Commission, addressing all issues in the Cause and asking for the Commission's approval. On August 8, 2008, the Commission issued its Order amending the procedural schedule and moving the hearing date to September 19, 2008. In September, testimony in support of the Joint Stipulation and Settlement Agreement was filed by Redbud, Staff and OG&E. On September 18, 2008, OG&E filed as an exhibit the FERC "Order Conditionally Authorizing Disposition of Jurisdictional Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

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### FERC FORM NO. 1 (ED. 12-96) Page 109.2

### Facilities" issued on September 16, 2008 in FERC Docket No. EC08-58-000. On September 24, 2008, the Commission issued its Final Order approving by a 2-0 vote the Joint Stipulation and Settlement Agreement and the Company's proposal to recover the costs of acquiring and operating the Redbud Power Plant. OG&E expects to complete its acquisition of the plant by October 1, 2008. OG&E will acquire a 51-percent interest in the Redbud plant for a purchase price of $434.5 million and will operate the plant on behalf of its co-owners, the Grand River Dam Authority and the Oklahoma Municipal Power Authority. In the Matter of the Application of Oklahoma Gas and Electric Company for an Order of the Commission Granting Pre-Approval to Construct a Transmission Line, Authorizing a Recovery Rider and Approving Other Associated Tariffs in Regard to its Renewable Plan, OCC Cause No. PUD 200800148, OKLAHOMA CORPORATION COMMISSION. OG&E is initiating the “OG&E Renewable Plan” to significantly expand delivery of the benefits associated with western Oklahoma’s vast wind resources to its customers. This initiative seeks to develop up to 600 MW of new wind generation on OG&E’s system by 2012. OG&E intends to seek up to 300 MW by 2010 through a Request for Proposals ("RFP") for wind energy and the remaining 300 MW by 2012 through a similar RFP. Expansion of the current transmission system is necessary to take advantage of these wind resources. On May 19, 2008, OG&E filed this Application and supporting testimony requesting that the Commission issue an Order on or before July 31, 2008 in regard to its Renewable Plan: (a) granting pre-approval to construct a 345 kV transmission line from Woodward to Oklahoma City and finding that the construction of the transmission line subject to the construction cost cap of $211 million, including AFUDC, is prudent; (b) authorizing OG&E to seek recovery, if necessary, of any prudently incurred costs above the construction cost cap in a separate proceeding; (c) approving a Renewable Transmission System Additions tariff as the appropriate mechanism to recover the construction costs, recovery to commence when the transmission line goes into service; (d) approving a Renewable Energy Program tariff as well as modifications to the existing Green Power Wind Rider, Off-System Sales of Electricity tariff, and the Economic Incentive Credit tariff; and (e) granting such other and further relief as the Commission may determine to be fair, just and equitable in the premises. On June 20, 2008, the Commission issued its Order establishing procedural schedule, setting hearing on the merits to begin August 7, 2008. In July 2008, testimony and statements of position were filed by the parties. On July 31, 2008, the parties submitted its negotiated Joint Stipulation and Settlement Agreement to the Commission for approval. On August 25, 2008, the Administrative Law Judge issued her Report, and on September 11, 2008, the Commission filed a Final Order adopting the Report, approving OG&E's comprehensive renewable energy program, which includes construction of a high-capacity transmission line between Woodward and Oklahoma City. The approval included the cost to build the transmission line, a rider to allow recovery of costs for the line beginning at the time it goes into service, and a tariff that will allow more OG&E customers to choose up to 100 percent renewable energy. The new line will be used to transport electricity produced by current and future wind farms in northwestern Oklahoma. In the Matter of the Application of Oklahoma Gas and Electric Company for an Order of the Commission Granting Recovery of the Storm Cost Regulatory Asset and Authorizing a Recovery Rider, Cause No. PUD 200800215, OKLAHOMA CORPORATION COMMISSION, On June 27, 2008, OG&E filed this Application requesting that the Commission issue an order authorizing the recovery of the regulatory asset regarding its Excess Storm Damage Costs in calendar year 2007 in the amount of $35,263,613, and approving the Storm Cost Recovery Rider as the appropriate mechanism to recover Excess Storm Damage Costs for the period 2007 through 2009. On June 27, 2008, OG&E filed its Motion to Consolidate this cause with Cause No. 200800447 (Application of Oklahoma Gas and Electric Company for an Order of the Commission Granting Recovery of the Costs Associated with the Cancellation of the Red Rock Generating Facility). Settlement negotiations in Cause No. 200700447 have included discussions regarding OG&E's recovery of storm damage costs, and the parties to both Causes anticipate filing a Joint Stipulation and Settlement Agreement providing for the settlement of both cases. On July 11, 2008, the Commission issued its Order granting the Motion to Consolidate. On July 24, 2008, the parties submitted a negotiated Joint Stipulation and Settlement Agreement to the Commission for its approval. On August 22, 2008, the Commission issued its Final Order approving the Joint Stipulation and Settlement Agreement. The Agreement allows OG&E to recoup part of the money it spent on the December 2007 ice storm and part of the money invested in the Company's plan to build the Red Rock coal-fired plant. The Company was allowed to recover approximately $7 million of the approximately $18 million spent on Red Rock and approximately $33 million on the ice storm. 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 Acquisition of Facilities Application for Hearing. In its order, the FERC stated that it would set the application for Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.3

### 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 for 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&E's 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&E's 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&E's: "...like OG&E's unilateral offer of settlement, the Intergen Offer of Settlement is vigorously contested. It therefore must satisfy 18 C.F.R. §385.602(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, . . . unnecessarily prolongs proceedings, eliminates the primary benefits that the parties achieve by reaching a settlement, is harmful to administrative efficiency, and is directly contrary to the Commission's regulations 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, 2004, 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 16, 2004, OG&E, FERC Staff, AES 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, primarily the fact that FERC regulations state that interlocutory appeals will not suspend a proceeding. On July 2, 2004, FERC 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, ". . . 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&E's 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, as consistent 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 OG&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 19, 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 order filed in this proceeding will be addressed in a future order." On October 14, 2004, and January 18, 2005, Potomac Economics filed its "Quarterly Market Monitoring Report on the OG&E Company." On April 18, 2005, the FERC issued an Order denying Redbud's request for rehearing. Redbud has 60 days from the date of the Order to decide whether to appeal the FERC's Order approving the transaction. On May 2, 2005, Potomac Economics filed its "Quarterly Market Monitoring Report on the OG&E Company." On May 31, 2005, OG&E filed a letter with FERC advising that "as of May 19, 2005, all transmission facilities that OG&E committed to construct under accepted settlement were placed into commercial operation. As a result, effective May 19, 2005, OG&E's obligation to redispatch its system as set forth in the settlement terminated." On August 8, 2005, Potomac Economics filed its "Quarterly Market Monitoring Report on the OG&E Company." On September 21, 2005, OG&E and SPP received letters from the FERC requesting additional information concerning the proposed 600 MW bridge between InterGen's Redbud Energy Project and OG&E's control area, one of the mitigation measures offered by OG&E to address the adverse effect on competition that could result from the sale of certain jurisdictional facilities by NRG McClain to OG&E. On October 3, Name of Respondent

Oklahoma Gas and Electric Company 

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### FERC FORM NO. 1 (ED. 12-96) Page 109.4

### 2005, OG&E and SPP responded to FERC's request for additional information. On October 18, 2005, Potomac Economics filed its "Quarterly Market Monitoring Report on the OG&E Company." On October 24, 2005, Redbud filed its Response to Compliance Reports of OG&E and SPP, stating Redbud's belief that "no firm transmission, and thus no mitigation, exists." On December 1, 2005, a Technical Conference was held to discuss whether the upgrades completed by OG&E resulted in an additional 600 MW of available transmission capacity, as required in the July 2004 Order. The parties were invited to file comments addressing several questions with respect to the Settlement approved on July 2, 2004. On December 16, 2005, post-technical comments were filed by OG&E, Redbud and SPP. On January 18, 2006, Potomac Economics filed its "Quarterly Market Monitoring Report on the OG&E Company" for the fourth quarter 2005. On January 20, 2006, a second round of post-technical comments were filed by OG&E and Redbud. On February 15, 2006, the SPP filed Clarifications to its December 16th filing, revising parts of the text and updating charts. On March 30, 2006, after review of comments filed by OG&E and SPP, the FERC issued a "Follow-Up Data Request" to both parties seeking additional information from OG&E and SPP. On April 24, 2006, Potomac Economics filed its "Quarterly Market Monitoring Report on the OG&E Company." In April and May, 2006, OG&E and SPP provided FERC the requested additional information. On June 20, 2006, the FERC issued its Order on Compliance, finding that OG&E has met its obligation to create at least 400 MWs of available transfer capability into the OG&E control area by constructing certain transmission upgrades, as required in the Commission's order conditionally accepting OG&E's Offer of Settlement. On July 28, 2006, Potomac Economics filed its "Quarterly Market Monitoring Report on the OG&E Company." On October 26, 2006, Potomac Economics filed its "Quarterly Market Monitoring Report on the OG&E Company." On December 1, 2006, OG&E sent the FERC a letter advising that they have informed Potomoc Economics that its monitoring role will cease as of November 30, 2006. On January 16, 2007, Potomac Economics filed its "Quarterly [October-November 2006] Market Monitoring Report on the OG&E Company." PENDING AT THE END OF 4th QUARTER OF 2008: In the Matter of the Joint Application of Entergy Arkansas, Inc., The Empire District Electric Company, Oklahoma Gas and Electric Company, and Southwestern Electric Power Company for Approval of Storm Cost Recovery Accounting and Storm Damage Rider, APSC Docket No. 08-091-U, ARKANSAS PUBLIC SERVICE COMMISSION. On June 6, 2008, Applicants filed this Application and supporting testimony of Applicants requesting Commission approval for storm cost recovery accounting and a new retail rate rider, Rider SDR. Purpose of the Rider is to address O&M expenses attributable to extraordinary storms or storm years in which costs are incurred in excess of that level which is currently reflected in each utility's base rates. The proposed Rider would establish and fund a Storm Damage Reserve. Following the Commission's approval of the proposed Rider, each utility will file a compliance tariff to implement the program consistent with the Commission's order. On July 10, 2008, Arkansas Electric Energy Consumers, Inc. filed its Petition to Intervene and Protest, saying its members' rates will increase substantially if the Commission approves the Joint Applicants' proposal. On September 25, 2008, the Commission initiated a proceeding in Docket No. 08-137-U to consider "innovative approaches to utility regulation in Arkansas to address the many challenges facing the electric and natural gas public utility industries." On October 9, 2008, in consideration of the Commission's establishment of this new proceeding that will address issues related to the recovery of extraordinary storm costs, the parties (Entergy Arkansas, Inc., Oklahoma Gas and Electric Company, Southwestern Electric Power Company, and The Empire District Electric Company) filed their Notice of Withdrawal of Application in this Docket No. 08-091-U. In the Matter of the Application of Oklahoma Gas and Electric Company for Approval of a General Change in Rates and Tariffs, APSC Docket No. 08-103-U, ARKANSAS PUBLIC SERVICE COMMISSION. On June 2, 2008, OG&E submitted to the Commission its Notice of Application ("Letter of Intent") for a general change or modification in rates, charges and tariffs no sooner than 60 days and no later than 90 days from the date of notice. On August 29, 2008, OG&E submitted its Application and supporting testimony, schedules and workpapers, requesting a general rate increase of approximately $26 million seeking recovery of costs for investments including a new power plant (Redbud) and improvements in its system of power lines, substations and related equipment to ensure that the Company can reliably meet growing customer demand for electricity. On September 29, 2008, the Commission issued its Order establishing a procedural schedule for the case, setting the hearing for April 7, 2009. OG&E filed revised testimony in October 2008. Staff and AG's Office served data requests on OG&E through December 2008. Application of Oklahoma Gas and Electric Company for an Order of the Commission Granting the Recovery of Costs Associated with its System Hardening Program and Authorizing a Recovery Rider, Cause No. PUD 200800387, OKLAHOMA CORPORATION COMMISSION. On December 2, 2008, OG&E filed this Application and supporting testimony requesting that the Commission issue an order authorizing the recovery of costs associated with the implementation of the System Hardening Program which includes circuit hardening, aggressive vegetation management, pilot programs to install breakaway connectors between poles and customers, and to underground certain customer service drops; and authorizing the recovery of such System Hardening Program costs through a System Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

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### FERC FORM NO. 1 (ED. 12-96) Page 109.5

### Hardening Rider. Application of Oklahoma Gas and Electric Company for an Order of the Commission Authorizing Applicant to Modify its Rates, Charges, and Tariffs for Retail Electric Service in Oklahoma, Cause No. 200800398, OKLAHOMA CORPORATION COMMISSION. On December 12, 2008, OG&E filed a Notice of Intent giving notice to the Commission of OG&E's intent to file an Application seeking to implement a plan which would modify the rates and charges for OG&E’s Oklahoma jurisdiction customers. OG&E stated it will also seek approval of appropriate tariffs. OG&E notified the Commission that OG&E: (1) plans to file an Application for a general rate change with a test year ending September 30, 2008; (2) anticipates filing its Application and supporting documentation in connection with the request for a general rate change on or about January 26, 2009; and (3) proposes that the new rates go into effect upon issuance of an order by the Commission, no later than one hundred eighty (180) days from the date of filing of the application. The proposed effective date of the general rate change is expected to be in August 2009. Oklahoma Gas and Electric Company and OGE Energy Resources, Inc., Docket Nos. ER98-511-002, ER97-4345-014, and EL05-107-000, 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. EL01-118-000 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 filed 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 that 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. On February 7, 2005, OG&E and OGE Energy Resources, Inc. ("the OGE Companies") filed its Updated Market Power Analysis. By this filing, the OGE Companies "demonstrate that they do not possess market power in any of the first-tier markets the OGE Companies studied." The OGE Companies demonstrated in the Updated Market Power Analysis that their inability to pass the Commission's market share screen does not provide a basis for setting their market-based rate authority for sales in that market for hearing or subjecting those sales to refund obligations. Therefore, the OGE Companies asked the Commission to conclude that the OGE Companies cannot exercise market power in any of the relevant markets and that the OGE Companies' market-based sales in any of those markets should not be set for hearing or made subject to refund. On February 28, 2005, the Oklahoma Municipal Power Authority filed its Motion to Intervene and Protest; such Motion was withdrawn on March 4, 2005. On February 28, 2005, Redbud Energy LP filed its Motion to Intervene and Protest. On March 15, 2005, OG&E and OERI filed their Answer to Motion to Intervene and Protest, asking the Commission to reject Redbud's Motion on the grounds that it addressed issues outside the scope of this proceeding, and that Redbud's demand for immediate implementation of its proposed economic dispatch program amounted to a collateral attack on prior Commission orders. On April 1, 2005, AES Shady Point LLC filed a motion to intervene out of time and asking FERC to require OG&E to implement an economic dispatch program to retain its market-based rate authority. On April 11, 2005, OG&E filed a blackline version of its market-based tariff, and on April 20, 2005, filed its revised filing superseding the April 11, 2005 fling. On June 7, 2005, the FERC issued its Order on Updated Market Power Analysis, Accepting Revised Tariff Sheets, Instituting Section 206 Proceeding and Establishing Refund Effective Date. On July 7, 2005, the OGE Companies filed certain tariff revisions and other data as required in the June 7th Order. Also, on August 8, 2005, the OGE Companies informed the FERC that they intend to adopt the FERC's default cost-based rate mechanism for all sales that the OGE Companies make for a term of less than one week to load that sinks in the OG&E control area, and that they would not make sales to load that sinks in the OG&E control area under their market-based rate tariff for a term of longer than one week. The FERC has yet to act on the July 7th or August 8th filings. On June 7, 2005, the Commission issued an order that instituted a proceeding in Docket No. EL05-107-000, pursuant to Section 206 of the Federal Power Act, concerning the justness and reasonableness of the OGE Companies market-based rates in the OG&E control area. On January 20, 2006, the Commission issued its Notice of Institution of Proceeding and Refund Effective Date advising that the refund effective date in Docket No. EL05-107-000 will be 60 days from the date of publication of this notice in The Federal Register. On March 21, 2006, the Commission issued an order on the OGE Companies’ default cost-based rate mitigation proposed in the August 8, 2005 filing. The Commission directed the OGE Companies to make certain revisions to their mitigation proposal and file a cost-based rate tariff for short-term sales (one week or less) made within the OG&E control area. The Commission also expanded the scope of the proposed mitigation to all sales made within the OG&E control area (instead of only to sales sinking to load within the OG&E control area). On April 20, 2006, OGE Companies filed (1) a compliance filing containing the specified revisions to the OGE Companies' market-based rate tariffs and the new cost-based rate Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.6

### tariff; and (2) a request for rehearing asking the Commission to reconsider its expanded mitigation directive contained in the March 21, 2006 order. On May 22, 2006, the Commission issued its order granting rehearing for further consideration of the March 21, 2006 order. On July 25, 2006, pursuant to order issued in FERC Docket ER06-451-000 regarding Southwest Power Pool, OGE Companies submitted their revised versions of their respective market-based rate tariffs to allow the OGE Companies to sell power at market-based rates in the Energy Imbalance Service ("EIS") market being established by the Southwest Power Pool. On August 25, 2006, OGE Companies resubmitted their July 25, 2006 filing, due to errors in posting and service, and requested that the Commission act on the proposed revisions to their market-based rate tariff within sixty days of the date of the supplemental filing. On February 6, 2007, OG&E submitted a letter to FERC regarding change in status report concerning market-based rate authority concerning Centennial Wind Farm. On March 9, 2007, FERC accepted OG&E's February 2007 submittal. On April 4, 2008, FERC issued its Order on Rehearing and Compliance Filing, denying OGE Companies' request for rehearing of the Commission's March 21, 2006 order that conditionally accepted OGE's proposal to mitigate the presumption of market power in the OG&E balancing authority area, and accepted in part and rejected in part OGE's compliance filing submitted pursuant to the March 21 Order. On May 5, 2008, OGE Companies submitted to FERC its compliance filing amending market-based rate tariffs by: revising tariff language related to the mitigation requirement for short-term sales to reflect the OGE Companies' commitment not to make sales at market-based rates in the OG&E balancing authority area; modifying the mitigation language in the tariffs regarding long-term transactions to be consistent with Commission precedent; and making certain other revisions to the market-based rate tariffs to bring those tariffs into compliance with the requirements of Order No. 697. On May 30, 2008, OGE Companies submitted to FERC its notice of non-material change in status report, notifying the Commission that OG&E has entered into a power purchase agreement with Westar Energy to purchase 300 MW of capacity and energy on a seasonal basis from Redbud Energy LP's Redbud Facility located within the OG&E balancing authority area. On July 24, 2008, OG&E received a letter from FERC accepting OG&E's amended filing of July 25, 2006, OG&E's compliance filing amending its Market-Based Rates. On October 27, 2008, OG&E submitted a Notice of Non-Material Change in Status relating to OG&E's acquisition of additional generation capacity (Redbud Facility) within its balancing authority area market. Joint Application of Oklahoma Gas and Electric Company and Redbud Energy L.P. for Authorization Under Section 203 of the Federal Power Act for Disposition of Jurisdictional Facilities, Docket No. EC08-58-000, FEDERAL ENERGY REGULATORY COMMISSION. On March 20, 2008, OG&E and Redbud Energy L.P. filed a Joint Application for authorization under Section 203 of the Federal Power Act for Disposition of Jurisdictional Facilities. Submitted for filing were Application, testimony, exhibits, Purchase and Sale Agreement, and Asset Purchase Agreement. Motions to intervene were filed by AES Shady Point and OMPA. AES also filed additional comments and protest requesting that the Commission impose conditions on the acquisition to "mitigate the significant additional market power created by the proposed transaction and promote a competitive market in OG&E's service area." On May 6, 2008, OG&E and Redbud Energy filed their Joint Motion for Leave to Answer and Answer to Protest. Joint Applicants declared that AES's protest is without merit; that AES's Power Sales Agreement with OG&E insulates it from the alleged adverse effects of the proposed transaction, and that the proposed transaction will have no adverse effect on competition. On September 16, 2008, FERC issued its Order Conditionally Authorizing Disposition of Jurisdictional Facilities. The Commission authorized the request as consistent with the public interest, subject to conditions to prevent increased market power, discussed at length in the Order. While the FERC did not agree that Applicants' transaction would not harm horizontal competition, it did agree that Applicants' proposed mitigation upgrades to the Entergy interconnections will increase simultaneous import limit values sufficiently to prevent competitive harm from the transaction. The Commission accepted Applicants' commitment to hold transmission customers harmless from costs related to the transaction, and found that the transaction would not adversely affect wholesale power rates. The Commission accepted OG&E's commitment to make certain transmission upgrades as described in the Order, and made that a condition of the Order. The Applicants shall notify the Commission within 10 days of the date that transmission upgrades have been completed; Applicants shall file quarterly updates describing the progress of the transmission upgrades until they are complete; Applicants must inform the Commission of any change in circumstances that would reflect a departure from the facts the Commission relief upon in authorizing the transaction; Applicants shall notify the Commission within 10 days of the date that the transaction has been consummated. On October 3, 2008, OG&E notified the Commission that the transaction was consummated on September 29, 2008. 10) None 11) Reserved 12) None 13) Cary Martin, Vice President of Human Resources left the company in the 1st quarter. Herbert Champlin retired from the OGE Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.7

### Energy Board of Directors on May 22, 2008. Ronald White's term also expired in May 2008. Former Xcel Energy Chairman and CEO Wayne Brunetti was elected to serve on the Board of Directors. Senior Vice President and CFO Jim Hatfield resigned effective July 11th. Controller and Chief Accounting Officer Scott Forbes will serve as interim CFO. Effective August 19th, Robert Grasty joined the company as Vice President of Human Resources. Effective September 2nd, Christina McQuistion was named Vice President Process & Performance Improvement. Effective December 17th, Wayne Walker joined the company as Director Business Development. 14) N/A Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)



### FERC FORM NO. 1 (ED. 12-96) Page 109.8

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission X Date of Report (Mo, Da, Yr) Year/Period of Report

End of COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)

Line No. Title of Account (a) Ref. Page No. (b) Current Year End of Quarter/Year Balance

(c) Prior Year End Balance 12/31

(d) Oklahoma Gas and Electric Company / / 2008/Q4

UTILITY PLANT 1 6,258,153,073 5,460,656,580 200-201 Utility Plant (101-106, 114) 2 169,154,630 112,342,284 200-201 Construction Work in Progress (107) 3 6,427,307,703 5,572,998,864 TOTAL Utility Plant (Enter Total of lines 2 and 3) 4 2,633,061,106 2,490,303,348 200-201 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5 3,794,246,597 3,082,695,516 Net Utility Plant (Enter Total of line 4 less 5) 6 0 0 202-203 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 7 0 0 Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 8 0 0 Nuclear Fuel Assemblies in Reactor (120.3) 9 0 0 Spent Nuclear Fuel (120.4) 10 0 0 Nuclear Fuel Under Capital Leases (120.6) 11 0 0 202-203 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 12 0 0 Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13 3,794,246,597 3,082,695,516 Net Utility Plant (Enter Total of lines 6 and 13) 14 0 0 122 Utility Plant Adjustments (116) 15 0 0 Gas Stored Underground - Noncurrent (117) 16 OTHER PROPERTY AND INVESTMENTS 17 1,189,002 286,886 Nonutility Property (121) 18 479,003 186,805 (Less) Accum. Prov. for Depr. and Amort. (122) 19 0 0 Investments in Associated Companies (123) 20 16,718 17,057 224-225 Investment in Subsidiary Companies (123.1) 21 (For Cost of Account 123.1, See Footnote Page 224, line 42) 22 0 0 228-229 Noncurrent Portion of Allowances 23 2,838,610 3,016,037 Other Investments (124) 24 0 0 Sinking Funds (125) 25 0 0 Depreciation Fund (126) 26 0 0 Amortization Fund - Federal (127) 27 0 0 Other Special Funds (128) 28 0 0 Special Funds (Non Major Only) (129) 29 0 0 Long-Term Portion of Derivative Assets (175) 30 0 0 Long-Term Portion of Derivative Assets – Hedges (176) 31 3,565,327 3,133,175 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 32 CURRENT AND ACCRUED ASSETS 33 0 0 Cash and Working Funds (Non-major Only) (130) 34 0 0 Cash (131) 35 0 0 Special Deposits (132-134) 36 13,750 13,150 Working Fund (135) 37 50,704,578 0 Temporary Cash Investments (136) 38 0 0 Notes Receivable (141) 39 155,673,108 123,222,349 Customer Accounts Receivable (142) 40 17,906,957 15,061,902 Other Accounts Receivable (143) 41 2,290,666 3,375,491 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42 0 0 Notes Receivable from Associated Companies (145) 43 1,304,407 1,116,628 Accounts Receivable from Assoc. Companies (146) 44 56,640,508 44,342,665 227 Fuel Stock (151) 45 0 0 227 Fuel Stock Expenses Undistributed (152) 46 0 0 227 Residuals (Elec) and Extracted Products (153) 47 67,393,826 59,874,271 227 Plant Materials and Operating Supplies (154) 48 0 0 227 Merchandise (155) 49 0 0 227 Other Materials and Supplies (156) 50 0 0 202-203/227 Nuclear Materials Held for Sale (157) 51 0 0 228-229 Allowances (158.1 and 158.2) 52



### FERC FORM NO. 1 (REV. 12-03) Page110

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission X Date of Report (Mo, Da, Yr) Year/Period of Report

End of COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)

Line No. Title of Account (a) Ref. Page No. (b) Current Year End of Quarter/Year Balance

(c) Prior Year End Balance 12/31

(d) Oklahoma Gas and Electric Company / / 2008/Q4 (Continued)

0 0 (Less) Noncurrent Portion of Allowances 53 0 0 227 Stores Expense Undistributed (163) 54 0 0 Gas Stored Underground - Current (164.1) 55 0 0 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 56 8,022,198 3,754,226 Prepayments (165) 57 0 0 Advances for Gas (166-167) 58 405,832 0 Interest and Dividends Receivable (171) 59 6,271 12,168 Rents Receivable (172) 60 46,965,283 45,735,240 Accrued Utility Revenues (173) 61 26,902,938 31,580,727 Miscellaneous Current and Accrued Assets (174) 62 0 0 Derivative Instrument Assets (175) 63 0 0 (Less) Long-Term Portion of Derivative Instrument Assets (175) 64 0 0 Derivative Instrument Assets - Hedges (176) 65 0 0 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 66 429,648,990 321,337,835 Total Current and Accrued Assets (Lines 34 through 66) 67 DEFERRED DEBITS 68 11,418,446 6,404,921 Unamortized Debt Expenses (181) 69 0 0 230 Extraordinary Property Losses (182.1) 70 0 0 230 Unrecovered Plant and Regulatory Study Costs (182.2) 71 457,317,435 303,798,586 232 Other Regulatory Assets (182.3) 72 738,534 575,148 Prelim. Survey and Investigation Charges (Electric) (183) 73 0 0 Preliminary Natural Gas Survey and Investigation Charges 183.1) 74 0 0 Other Preliminary Survey and Investigation Charges (183.2) 75 0 0 Clearing Accounts (184) 76 0 0 Temporary Facilities (185) 77 165,712 14,795,784 233 Miscellaneous Deferred Debits (186) 78 0 0 Def. Losses from Disposition of Utility Plt. (187) 79 0 0 352-353 Research, Devel. and Demonstration Expend. (188) 80 17,719,822 18,906,520 Unamortized Loss on Reaquired Debt (189) 81 83,036,001 60,567,930 234 Accumulated Deferred Income Taxes (190) 82 0 0 Unrecovered Purchased Gas Costs (191) 83 570,395,950 405,048,889 Total Deferred Debits (lines 69 through 83) 84 4,797,856,864 3,812,215,415 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85



### FERC FORM NO. 1 (REV. 12-03) Page111

### Year/Period of Report Name of Respondent This Report is: (1) An Original (2) A Rresubmission x Date of Report (mo, da, yr) end of

Line No. Title of Account (a) Ref. Page No. (b) Current Year End of Quarter/Year Balance

(c) Prior Year End Balance 12/31

(d) Oklahoma Gas and Electric Company / / 2008/Q4 

### COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)

PROPRIETARY CAPITAL 1 100,946,863 100,946,863 Common Stock Issued (201) 2 250-251 0 0 Preferred Stock Issued (204) 3 250-251 0 0 Capital Stock Subscribed (202, 205) 4 252 0 0 Stock Liability for Conversion (203, 206) 5 252 409,501,960 409,501,960 Premium on Capital Stock (207) 6 252 154,997,342 447,997,342 Other Paid-In Capital (208-211) 7 253 0 0 Installments Received on Capital Stock (212) 8 252 0 0 (Less) Discount on Capital Stock (213) 9 254 0 0 (Less) Capital Stock Expense (214) 10 254 757,803,524 865,810,410 Retained Earnings (215, 215.1, 216) 11 118-119 102,841 102,502 Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119 0 0 (Less) Reaquired Capital Stock (217) 13 250-251 0 0 Noncorporate Proprietorship (Non-major only) (218) 14 0 0 Accumulated Other Comprehensive Income (219) 15 122(a)(b) 1,423,352,530 1,824,359,077 Total Proprietary Capital (lines 2 through 15) 16 LONG-TERM DEBT 17 135,400,000 135,300,000 Bonds (221) 18 256-257 0 0 (Less) Reaquired Bonds (222) 19 256-257 0 0 Advances from Associated Companies (223) 20 256-257 709,950,000 1,409,950,000 Other Long-Term Debt (224) 21 256-257 0 0 Unamortized Premium on Long-Term Debt (225) 22 1,988,737 3,821,355 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 23 843,361,263 1,541,428,645 Total Long-Term Debt (lines 18 through 23) 24 OTHER NONCURRENT LIABILITIES 25 0 0 Obligations Under Capital Leases - Noncurrent (227) 26 0 0 Accumulated Provision for Property Insurance (228.1) 27 2,405,000 2,216,375 Accumulated Provision for Injuries and Damages (228.2) 28 118,125,206 261,842,728 Accumulated Provision for Pensions and Benefits (228.3) 29 0 0 Accumulated Miscellaneous Operating Provisions (228.4) 30 0 0 Accumulated Provision for Rate Refunds (229) 31 0 0 Long-Term Portion of Derivative Instrument Liabilities 32 0 0 Long-Term Portion of Derivative Instrument Liabilities - Hedges 33 4,928,405 5,221,787 Asset Retirement Obligations (230) 34 125,458,611 269,280,890 Total Other Noncurrent Liabilities (lines 26 through 34) 35 CURRENT AND ACCRUED LIABILITIES 36 757,577 0 Notes Payable (231) 37 164,347,799 105,043,478 Accounts Payable (232) 38 278,655,539 15,836,884 Notes Payable to Associated Companies (233) 39 81,009,277 9,016,592 Accounts Payable to Associated Companies (234) 40 53,633,284 56,769,703 Customer Deposits (235) 41 24,881,211 27,904,554 Taxes Accrued (236) 42 262-263 21,468,057 33,155,200 Interest Accrued (237) 43 0 0 Dividends Declared (238) 44 0 0 Matured Long-Term Debt (239) 45



### FERC FORM NO. 1 (rev. 12-03) Page112

### Year/Period of Report Name of Respondent This Report is: (1) An Original (2) A Rresubmission x Date of Report (mo, da, yr) end of

Line No. Title of Account (a) Ref. Page No. (b) Current Year End of Quarter/Year Balance

(c) Prior Year End Balance 12/31

(d) Oklahoma Gas and Electric Company / / 2008/Q4 (continued) 

### COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)

0 0 Matured Interest (240) 46 8,014,719 10,664,326 Tax Collections Payable (241) 47 41,847,372 47,380,419 Miscellaneous Current and Accrued Liabilities (242) 48 0 202,804 Obligations Under Capital Leases-Current (243) 49 0 0 Derivative Instrument Liabilities (244) 50 0 0 (Less) Long-Term Portion of Derivative Instrument Liabilities 51 0 0 Derivative Instrument Liabilities - Hedges (245) 52 0 0 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 53 674,614,835 305,973,960 Total Current and Accrued Liabilities (lines 37 through 53) 54 DEFERRED CREDITS 55 0 0 Customer Advances for Construction (252) 56 21,970,123 17,329,819 Accumulated Deferred Investment Tax Credits (255) 57 266-267 0 0 Deferred Gains from Disposition of Utility Plant (256) 58 13,167,203 19,984,674 Other Deferred Credits (253) 59 269 28,065,540 26,401,697 Other Regulatory Liabilities (254) 60 278 0 0 Unamortized Gain on Reaquired Debt (257) 61 0 0 Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277 591,683,261 686,981,063 Accum. Deferred Income Taxes-Other Property (282) 63 90,542,049 106,117,039 Accum. Deferred Income Taxes-Other (283) 64 745,428,176 856,814,292 Total Deferred Credits (lines 56 through 64) 65 3,812,215,415 4,797,856,864 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66



### FERC FORM NO. 1 (rev. 12-03) Page113Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

STATEMENT OF INCOME Oklahoma Gas and Electric Company X / / 2008/Q4

Line

(c) (b) (a) Title of Account No. Total Current Year to Date Balance for

Quarter/Year (d) (Ref.) Page No. Quarterly 1. Enter in column (d) the balance for the reporting quarter and in column (e) the balance for the same three month period for the prior year. 2. Report in column (f) the quarter to date amounts for electric utility function; in column (h) the quarter to date amounts for gas utility, and in (j) the quarter to date amounts for other utility function for the current year quarter. 3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in (k) the quarter to date amounts for other utility function for the prior year quarter. 4. If additional columns are needed place them in a footnote. Annual or Quarterly if applicable 5. Do not report fourth quarter data in columns (e) and (f) 6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals. 7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above. 8. Report data for lines 8, 10 and 11 for Natural Gas companies using accounts 404.1, 404.2, 404.3, 407.1 and 407.2.

Current 3 Months Ended Quarterly Only No 4th Quarter (e) Prior 3 Months Ended Quarterly Only No 4th Quarter (f) Total Prior Year to Date Balance for

Quarter/Year

UTILITY OPERATING INCOME 1 2,036,213,558 1,902,651,057 300-301 Operating Revenues (400) 2 Operating Expenses 3 1,424,171,865 1,308,503,980 320-323 Operation Expenses (401) 4 122,160,355 106,443,855 320-323 Maintenance Expenses (402) 5 145,532,587 135,906,613 336-337 Depreciation Expense (403) 6 45,247 45,250 336-337 Depreciation Expense for Asset Retirement Costs (403.1) 7 3,804,341 2,829,927 336-337 Amort. & Depl. of Utility Plant (404-405) 8 336-337 Amort. of Utility Plant Acq. Adj. (406) 9 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10Amort. of Conversion Expenses (407) 11 Regulatory Debits (407.3) 12 (Less) Regulatory Credits (407.4) 13 59,952,017 56,286,140 262-263 Taxes Other Than Income Taxes (408.1) 14 -29,898,238 68,251,058 262-263 Income Taxes - Federal (409.1) 15 -3,798,508 633,069 262-263 - Other (409.1) 16 120,753,646 62,538,134 234, 272-277 Provision for Deferred Income Taxes (410.1) 17 28,850,624 54,199,551 234, 272-277 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 18 -4,640,304 -4,812,540 266 Investment Tax Credit Adj. - Net (411.4) 19 (Less) Gains from Disp. of Utility Plant (411.6) 20 Losses from Disp. of Utility Plant (411.7) 21 389,346 472,993 (Less) Gains from Disposition of Allowances (411.8) 22 Losses from Disposition of Allowances (411.9) 23Accretion Expense (411.10) 24 1,808,843,038 1,681,952,942 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25 227,370,520 220,698,115 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 26

FERC FORM NO. 1/3-Q (REV. 02-04) Page 114Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STATEMENT OF INCOME FOR THE YEAR (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line Previous Year to Date (in dollars) (k) (j) (g) ELECTRIC UTILITY

No. Current Year to Date (in dollars) OTHER UTILITY

(l) GAS UTILITY Previous Year to Date (in dollars) Current Year to Date (in dollars) Previous Year to Date (in dollars) Current Year to Date (in dollars) (h) (i) 9. Use page 122 for important notes regarding the statement of income for any account thereof. 10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases. 11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income, and expense accounts. 12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122. 13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income, including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes. 14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports. 15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to this schedule.

1 2,036,213,558 1,902,651,057 2 3 1,424,171,865 1,308,503,980 4 122,160,355 106,443,855 5 145,532,587 135,906,613 6

45,247 45,250 7 3,804,341 2,829,927 8 9 10 11 12 13 59,952,017 56,286,140 14 -29,898,238 68,251,058 15 -3,798,508 633,069 16 120,753,646 62,538,134 17 28,850,624 54,199,551 18 -4,640,304 -4,812,540 19 20 21 389,346 472,993 22 23 24 1,808,843,038 1,681,952,942 25 227,370,520 220,698,115 26

FERC FORM NO. 1 (ED. 12-96) Page 115Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STATEMENT OF INCOME FOR THE YEAR (continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line

Previous Year (c) (b) (a) Title of Account No.

Current Year TOTAL

(d) (Ref.) Page No. Current 3 Months Ended Quarterly Only No 4th Quarter (e) Prior 3 Months Ended Quarterly Only No 4th Quarter (f)

227,370,520 220,698,115 Net Utility Operating Income (Carried forward from page 114) 27 Other Income and Deductions 28 Other Income 29 Nonutilty Operating Income 30 2,265,348 2,331,821 Revenues From Merchandising, Jobbing and Contract Work (415) 31 2,258,170 2,338,029 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32 134,319 143,624 Revenues From Nonutility Operations (417) 33 2,410 8,292 (Less) Expenses of Nonutility Operations (417.1) 34 254,015 474,823 Nonoperating Rental Income (418) 35 -339 -110 119 Equity in Earnings of Subsidiary Companies (418.1) 36 4,423,218 25,677 Interest and Dividend Income (419) 37Allowance for Other Funds Used During Construction (419.1) 38 3,220,212 4,347,422 Miscellaneous Nonoperating Income (421) 39 1,367,436 1,339,484 Gain on Disposition of Property (421.1) 40 9,403,629 6,316,420 TOTAL Other Income (Enter Total of lines 31 thru 40) 41 Other Income Deductions 42 3,562 3,834,803 Loss on Disposition of Property (421.2) 43 1,466,194 340 Miscellaneous Amortization (425) 44 1,789,047 2,210,503 340 Donations (426.1) 45Life Insurance (426.2) 46 11,467 226,278 Penalties (426.3) 47 647,053 685,178 Exp. for Certain Civic, Political & Related Activities (426.4) 48 9,424,173 196,399 Other Deductions (426.5) 49 13,341,496 7,153,161 TOTAL Other Income Deductions (Total of lines 43 thru 49) 50 Taxes Applic. to Other Income and Deductions 51 262-263 Taxes Other Than Income Taxes (408.2) 52 -1,231,498 716,804 262-263 Income Taxes-Federal (409.2) 53 68,569 25,569 262-263 Income Taxes-Other (409.2) 54 234, 272-277 Provision for Deferred Inc. Taxes (410.2) 55 234, 272-277 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 56 Investment Tax Credit Adj.-Net (411.5) 57 (Less) Investment Tax Credits (420) 58 -1,162,929 742,373 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59 -2,774,938 -1,579,114 Net Other Income and Deductions (Total of lines 41, 50, 59) 60 Interest Charges 61 67,782,003 51,528,035 Interest on Long-Term Debt (427) 62 796,829 637,225 Amort. of Debt Disc. and Expense (428) 63 1,186,698 1,186,698 Amortization of Loss on Reaquired Debt (428.1) 64 (Less) Amort. of Premium on Debt-Credit (429) 65 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66 2,076,649 6,091,528 340 Interest on Debt to Assoc. Companies (430) 67 13,697,074 1,955,558 340 Other Interest Expense (431) 68 3,950,218 3,989,407 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69 81,589,035 57,409,637 Net Interest Charges (Total of lines 62 thru 69) 70 143,006,547 161,709,364 Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71 Extraordinary Items 72 Extraordinary Income (434) 73 (Less) Extraordinary Deductions (435) 74 Net Extraordinary Items (Total of line 73 less line 74) 75 262-263 Income Taxes-Federal and Other (409.3) 76 Extraordinary Items After Taxes (line 75 less line 76) 77 143,006,547 161,709,364 Net Income (Total of line 71 and 77) 78

FERC FORM NO. 1/3-Q (REV. 02-04) Page 117Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

STATEMENT OF RETAINED EARNINGS Oklahoma Gas and Electric Company X / / 2008/Q4

Line Current Quarter/Year Year to Date

Balance

(c) (b) (a) Item Contra Primary

No. Account Affected 

### 1. Do not report Lines 49-53 on the quarterly version. 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 Quarter/Year Year to Date

Balance

(d) UNAPPROPRIATED RETAINED EARNINGS (Account 216) 655,935,570 757,803,524 1 Balance-Beginning of Period 2 Changes 3Adjustments to Retained Earnings (Account 439) ( 6,267,420) 4 FIN 48 Interest Adjustment 5 6 7 8 ( 6,267,420) 9TOTAL Credits to Retained Earnings (Acct. 439) 2,068,510 10 Federal income tax effect of FIN 48 357,390 11 State income tax effect of FIN 48 12 13 14 2,425,900 15TOTAL Debits to Retained Earnings (Acct. 439) 161,709,474 143,006,886 16 Balance Transferred from Income (Account 433 less Account 418.1) 17Appropriations of Retained Earnings (Acct. 436) 18 19 20 21 22TOTAL Appropriations of Retained Earnings (Acct. 436) 23 Dividends Declared-Preferred Stock (Account 437) 24 25 26 27 28 29TOTAL Dividends Declared-Preferred Stock (Acct. 437) 30 Dividends Declared-Common Stock (Account 438) ( 56,000,000) -35,000,000 31 32 33 34 35 ( 56,000,000) -35,000,000 36TOTAL Dividends Declared-Common Stock (Acct. 438) 37Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings 757,803,524 865,810,410 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37) APPROPRIATED RETAINED EARNINGS (Account 215) 39 40 FERC FORM NO. 1/3-Q (REV. 02-04) Page 118Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

STATEMENT OF RETAINED EARNINGS Oklahoma Gas and Electric Company X / / 2008/Q4

Line Current Quarter/Year Year to Date

Balance

(c) (b) (a) Item Contra Primary

No. Account Affected 

### 1. Do not report Lines 49-53 on the quarterly version. 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 Quarter/Year Year to Date

Balance

(d) 41 42 43 44 45TOTAL Appropriated Retained Earnings (Account 215) APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1) 46TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1) 47TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46) 757,803,524 865,810,410 48TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1) UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account Report only on an Annual Basis, no Quarterly 102,951 102,841 49 Balance-Beginning of Year (Debit or Credit) ( 110) -339 50 Equity in Earnings for Year (Credit) (Account 418.1) 51 (Less) Dividends Received (Debit) 52 102,841 102,502 53 Balance-End of Year (Total lines 49 thru 52)

FERC FORM NO. 1/3-Q (REV. 02-04) Page 119(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. (2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. (3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. (4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

STATEMENT OF CASH FLOWS Oklahoma Gas and Electric Company X / / 2008/Q4

Line Description (See Instruction No. 1 for Explanation of Codes) Current Year to Date Quarter/Year (b) (a) No. Previous Year to Date Quarter/Year (c) 1 Net Cash Flow from Operating Activities: 161,709,364 143,006,547 2 Net Income (Line 78(c) on page 117) 3 Noncash Charges (Credits) to Income: 135,951,863 145,577,834 4 Depreciation and Depletion 5 Amortization of 2,829,927 3,804,341 6 Limited-Term Electric Plant 7 8,338,583 91,903,022 8 Deferred Income Taxes (Net) -4,812,540 -4,640,304 9 Investment Tax Credit Adjustment (Net) 2,345,773 -36,968,353 10 Net (Increase) Decrease in Receivables -19,667,944 -19,817,398 11 Net (Increase) Decrease in Inventory 12 Net (Increase) Decrease in Allowances Inventory 38,319,255 -105,267,447 13 Net Increase (Decrease) in Payables and Accrued Expenses 21,078,445 -153,518,849 14 Net (Increase) Decrease in Other Regulatory Assets 8,484,181 -1,663,843 15 Net Increase (Decrease) in Other Regulatory Liabilities 16 (Less) Allowance for Other Funds Used During Construction -110 -339 17 (Less) Undistributed Earnings from Subsidiary Companies 18 Other (provide details in footnote): -6,000,000 -1,230,043 19 Net (Increase) Decrease in Accrued Utility Revenues -15,947,004 409,817 20 Net (Increase) Decrease in Other Current Assets -98,148,769 142,256,106 21 Net (Decrease) Increase in Other Operating Activities 234,481,244 203,851,769 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 23 24 Cash Flows from Investment Activities: 25 Construction and Acquisition of Plant (including land): -377,360,532 -840,090,803 26 Gross Additions to Utility Plant (less nuclear fuel) 27 Gross Additions to Nuclear Fuel 28 Gross Additions to Common Utility Plant -410 -908,897 29 Gross Additions to Nonutility Plant 30 (Less) Allowance for Other Funds Used During Construction 31 Other (provide details in footnote): 32 33 -377,360,942 -840,999,700 34 Cash Outflows for Plant (Total of lines 26 thru 33) 35 36 Acquisition of Other Noncurrent Assets (d) 37 Proceeds from Disposal of Noncurrent Assets (d) 930,693 539,841 38 Proceeds from Sale of Fixed Assets 39 Investments in and Advances to Assoc. and Subsidiary Companies 197,239,528 30,181,345 40 Contributions and Advances from Assoc. and Subsidiary Companies 41 Disposition of Investments in (and Advances to) 42 Associated and Subsidiary Companies 43 44 Purchase of Investment Securities (a) 45 Proceeds from Sales of Investment Securities (a)

FERC FORM NO. 1 (ED. 12-96) Page 120(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as investments, fixed assets, intangibles, etc. (2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash Equivalents at End of Period" with related amounts on the Balance Sheet. (3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid. (4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the dollar amount of leases capitalized with the plant cost. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

STATEMENT OF CASH FLOWS Oklahoma Gas and Electric Company X / / 2008/Q4

Line Description (See Instruction No. 1 for Explanation of Codes) Current Year to Date Quarter/Year (b) (a) No. Previous Year to Date Quarter/Year (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) Investing Activities -179,190,721 -810,278,514 57Total of lines 34 thru 55) 58 59 Cash Flows from Financing Activities: 60 Proceeds from Issuance of: 742,989,500 61 Long-Term Debt (b) 62 Preferred Stock 63 Common Stock 64 Other (provide details in footnote): 65 757,577 66 Net Increase in Short-Term Debt (c) 67 Other (provide details in footnote): 68 69 757,577 742,989,500 70 Cash Provided by Outside Sources (Total 61 thru 69) 71 72 Payments for Retirement of: -50,000 -50,100,000 73 Long-term Debt (b) 74 Preferred Stock 75 Common Stock 76 Other (provide details in footnote): 77 -757,577 78 Net Decrease in Short-Term Debt (c) 79 80 Dividends on Preferred Stock -56,000,000 -35,000,000 81 Dividends on Common Stock 82 Net Cash Provided by (Used in) Financing Activities -55,292,423 657,131,923 83 (Total of lines 70 thru 81) 84 85 Net Increase (Decrease) in Cash and Cash Equivalents -1,900 50,705,178 86 (Total of lines 22,57 and 83) 87 15,050 13,150 88 Cash and Cash Equivalents at Beginning of Period 89 13,150 50,718,328 90 Cash and Cash Equivalents at End of period

FERC FORM NO. 1 (ED. 12-96) Page 121

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report Year/Period of Report End of

NOTES TO FINANCIAL STATEMENTS 

### Oklahoma Gas and Electric Company X / / 2008/Q4

PAGE 122 INTENTIONALLY LEFT BLANK SEE PAGE 123 FOR REQUIRED INFORMATION. 1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement, providing a subheading for each statement except where a note is applicable to more than one statement. 2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on cumulative preferred stock. 3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant adjustments and requirements as to disposition thereof. 4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts. 5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such restrictions. 6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein. 7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be omitted. 8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements; status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters shall be provided even though a significant change since year end may not have occurred. 9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are applicable and furnish the data required by the above instructions, such notes may be included herein.

FERC FORM NO. 1 (ED. 12-96) Page 122

### OKLAHOMA GAS AND 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. The Company is subject to regulation by the Oklahoma Corporation Commission (“OCC”), the Arkansas Public Service Commission (“APSC”) and the Federal Energy Regulatory Commission (“FERC”). The Company is a wholly-owned subsidiary of OGE Energy Corp. (“OGE Energy”) which is an energy and energy services provider offering physical delivery and related services for 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. The Company 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. The accompanying financial statements have been presented in the format prescribed by FERC. The requirements of FERC related to the grouping of assets, liabilities, revenue and expense accounts differ from those under accounting principles generally accepted in the United States. The Company records certain actual or anticipated 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. The following is a description of the Company's major regulatory assets and liabilities. The Company adopted SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106 and 132R,” effective December 31, 2006, which required the Company to separately disclose the items that had not yet been recognized as components of net periodic pension cost including, net loss, prior service cost and net transition obligation at December 31, 2006. For companies not subject to SFAS No. 71, SFAS No. 158 required these charges to be included in Accumulated Other Comprehensive Income. However, for companies subject to SFAS No. 71, these charges were allowed to be recorded as a regulatory asset if: (i) the utility had historically recovered and currently recovers pension and postretirement benefit plan expense in its electric rates; and (ii) there was no negative evidence that the existing regulatory treatment will change. The Company met both criteria and, therefore, recorded the net loss, prior service cost and net transition obligation as a regulatory asset as these expenses are probable of future recovery. If, in the future, the regulatory bodies indicate a change in policy related to the recovery of pension and postretirement benefit plan expenses, this could cause the SFAS No. 158 regulatory asset balance to be reclassified to Accumulated Other Comprehensive Income. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.1

### The following table is a summary of the components of the SFAS No. 158 regulatory asset at December 31: December 31(In millions) 2008 2007 Defined benefit pension plan and restoration of retirement income plan: Net loss $ 259.8 $ 112.3 Prior service cost 3.5 4.8 Defined benefit postretirement plans: Net loss 70.4 42.5 Net transition obligation 10.2 12.7 Prior service cost 0.8 2.3 Total $ 344.7 $ 174.6 The following amounts in the SFAS No. 158 regulatory asset at December 31, 2008 are expected to be recognized as components of net periodic benefit cost in 2009:

(In millions) Defined benefit pension plan and restoration of retirement income plan: Net loss $ 20.4 Prior service cost 1.2 Defined benefit postretirement plans: Net loss 3.6 Net transition obligation 2.5 Prior service cost 1.5 Total $ 29.2 For a discussion of regulatory matters related to the deferred storm expenses and deferred Red Rock expenses and related reductions in the amounts previously recorded, see Note 13. In accordance with the OCC order received by the Company in December 2005 in its Oklahoma rate case, the Company was allowed to recover a certain amount of pension plan expenses. At December 31, 2008, there was approximately $14.6 million of expenses exceeding this level primarily related to pension settlement charge recorded by the Company during 2007 (see Note 11 for a further discussion). These excess amounts have been recorded as a regulatory asset as the Company believes these expenses are probable of future recovery. Income taxes recoverable from customers represent income tax benefits previously used to reduce the Company’s revenues. These amounts are being recovered in rates as the temporary 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 estimated 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”) natural gas-fired combined cycle NRG McClain Station (the “McClain Plant”) completed on July 9, 2004, and consistent with the 2002 agreed-upon settlement of aCompany rate case with the OCC,the Companyhad 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.At December 31, 2008, the McClain Plant regulatory asset was approximately $6.2 million which is being recovered over the remaining one-year time period as authorized in the OCC rate order which began in January 2006.Approximately $15.5 million of the McClain Plant deferred expenses are included inthe Company’s rate base for purposes of earning a return. 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. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.2

### 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 effect on the Company’s Financial Statements. 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, asset retirement obligations (“ARO”), fair value and cash flow hedges, regulatory assets and liabilities, unbilled revenues and the allowance for uncollectible accounts receivable. 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.

Allowance for Uncollectible Accounts Receivable Customer balances are generally written off if not collected within six months after the final billing 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 12-month 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 $2.3 million and $3.4 million at December 31, 2008 and 2007, respectively. New business customers are required to provide a security deposit in the form of cash, bond or irrevocable letter of credit that is refunded when the account is closed. New residential customers, whose outside credit scores indicate risk, are required to provide a security deposit that is refunded based on customer protection rules defined by the OCC and the APSC. The payment behavior of all existing customers is continuously monitored and, if the payment behavior indicates sufficient risk within the meaning of the applicable utility regulation, 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. Historically, the Company has used the last-in, first-out (“LIFO”) method of accounting for inventory removed from storage or stockpiles. Effective January 1, 2008, the Company began using the weighted-average cost method to value inventory that is physically added to or withdrawn from storage or stockpiles in accordance with Oklahoma Senate Bill No. 609 (“SB 609”) that was adopted in Oklahoma in 2007. SB 609 requires that electric utilities record fuel or natural gas removed from storage or stockpiles using the weighted-average cost method of accounting for inventory. In addition to satisfying the requirements of SB 609, management believes that the change from LIFO to weighted-average cost is also preferable because it provides for a more meaningful presentation in the financial statements taken as a whole and reduces the volatility associated with fuel price fluctuations on the Company’s customers. The majority of electric utility companies use the weighted-average cost method. SFAS No. 154, “Accounting Changes and Error Corrections, a replacement of Accounting Principles Board (“APB”) Opinion No. 20 and FASB Statement No. 3,” requires that an entity report a change in accounting principle through retrospective application of the new principle to all prior periods unless it is impractical to do so. However, SFAS No. 71 requires that changes in accounting methods for regulated entities that affect allowable costs for rate-making purposes should be implemented in the same way that such an accounting change would be implemented for rate-making purposes. In accordance with an order from the OCC, the Company’s change in accounting method for inventory affected allowable costs for rate-making purposes, on a prospective basis only beginning January 1, 2008. Therefore the change in accounting was implemented prospectively and the Company did not restate previously issued financial statements. Also, in accordance with the order from the OCC, on January 1, 2008, the Company recorded an increase in Fuel Stock of approximately $7.9 million with a corresponding offset recorded in Miscellaneous Current and Accrued Assets on the Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.3

### Company’s Financial Statements. The Company began recovering costs from its customers using the weighted-average cost method for inventory on January 1, 2008. The change in accounting for fuel inventory to the weighted-average cost method resulted in a higher fuel inventory balance of approximately $0.4 million at December 31, 2008. The change in accounting for fuel inventory to the weighted-average cost method did not impact the Statement of Income for the year ended December 31, 2008 as the Company’s fuel costs are passed through to its customers through fuel adjustment clauses. The amount of fuel inventory was approximately $56.6 million and $44.3 million at December 31, 2008 and 2007, respectively. The estimated replacement cost of fuel inventories was higher than the stated LIFO cost by approximately $7.4 million for 2007 based on the average cost of fuel purchased. Property, Plant and Equipment All property, plant and equipment are recorded at cost. Newly constructed plant is added to plant balances at cost which includes contracted services, direct labor, materials, overhead, transportation costs and the allowance for funds used during construction (“AFUDC”). Replacements of units of property are capitalized as plant. For assets that belong to a common plant account, the replaced plant is removed from plant balances and the cost of such property less net salvage is charged to Accumulated Depreciation. For assets that do not belong to a common plant account, the replaced plant is removed from plant balances with the related accumulated depreciation and the remaining balance is recorded as a loss in the Statement of Income as Loss on Disposition of Property. Repair and replacement of minor items of property are included in the Statement of Income as Maintenance Expense. The below table presents the Company’s ownership interest in the jointly-owned McClain Plant and the jointly-owned 1,230 MW natural gas-fired, combined-cycle power generation facility in Luther, Oklahoma (the “Redbud Facility”), and, as disclosed below, only the Company’s ownership interest is reflected in the property, plant and equipment and accumulated depreciation balances in this table. The owners of the remaining interests in the McClain Plant and the Redbud Facility are responsible for providing their own financing of capital expenditures. Also, only the Company’s proportionate interests of any direct expenses of the McClain Plant and the Redbud Facility such as fuel, maintenance expense and other operating expenses are included in the applicable financial statements captions in the Statement of Income.

December 31, 2008 (In millions) Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment

McClain Plant 77 $ 181.0 $ 44.6 $ 136.4 Redbud Facility 51 $ 496.6 (A) $ 63.9 (B) $ 432.7 (A) This amount includes a plant acquisition adjustment of approximately $153.7 million. (B) This amount includes accumulated amortization of the plant acquisition adjustment of approximately $1.5 million.

December 31, 2007 (In millions) Percentage Ownership Total Property, Plant and Equipment Accumulated Depreciation Net Property, Plant and Equipment

McClain Plant 77 $ 181.0 $ 35.4 $ 145.6 Depreciation and Amortization The provision for depreciation, which was approximately 2.7 percent of the average depreciable utility plant for both 2008 and 2007, 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 method. In 2009, the provision for depreciation is projected to be approximately 2.8 percent of the average depreciable utility plant. Amortization of intangibles is computed using the straight-line method. Approximately 6.3 percent of the remaining amortizable intangible plant balance at December 31, 2008 will be amortized over three years with approximately 37 percent of the remaining amortizable intangible plant balance at December 31, 2008 being amortized over their respective lives ranging from four to 25 years. Amortization Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.4

### of plant acquisition adjustments is provided on a straight-line basis over the estimated remaining service life on the acquired asset. Plant acquisition adjustments include approximately $153.7 million for the Redbud Facility, which will be amortized over a 27-year life and approximately $0.5 million for certain substation facilities in the Company’s service territory, which will be amortized over a 26 to 59-year period. Asset Retirement Obligations In accordance with SFAS No. 143, “Accounting for Asset Retirement Obligations,” for periods subsequent to the initial measurement of an ARO, the Company recognizes period-to-period changes in the liability for an ARO resulting from: (i) the passage of time; and (ii) revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Also, in accordance with FASB Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations,” the Company recognizes a liability for the fair value of an ARO that is conditional on a future event if the liability’s fair value can be reasonably estimated. The fair value of a liability for the conditional ARO is recognized when incurred. Uncertainty surrounding the timing and method of settlement of a conditional ARO is factored into the measurement of the liability when sufficient information existed. However, in some cases, there is insufficient information to estimate the fair value of an ARO. In these cases, the liability is initially recognized in the period in which sufficient information is available for the Company to make a reasonable estimate of the liability’s fair value. The Company did not recognize any new AROs during 2008; however, the Company has identified certain AROs that have not been recorded because the Company determined that these assets, primarily related to the Company’s power plant sites, have indefinite lives. 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 a credit in the Statement of Income and as a charge to Construction Work in Progress in the Comparative Balance Sheet. AFUDC rates, compounded semi-annually, were 3.58 percent, 5.78 percent and 7.79 percent for the years 2008, 2007 and 2006, respectively. The decrease in the AFUDC rates in 2008 was primarily due to lower interest rates on short-term borrowings.

Collection of Sales Tax In the course of its operations, the Company collects sales tax from its customers. The Company records a current liability from sales taxes when it bills its customers and eliminates this liability when the taxes are remitted to the appropriate governmental authorities. The Company excludes the sales tax collected from its operating revenues. Revenue Recognition

GeneralThe 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.

SPP Purchases and Sales In February 2007, the Company began participating in the Southwest Power Pool’s (“SPP”) energy imbalance service market in a dual role as a load serving entity and as a generation owner. The energy imbalance service market requires cash settlements for over or under schedules of generation and load. Market participants, including the Company, are required to submit resource plans and can submit offer curves for each resource available for dispatch. A function of interchange accounting is to match participants’ megawatt-hour (“MWH”) entitlements (generation plus scheduled bilateral purchases) against their MWH obligations (load plus scheduled bilateral sales) during every hour of every day. If the net result during any given hour is an entitlement, the participant is credited with a spot-market sale to the SPP at the respective market price for that hour; if the net result is an obligation, the participant is charged with a spot-market purchase from the SPP at the respective market price for that hour. The SPP purchases and sales are not Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.5

### allocated to individual customers. The Company records the hourly sales to the SPP at market rates in Operating Revenues and the hourly purchases from the SPP at market rates in Operation Expenses in its Financial Statements. 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 fuel adjustment clauses, which are subject to periodic review by the OCC, the APSC and the FERC. Fuel clause under recoveries are generated from under recoveries from the Company’s customers when the Company’s cost of fuel exceeds the amount billed to its customers. Fuel clause over recoveries are generated from over recoveries from the Company’s customers when the amount billed to its customers exceeds the Company’s cost of fuel. The Company’s fuel recovery clauses are designed to smooth the impact of fuel price volatility on customers’ bills. As a result, the Company under recovers fuel costs in periods of rising fuel prices above the baseline charge for fuel and over recovers fuel costs when prices decline below the baseline charge for fuel. Provisions in the fuel clauses are intended to allow the Company to amortize under and over recovery balances.

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. 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 to 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. Accrued 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 OGE Energy allocated operating costs to the Company of approximately $87.4 million, $96.4 million and $88.0 million during 2008, 2007 and 2006, respectively. OGE Energy allocates operating costs to its subsidiaries based on several factors. Operating costs directly related to specific subsidiaries are assigned to those subsidiaries. Where more than one subsidiary benefits from certain expenditures, the costs are shared between those subsidiaries receiving the benefits. Operating costs incurred for the benefit of all subsidiaries are allocated among the subsidiaries, based primarily upon head-count, occupancy, usage or the “Distrigas” method. The Distrigas method is a three-factor formula that uses an equal weighting of payroll, net operating revenues and gross property, plant and equipment. OGE Energy adopted the Distrigas method in January 1996 as a result of a recommendation by the OCC Staff. OGE Energy believes this method provides a reasonable basis for allocating common expenses. In 2008, 2007 and 2006, the Company recorded an expense from its affiliate, Enogex LLC and its subsidiaries (“Enogex”), of approximately $34.8 million, $34.7 million and $34.9 million, respectively, for transporting gas to the Company’s natural gas-fired generating facilities. In each of 2008, 2007 and 2006, the Company recorded an expense from Enogex of approximately $12.7 million for natural gas storage services. In 2008, 2007 and 2006, the Company also recorded natural gas purchases from its affiliate, OGE Energy Resources, Inc. (“OERI”) of approximately $79.6 million, $55.2 million and $60.4 million, respectively. Approximately $6.6 million and $11.3 million were recorded at December 31, 2008 and 2007, respectively, and are included in Accounts Payable to Associated Companies in the Comparative Balance Sheet for these activities. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.6

### In both 2008 and 2007, the Company recorded interest income of less than $0.1 million from OGE Energy for advances made to OGE Energy from the Company. In 2006, the Company recorded interest income of approximately $0.3 million from OGE Energy for advances made to OGE Energy by the Company. In 2008, 2007 and 2006, the Company recorded interest expense of approximately $2.1 million, $6.1 million and $2.6 million, respectively, to OGE Energy for advances made by OGE Energy to the Company. The interest rate charged on advances to the Company from OGE Energy approximates OGE Energy’s commercial paper rate. In 2008, 2007 and 2006, the Company declared dividends of approximately $35.0 million, $56.0 million and $24.0 million, respectively, to OGE Energy. On September 25, 2008, OGE Energy made a capital contribution to the Company for approximately $293.0 million. 2. Accounting Developments In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities,” which requires enhanced disclosures about an entity’s derivative and hedging activities and is intended to improve the transparency of financial reporting. SFAS No. 161 applies to all entities. SFAS No. 161 applies to all derivative instruments, including bifurcated derivative instruments and related hedging items accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and its related interpretations. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133 with the intent to provide users of financial statements with an enhanced understanding of: (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The Company adopted this new standard effective January 1, 2009. The adoption of this new standard will change the disclosure related to derivative and hedging activities in the Company’s financial statements. In 2004, the Company adopted a standard costing model utilizing a fully loaded activity rate (including payroll, benefits, other employee related costs and overhead costs) to be applied to projects eligible for capitalization or deferral. In March 2008, the Company determined that the application of the fully loaded activity rates had unintentionally resulted in the over-capitalization of immaterial amounts of certain payroll, benefits, other employee related costs and overhead costs in prior years. To correct this issue, in March 2008, the Company recorded a pre-tax charge of approximately $9.5 million ($5.8 million after tax) as an increase in Operation Expense in the Statements of Income for the three months ended March 31, 2008 and a corresponding $8.6 million decrease in Construction Work in Progress and $0.9 million decrease in Other Regulatory Assets related to the regulatory asset associated with storm costs in the Comparative Balance Sheet as of March 31, 2008.

3. Fair Value Measurements In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements,” which defines fair value, establishes a framework for measuring fair value in GAAP and establishes a hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value. SFAS No. 157 expands disclosures about the use of fair value to measure assets and liabilities in interim and annual periods subsequent to initial recognition. The guidance in SFAS No. 157 applies to derivatives and other financial instruments measured at fair value under SFAS No. 133 at initial recognition and in all subsequent periods. Therefore, SFAS No. 157 nullifies the guidance in footnote 3 of Emerging Issues Task Force (“EITF”) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” SFAS No. 157 also amends SFAS No. 133 to remove the guidance similar to that nullified in EITF Issue No. 02-3. SFAS No. 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The provisions of SFAS No. 157 generally are to be applied prospectively as of the beginning of the fiscal year in which it is initially applied. The Company adopted this new standard effective January 1, 2008. The following table is a summary of the Company’s liabilities that are measured at fair value on a recurring basis in accordance with SFAS No. 157. At December 31, 2008, the Company had no assets measured at fair value on a recurring basis in accordance with SFAS No. 157. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.7

### December 31, (In millions) 2008 Level 3 Liabilities Asset retirement obligations $ 5.2 $ 5.2 Total $ 5.2 $ 5.2 The three levels defined by the SFAS No. 157 hierarchy and examples of each are as follows: Level 1 inputs are quoted prices in active markets for identical assets or liabilities that the reporting entity has the ability to access at the measurement date. An active market for the asset or liability is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. If the asset or liability has a specified (contractual) term, a Level 2 input must be observable for substantially the full term of the asset or liability. Level 2 inputs include the following: (i) quoted prices for similar assets or liabilities in active markets; (ii) quoted prices for identical or similar assets or liabilities in markets that are not active; (iii) inputs other than quoted prices that are observable for the asset or liability; or (iv) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Level 3 inputs are unobservable inputs for the asset or liability. Unobservable inputs shall be used to measure fair value to the extent that observable inputs are not available. Unobservable inputs shall reflect the reporting entity’s own assumptions about the assumptions that market participants would use in pricing the asset or liability (including assumptions about risk). Unobservable inputs shall be developed based on the best information available in the circumstances, which might include the reporting entity’s own data. The reporting entity’s own data used to develop unobservable inputs shall be adjusted if information is reasonably available that indicates that market participants would use different assumptions. An example of instruments that may be classified as Level 3 includes the valuation of ARO’s such that there are no closely related markets in which quoted prices are available. The impact to the fair value of derivatives due to credit risk is calculated using the probability of default based on Standard & Poor’s Ratings Services (“Standard & Poor’s”) and/or internally generated ratings. The fair value of derivative assets is adjusted for credit risk. The fair value of derivative liabilities is adjusted for credit risk only if the impact is deemed material. The Company has no derivatives at December 31, 2008. The following table is a summary of the Company’s liabilities that are measured at fair value on a recurring basis in accordance with SFAS No. 157 using significant unobservable inputs (Level 3).

Year Ended (In millions) December 31, 2008 Asset Retirement Obligations Beginning balance $ 4.9 Total gains or losses (realized/unrealized)

Included in earnings 0.3 Included in other comprehensive income

--- Purchases, sales, issuances and settlements, net

--- Transfers in and/or out of Level 3

--- Ending balance $ 5.2 The amount of total gains or losses for the periods included in earnings attributable to the change in unrealized gains or losses relating to assets held at December 31, 2008 $

--- Gains and losses (realized and unrealized) included in earnings for the year ended December 31, 2008 attributable to the change in unrealized gains or losses relating to liabilities held at December 31, 2008, if any, are reported in operating revenues. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.8

### 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 31:

2008 2007 Carrying Fair Carrying Fair December 31(In millions) Amount Value Amount Value Price Risk Management Liabilities Interest Rate Swap $

--- $

--- $ 1.7 $ 1.7 Long-Term Debt Senior Notes $ 1,406.1 $ 1,327.4 $ 708.0 $ 729.2 Industrial Authority Bonds 135.3 135.3 135.4 135.4 The carrying value of the financial instruments on the Comparative Balance Sheet not otherwise discussed above approximates fair value except for long-term debt which is valued at the carrying amount. The valuation of the Company’s interest rate swap was determined generally based on quoted market prices. However, in certain instances where market quotes are not available, other valuation techniques or models are used to estimate market values. The fair value of the Company’s long-term debt is based on quoted market prices and management’s estimate of current rates available for similar issues with similar maturities. 4. Stock-Based Compensation On January 21, 1998, OGE Energy adopted a Stock Incentive Plan (the “1998 Plan”) and in 2003, OGE Energy adopted another Stock Incentive Plan (the “2003 Plan” that replaced the 1998 Plan). In 2008, OGE Energy adopted, and its shareowners approved, a new Stock Incentive Plan (the “2008 Plan” and together with the 1998 Plan and the 2003 Plan, the “Plans”). The 2008 Plan replaced the 2003 Plan and no further awards will be granted under the 2003 Plan or the 1998 Plan. As under the 2003 Plan and the 1998 Plan, under the 2008 Plan, restricted stock, stock options, stock appreciation rights and performance units may be granted to officers, directors and other key employees of OGE Energy and its subsidiaries. OGE Energy has authorized the issuance of up to 2,750,000 shares under the 2008 Plan. Effective January 1, 2006, OGE Energy adopted SFAS No. 123 (Revised), “Share-Based Payment,” using the modified prospective transition method. Under that transition method, the Company’s compensation cost recognized in the first quarter of 2006 included: (i) compensation cost for all share-based payments granted prior to, but not yet vested as of, January 1, 2006, based on the fair value calculated in accordance with the provisions of SFAS No. 123(R); and (ii) compensation cost for all share-based payments granted in the first quarter of 2006, based on the fair value calculated in accordance with the provisions of SFAS No. 123(R). Results for prior periods were not restated. As a result of adopting SFAS No. 123(R) on January 1, 2006, the Company recorded compensation expense of approximately $1.8 million pre-tax ($1.1 million after tax) in 2006 related to the Company’s portion of OGE Energy’s share-based payments. The Company recorded compensation expense of approximately $1.0 million pre-tax ($0.6 million after tax) and approximately $0.9 million pre-tax ($0.6 million after tax) in 2008 and 2007, respectively, related to the Company’s portion of OGE Energy’s share-based payments. Also, during 2008, OGE Energy converted 166,504 performance units based on a payout ratio of 147.33 percent of the target number of performance units granted in February 2005, of which 36,941 performance units related to the Company’s portion. One-third of the performance units were settled in cash for approximately $3.0 million, of which approximately $0.7 million was the Company’s portion, and two-thirds of the performance units were settled in the Company’s common stock. OGE Energy issues new shares to satisfy stock option exercises and payouts of earned performance units. During 2008, 2007 and 2006, there were 875,434 shares, 496,565 shares and 738,426 shares, respectively, of new common stock issued pursuant to OGE Energy’s Plans related to exercised stock options and payouts of earned performance units, of which 38,684, 129,568 and 299,331 shares, respectively, related to the Company’s employees. OGE Energy received approximately $15.0 million, $8.2 million and $14.5 million in 2008, 2007 and 2006, respectively, related to exercised stock options. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.9

### Performance Units Under the Plans, OGE Energy has issued performance units which represent the value of one share of OGE Energy’s common stock. The performance units provide for accelerated vesting if there is a change in control (as defined in the Plans). Each performance unit is subject to forfeiture if the recipient terminates employment with OGE Energy or a subsidiary prior to the end of the three-year award cycle for any reason other than death, disability or retirement. In the event of death, disability or retirement, a participant will receive a prorated payment based on such participant’s number of full months of service during the three-year award cycle, further adjusted based on the achievement of the performance goals during the award cycle. The performance units granted based on total shareholder return (“TSR”) are contingently awarded and will be payable in shares of OGE Energy’s common stock 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 (i.e. three-year cliff vesting period) is dependent on OGE Energy’s TSR ranking relative to a peer group of companies. The performance units granted based on earnings per share (“EPS”) are contingently awarded and will be payable in shares of OGE Energy’s common stock based on OGE Energy’s EPS growth over a three-year award cycle (i.e. three-year cliff vesting period) compared to a target set at the time of the grant by the Compensation Committee of OGE Energy’s Board of Directors. All of the Company’s performance units are classified as equity under SFAS No. 123(R). If there is no or only a partial payout for the performance units at the end of the three-year award cycle, the unearned performance units are cancelled. During 2008, 2007 and 2006, OGE Energy awarded 242,503, 162,730 and 239,856 performance units, respectively, to certain employees of OGE Energy and its subsidiaries, of which 43,508, 27,322 and 34,459, respectively, related to the Company’s employees.
Performance Units – Total Shareholder Return The Company recorded compensation expense of approximately $0.7 million pre-tax ($0.4 million after tax), $0.6 million pre-tax ($0.4 million after tax) and $1.4 million pre-tax ($0.9 million after tax) in 2008, 2007 and 2006, respectively, related to the performance units based on TSR. The fair value of the performance units based on TSR was estimated on the grant date using a lattice-based valuation model that factors in information, including the expected dividend yield, expected price volatility, risk-free interest rate and the probable outcome of the market condition, over the expected life of the performance units. Compensation expense for the performance units is a fixed amount determined at the grant date fair value and is recognized over the three-year award cycle regardless of whether performance units are awarded at the end of the award cycle. Dividends are not accrued or paid during the performance period and, therefore, are not included in the fair value calculation. Expected price volatility is based on the historical volatility of OGE Energy’s common stock for the past three years and was simulated using the Geometric Brownian Motion process. The risk-free interest rate for the performance unit grants is based on the three-year U.S. Treasury yield curve in effect at the time of the grant. The expected life of the units is based on the non-vested period since inception of the three-year award cycle. There are no post-vesting restrictions related to OGE Energy’s performance units based on TSR. The fair value of the performance units based on TSR was calculated based on the following assumptions at the grant date.

2008 2007 2006 Expected dividend yield 3.8% 3.6% 4.9% Expected price volatility 18.7% 15.9% 16.8% Risk-free interest rate 2.21% 4.47% 4.66% Expected life of units (in years) 2.84 2.95 2.85 Fair value of units granted $ 33.62 $ 24.18 $ 22.93 A summary of the activity for OGE Energy’s performance units applicable to the Company’s employees based on TSR at December 31, 2008 and changes during 2008 are summarized in the following table. Following the end of a three-year performance period, payout of the performance units based on TSR is determined by OGE Energy’s TSR for such period compared to a peer group and payout requires the approval of the Compensation Committee of OGE Energy’s Board of Directors. Payouts, if any, are all made in common stock and are considered made when the payout is approved by the Compensation Committee. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.10

### Stock Aggregate Number Conversion Intrinsic (dollars in millions) of Units Ratio (A) Value Units Outstanding at 12/31/07 72,638 1:1 Granted (B) 32,635 1:1 Converted (27,710) 1:1 $ 0.7 Forfeited (590) 1:1 Employee migration (C) 8,057 1:1 Units Outstanding at 12/31/08 85,030 1:1 $ 1.1 Units Fully Vested at 12/31/08 (D) 29,662 1:1 $ 0.9 (A) One performance unit = one share of OGE Energy’s common stock. (B) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target. (C) Due to certain employees transferring between OGE Energy and its subsidiaries. (D) These performance units, which were awarded in 2006 and became fully vested at December 31, 2008, were certified by the Compensation Committee of OGE Energy’s Board of Directors in February 2009. A summary of the activity for OGE Energy’s non-vested performance units applicable to the Company’s employees based on TSR at December 31, 2008 and changes during 2008 are summarized in the following table: Weighted-Average Number Grant Date of Units Fair Value Units Non-Vested at 12/31/07 44,928 $ 23.43 Granted (E) 32,635 $ 33.62 Vested (F) (29,662) $ 22.93 Forfeited (590) $ 33.62 Employee migration (G) 8,057 $ 27.44 Units Non-Vested at 12/31/08 (H) 55,368 $ 30.18 (E) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target. (F) These performance units, which were awarded in 2006 and became fully vested at December 31, 2008, were certified by the Compensation Committee of OGE Energy’s Board of Directors in February 2009. (G) Due to certain employees transferring between OGE Energy and its subsidiaries. (H) Of the 55,368 performance units not vested at December 31, 2008, 47,133 performance units are assumed to vest at the end of the applicable vesting period. At December 31, 2008, there was approximately $0.7 million in unrecognized compensation cost related to non-vested performance units based on TSR which is expected to be recognized over a weighted-average period of 1.84 years. Performance Units – Earnings Per Share The Company recorded compensation expense of approximately $0.3 million pre-tax ($0.2 million after tax), $0.3 million pre-tax ($0.2 million after tax) and $0.4 million pre-tax ($0.2 million after tax) in 2008, 2007 and 2006, respectively, related to the performance units based on EPS. The fair value of the performance units based on EPS is based on grant date fair value which is equivalent to the price of one share of OGE Energy’s common stock on the date of grant. The fair value of performance units based on EPS varies as the number of performance units that will vest is based on the grant date fair value of the units and the probable outcome of the performance condition. OGE Energy reassesses at each reporting date whether achievement of the performance condition is probable and accrues compensation expense if and when achievement of the performance condition is probable. As a result, the compensation expense recognized for these performance units can vary from period to period. There are no post-vesting restrictions related to OGE Energy’s performance units based on EPS. The grant date fair value of the 2006, 2007 and 2008 performance units was $28.00, $33.59 and $29.22, respectively. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.11

### A summary of the activity for OGE Energy’s performance units applicable to the Company’s employees based on EPS at December 31, 2008 and changes during 2008 are summarized in the following table. Following the end of a three-year performance period, payout of the performance units based on EPS growth is determined by OGE Energy’s growth in EPS for such period compared to a target set at the beginning of the three-year period by the Compensation Committee of OGE Energy’s Board of Directors and payout requires the approval of the Compensation Committee. Payouts, if any, are all made in common stock and are considered made when approved by the Compensation Committee.
Stock Aggregate Number Conversion Intrinsic (dollars in millions) of Units Ratio (A) Value Units Outstanding at 12/31/07 24,149 1:1 Granted (B) 10,873 1:1 Converted (9,231) 1:1 $ 0.4 Forfeited (196) 1:1 Employee migration (C) 2,686 1:1 Units Outstanding at 12/31/08 28,281 1:1 $ 0.5 Units Fully Vested at 12/31/08 (D) 9,885 1:1 $ 0.5 (A) One performance unit = one share of OGE Energy’s common stock. (B) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target. (C) Due to certain employees transferring between OGE Energy and its subsidiaries. (D) These performance units, which were awarded in 2006 and became fully vested December 31, 2008, were certified by the Compensation Committee of OGE Energy’s Board of Directors in February 2009. A summary of the activity for OGE Energy’s non-vested performance units applicable to the Company’s employees based on EPS at December 31, 2008 and changes during 2008 are summarized in the following table: Weighted-Average Number Grant Date of Units Fair Value Units Non-Vested at 12/31/07 14,918 $ 30.24 Granted (E) 10,873 $ 29.22 Vested (F) (9,885) $ 28.00 Forfeited (196) $ 29.22 Employee migration (G) 2,686 $ 29.90 Units Non-Vested at 12/31/08 (H) 18,396 $ 30.80 (E) Represents target number of units granted. Actual number of units earned, if any, is dependent upon performance and may range from 0 percent to 200 percent of the target. (F) These performance units, which were awarded in 2006 and became fully vested at December 31, 2008, were certified by the Compensation Committee of OGE Energy’s Board of Directors in February 2009. (G) Due to certain employees transferring between OGE Energy and its subsidiaries. (H) Of the 18,396 performance units not vested at December 31, 2008, 15,708 performance units are assumed to vest at the end of the applicable vesting period. At December 31, 2008, there was approximately $0.2 million in unrecognized compensation cost related to non-vested performance units based on EPS which is expected to be recognized over a weighted-average period of 2.0 years. Stock Options The Company recorded no compensation expense in 2008 or 2007 related to stock options because at December 31, 2006, there was no unrecognized compensation cost related to non-vested options, which became fully vested in January 2007. The Company recorded compensation expense of less than $0.1 million pre-tax and after tax in 2006 related to stock options. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.12

### A summary of the activity for OGE Energy’s options applicable to the Company’s employees at December 31, 2008 and changes during 2008 are summarized in the following table:

(dollars in millions) Number of Options Weighted-Average Exercise Price Aggregate Intrinsic

Value Weighted-Average Remaining Contractual Term Options Outstanding at 12/31/07 62,212 $ 22.64 Exercised (3,100) $ 24.66 $ --- Employee migration 18,300 $ 21.27 Expired

--- $ --- Options Outstanding at 12/31/08 77,412 $ 22.21 $ 0.3 4.97 years Options Fully Vested and Exercisable at 12/31/08 77,412 $ 22.21 $ 0.3 4.97 years

Restricted Stock Under the Plans and in the third quarter of 2008, OGE Energy issued restricted stock to certain existing non-officer employees as well as other executives upon hire to attract and retain individuals to be competitive in the marketplace. The restricted stock vests in one-third annual increments. Prior to vesting, each share of restricted stock is subject to forfeiture if the recipient ceases to render substantial services to OGE Energy or a subsidiary for any reason other than death, disability or retirement. These shares may not be sold, assigned, transferred or pledged and are subject to a risk of forfeiture. During 2008, OGE Energy awarded 56,798 shares of restricted stock, of which 21,618 shares of restricted stock related to the Company’s employees. The Company recorded compensation expense of approximately $0.1 million pre-tax ($0.1 million after tax) in 2008 related to the restricted stock. The fair value of the restricted stock was based on the closing market price of OGE Energy’s common stock on the grant date. Compensation expense for the restricted stock is a fixed amount determined at the grant date fair value and is recognized as services are rendered by employees over a three-year vesting period. Also, the Company treats its restricted stock as multiple separate awards by recording compensation expense separately for each tranche whereby a substantial portion of the expense is recognized in the earlier years in the requisite service period. Dividends are accrued and paid during the vesting period and, therefore, are included in the fair value calculation. The expected life of the restricted stock is based on the non-vested period since inception of the three-year award cycle. There are no post-vesting restrictions related to OGE Energy’s restricted stock. The weighted-average grant date fair value of the 2008 restricted stock was $30.88. At December 31, 2008, there was approximately $0.6 million in unrecognized compensation cost related to non-vested restricted stock which is expected to be recognized over a weighted-average period of 2.75 years. 5. Price Risk Management Assets and Liabilities The Company periodically utilizes derivative contracts to reduce exposure to adverse interest rate fluctuations. During 2007, the Company’s use of price risk management instruments involved the use of treasury lock agreements. The treasury lock agreements help protect against the variability of future interest payments of long-term debt that was issued by the Company.The Company has no derivatives at December 31, 2008. In accordance with SFAS No. 133, the Company recognizes its non-exchange traded derivative instruments as Derivative Instrument Assets – Hedges in the Comparative Balance Sheet at fair value with such amounts classified as current or long-term based on their anticipated settlement. For derivatives that are designated and qualify as a cash flow hedge, the effective portion of the change in fair value of the derivative instrument is reported as a component of Accumulated Other Comprehensive Income and recognized into earnings in the same period during which the hedged transaction affects earnings. The ineffective portion of a derivative’s change in fair value is recognized currently in earnings. Forecasted transactions designated as the hedged transaction 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 be recognized directly in earnings. If the forecasted transactions are no longer reasonably possible of occurring, any associated amounts recorded in Accumulated Other Comprehensive Income will also be recognized directly in earnings. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.13

### The Company measures the ineffectiveness of treasury lock cash flow hedges using the hypothetical derivative method prescribed by SFAS No. 133. Under the hypothetical derivative method, the Company designates that the critical terms of the hedging instrument are the same as the critical terms of the hypothetical derivative used to value the forecasted transaction, and, as a result, no ineffectiveness is expected. Management may designate certain derivative instruments for the purchase or sale of electric power and fuel procurement as normal purchases and normal sales contracts under the provisions of SFAS No. 133. Normal purchases and normal sales contracts are not recorded in Derivative Instrument Assets – Hedges in the Comparative Balance Sheet and earnings recognition is recorded in the period in which physical delivery of the commodity occurs. Management applies normal purchases and normal sales to electric power contracts by the Company and for fuel procurement by the Company. At December 31, 2007, the Company’s treasury lock agreements were not designated as cash flow hedges under SFAS No. 133. The 2007 treasury lock agreements were settled on January 29, 2008. 6. 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 for income taxes, net of income tax refunds.

Year ended December 31(In millions) 2008 2007 2006 NON-CASH INVESTING AND FINANCING ACTIVITIES Power plant long-term service agreement $ 3.5 $ 0.7 $ --- Capital lease for distribution equipment 0.3 --- --- SUPPLEMENTAL CASH FLOW INFORMATION Cash Paid During the Period for Interest (net of interest capitalized of $4.0, $4.0, $4.5) $ 67.1 $ 57.9 $ 50.5 Income taxes (net of income tax refunds) 29.3 30.2 61.0

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

Year ended December 31(In millions) 2008 2007 2006 Provision (Benefit) for Current Income Taxes Federal $ (30.2) $ 68.3 $ 81.6 State (3.6) 0.6 (7.7) Total Provision (Benefit) for Current Income Taxes (33.8) 68.9 73.9 Provision (Benefit) for Deferred Income Taxes, net Federal 92.1 6.9 15.3 State (0.3) 1.5 1.0 Total Provision for Deferred Income Taxes, net 91.8 8.4 16.3 Deferred Federal Investment Tax Credits, net (4.6) (4.8) (5.0) Income Taxes Relating to Other Income and Deductions (1.0) 0.7 (0.4) Total Income Tax Expense $ 52.4 $ 73.2 $ 84.8 The Company is a member of an affiliated group that files consolidated income tax returns in the U.S. Federal jurisdiction and various state jurisdictions. With few exceptions, the Company is no longer subject to U.S. Federal or state and local income tax examinations by tax authorities for years before 2005. In September 2008, the Internal Revenue Service (“IRS”) completed its audit of Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.14

### tax years 2005 and 2006. Income taxes are generally allocated to each company in the affiliated group based on its stand-alone taxable income or loss. Federal investment tax credits previously claimed on electric utility property have been deferred and are being amortized to income over the life of the related property. The Company continues to amortize its Federal investment tax credits on a ratable basis throughout the year. In addition, the Company earns both Federal and Oklahoma state tax credits associated with the production from its 120 MW wind farm in northwestern Oklahoma (“Centennial”) wind farm that further reduce the Company’s effective tax rate. The following schedule reconciles the statutory Federal tax rate to the effective income tax rate:

Year ended December 31 2008 2007 2006 Statutory Federal tax rate 35.0% 35.0% 35.0% Amortization of net unfunded deferred taxes 1.3 1.3 1.1 Medicare Part D subsidy (0.4) (0.3) (0.9) State income taxes, net of Federal income tax benefit (2.1) 1.2 2.5 Federal investment tax credits, net (2.4) (2.0) (2.1) Federal renewable energy credit (A) (4.6) (3.0) --- 401(k) dividends --- --- 1.3 Other --- (1.0) (0.7) Effective income tax rate as reported 26.8% 31.2% 36.2% (A) These are credits the Company began earning associated with the production from the Centennial wind farm that was placed in service during January 2007. The Company adopted the provisions of FIN No. 48, “Accounting for Uncertainty in Income Taxes – an interpretation of FASB Statement No. 109,” on January 1, 2007. As a result of the implementation of FIN No. 48, the Company recognized an approximate $6.2 million increase in the accrued interest liability. The after-tax effect, of approximately $3.8 million, was accounted for as a reduction to the January 1, 2007 balance of retained earnings. The balance of uncertain tax positions at January 1, 2007 consisted of approximately $171.6 million of tax positions associated with the capitalization of costs for self-constructed assets discussed above. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. The Company reached a final settlement with the IRS on November 27, 2007 related to the tax method of accounting for the capitalization of costs for self-constructed assets. A reconciliation of the beginning and ending amounts of unrecognized tax benefits is as follows:

December 31(In millions) 2008 2007 Beginning Balance..................................................................... $ --- $ 66.4 Settlements with tax authorities................................................................ --- (66.4) Ending Balance................................................................ $ --- $ --- The Company recognizes accrued interest related to tax benefits in interest expense and recognizes penalties in other income deductions. The Company recorded interest expense associated with the IRS audit of approximately $0.3 million in 2006 and $2.6 million in 2007. On November 27, 2007, the Company reached a final settlement with the IRS related to the tax method of accounting, which resulted in a reversal of approximately $9.5 million of previously accrued interest expense related to this previously uncertain tax position. At December 31, 2007, the Company had approximately $2.9 million of accrued interest related to the capitalization of costs for self-constructed assets discussed above. 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 liabilities are computed based on the difference between the financial statement and income tax bases of assets and liabilities using the enacted marginal tax rate. Deferred income 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 recognized 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 31, 2008 and 2007, respectively, were as follows: Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.15

### December 31(In millions) 2008 2007 Current Accumulated Deferred Tax Assets Federal renewable energy credit $ 9.1 $ --- Accrued vacation 4.3 3.9 Uncollectible accounts 1.1 1.4 Accrued liabilities --- 1.2 Derivative instruments --- 0.4 Other --- 4.5 Total Current Accumulated Deferred Tax Assets 14.5 11.4 Current Accumulated Deferred Tax Liabilities Accrued liabilities (0.1) --- Other (1.7) --- Total Current Accumulated Deferred Tax Liabilities (1.8) --- Current Accumulated Deferred Tax Assets, net $ 12.7 $ 11.4

Non-Current Accumulated Deferred Tax Liabilities Accelerated depreciation and other property related differences $ 734.2 $ 633.4 Company pension plan 77.6 62.6 Income taxes refundable to customers, net 5.7 6.7 Bond redemption-unamortized costs 5.7 6.1 Regulatory asset 3.2 7.7 Total Non-Current Accumulated Deferred Tax Liabilities 826.4 716.5

Non-Current Accumulated Deferred Tax Assets Regulatory liabilities (58.5) (54.7) Postretirement medical and life insurance benefits (23.5) (20.3) State tax credit carryforward (11.8)

--- Deferred Federal investment tax credits (6.7) (8.5) Other (3.1) --- Total Non-Current Accumulated Deferred Tax Assets (103.6) (83.5) Non-Current Accumulated Deferred Income Tax Liabilities, net $ 722.8 $ 633.0 The Company currently estimates a Federal tax operating loss for 2008 of approximately $53.2 million primarily caused by the accelerated tax depreciation provisions contained within theEconomic Stimulus Act of 2008 (“Stimulus Act”). The Stimulus Act allows a current deduction for 50 percent of the cost of certain property placed into service during 2008. This loss results in an approximately $18.6 current income tax receivable related to the 2008 tax year. It is the Company’s intent to carry this tax loss back to a prior period in order to obtain cash refunds. As noted above, the impact of deferred tax accounting will not cause this refund to impact the effective tax rate. The Company has an Oklahoma investment tax credit carryover from 2007 of approximately $7.1 million. During 2008, additional Oklahoma tax credits of approximately $16.1 million were generated or purchased by the Company. The Company currently believes that approximately $5.1 million of these state tax credit amounts will be utilized in the 2008 tax year and approximately $18.1 million will be carried over to the 2009 tax year and later years. The Company’s credits do not have an expiration date.

8. Common Stock and Cumulative Preferred Stock There were no new shares of common stock issued during 2008, 2007 or 2006. The Company’s Restated Certificate of Incorporation permits the issuance of a new series of preferred stock with dividends payable other than quarterly. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.16

### 9. Long-Term Debt At December 31, 2008, the Company was in compliance with all of its debt agreements. Optional Redemption of Long-Term Debt The Company has three series of variable-rate industrial 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 can be tendered at the option of the holder during the next 12 months, are as follows (dollars in millions):

SERIES DATE DUE AMOUNT 1.40% - 8.35%(A) Garfield Industrial Authority, January 1, 2025 $ 47.0 1.24% - 8.14%(A) Muskogee Industrial Authority, January 1, 2025 32.4 1.35% - 7.75%(A) Muskogee Industrial Authority, June 1, 2027 55.9 Total (redeemable during next 12 months) $ 135.3 (A) During the first six months of 2008, the interest rates for the Bonds were between 1.24% and 3.45%. In September 2008, the interest rates for the Bonds significantly increased to a one-week high of 8.35%. Currently, the interest rates for the Bonds are between 0.55% and 0.95%. All of these Bonds are subject to an optional tender at the request 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 irrevocable notice to the tender agent stating the principal amount of the Bond, payment instructions for the purchase price 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. When a tender notice has been received by the trustee, a third party remarketing agent for the Bonds will attempt to remarket any Bonds tendered for purchase. This process occurs once per week. Since the original issuance of these series of Bonds in 1995 and 1997, the remarketing agent has successfully remarketed all tendered bonds except as discussed below. If the remarketing agent is unable to remarket any such Bonds, the Company is obligated to repurchase such unremarketed Bonds. The Company believes that it has sufficient long-term liquidity to meet these obligations. In September 2008, the Company received a request for repayment of approximately $0.1 million of principal related to a portion of the Company’s Muskogee Industrial Authority variable-rate bonds, due June 1, 2027. In September 2008, approximately $0.1 million of principal and accrued interest were paid to the bondholder. The $0.1 million of variable-rate industrial authority bonds is being remarketed by the remarketing agent. Long-Term Debt Maturities There are no maturities of the Company’s long-term debt during the next five years. The Company has previously incurred costs related to debt refinancings. Unamortized debt expense and unamortized loss on reacquired debt are classified as Deferred Debits and unamortized premium and discount on long-term debt is classified as Long-Term Debt, respectively, in the Comparative Balance Sheet and are being amortized over the life of the respective debt. Issuance of Long-Term Debt In January 2008, the Company issued $200 million of 6.45% senior notes due February 1, 2038. The proceeds from the issuance were used to repay commercial paper borrowings. The Company entered into two separate treasury lock arrangements, effective November 16, 2007 and November 19, 2007, to hedge interest payments on the first $50.0 million and $25.0 million, respectively, of the long-term debt that was issued in January 2008. These treasury lock agreements were settled on January 29, 2008. In September 2008, the Company issued $250 million of 6.35% senior notes due September 1, 2018. The proceeds from the issuance were used to fund a portion of the acquisition of the Redbud Facility. Pending such use, the proceeds were used to temporarily repay a portion of the Company’s outstanding commercial paper borrowings, as well as short-term borrowings from OGE Energy, both of which were incurred in part to fund the Company’s daily operational needs. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.17

### In December 2008, the Company issued $250 million of 8.25% senior notes due January 15, 2019. The proceeds from the issuance were used to repay borrowings under the Company’s term loan agreement with UBS AS, Stamford Branch and UBS Securities LLC, as discussed in Note 10, and OGE Energy’s and the Company’s revolving credit agreements, which were used to fund the Company’s daily operational needs as well as the Company’s acquisition of the Redbud Facility.

10. Short-Term Debt There was no short-term debt outstanding at December 31, 2008. The short-term debt balance was approximately $0.8 million at December 31, 2007. At December 31, 2008 and 2007, the Company had approximately $15.8 million and $278.7 million, respectively, in outstanding advances from OGE Energy. The following table shows OGE Energy’s and the Company’s revolving credit agreements and available cash at December 31, 2008. Revolving Credit Agreements and Available Cash(In millions)

Aggregate Commitment (A) Amount Weighted-Average Entity Outstanding (B) Interest Rate Maturity OGE Energy (C) $ 596.0 $ 298.0 0.75% (F) December 6, 2012 (E) The Company (D) 389.0 --- ---% (F) December 6, 2012 (E) 985.0 298.0 0.75% Cash 50.7 N/A N/A N/A Total $ 1,035.7 $ 298.0 0.75% (A)All of the lenders that participate in OGE Energy’s and the Company’s revolving credit agreements have funded their commitment, with the exception of Lehman Brothers Holdings, Inc. (“Lehman”), which filed for bankruptcy protection on September 15, 2008 and has not funded their portion of the revolving credit agreements. At December 31, 2008, approximately $4 million and $11 million, respectively, of OGE Energy’s and the Company’s revolving credit agreements are not available as this portion was assigned to Lehman. (B) Includes direct borrowings, outstanding commercial paper and letters of credit at December 31, 2008. (C) This bank facility is available to back up OGE Energy’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2008, there was approximately $298.0 million in outstanding borrowings under this revolving credit agreement. There were no outstanding commercial paper borrowings at December 31, 2008. (D) This bank facility is available to back up the Company’s commercial paper borrowings and to provide revolving credit borrowings. This bank facility can also be used as a letter of credit facility. At December 31, 2008, there were no outstanding borrowings under this revolving credit agreement and approximately $0.3 million supporting letters of credit. There were no outstanding commercial paper borrowings at December 31, 2008. (E) In December 2006, OGE Energy and the Company amended and restated their revolving credit agreements to total in the aggregate $1.0 billion, $600 million for OGE Energy and $400 million for the Company. Each of the credit facilities has a five-year term with an option to extend the term for two additional one-year periods upon agreement of all banks participating in the revolving credit agreements. In November 2007, OGE Energy and the Company utilized one of these one-year extensions to extend the maturity of their credit agreements to December 6, 2012. Also, each of these credit facilities has an additional option at maturity to convert the outstanding balance to a one-year term loan. (F) Represents the weighted-average interest rate for the outstanding borrowings under the revolving credit agreements. OGE Energy’s and the Company’s ability to access the commercial paper market has been adversely impacted by the market turmoil since September 2008. Accordingly, in order to ensure the availability of funds, OGE Energy and the Company utilized borrowings under their revolving credit agreements, which generally bear a higher interest rate and a minimum 30-day maturity compared to commercial paper, which has historically been available at lower interest rates and on a daily basis. However, in late 2008, OGE Energy’s and the Company’s revolving credit borrowings had a lower interest rate than commercial paper due to disruptions in the credit markets. In December 2008, the Company repaid the outstanding borrowings under its revolving credit agreement with a portion of the proceeds received from the issuance of long-term debt in December. The Company intends to utilize Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.18

### commercial paper in the commercial paper market when available. OGE Energy expects to repay the borrowings under its revolving credit agreements and begin utilizing the commercial paper market when available. The Company also borrowed under the term loan agreements discussed below. In addition to general market conditions, OGE Energy’s and the Company’s ability to access the commercial paper market could also be adversely impacted by a credit ratings downgrade. Pricing grids associated with the back-up lines of credit could cause annual fees and borrowing rates to increase if an adverse ratings impact occurs. The impact of any future downgrades of the ratings of OGE Energy or the Company 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. Any future downgrade of the Company would also lead to higher long-term borrowing costs and, if below investment grade, would require the Company to post cash collateral or letters of credit.

The Company had a commercial paper arrangement withLehman, which filed for bankruptcy protection on September 15, 2008. On September 22,2008, Barclays Plc purchased the investment banking and capital markets operations of Lehman and replaced Lehman as the commercial paper dealer in the Company’scommercial paper arrangement. Also, the Company has a commercial paper arrangement withWachovia Bank, National Association, which merged with Wells Fargo & Company on December 31, 2008. On September 26, 2008, the Company entered into a 10-day $300 million term loan agreement with Royal Bank of Scotland PLC (“RBS”). On September 29, 2008, after the Company purchased the entire partnership interest in the Redbud Facility, the Oklahoma Municipal Power Authority (“OMPA”) and the Grand River Dam Authority (“GRDA”) purchased their respective undivided interests in the Redbud Facility from the Company for approximately $417.5 million. After the closing of the sale of the undivided interests in the Redbud Facility, the Company used the $417.5 million in proceeds and repaid in full, on September 30, 2008, the $300 million borrowed from RBS and invested the remainder of the proceeds in short-term investments which were recorded as Temporary Cash Investments on the Company’s Comparative Balance Sheet. On September 26, 2008, the Company entered into a $200 million term loan agreement with UBS AS, Stamford Branch and UBS Securities LLC maturing March 26, 2010. This loan could be used for general corporate purposes and permitted acquisitions as defined in the loan agreement. On December 15, 2008, the Company repaid the outstanding $50.0 million balance and terminated this loan agreement. Unlike OGE Energy, the Company must obtain regulatory approval from the FERC in order to borrow on a short-term basis. The Company has the necessary regulatory approvals to incur up to $800 million in short-term borrowings at any one time for a two-year period beginning January 1, 2009 and ending December 31, 2010.

11. Retirement Plans and Postretirement Benefit Plans In September 2006, the FASB issued SFAS No. 158 which required an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multiemployer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income of a business entity. The requirement to initially recognize the funded status of the defined benefit postretirement plan and the disclosure requirements were effective for the year ended December 31, 2006 for the Company. Also, as a part of SFAS No. 158, an employer is required to measure the fair value of the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. The requirement to measure plan assets and benefit obligations at fair value in accordance with SFAS No. 157 as of the date of the employer’s fiscal year-end statement of financial position was effective for fiscal years ending after December 15, 2008. The Company adopted this additional provision of SFAS No. 158 effective December 31, 2008 which had no impact to the Company as its measurement date and its fiscal year-end statement of financial position were the same. Defined Benefit Pension Plan All eligible employees of the Company are covered by a non-contributory defined benefit pension plan sponsored by OGE Energy. For employees hired on or after February 1, 2000, the pension plan is a cash balance plan, under which OGE Energy annually will credit to the employee’s account an amount 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 a benefit based primarily on years of Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.19

### service and the average of the five highest consecutive years of compensation during an employee’s last ten years prior to retirement, with reductions in benefits for each year prior to age 62 unless the employee’s age and years of credited service equal or exceed 80. It is OGE Energy’s policy to fund the plan on a current basis based on the net periodic SFAS No. 87, “Employers’ Accounting for Pensions,” pension expense as determined by the Company’s actuarial consultants. Additional amounts may be contributed from time to time to increase the funded status of the plan. During both 2008 and 2007, OGE Energy made contributions to its pension plan of approximately $50.0 million of which approximately $47.0 million and $38.3 million, respectively, were the Company’s portion, to help ensure that the pension plan maintains an adequate funded status. Such contributions are intended to provide not only for benefits attributed to service to date, but also for those expected to be earned in the future. In August 2006, legislation was passed that changed the funding requirement for single- and multi-employer defined benefit pension plans as discussed below. During 2009, OGE Energy may contribute up to $50.0 million to its pension plan, of which approximately $47.0 million is expected to be the Company’s portion. The expected contribution to the pension plan during 2009 would be a discretionary contribution, anticipated to be in the form of cash, and is not required to satisfy the minimum regulatory funding requirement specified by the Employee Retirement Income Security Act of 1974, as amended. At December 31, 2008, the projected benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s pension plan and restoration of retirement income plan was approximately $433.7 million and $309.2 million, respectively, for an underfunded status of approximately $124.5 million. These amounts have been recorded in Accumulated Provision for Pensions and Benefits with the offset recorded as a regulatory asset in the Company’s Comparative Balance Sheet as discussed in Note 1. The amount recorded as a regulatory asset represents a net periodic benefit cost to be recognized in the Statement of Income in future periods.At December 31, 2007, the projected benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s pension plan and restoration of retirement income plan was approximately $414.4 million and $400.7 million, respectively, for an underfunded status of approximately $13.7 million. These amounts have been recorded in Accumulated Provision for Pensions and Benefits with the offset recorded as a regulatory asset in the Company’s Comparative Balance Sheet as discussed in Note 1. The amount recorded as a regulatory asset represents a net periodic benefit cost to be recognized in the Statement of Income in future periods.In accordance with SFAS No. 88, “Employer’s Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,” a one-time settlement charge is required to be recorded by an organization when lump-sum payments or other settlements that relieve the organization from the responsibility for the pension benefit obligation or the retirement restoration benefit obligation during a plan year exceed the service cost and interest cost components of the organization’s net periodic pension cost or retirement restoration cost. During 2007, OGE Energy and the Company experienced an increase in both the number of employees electing to retire and the amount of lump sum payments to be paid to such employees upon retirement as well as the death of the Company’s Chairman and Chief Executive Officer in September 2007. As a result, OGE Energy recorded a pension settlement charge and a retirement restoration plan settlement charge in 2007. The Company did not record a pension settlement charge during 2008. The pension settlement charge and retirement restoration plan settlement charge did not require a cash outlay by the Company and did not increase the Company’s total pension expense or restoration retirement expense over time, as the charges were an acceleration of costs that otherwise would have been recognized as pension expense or retirement restoration expense in future periods.

(In millions) OGE Energy Company’s Portion (A) Pension Settlement Charge:

2007 $ 16.7 $ 13.3 Retirement Restoration Plan Settlement Charge:

2007 $ 2.3 $ 0.1 (A) The Company’s Oklahoma jurisdictional portion of thesecharges were recorded as a regulatory asset (see Note 1 for a further discussion). Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.20

### Pension Plan Costs and Assumptions On August 17, 2006, President Bush signed The Pension Protection Act of 2006 (the “Pension Protection Act”) into law. The Pension Protection Act makes changes to important aspects of qualified retirement plans. Among other things, it alters the manner in which pension plan assets and liabilities are valued for purposes of calculating required pension contributions, introduces a new funding requirement for single- and multi-employer defined benefit pension plans, provides legal certainty on a prospective basis for cash balance and other hybrid plans and addresses contributions to defined contribution plans, deduction limits for contributions to retirement plans and investment advice provided to plan participants. 

## Many of the changes enacted as part of the Pension Protection Act were required to be implemented as of the first plan year beginning in 2008. While OGE Energy generally has until the last day of the first plan year beginning in 2009 to reflect those changes as part of the plan document, plans must nevertheless comply in operation as of each provision’s effective date. In order to be in compliance with the Pension Protection Act, the Company has implemented the following changes to its defined benefit pension plan and defined contribution plan, as applicable: (i)effective January 1, 2008, the Company’sdefined benefit pension plan and defined contribution planswere amended to incorporate clarifying provisions and changes relating to the Pension Protection Act notice requirements and allow a non-spouse beneficiary to directly rollover an eligible distribution to an eligible individual retirement account (“IRA”) or to a Roth IRA; (ii) effective January 1, 2008, the Company’sdefined benefit pension plan and defined contribution planswere amended to provide 100 percent vesting after completing three years of service; (iii) for the Company’s defined benefit pension plan, effective January 1, 2008, that plan was amended to incorporate the new Pension Protection Act applicable mortality table and applicable interest rate under Internal Revenue Code Section 417(e)(3) for determining the actuarial equivalent value of a benefit that is converted to a lump sum; (iv) for the Company’s defined contribution plan, effective January 1, 2008, that plan was amended to provide, in accordance with the Pension Protection Act that participants under age 55 may diversify amounts held in his/her TRASOP account out of the OGE Energy Corp Common Stock Fund into other investment funds; and (v) for the Company’s defined contribution plan, that plan was amended to implement an eligible automatic contribution arrangement and provide for a qualified default investment alternative consistent with the Department of Labor regulations.The Company has taken steps to ensure that its plans, as well as participants and outside administrators, are aware of the changes. Plan Investments, Policies and Strategies The pension plan’s assets consist primarily of investments in mutual funds, U.S. Government securities, listed common stocks and corporate debt. The following table shows, by major category, the percentage of the fair value of the plan assets held at December 31, 2008 and 2007:
December 31 2008 2007 Equity securities 45 % 61 % Debt securities 53 % 37 % Other 2 % 2 % Total 100 % 100 % The pension plan assets are held in a trust which follows an investment policy and strategy designed to maximize the long-term investment returns of the trust at prudent risk levels. Common stocks are used as a hedge against moderate inflationary conditions, as well as for participation in normal economic times. Fixed income investments are utilized for high current income and as a hedge against deflation. OGE Energy has retained an investment consultant responsible for the general investment oversight, analysis, monitoring investment guideline compliance and providing quarterly reports to certain of OGE Energy’s members and OGE Energy’s Employee Benefit Funds Management Committee (the “Investment Committee”). The various investment managers used by the 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: Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

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### FERC FORM NO. 1 (ED. 12-88) Page 123.21

### Asset Class Target Allocation Minimum 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 an annual 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 markets which may cause the trust’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 will be met over a full market 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 trust is to provide a rate of return consistently from three to five percent over the rate of inflation (as measured by the national Consumer Price Index) on a fee adjusted basis 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 asset class utilized with appropriate comparative benchmark(s) each manager is evaluated against:

Asset Class Comparative Benchmark(s) Fixed Income Lehman Aggregate Index Equity Index S&P 500 Index Value Equity Russell 1000 Value Index – Short-term S&P 500 Index – Long-term Growth Equity Russell 1000 Growth Index – Short-term S&P 500 Index – Long-term Mid-Cap Equity S&P 400 Midcap Index Small-Cap Equity Russell 2000 Index International Equity Morgan Stanley Capital International Europe, Australia and Far East Index The fixed income manager is expected to use discretion over the asset mix of the 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. At least 75 percent of the invested assets must possess an investment grade rating at or above Baa3 or BBB- by Moody’s Investors Service (“Moody’s”), Standard & Poor’s or Fitch Ratings. The portfolio may invest up to ten percent of the portfolio’s market value in convertible bonds as long as the securities purchased meet the quality guidelines. The purchase of any of OGE Energy’s equity, debt or other securities is prohibited. The domestic value equity managers focus on stocks that 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 payments. The domestic growth equity manager will invest primarily in 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 domestic mid-cap equity portfolio manager focuses 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 S&P 400 Midcap Index, small dividend yield, return on equity at or near the S&P 400 Midcap Index and earnings per share growth rate at or near the S&P 400 Midcap Index. The domestic small-capitalization equity manager will purchase shares of 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 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 international global equity manager invests primarily in non-dollar denominated equity securities. Investing internationally diversifies the overall trust across 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”) is the benchmark for comparative performance purposes. The EAFE Index is a market value weighted index comprised of over 1,000 companies traded on the stock markets of Europe, Australia, New Zealand and the Far East. All of the equities which are purchased for the international Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

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### FERC FORM NO. 1 (ED. 12-88) Page 123.22

### portfolio are thoroughly researched. Only companies with a market capitalization in excess of $100 million are allowable. No more than five percent of the portfolio can be invested in any one stock at the time of purchase. All securities are freely traded on a recognized stock exchange and there are no 144-A securities and no over-the-counter derivatives. The following investment categories are excluded: options (other than traded currency options), commodities, futures (other than currency futures or currency hedging), short sales/margin purchases, private placements, unlisted securities and real estate (but not real estate shares). For all domestic equity investment managers, no more than eight percent (five percent for mid-cap and small-cap equity managers) can be invested in any one stock at the time of purchase and no more than 16 percent (ten percent for mid-cap and small-cap equity managers) after accounting for price appreciation. A minimum of 95 percent of the total assets of an equity manager’s portfolio must be allocated to the equity markets. Options or financial futures may not be purchased unless prior approval of the Investment Committee is received. The purchase of securities on margin is prohibited as is securities lending. Private placement or venture capital may not be purchased. All interest and dividend payments must be swept on a daily basis into a short-term money market fund for re-deployment. The purchase of any of OGE Energy’s equity, debt or other securities is prohibited. The purchase of equity or debt issues of the portfolio manager’s organization is also prohibited. The aggregate positions in any company may not exceed one percent of the fair market value of its outstanding stock. Restoration of Retirement Income Plan OGE Energy provides a restoration of retirement income plan to those participants in OGE Energy’s pension plan whose benefits are subject to certain limitations under the Internal Revenue Code (the “Code”). The benefits payable under this restoration of retirement income plan are equivalent to the amounts that would have been payable under the pension plan but for these limitations. The restoration of retirement income plan is intended to be an unfunded plan. The Company expects to pay benefits related to its pension plan and restoration of retirement income plan of approximately $48.5 million in 2009, $48.7 million in 2010, $49.6 million in 2011, $51.9 million in 2012, $51.3 million in 2013 and an aggregate of $215.0 million in years 2014 to 2018. These expected benefits are based on the same assumptions used to measure the Company’s benefit obligation at the end of the year and include benefits attributable to estimated future employee service. Postretirement Benefit Plans In addition to providing pension benefits, OGE Energy provides certain medical and life insurance benefits for eligible retired members (“postretirement benefits”). Regular, full-time, active employees hired prior to February 1, 2000 whose age and years of credited service total or exceed 80 or have attained age 55 with ten years of vesting service at the time of retirement are entitled to postretirement medical benefits while employees hired on or after February 1, 2000 are not entitled to postretirement medical benefits. Prior to January 1, 2008, all regular, full-time, active employees whose age and years of credited service total or exceed 80 or have attained age 55 with five years of vesting service at the time of retirement are entitled to postretirement life insurance benefits. Effective January 1, 2008, all regular, full-time, active employees whose age and years of credited service total or exceed 80 or have attained age 55 with three years of vesting service at the time of retirement are entitled to postretirement life insurance benefits. Eligible retirees must contribute such amount as OGE Energy 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 includes an annual amount as a component of the cost-of-service in future ratemaking proceedings. At December 31, 2008, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s postretirement benefit plans was approximately $191.9 million and $55.1 million, respectively, for an underfunded status of approximately $136.8 million. These amounts have been recorded in Accumulated Provision for Pensions and Benefits with the offset recorded as a regulatory asset in the Company’s Comparative Balance Sheet as discussed in Note 1. The amount recorded as a regulatory asset represents a net periodic benefit cost to be recognized in the Statement of Income in future periods. At December 31, 2007, the accumulated postretirement benefit obligation and fair value of assets of the Company’s portion of OGE Energy’s postretirement benefit plans was approximately $179.2 million and $76.0 million, respectively, for an underfunded status of approximately $103.2 million. These amounts have been recorded in Accumulated Provision for Pensions and Benefits with Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

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### FERC FORM NO. 1 (ED. 12-88) Page 123.23

### the offset recorded as a regulatory asset in the Company’s Comparative Balance Sheet as discussed in Note 1. The amount recorded as a regulatory asset represents a net periodic benefit cost to be recognized in the Statement of Income in future periods. The assumed health care cost trend rates have a significant effect on the amounts reported for postretirement medical benefit plans. Future health care cost trend rates are assumed to be 9.0 percent in 2009 with the rates decreasing in subsequent years by one percentage point per year through 2012. A one-percentage point change in the assumed health care cost trend rate would have the following effects:
ONE-PERCENTAGE POINT INCREASE

Year ended December 31(In millions) 2008 2007 2006 Effect on aggregate of the service and interest cost components $ 1.7 $ 1.8 $ 1.7 Effect on accumulated postretirement benefit obligations 22.3 21.4 23.4

ONE-PERCENTAGE POINT DECREASE Year ended December 31(In millions) 2008 2007 2006 Effect on aggregate of the service and interest cost components $ 1.4 $ 1.5 $ 1.4 Effect on accumulated postretirement benefit obligations 18.6 17.8 19.3 Medicare Prescription Drug, Improvement and Modernization Act 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. Management expects that the accumulated plan benefit obligation (“APBO”) for OGE Energy with respect to its postretirement medical plan will be reduced by approximately $70.9 million as a result of savings to OGE Energy with respect to its postretirement medical plan resulting from the Medicare Act provided subsidy, which will reduce OGE Energy’s costs for its postretirement medical plan by approximately $5.6 million annually. The $5.6 million in annual savings is comprised of a reduction of approximately $2.4 million from amortization of the $70.9 million gain due to the reduction of the APBO, a reduction in the interest cost on the APBO of approximately $2.6 million and a reduction in the service cost due to the subsidy of approximately $0.6 million. The Company expects to pay gross benefits payments related to its postretirement benefit plans, including prescription drug benefits, of approximately $11.6 million in 2009, $12.5 million in 2010, $13.5 million in 2011, $14.2 million in 2012, $14.9 million in 2013 and an aggregate of $81.4 million in years 2014 to 2018. The Company expects to receive Federal subsidy receipts provided by the Medicare Act of approximately $1.5 million in 2009, $1.6 million in 2010, $1.8 million in 2011, $1.9 million in 2012, $2.1 million in 2013 and an aggregate of $12.2 million in years 2014 to 2018. OGE Energy received approximately $0.8 million in Federal subsidy receipts in 2008. Obligations and Funded Status The following table presents the status of the Company’s portion of OGE Energy’s pension plan, the restoration of retirement income plan and the postretirement benefit plans for 2008 and 2007. The Company’s portion of the benefit obligation for OGE Energy’s pension plan and the restoration of retirement income plan represents the projected benefit obligation, while the benefit obligation for the postretirement benefit plans represents the accumulated benefit obligation. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels. The accumulated benefit obligation for the pension plan and the restoration of retirement income plan at December 31, 2008 was approximately $391.7 million and $0.8 million, respectively. The accumulated benefit obligation for the pension plan and the restoration of retirement income plan at December 31, 2007 was approximately $373.8 million and $0.8 million, respectively.The details of the funded status of the pension plan, the restoration of retirement income plan and the postretirement benefit plans and the amounts included in the Comparative Balance Sheet are as follows: Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

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### FERC FORM NO. 1 (ED. 12-88) Page 123.24

### Restoration of Retirement Postretirement Pension Plan Income Plan Benefit Plans December 31(In millions) 2008 2007 2008 2007 2008 2007 Change in Benefit Obligation Beginning obligations $ (413.6) $ (465.2) $ (0.8) $ (0.4) $ (179.2) $ (188.0) Service cost (12.4) (13.8) --- --- (2.3) (2.7) Interest cost (24.9) (25.6) (0.1) --- (11.1) (10.4) Plan changes --- 12.6 --- (0.1) --- --- Participants’ contributions --- --- --- --- (4.9) (4.5) Actuarial gains (losses) (15.3) 13.2 (0.5) (0.5) (6.4) 12.7 Benefits paid 33.6 65.2 0.3 0.2 12.0 13.7 Ending obligations (432.6) (413.6) (1.1) (0.8) (191.9) (179.2) Change in Plans’ Assets Beginning fair value 400.7 410.1 --- --- 76.0 71.7 Actual return on plans’ assets (104.9) 17.5 --- --- (18.7) 5.4 Employer contributions 47.0 38.3 0.3 0.2 4.9 8.1 Participants’ contributions --- --- --- --- 4.9 4.5 Benefits paid (33.6) (65.2) (0.3) (0.2) (12.0) (13.7) Ending fair value 309.2 400.7 --- --- 55.1 76.0 Funded status at end of year $ (123.4) $ (12.9) $ (1.1) $ (0.8) $ (136.8) $ (103.2)

Net Periodic Benefit Cost

Restoration of Retirement Postretirement Pension Plan Income Plan Benefit Plans Year ended December 31 (In millions) 2008 2007 2006 2008 2007 2006 2008 2007 2006 Service cost $ 12.4 $ 13.8 $ 13.4 $ --- $ --- $ --- $ 2.3 $ 2.7 $ 2.6 Interest cost 24.9 25.6 24.7 0.1 --- --- 11.1 10.4 10.0 Return on plan assets (34.3) (34.5) (30.4) --- --- --- (6.3) (5.7) (5.5) Amortization of transition obligation --- --- --- --- --- --- 2.5 2.5 2.5 Amortization of net loss 7.4 8.4 13.4 0.1 --- --- 3.5 5.5 7.6 Amortization of recognized prior service cost 1.1 4.5 4.6 0.1 0.1 0.1 1.5 1.5 1.5 Settlement --- 13.3 13.3 --- 0.1 --- --- --- --- Net periodic benefit cost (A) $ 11.5 $ 31.1 $ 39.0 $ 0.3 $ 0.2 $ 0.1 $ 14.6 $ 16.9 $ 18.7 (A) In addition to the $11.8 million and $31.3 million in SFAS No. 87 net periodic benefit cost recognized in 2008 and 2007, respectively, the Company also recognized an expense of approximately $7.5 million and a gain of approximately $8.3 million, respectively, related to the reversal of a portion of the regulatory asset identified as Deferred Pension Expense (see Note 1). The capitalized portion of the net periodic pension benefit cost was approximately $3.6 million, $5.2 million and $7.2 million at December 31, 2008, 2007 and 2006, respectively. The capitalized portion of the net periodic postretirement benefit cost was approximately $4.2 million, $4.5 million and $5.6 million at December 31, 2008, 2007 and 2006, respectively. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

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### FERC FORM NO. 1 (ED. 12-88) Page 123.25

### Rate Assumptions

Pension Plan and Postretirement Restoration of Retirement Income Plan Benefit Plans Year ended December 31 2008 2007 2006 2008 2007 2006 Discount rate 6.25% 6.25% 5.75% 6.25% 6.25% 5.75% Rate of return on plans’ assets 8.50% 8.50% 8.50% 8.50% 8.50% 8.50% Compensation increases 4.50% 4.50% 4.50% 4.50% 4.50% 4.50% Assumed health care cost trend: Initial trend N/A N/A N/A 9.00% 9.00% 9.00% Ultimate trend rate N/A N/A N/A 4.50% 4.50% 4.50% Ultimate trend year N/A N/A N/A 2014 2013 2012 N/A - not applicable The overall expected rate of return on plan assets assumption remained at 8.50 percent in 2007 and 2008 in determining net periodic benefit cost. The rate of return on plan assets assumption is the average long-term rate of earnings expected on the funds currently invested and to 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 rate of return on plan assets assumption reflects a combination of historical return analysis, forward-looking return expectations and the plans’ current and expected asset allocation. Post-Employment Benefit Plan Disabled employees receiving benefits from OGE Energy’s Group Long-Term Disability Plan are entitled to continue participating in the Company’s Medical Plan along with their dependents. The post-employment benefit obligation represents the actuarial present value of estimated future medical benefits that are attributed to employee service rendered prior to the date as of which such information is presented. The obligation also includes future medical benefits expected to be paid to current employees participating in OGE Energy’s Group Long-Term Disability Plan and their dependents, as defined in OGE Energy’s Medical Plan. The post-employment benefit obligation is determined by an actuary on a basis similar to the accumulated postretirement benefit obligation. The estimated future medical benefits are projected to grow with expected future medical cost trend rates and are discounted for interest at the discount rate and for the probability that the participant will discontinue receiving benefits from OGE Energy’s Group Long-Term Disability Plan due to death, recovery from disability, or eligibility for retiree medical benefits. The Company’s post-employment benefit obligation was approximately $1.6 million and $1.3 million at December 31, 2008 and 2007, respectively. Defined Contribution Plan OGE Energy provides a defined contribution savings plan. Each regular full-time employee of OGE Energy or a participating affiliate is eligible to participate in the plan immediately. All other employees of OGE Energy or a participating affiliate are eligible to become participants in the plan after completing one year of service as defined in the plan. Participants may contribute each pay period any whole 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 any contributions over six percent of compensation are called “Supplemental Contributions.” Participants who have attained age 50 before the close of a year are allowed to make additional contributions referred to as “Catch-Up Contributions,” subject to the limitations of the Code. OGE Energy contributes to the plan each pay period on behalf of each participant an amount equal to 50 percent of the participant’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 amount equal to 75 percent of the participant’s Regular Contributions for participants whose employment or re-employment date occurred before February 1, 2000 and who have 20 or more years of service. For participants whose employment or re-employment date occurred on or after February 1, 2000, OGE Energy contributes 100 percent of the Regular Contributions deposited during such pay period by such participant. No OGE Energy contributions are made with respect to a participant’s Supplemental Contributions, Catch-Up Contributions, rollover contributions, or with respect to a participant’s Regular Contributions based on overtime payments, pay-in-lieu of overtime for exempt personnel, special lump-sum recognition awards and lump-sum merit awards included in compensation for determining the amount of participant contributions. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

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### FERC FORM NO. 1 (ED. 12-88) Page 123.26

### OGE Energy’s contribution which is initially allocated for investment to the OGE Energy Common Stock Fund may be made in shares of OGE Energy’s common stock or in cash which is used to invest in OGE Energy’s common stock. Once made, OGE Energy’s contribution may be reallocated, on any business day, by participants to other available investment options. The Company contributed approximately $5.1 million, $4.7 million and $4.2 million during 2008, 2007 and 2006 respectively, to the defined contribution plan. Deferred Compensation Plan OGE Energy provides a deferred compensation plan. The plan’s primary purpose is to provide a tax-deferred capital accumulation vehicle for a select group of management, highly compensated employees and non-employee members of the Board of Directors of OGE Energy and to supplement such employees’ defined contribution plan contributions as well as offering this plan to be competitive in the marketplace. Eligible employees who enroll in the plan have the following deferral options: (i) eligible employees may elect to defer up to a maximum of 70 percent of base salary and 100 percent of bonus awards; or (ii) eligible employees may elect a deferral percentage of base salary 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 qualified 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 100 percent of directors’ meeting fees and annual retainers. OGE Energy matches employee (but not non-employee director) deferrals to provide for the match that would have been made under the defined contribution plan had 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. OGE Energy accounts for the contributions related to the Company’s executive officers in this plan as Accrued Benefit Obligations and the Company accounts for the contributions related to the Company’s directors in this plan as Other Deferred Credits and Other Liabilities in the Consolidated Balance Sheets. The investment associated with these contributions is accounted for as Other Property and Investments in OGE Energy’s Consolidated Balance Sheets. The appreciation of these investments is accounted for as Other Income and the increase in the liability under the plan is accounted for as Other Expense in OGE Energy’s Consolidated Statements of Income. Supplemental Executive Retirement Plan OGE Energy provides a supplemental executive retirement plan in order to attract and retain lateral hires or other executives designated by the Compensation Committee of OGE Energy’s Board of Directors who may not otherwise qualify for a sufficient level of benefits under OGE Energy’s 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 Operating Lease Obligations Future minimum payments for the noncancellable operating lease for railcars are as follows:

2014 and Year ended December 31(In millions) 2009 2010 2011 2012 2013 Beyond

Railcars $ 3.96 $ 3.8 $ 38.0 $ --- $ --- $ --- Payments for operating lease obligations were approximately $3.9 million, $3.9 million and $4.2 million in 2008, 2007 and 2006, respectively. Railcar Lease Agreement At December 31, 2007, the Company had a noncancellable operating lease with purchase options, covering 1,409 coal hopper railcars to transport coal from Wyoming to the Company’s coal-fired generation units. Rental payments are charged to Operation Expense and are recovered through the Company’s tariffs and fuel adjustment clauses. On December 29, 2005, the Company entered Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.27

### into a new lease agreement for railcars effective February 1, 2006 with a new lessor as described below. In April 2008, the Company amended its contract to add 55 new railcars for approximately $3.5 million. At the end of the new lease term, which is January 31, 2011, the Company has the option to either purchase the railcars at a stipulated fair market value or renew the lease. If the Company chooses not to purchase the railcars or renew the lease agreement and the actual value of the railcars is less than the stipulated fair market value, the Company would be responsible for the difference in those values up to a maximum of approximately $31.5 million. In mid-February 2009, the Company expects to enter into a new short-term lease agreement to add 270 new railcars for approximately $1.2 million to satisfy the requirements of its new coal transportation contracts with BNSF Railway and Union Pacific as discussed below. The expiration dates of the lease agreement are expected to be: (i) six months from the effective date of the lease agreement for 135 cars and (ii) one year from the effective date of the lease agreement for the other 135 cars. The Company 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 furnish this maintenance. Coal Transportation Contracts The Company has transportation contracts for the transportation of coal to its coal-fired power plants. The Company’s transportation contracts expired on December 31, 2008. On December 19, 2008, the Company entered into a new rail transportation agreement with the BNSF Railway for the movement of coal to the Company’s Sooner power plant. The Company has also filed a complaint at the Surface Transportation Board (“STB”) requesting the establishment of reasonable rates, practices and service terms for the transportation of coal from Union Pacific served mines in the southern Powder River Basin, Wyoming to the Company’s Muskogee power plant. The timing of the completion of this proceeding is uncertain at this time. The effect of the new BNSF Railway agreement and the anticipated rail rate prescription from the STB for rail transportation to the Company’s Sooner and Muskogee power plants is expected to cause an approximate 50 percent increase in the Company’s delivered coal prices . Public Utility Regulatory Policy Act of 1978 At December 31, 2008, the Company has agreements with two qualifying cogeneration facilities (“QF”) having terms of 15 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 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 suspended. The total cost of cogeneration payments is recoverable in rates from customers. For the AES-Shady Point, Inc. (“AES”) QF contract for 320 MWs, the Company purchases 100 percent of the electricity generated by the QF. In addition, effective September 1, 2004, the Company entered into a new 15-year power purchase agreement for 120 MWs with Powersmith Cogeneration Project, L.P. (“PowerSmith”) in which the Company purchases 100 percent of electricity generated by PowerSmith. During 2008, 2007 and 2006, the Company made total payments to cogenerators of approximately $152.8 million, $156.8 million and $162.6 million, respectively, of which approximately $84.4 million, $88.9 million and $94.9 million, respectively, represented capacity payments. All payments for purchased power, including cogeneration, are included in the Statement of Income as Operation Expense. The future minimum capacity payments under the contracts are approximately: 2009 – $86.8 million, 2010 – $85.0 million, 2011 – $83.1 million, 2012 – $81.0 million and 2013 – $81.0 million.

Fuel Minimum Purchase Commitments The Company purchased necessary fuel supplies of coal and natural gas for its generating units of approximately $215.1 million, $190.2 million and $195.1 million for the years ended December 31, 2008, 2007 and 2006, respectively. The Company has entered into purchase commitments of necessary fuel supplies of approximately: 2009 – $320.7 million, 2010 – $114.1 million, 2011 – $65.2 million, 2012 – $3.9 million, 2013 – $3.9 million and 2014 and Beyond – $19.5 million. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.28

### Natural Gas Units In August 2008, the Company issued a request for proposal (“RFP”) for gas supply purchases for periods from November 2008 through March 2009, which accounted for approximately 15 percent of its projected 2009 natural gas requirements. The contracts resulting from this RFP are tied to various gas price market indices that will expire in 2009. Additional gas supplies to fulfill the Company’s remaining 2009 natural gas requirements will be acquired through additional RFPs in early to mid-2009, along with monthly and daily purchases, all of which are expected to be made at market prices.

Natural Gas Measurement Cases United States of America ex rel., Jack J. Grynberg v. Enogex Inc., Enogex Services Corporation and the Company. (U.S. District Court for the Western District of Oklahoma, Case No. CIV-97-1010-L.)United States of America ex rel., Jack J. Grynberg v. Transok Inc. et al.(U.S. District Court for the Eastern District of Louisiana, Case No. 97-2089; U.S. District Court for the Western District of Oklahoma, Case No. 97-1009M.). On June 15, 1999, the Company was served with the plaintiff’s complaint, which is a qui tam action under the False Claims Act. Plaintiff Jack J. Grynberg, as individual relator on behalf of the Federal government, alleges: (a) each of the named defendants have improperly or intentionally mismeasured gas (both volume and British thermal unit content) purchased from Federal and Indian lands which have resulted in the under-reporting and underpayment of gas royalties owed to the Federal government; (b) certain provisions generally found in gas purchase contracts are improper; (c) transactions by affiliated companies are not arms-length; (d) excess processing cost deduction; and (e) 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 Federal government can intervene and take over such actions from the relator. The Department of Justice, on behalf of the Federal government, decided not to intervene in this action. The plaintiff filed over 70 other cases naming over 300 other defendants in various Federal courts across the country containing nearly identical allegations. The Multidistrict Litigation Panel entered its order in late 1999 transferring and consolidating for pretrial purposes approximately 76 other similar actions filed in nine other Federal courts. The consolidated cases are now before the U.S. District Court for the District of Wyoming. In October 2002, the court granted the Department of Justice’s motion to dismiss certain of the plaintiff’s claims and issued an order dismissing the plaintiff’s valuation claims against all defendants. Various procedural motions have been filed. A hearing on the defendants’ motions to dismiss for lack of subject matter jurisdiction, including public disclosure, original source and voluntary disclosure requirements was held in 2005 and the special master ruled that the Company and all Enogex parties named in these proceedings should be dismissed. This ruling was appealed to the District Court of Wyoming. On October 20, 2006, the District Court of Wyoming ruled on Grynberg’s appeal, following and confirming the recommendation of the special master dismissing all claims against Enogex Inc., Enogex Services Corp., Transok, Inc. and the Company, for lack of subject matter jurisdiction. Judgment was entered on November 17, 2006 and Grynberg filed his notice of appeal with the District Court of Wyoming. The defendants filed motions for attorneys’ fees on various bases on January 8, 2007. The defendants also filed for other legal costs on December 18, 2006. A hearing on these motions was held on April 24, 2007, at which time the judge took these motions under advisement. Grynberg has also filed appeals with the Tenth Circuit Court of Appeals. In compliance with the Tenth Circuit’s June 19, 2007 scheduling order, Grynberg filed appellants’ opening brief on July 31, 2007 and the appellees’ consolidated response briefs were filed on November 21, 2007. Also, on December 5, 2007, OGE Energy and the Enogex parties filed a notice of its intent to file a separate response brief, which OGE Energy filed on January 11, 2008. Oral arguments were made to the Tenth Circuit on September 25, 2008. No ruling was made on the oral arguments and the court took the case under advisement. The Company intends to vigorously defend this action. At this time, the Company 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 the Company. Will Price, et al. v. El Paso Natural Gas Co., et al.(Price I). On September 24, 1999, various subsidiaries of OGE Energy were served with a class action petition filed in the District Court of Stevens County, Kansas by Quinque Operating Company and Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.29

### other named plaintiffs alleging the mismeasurement of natural gas on non-Federal lands. On April 10, 2003, the court entered an order denying class certification. On May 12, 2003, the plaintiffs (now Will Price, Stixon Petroleum, Inc., Thomas F. Boles and the Cooper Clark Foundation, on behalf of themselves and other royalty interest owners) filed a motion seeking to file an amended class action petition, and the court granted the motion on July 28, 2003. In its amended petition (the “Fourth Amended Petition”), the Company and Enogex Inc. were omitted from the case but two of OGE Energy’s subsidiary entities remained as defendants. The plaintiffs’ Fourth Amended Petition seeks class certification and alleges that approximately 60 defendants, including two of OGE Energy’s subsidiary entities, have improperly measured the volume of natural gas. The Fourth Amended Petition asserts theories of civil conspiracy, aiding and abetting, accounting and unjust enrichment. In their briefing on class certification, the plaintiffs seek to also allege a claim for conversion. The plaintiffs seek unspecified actual damages, attorneys’ fees, costs and pre-judgment and post-judgment interest. The plaintiffs also reserved the right to seek punitive damages. Discovery was conducted on the class certification issues, and the parties fully briefed these same issues. A hearing on class certification issues was held April 1, 2005. In May 2006, the court heard oral argument on a motion to intervene filed by Colorado Consumers Legal Foundation, which is claiming entitlement to participate in the putative class action. The court has not yet ruled on the motion to intervene. On July 2, 2007, the court ordered the plaintiffs and defendants to file proposed findings of facts and conclusions of law on class certification by July 31, 2007. On July 31, 2007, the two subsidiary entities of OGE Energy filed their proposed findings of fact and conclusions of law regarding conflict of law issues and the coordinated defendants filed their proposed findings of facts and conclusions of law on class certification. OGE Energy intends to vigorously defend this action. At this time, OGE Energy 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 OGE Energy.

Franchise Fee Lawsuit On June 19, 2006, two Company customers brought a putative class action, on behalf of all similarly situated customers, in the District Court of Creek County, Oklahoma, challenging certain charges on the Company’s electric bills. The plaintiffs claim that the Company improperly charged sales tax based on franchise fee charges paid by its customers. The plaintiffs also challenge certain franchise fee charges, contending that such fees are more than is allowed under Oklahoma law. The Company’s motion for summary judgment was denied by the trial judge. The Company filed a writ of prohibition at the Oklahoma Supreme Court asking the court to direct the trial court to dismiss the class action suit. In January 2007, the Oklahoma Supreme Court “arrested” the District Court action until, and if, the propriety of the complaint of billing practices is determined by the OCC. In September 2008, the plaintiffs filed an application with the OCC asking the OCC to modify its order which authorizes the Company to collect the challenged franchise fee charges. A procedural schedule and notice requirements for the matter were established by the OCC on December 4, 2008. The OCC expects to hear arguments for a motion to dismiss on March 26, 2009. The Company believes that this case is without merit. Oxley Litigation The Company has been sued by John C. Oxley D/B/A Oxley Petroleum et al. in the District Court of Haskell County, Oklahoma. This case has been pending for more than 11 years. The plaintiffs’ alleged that the Company breached the terms of contracts covering several wells by failing to purchase gas from the plaintiff in amounts set forth in the contracts. The plaintiffs’ most recent Statement of Claim describes approximately $2.7 million in take-or-pay damages (including interest) and approximately $36 million in contract repudiation damages (including interest), subject to the limitation described below. In 2001, the Company agreed to provide the plaintiffs with approximately $5.8 million of consideration and the parties agreed to arbitrate the dispute. Consequently, the Company will only be liable for the amount, if any, of an arbitration award in excess of $5.8 million. The Company expects the arbitration to occur in the first half of 2009. While the Company cannot predict the precise outcome of the arbitration, based on the information known at this time, The Company believes that this lawsuit will not have a material adverse effect on the Company’s financial position or results of operations. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.30

### Environmental Laws and Regulations The activities of the Company are subject to stringent and complex Federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws and regulations can restrict or impact the Company’s business activities in many ways, such as restricting the way it can handle or dispose of its wastes, requiring remedial action to mitigate pollution conditions that may be caused by its operations or that are attributable to former operators, regulating future construction activities to avoid endangered species or enjoining some or all of the operations of facilities deemed in noncompliance with permits issued pursuant to such environmental laws and regulations. In most instances, the applicable regulatory requirements relate to water and air pollution control or solid waste management measures. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances or wastes have been disposed or otherwise released into the environment. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or wastes into the environment. The Company handles some materials subject to the requirements of the Federal Resource Conservation and Recovery Act and the Federal Water Pollution Control Act of 1972, as amended (“Clean Water Act”) and comparable state statutes, prepares and files reports and documents pursuant to the Toxic Substance Control Act and the Emergency Planning and Community Right to Know Act and obtains permits pursuant to the Federal Clean Air Act and comparable state air statutes. Environmental regulation can increase the cost of planning, design, initial installation and operation of the Company’s facilities. Historically, the Company’s total expenditures for environmental control facilities and for remediation have not been significant in relation to its financial position or results of operations. The Company believes, however, that it is reasonably likely that the trend in environmental legislation and regulations will continue towards more restrictive standards. Compliance with these standards may increase the cost of conducting business. Approximately $1.0 million and $31.5 million, respectively of the Company’s capital expenditures budgeted for 2009 and 2010 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 environmental standards. It is estimated that the Company’s total expenditures for capital, operating, maintenance and other costs to preserve and enhance environmental quality will be approximately $35.7 million during 2009 as compared to approximately $37.1 million in 2008. The Company continues to evaluate its environmental management systems to ensure compliance with existing and proposed environmental legislation and regulations and to better position itself in a competitive market.

Air On March 15, 2005, the U.S. Environmental Protection Agency (“EPA”) issued the Clean Air Mercury Rule (“CAMR”) to limit mercury emissions from coal-fired boilers. On February 8, 2008, the U.S. Court of Appeals for the D.C. Circuit Court vacated the rule. Various petitions and appeals related to this decision have been made and are not yet resolved. On February 6, 2009, the EPA filed a motion to dismiss their earlier request for the U.S. Supreme Court to review the 2008 decision. Industry interests are still seeking the U.S. Supreme Court review in the case. The EPA has stated that it intends to draft mercury rules under the Federal Clean Air Act. The Company cannot predict the outcome of the Federal litigation at this time. Until the rule was vacated, the CAMR required mercury monitoring to begin in 2009. Accordingly, the Company installed mercury monitoring equipment on all five of its coal units. The cost of the monitoring equipment was approximately $5.0 million in 2007 and approximately $0.4 million in 2008. Because the CAMR litigation is ongoing, the cost to install mercury controls is uncertain at this time but may be significant, particularly if the EPA develops more stringent requirements. Because of the uncertainty caused by the litigation regarding the CAMR, the promulgation of an Oklahoma rule that would apply to existing facilities has been delayed. The Company will continue to participate in the state rule making process. On June 15, 2005, the EPA issued final amendments to its 1999 regional haze rule. These regulations are intended to protect visibility in national parks and wilderness areas (“Class I areas”) throughout the United States. In Oklahoma, the Wichita Mountains are 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 joined with eight other central states to address these visibility impacts. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.31

### In September 2005, the Oklahoma Department of Environmental Quality (“ODEQ”) informally notified affected utilities that they would be required to perform a study to determine their impact on visibility in Federal Class I areas. Affected utilities are those which have “Best Available Retrofit Technology (“BART”) eligible sources” (sources built between 1962 and 1977). For the Company, these include various generating units at various generating stations. Regulations, however, allow an owner or operator of a BART-eligible source to request and obtain a waiver from BART if modeling shows no significant impact on visibility in nearby Class I areas. Based on this modeling, the ODEQ made a preliminary determination to accept an application for a waiver for the Horseshoe Lake generating station. The Horseshoe Lake waiver is expected to be included in the ODEQ state implementation plan. The modeling did not support waivers for the affected units at the Seminole, Muskogee and Sooner generating stations. The Company submitted a BART compliance plan for Seminole on March 30, 2007 committing to installation of nitrogen oxide (“NOX”) controls on all three units. At the same time, the Company submitted a determination to the ODEQ that an alternative compliance plan for the affected units at the Muskogee and Sooner power plants will achieve overall greater visibility improvement than BART in the affected Class I areas and the alternative plan extends the timeline for compliance to 2018. The cost for this alternative compliance plan, including the BART compliance plan for the Seminole power plant (the alternative compliance plan and the BART compliance plan are collectively referred to herein as the “alternative plan”), was estimated at approximately $470 million in March 2007. The alternative plan included installing semi-dry scrubbers on three of four affected coal units and low NOX burner equipment on all four coal units. This alternative plan was subject to approval by the ODEQ and the EPA. The EPA provided comments to the ODEQ on the Company’s alternative plan. On November 16, 2007, the ODEQ notified the Company that additional analysis would be required before the Company alternative plan could be accepted. On May 30, 2008, the Company filed the results with the ODEQ for the affected generating units as well as withdrawing its alternative plan filed in March 2007. In the May 30, 2008 filing, the Company indicated its intention to install low NOX combustion technology at its affected generating stations and to continue to burn low sulfur coal at its four coal-fired generating units at its Muskogee and Sooner generating stations. The capital expenditures associated with the installation of the low NOX combustion technology are expected to be approximately $110 million. The Company believes that these control measures will achieve visibility improvements in a cost-effective manner. The Company did not propose the installation of scrubbers at its four coal-fired generating units because the Company concluded that, consistent with the EPA’s regulations on BART, the installation of scrubbers (at an estimated cost of $1.7 billion) would not be cost-effective. The Company previously reported an expectation that a compliance plan would be approved by the EPA by December 31, 2008; however, submission of the overall compliance plan by the ODEQ (which will include the Company’s compliance plan previously submitted to the ODEQ) has been delayed and the current timing of the EPA approval cannot be reasonably predicted. In a letter dated November 4, 2008, the EPA notified the ODEQ that they had completed their review of BART applications for all affected sources in Oklahoma, which included the Company. The EPA did not approve or disapprove the applications, however, additional information was requested from the ODEQ by the EPA regarding the Company’s plan. The Company cannot predict what action the EPA or the ODEQ will take in response to the Company’s May 30, 2008 filing or the November 4, 2008 letter from the EPA. Until the compliance plan is approved, the total cost of compliance, including capital expenditures, cannot be estimated by the Company with a reasonable degree of certainty. The Company expects that any necessary environmental expenditures will qualify as part of a pre-approval plan to handle state and federally mandated environmental upgrades which will be recoverable in Oklahoma from the Company’s retail customers under House Bill 1910, which was enacted into law in May 2005. The original deadline for the ODEQ to submit a state implementation plan for regional haze that includes final BART determinations was December 17, 2007. The ODEQ did not meet this deadline. On January 15, 2009, the EPA published a rule that gives the ODEQ two years to complete the state implementation plan. If the ODEQ fails to meet this deadline, the EPA can issue a Federal implementation plan. The 1990 Clean Air Act includes an acid rain program to reduce sulfur dioxide (“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 ton of SO2 released from the chimney. Plants may only release as much SO2 as they have allowances. Allowances may be banked and traded or sold nationwide. Beginning in 2000, the Company became subject to more stringent SO2 emission requirements in Phase II of the acid rain program. These lower limits had no significant financial impact due to the Company’s earlier decision to burn low sulfur coal. In 2008, the Company’s SO2 emissions were below the allowable limits. The EPA allocated SO2 allowances to the Company starting in 2000 and the Company started banking allowances in 2001. The Company sold no banked allowances in 2008. Also, during 2008, the Company received proceeds of approximately $0.4 million from the annual EPA spot (year 2008) and seven-year advance (year 2015) allowance auctions that were held in March 2008. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.32

### With respect to the NOX regulations of the acid rain program, 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 extend the effective date of the lower emission requirements from the year 2000 until 2008. The regulations required that the Company achieve a NOX emission level of 0.40 lbs/MMBtu for these boilers which began in 2008. The Company’s average NOX emissions from its coal-fired boilers for 2008 were approximately 0.32 lbs/MMBtu. It is expected that NOX emissions will be further reduced to 0.15 lbs/MMBtu by 2016 if the regional haze compliance plan discussed above is approved by the EPA. Further reductions in NOX emissions could be required if the ODEQ determines that such NOX emissions are impacting 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 likely require significant capital and operating expenditures. On September 21, 2006, the EPA lowered the 24-hour fine particulate ambient standard while retaining the annual standard at its current level and promulgated a new standard for inhalable coarse particulates. Based on past monitoring data, it appears that Oklahoma may be able to remain in attainment with these standards. However if parts of Oklahoma do become “non-attainment”, reductions in emissions from the Company’s coal-fired boilers could be required which may result in significant capital and operating expenditures. Currently, the EPA has designated Oklahoma “in attainment” with the ambient standard for ozone of 0.08 parts per million (“PPM”). In March 2008, the EPA lowered the ambient primary and secondary standards to 0.075 PPM. Oklahoma has until March 2009 to designate any areas of non-attainment within the state, based on ozone levels in 2006 through 2008. Following the state’s designation, the EPA is expected to determine a final designation by March 2010. States will be required to meet the ambient standards between 2013 and 2030, with deadlines depending on the severity of their ozone level. Oklahoma City and Tulsa are the most likely areas to be designated non-attainment in Oklahoma. The Company cannot predict the final outcome of this evaluation or its timing or affect on the Company’s operations. On April 25, 2005, the EPA published a finding that all 50 states failed to submit the interstate pollution transport plans required by the Clean Air Act as a result of the adoption of the revised ambient ozone and fine particle standards. Failure to submit these implementation plans began a two-year timeframe, starting on May 25, 2005, during which states must submit a demonstration to the EPA that they do not affect air quality in downwind states. The demonstration was properly submitted by the state to the EPA on May 7, 2007, and additional information was submitted by the state to EPA on December 5, 2007. Assuming the state implementation plan is approved as submitted, there should be no significant adverse impact to the Company as a result of the April 25, 2005 finding. The date of EPA approval of Oklahoma’s demonstration is currently unknown. In July 2008, the Company received a request for information from the EPA regarding Clean Air Act compliance at the Company’s Muskogee and Sooner generating plants. In recent years, the EPA has issued similar requests to numerous other electric utilities seeking to determine whether various maintenance, repair and replacement projects should have required permits under the Clean Air Act’s new source review process. The Company believes it has acted in full compliance with the Clean Air Act and new source review process and is cooperating with the EPA. On August 28, 2008, the Company submitted information to the EPA and submitted additional information on October 31, 2008. The Company cannot predict what, if any, further actions the EPA may take with respect to this matter. At December 31, 2008, the Company had received Title V permits for all of its generating stations and intends to continue to renew these permits as necessary. In January 2008, the ODEQ proposed fee increases of approximately 28 percent for Title V sources and 13 percent for minor sources. These fee increases were approved and became effective July 1, 2008. Air permit fees for the Company’s generating stations were approximately $0.8 million in 2008. In addition to the requirements related to emissions of SO2, NOX and mercury discussed above, there is a growing concern nationally and internationally about global climate change and the contribution of emissions of greenhouse gases including, most significantly, carbon dioxide. This concern has led to increased interest in legislation at the Federal level, actions at the state level, as well as litigation relating to greenhouse gas emissions, including a recent U.S. Supreme Court decision holding that the EPA has the authority to regulate carbon dioxide emissions from motor vehicles under the Clean Air Act. Increased pressure for carbon dioxide emissions reduction also is coming from investor organizations and the international community. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.33

### On the legislative front, in June 2005, the U.S. Senate adopted a resolution declaring that mandatory reductions in greenhouse gases are needed. Despite executive branch opposition to any mandatory requirements, several bills that would cap or tax greenhouse gases from electric utilities are being considered by Congress, and the concept of such regulation has received support from the majority leadership in both the U.S. Senate and U.S. House of Representatives. Oklahoma and Arkansas have not, at this time, established any mandatory programs to regulate carbon dioxide and other greenhouse gases. However, government officials in these states have declared support for state and Federal action on climate change issues. The Company reports quarterlyits carbon dioxide emissions and is continuing to evaluate various options for reducing, avoiding, off-setting or sequestering its carbon dioxide emissions. If legislation or regulations are passed at the Federal or state levels in the future requiring mandatory reductions of carbon dioxide and other greenhouse gases on generation facilities to address climate change, this could result in significant additional compliance costs that would affect our future financial position, results of operations and cash flows if such costs are not recovered through regulated rates.

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 recycling efforts. In 2008, the Company obtained refunds of approximately $2.2 million from its recycling efforts. This figure does not include the additional savings gained through the reduction and/or avoidance of disposal costs and the reduction in material purchases due to the reuse of existing materials. Similar savings are anticipated in future years.

Water The Company received two Oklahoma Pollutant Discharge Elimination System (“OPDES”) renewal permits in February 2008 from the state of Oklahoma. The Company filed an OPDES renewal application with the state of Oklahoma on August 4, 2008 for its Seminole power plant and received a draft permit for review on January 9, 2009. The Company is currently reviewing this draft permit to determine if it is reasonable in its requirements and allows operational flexibility. 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 technology” for minimizing environmental impacts. The EPA Section 316(b) rules for existing facilities became effective July 23, 2004. On January 25, 2007, a Federal court reversed and remanded certain portions of the Section 316(b) rules to the EPA. On July 9, 2007, the EPA suspended these portions of the Section 316(b) rules for existing facilities. As a result of such suspension, permits required for existing facilities are to be developed by the individual states using their best professional judgment until the EPA completes its review of the suspended sections. In September 2007, the state of Oklahoma required a comprehensive demonstration study be submitted by January 7, 2008 for each affected facility. On January 7, 2008, the Company submitted the requested studies for its facilities. Additionally, on April 14, 2008, the U.S. Supreme Court granted writs of certiorari and will review the question of whether the Section 316(b) rules authorize the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. It is not clear what changes, if any, the EPA will ultimately make to the Section 316(b) rules or how those changes may affect the Company. Depending on the ultimate analysis and final determinations regarding the Section 316(b) rules and the comprehensive demonstration studies, capital and/or operating costs may increase at any affected Company generating facility. The Company expects a ruling from the U.S. Supreme Court on the Section 316(b) rules in mid-2009.

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, claims made by third parties, environmental actions or the action of various regulatory agencies. When appropriate, management consults with legal counsel and other appropriate experts to assess the claim. If in management’s opinion, the Company 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. Except as otherwise stated above and in Note 13 below, management, after consultation with legal counsel, does not currently anticipate that liabilities arising out of these pending or threatened lawsuits, claims and contingencies will have a material adverse effect on the Company’s financial position, results of operations or cash flows. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.34

### 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 Department of Energy has jurisdiction over some of the Company’s facilities and operations. For the year ended December 31, 2008, approximately 88 percent of the Company’s electric revenue was subject to the jurisdiction of the OCC, nine percent to the APSC and three percent to the FERC. The OCC issued an order in 1996 authorizing the Company to reorganize into a subsidiary of OGE Energy. The order required that, among other things, (i) OGE Energy permit the OCC access to the books and records of OGE Energy and its affiliates relating to transactions with the Company; (ii) OGE Energy employ accounting and other procedures and controls to protect against subsidization of non-utility activities by the Company’s customers; and (iii) OGE Energy refrain from pledging Company assets or income for affiliate transactions. In addition, the Energy Policy Act of 2005 enacted the Public Utility Holding Company Act of 2005, which in turn granted to the FERC access to the books and records of OGE Energy and its affiliates as the FERC deems relevant to costs incurred by the Company or necessary or appropriate for the protection of utility customers with respect to the FERC jurisdictional rates. Completed Regulatory Matters Acquisition of Redbud Power Plant On January 21, 2008, the Company entered into a Purchase and Sale Agreement (“Purchase and Sale Agreement”) with Redbud Energy I, LLC, Redbud Energy II, LLC and Redbud Energy III, LLC (“Redbud Sellers”), which were indirectly owned by Kelson Holdings LLC, a subsidiary of Harbinger Capital Partners Master Fund I, Ltd. and Harbinger Capital Partners Special Situations Fund, L.P. Pursuant to the Purchase and Sale Agreement, the Company agreed to acquire from the Redbud Sellers the entire partnership interest in Redbud Energy LP which owned the Redbud Facility for approximately $852 million, subject to working capital and inventory adjustments in accordance with the terms of the Purchase and Sale Agreement. In connection with the Purchase and Sale Agreement, the Company also entered into (i) an Asset Purchase Agreement (“Asset Purchase Agreement”) with the OMPA and the GRDA, pursuant to which the Company agreed that it would, after the closing of the transaction contemplated by the Purchase and Sale Agreement, dissolve Redbud Energy LP and sell a 13 percent undivided interest in the Redbud Facility to the OMPA and sell a 36 percent undivided interest in the Redbud Facility to the GRDA, and (ii) an Ownership and Operating Agreement (“Ownership and Operating Agreement”) with the OMPA and the GRDA, pursuant to which the Company, the OMPA and the GRDA, following the completion of the transaction contemplated by the Asset Purchase Agreement, would jointly own the Redbud Facility and the Company will act as the operations manager and perform the day-to-day operation and maintenance of the Redbud Facility. Under the Ownership and Operating Agreement, each of the parties would be entitled to its pro rata share, which is equal to its respective ownership interest, of all output of the Redbud Facility and would pay its pro rata share of all costs of operating and maintaining the Redbud Facility, including its pro rata share of the operations manager’s general and administrative overhead allocated to the Redbud Facility. The transactions described above were subject to an order from the FERC authorizing the contemplated transactions and an order from the OCC approving the prudence of the transactions and an appropriate reasonable recovery mechanism, and other customary conditions. On September 16, 2008, the FERC issued an order approving the Redbud acquisition. In the order, the FERC concluded that the Redbud acquisition could harm horizontal competition by increasing market concentration. However, the FERC concluded, that since the Company had committed to construct specific upgrades on the system, these would be adequate mitigation measures. Accordingly, the FERC conditioned its approval of the Redbud acquisition on the Company’s completion of these upgrades. The Company is required to file quarterly updates describing the progress of the transmission upgrades, the first of which was filed December 16, 2008. The Company also must notify the FERC of any change in circumstances regarding these projects. During the Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.35

### approximately 27-month period required to construct the transmission upgrades, the FERC did not require any interim mitigation beyond the limits of the Company’s market-based rate authority and the SPP market monitoring programs currently in place. In addition, the FERC found that the proposed transaction would have no adverse effects on vertical market power, on wholesale rates, or on state or Federal regulation. The FERC also determined that the transaction presented no cross-subsidy concerns. Finally, the FERC rejected various arguments raised by AES that sought to expand the scope of the FERC proceeding or to impose additional conditions on the Redbud acquisition. On September 24, 2008, the OCC issued an order approving the Redbud acquisition. The Company closed on the Redbud acquisition on September 29, 2008. The Company implemented a rider at the end of September 2008 to recover the Oklahoma jurisdiction revenue requirement until new rates are implemented that include Redbud’s net investment, operation and maintenance expense, depreciation expense and ad valorem taxes. The Company purchased the entire partnership interest in the Redbud Facility using the following sources of cash: (i) net proceeds from the issuance by the Company of $250 million of 6.35% senior notes due September 1, 2018 in early September 2008, which net proceeds were temporarily used to repay a portion of the Company's outstanding commercial paper borrowings, (ii) $300 million of borrowings under a term loan agreement the Company entered into with Royal Bank of Scotland PLC ("RBS") on September 26, 2008 and (iii) borrowings under OGE Energy's and the Company's revolving credit agreements. On September 29, 2008, after the Company purchased the entire partnership interest in the Redbud Facility, the OMPA and the GRDA purchased their respective undivided interests in the Redbud Facility from the Company for approximately $417.5 million. After the closing of the sale of the undivided interest in the Redbud Facility, the Company used the $417.5 million in proceeds and repaid in full, on September 30, 2008, the $300 million borrowed from RBS discussed above and invested the remainder of the proceeds in short-term investments which are recorded as Temporary Cash Investments on the Company's Comparative Balance Sheet. The cash flows associated with the Company's purchase of the entire partnership interest in the Redbud Facility and the subsequent sale of the undivided interests in the Redbud Facility to the OMPA and the GRDA on September 29, 2008 are presented on a net basis as an investing cash outflow in Gross Additions to Utility Plant in the Company's Comparative Statement of Cash Flows. Cancelled Red Rock Power Plant and Storm Cost Recovery Rider On October 11, 2007, the OCC issued an order denying the Company and Public Service Company of Oklahoma’s (“PSO”) request for pre-approval of their proposed 950 MW Red Rock coal-fired power plant project. The plant, which was to be built at the Company’s Sooner plant site, was to be 42 percent owned by the Company, 50 percent owned by PSO and eight percent owned by the OMPA. As a result, on October 11, 2007, the Company, PSO and the OMPA agreed to terminate agreements to build and operate the plant. At December 31, 2007, the Company had incurred approximately $17.5 million of capitalized costs associated with the Red Rock power plant project. In December 2007, the Company filed an application with the OCC requesting authorization to defer, and establish a method of recovery of, approximately $14.7 million of Oklahoma jurisdictional costs associated with the Red Rock power plant project. Specifically, the Company requested authorization to sell approximately $14.7 million of its SO2 allowances and to retain 100 percent of the proceeds to offset the $14.7 million of Red Rock costs. Under a prior order of the OCC, 90 percent of the proceeds from sales of SO2 allowances were to be credited to ratepayers. Any portion of the $14.7 million of deferred costs that the OCC did not approve for recovery by the Company was to be expensed. In its response to the Company’s Red Rock cost recovery application, the OCC Staff recommended, among other things, that the Company sell SO2 allowances and retain 100 percent of the proceeds from the sale to be used to offset the Company’s December 2007 ice storm costs. These ice storm costs were included as part of the regulatory asset balance of approximately $35.9 million at December 31, 2007 (see Note 1), in accordance with a prior order of the OCC, pending recovery in a future rate case. On June 27, 2008, the Company filed an application requesting a Storm Cost Recovery Rider (“SCRR”) for the years 2007 through 2009 to recover excess storm damage costs and, at the same time, filed a motion to consolidate for hearing the Red Rock application and the SCRR application. On July 24, 2008, a settlement agreement was signed by all the parties involved in the two cases. Under the terms of the settlement agreement, the Company will: (i) recover approximately $7.2 million, or 50 percent, of the Oklahoma jurisdictional portion of the Red Rock power plant deferred costs through a regulatory asset, (ii) amortize the Red Rock regulatory asset over a 27-year amortization period and earn the OCC’s authorized rate of return beginning with the Company’s next rate case, (iii) accrue carrying costs on the debt portion of the Red Rock regulatory asset from October 1, 2007 until the date the Company begins to recover the regulatory asset through the base rates established in the Company’s next rate case, (iv) recover the OCC Staff and Attorney General consulting fees of approximately $0.3 million related to the Red Rock pre-approval case, in the Company’s next rate case by amortizing this over a two-year period, (v) recover approximately $33.7 million of the 2007 storm costs regulatory asset, which resulted in a write-down of approximately $1.5 million, (vi) implement the SCRR to recover the Company’s actual storm expense for the four-year period from 2006 through 2009, (vii) retain the first $3.4 million from the sale of excess SO2 allowances, (viii) reduce storm costs recovered through the SCRR by the proceeds from the sale of SO2 Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.36

### allowances above the amount retained by the Company and (ix) earn the most recent OCC authorized return on the unrecovered storm cost balance through the SCRR. On August 22, 2008, the OCC issued an order approving the settlement agreement and the SCRR was implemented in September 2008. In June 2008, the Company wrote down the Red Rock deferred cost and the storm costs to their net present value, which resulted in a pre-tax charge of approximately $9.0 million, which is currently included in Other Regulatory Assets with an offset in Other Deductions on the Company’s Financial Statements. Renewable Energy Filing The Company announced in October 2007 its goal to increase its wind power generation over the next four years from its current 170 MWs to 770 MWs and, as part of this plan, on December 8, 2008, the Company issued anRFPto wind developers for construction of up to 300 MWs of new capability. The Company intends to add the new capacity to its power-generation portfolio no later than the end of 2010. The Company filed an application on May 19, 2008 with the OCC requesting pre-approval to recover from Oklahoma customers the cost to construct a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma at a cost of approximately $211 million. This transmission line is a critical first step to increased wind development in western Oklahoma. In the application, the Company also requested authorization to implement a recovery rider to be effective when the transmission line is completed and in service, which is expected during 2010. Finally, the application requested the OCC to approve new renewable tariff offerings to the Company’s Oklahoma customers. On July 11, 2008, the OCC Staff filed responsive testimony recommending approval of the Company’s renewable plan and the Oklahoma Industrial Energy Consumers opposed the Company’s request. A settlement agreement was signed by all parties in the matter on July 31, 2008. Under the terms of the settlement agreement, the parties agreed that the Company will: (i) receive pre-approval for construction of a transmission line from Oklahoma City, Oklahoma to Woodward, Oklahoma and a conclusion that the construction costs of the transmission line are prudent, (ii) receive a recovery rider for the revenue requirement of the $218 million in construction costs and AFUDC when the transmission line is completed and in service until new rates are implemented in a subsequent rate case and (iii) to the extent the construction costs and AFUDC for the transmission line exceed $218 million the Company be permitted to show that such additional costs are prudent and allowed to be recovered. On September 11, 2008, the OCC issued an order approving the settlement agreement. Separately, on July 29, 2008, the SPP Board of Directors approved the proposed transmission line discussed above. On February 2, 2009, the Company received SPP approval to begin construction of the transmission line and the associated Woodward Extra High Voltage substation. Review of the Company’s Fuel Adjustment Clause for Calendar Year 2006 The OCC routinely audits activity in the Company’s fuel adjustment clause for each calendar year. In September 2007, the OCC Staff filed an application for a prudence review of the Company’s 2006 fuel adjustment clause. In September 2008, the OCC issued an order approving the fuel, purchased power and purchase gas adjustment clause cost recoveries for calendar year 2006. Pending Regulatory Matters FERC Formula Rate Filing On November 30, 2007, the Company made a filing at the FERC to increase its transmission rates to wholesale customers moving electricity on the Company’s transmission lines. Interventions and protests were due by December 21, 2007. While several parties filed motions to intervene in the docket, only the OMPA filed a protest to the contents of the Company’s filing. The Company filed an answer to the OMPA’s protest on January 7, 2008. On January 31, 2008, the FERC issued an order (i) conditionally accepting the rates; (ii) suspending the effectiveness of such rates for five months, to be effective July 1, 2008, subject to refund; (iii) establishing hearing and settlement judge procedures; and (iv) directing the Company to make a compliance filing. In July 2008, rates were implemented in an annual amount of approximately $2.4 million, subject to refund. Several settlement conferences have been held with the most recent being on November 17 and 18, 2008. Since the November 17 and 18, 2008 settlement conferences, the parties have continued to engage in settlement discussions. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.37

### Arkansas Rate Case Filing On August 29, 2008, the Company filed with the APSC an application for an annual rate increase of approximately $26.4 million to recover, among other things, costs for investments including the Redbud Facility and improvements in its system of power lines, substations and related equipment to ensure that the Company can reliably meet growing customer demand for electricity, and a return on equity of 12.25 percent. In January 2009, the APSC Staff recommended a $12.0 million rate increase based on a 10.5 percent return on equity. The Attorney General’s consultant recommended a return on equity at the current authorized level of 10.0 percent and stated that his analysis identified at least $10.9 million in reductions to the Company’s rate increase request. A hearing is scheduled for April 7, 2009. An order from the APSC is expected in June 2009 with new rates targeted for implementation in July 2009. 2008 Storm Cost Filing On October 30, 2008, the Company filed an application with the APSC requesting authority to defer its 2008 storm costs that exceed the amount recovered in base rates. The application also requests the APSC to provide for recovery of the deferred 2008 storm costs in the Company’s pending rate case. On December 19, 2008, the APSC issued an order authorizing the Company to defer approximately $0.6 million in 2008 for incremental storm costs in excess of the amount included in the Company’s rates. The Company was also authorized to seek recovery in its pending rate case but was not guaranteed recovery. At December 31, 2008, these incremental storm costs were approximately $0.6 million, which has been recorded as a regulatory asset (see Note 1). 2009 Oklahoma Rate Case Filing Beginning in October 2008, the Company began developing a rate case filing for the Oklahoma jurisdiction. On January 20, 2009, the Company notified the OCC that it will make its planned Oklahoma rate case filing on or about February 26, 2009. The Company is finalizing the preparation of the rate case and expects to request an increase of between $100 million and $110 million. The case is expected to proceed through the first half of 2009. If an increase is approved by the OCC, electric rates would likely be implemented in September 2009 at the earliest. System Hardening Filing In December 2007, a major ice storm affected the Company’s service territory which resulted in a large number of customer outages. The OCC requested its Staff to review and determine if a rulemaking was warranted. The OCC Staff issued numerous data requests and is in the process of determining if other regulatory jurisdictions have policies or rules requiring that electric transmission and distribution lines be placed underground. The OCC Staff also surveyed customers. On June 30, 2008, the OCC Staff submitted a report entitled, “Inquiry into Undergrounding Electric Facilities in the State of Oklahoma.” The Company formed a plan to place facilities underground (sometimes referred to as system hardening) with capital expenditures of approximately $115 million over five years for underground facilities, as well as $10 million annually for enhanced vegetation management. On December 2, 2008, the Company filed an application with the OCC requesting approval of it proposed system hardening plan with a recovery rider. On February 5, 2009, a procedural schedule was set in this matter with a hearing scheduled for March 25, 2009. The Company expects to receive an order from the OCC in the second quarter of 2009, with a targeted implementation date for the program and rider in the third quarter of 2009. Review of the Company’s Fuel Adjustment Clause for Calendar Year 2007 The OCC routinely audits activity in the Company’s fuel adjustment clause for each calendar year. In September 2008, the OCC Staff filed an application for a prudence review of the Company’s 2007 fuel adjustment clause. The Company is required to provide minimum filing requirements (“MFR”) within 60 days of the application; however, the Company requested and was granted an extension to file the MFRs by January 16, 2009, on which date the MFRs were submitted by the Company. Aprocedural schedule has not been established in this matter. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.38

### Security Enhancements On January 15, 2009, the Company filed an application with the OCC to amend its security plan. The Company is seeking approval of new security projects and cost recovery through the previously authorized security rider. The annual revenue requirement is approximately $0.9 million. The Company expects to receive an order from the OCC in the third quarter of 2009. Aprocedural schedule has not been established in this matter. Southwest Power Pool Transmission/Substation Project In January 2009, the Company received notification from the SPP to begin construction on approximately 50 miles of new 345kV transmission line and certain substation upgrades at the Company’s Sunnyside substation, among other projects. The line will extend from the Company’s Sunnyside substation near Ardmore, Oklahoma, to a point approximately one-half of the distance to the Hugo substation owned by the Western Farmers Electric Cooperative near Hugo, Oklahoma. The line and substation improvements are estimated to cost approximately $96 million. The Company intends to begin preliminary line routing and acquisition of rights-of-way in early 2009. When construction is completed, which is expected in April 2012, the SPP will allocate a portion of the annual revenue requirement to Company customers according to the base-plan funding mechanism as provided in the SPP tariff for application to such improvements. Market-Based Rate Authority On December 22, 2003, the Company and OERI filed a triennial market power update based on the supply margin assessment test.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 new interim tests.The Companyand OERI submitted a compliance filing to the FERC on February 7, 2005 thatapplied the interim tests tothe Companyand OERI. In the compliance filing,the Companyand OERI passed the pivotal supplier screen butdid not pass the market share screeninthe Company’s control area

.The Companyand OERI provided an explanation as to whytheirfailure of the market share screeninthe Company’s control areashould not be viewed as an indication that they can exercise generation market power. On June 7, 2005, the FERC issued an order onthe Company’s and OERI’s market-based rate filing. Becausethe Company and OERI failed the market share screen forthe Company’s control area, the FERCestablished hearing proceduresto investigate whetherthe Companyand OERI may continue to sell power at market-based rates inthe Company’s control area. Theorder established a rebuttable presumption thatthe Companyand OERI have the ability toexercise market powerinthe Company’s control
area. The Companyand OERIwererequested to provide additional information that demonstrates to the FERC that they cannot exercise market power in the first-tier markets as well. However, the order conditionally allowsthe Companyand OERI to sell power in first-tier markets subject tothe Companyand OERI providing additional information that clearly shows that they pass the market share screen for the first-tier markets. The Companyand OERI provided that additional information on July 7, 2005. On August 8, 2005,the Companyand OERI informed the FERC that they will: (i) adopt the FERC default rate mechanism for sales of one week or lessto loadsthatsink inthe Company’s control area; and (ii) commit not to enter into any sales with a duration of between one week and one year to loads thatsinkinthe Company’s control area.The Companyand OERI also informed the FERC that any new agreements for long-term sales(one year or longer in duration)to loads thatsink inthe Company’s control area will be filed with the FERCand thatthe Companyand OERI will not make such salesundertheir respectivemarket-based rate tariffs. On January 20, 2006, the FERC issued a Notice of Institution of Proceeding and Refund Effective Date for the purpose of establishing the date from which any subsequent market-based sales would be subject to refund in the event the FERC concludes after investigation thatthe rates for such sales are not just and reasonable. The refund effective date was March 27, 2006. On March 21, 2006, the FERC issued an order conditionally accepting the Company’s and OERI’s proposal to mitigate the presumption of market power in the Company’s control area. First, the FERC accepted the additional information related to first-tier markets submitted by the Company and OERI, and concluded that the Company and OERI satisfy the FERC’s generation market power standard for directly interconnected first-tier control areas. Second, the FERC directed the Company to make certain revisions to its mitigation proposal and file a cost-based rate tariff for short-term sales (one week or less) made within the Company’s control area. The FERC also expanded the scope of the proposed mitigation to all sales made within the Company’s control area (instead of only to sales sinking to load within the Company’s control area). On April 20, 2006, the Company submitted: (i) a compliance filing containing the specified revisions to the Company’s market-based rate tariffs and the new cost-based rate tariff; and (ii) a request for Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.39

### rehearing asking the FERC to reconsider its expanded mitigation directive contained in the March 21, 2006 order. On May 22, 2006, the FERC issued a tolling order that effectively provided the FERC additional time to consider the April 20, 2006 rehearing request. On July 25, 2006 and August 25, 2006, pursuant to a FERC March 20, 2006 order, the Company and OERI filed revisions to their market-based rate tariffs to allow them to sell energy imbalance service into the wholesale markets administered by the SPP at market-based rates. On April 4, 2008, the FERC rejected the Company’s April 20, 2006 request for rehearing and approved in part and rejected in part the Company’s April 20, 2006 compliance filing. The April 4, 2008 order directed the Company to evaluate whether any refunds are required to comply with the April 4, 2008 order and to: (i) make any necessary refunds, or (ii) file a report with the FERC stating that no refunds are due. Refunds would apply only to new market-based sales made or new market-based contracts entered into after the March 21, 2006 order. The April 4, 2008 order also directed the Company to make another compliance filing to revise its market-based rate tariffs to adhere to the FERC’s June 21, 2007 final rule that revised standards for market-based rate sales of electric energy, capacity and ancillary services. On May 5, 2008, the Company submitted a compliance report stating that no refunds were due.On May 30, 2008, the Company and OERI submitted to the FERC a change in status report notifying the FERC that the Company had entered into a contract with Westar Energy under which the Company agreed to purchase 300 MWs of capacity and energy for the periods from May 1, 2008 through August 31, 2008, and from May 1, 2009 through August 31, 2009. The Company and OERI explained that this purchase agreement was not material to the FERC’s grant of market-based rate status to the Company and OERI. The FERC has not yet acted on the Company and OERI’s May 30, 2008 change of status filing. On October 27, 2008, the Company and OERI submitted to the FERC another change of status filing notifying FERC that the Company had acquired a 51 percent interest in the Redbud Facility in Oklahoma, which increases the size of its generation resources by 610 MW. This filing indicated that: (i) the Company’s acquisition of the Redbud Facility does not reflect a material departure from the characteristics relied upon in granting the Company/OERI market-based rate authority; (ii) the Company/OERI continue to lack generation market power in first-tier markets; and (iii) the Company’s acquisition of the Redbud Facility does not effect the Company’s or OERI’s previous analysis on transmission market power, affiliate abuse or barriers to entry. The FERC has not yet acted on the Company’s and OERI’s October 27, 2008 change of status filing. North American Electric Reliability Council The Energy Policy Act of 2005 gave the FERC authority to establish mandatory electric reliability rules enforceable with monetary penalties. The FERC approved the North American Electric Reliability Council (“NERC”) as the Electric Reliability Organization for North America and delegated to it the development and enforcement of electric transmission reliability rules. On April 19, 2007, the FERC approved the SPP as a Regional Entity whose primary function is to review and enforce compliance of reliability standards with all registered entities in the region. In March 2007, the FERC approved mandatory NERC reliability standards which became effective June 18, 2007. In November 2008, the Company completed its periodic NERC compliance audit. Resolution of any audit findings is expected in 2009; however, the Company does not expect the resolution of any audit findings to have a material impact on its operations. The Company is subject to a NERC readiness evaluation and compliance audit every three years. The next readiness evaluation is scheduled for 2010 and the next compliance audit is scheduled for 2011. National Legislative Initiatives In October 2008, Congress enacted and the President signed into law the Emergency Economic Stabilization Act of 2008 which contains, among other things, provisions designed to provide programs to: (i) address the nation’s credit liquidity problems; (ii) provide disaster relief for adversely affected communities; (iii) preserve the value of homes, retirement accounts and promote job creation; and (iv) implement a wide range of tax provisions, including several of particular interest to the investor-owned utility sector. Among the tax provisions benefiting the utility sector are the extension of tax credits for renewable energy production, carbon mitigation and clean coal technology, plug-in hybrid vehicles, increasing residential and commercial building energy efficiency, energy efficient appliances and accelerated depreciation for smart meters and smart grid systems.Of particular interest to the Company is the extension through 2009 of the renewable energy production tax credit that was scheduled to expire at the end of 2008, which plays a prominent role regarding the financing and economics of wind energy projects. In December 2008, Congress enacted and the President signed into law legislation providing some relief for companies regarding mandatory pension payment obligations that had become complicated by the economic downturn. This legislation allowed companies greater latitude in meeting their pension obligations through temporary adjustments regarding mandatory minimum distributions and plan funding targets. The utility industry supported this legislation and is seeking broader temporary adjustments for pension plan funding in 2009. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.40

### State Legislative Initiatives House Bill 2813 (“HB 2813”) was signed into law in May 2008, at which time it became effective. HB 2813 was created in order to advance the development of Oklahoma’s vast wind power potential. This law providesfor additional financial certainty for transmission line projects deemed necessary for the development of wind energy. The costs associated with such transmission lines are to be presumed to be recoverable if the lines are in service within five years of the passage of the law and meet the necessary criteria. The Company has announced its intentions to build transmission lines and substantially increase the amount of generation it produces by wind, and management believes that this legislation increases the likelihood of recovering the costs associated with the construction of transmission lines. House Bill 1739 (“HB 1739”) was signed into law in May 2008, with an effective date of January 1, 2009. HB 1739 creates a system whereby utilities can divide their territories with the proper government oversight. The bill only relates to new customers in the territory and does not allow switching of existing customers. The law also codifies the right of investor-owned utilities to be able to continue serving in annexed territories of cities with municipal electric systems, where they can demonstrate a prior right to be in the annexed territory. The law is retroactive to include previous annexations as well as those that may occur in the future. This law also clarifies which utilities can serve in a territory annexed by a city because duplication of infrastructure has caused problems over the years since it possesses a potential safety hazard to line workers. The benefits of this law to the Company include being able to reduce future duplication of power lines and other infrastructure as well as clearly establishing the right to serve in areas previously considered legally questionable by certain parties. Legislation was enacted in Oklahoma in the 1990’s that was to restructure the electric utility industry in that state. The implementation of the Oklahoma restructuring legislation was delayed and seems unlikely to proceed anytime in the near future. Yet, if ultimately enacted, 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. The previously-enacted Oklahoma 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. 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 Policy Act of 2005, 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. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 NOTES TO FINANCIAL STATEMENTS (Continued)



### FERC FORM NO. 1 (ED. 12-88) Page 123.41Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. 1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate. 2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges. 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.

Other Adjustments (e) Foreign Currency Hedges

(d) Minimum Pension Liability adjustment (net amount) (c) Unrealized Gains andLosses on Availablefor-Sale Securities (b) Item

(a) Balance of Account 219 at Beginning of Preceding Year 1

Preceding Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 2

Preceding Quarter/Year to Date Changes in Fair Value 3

Total (lines 2 and 3) 4 Balance of Account 219 at End of Preceding Quarter/Year 5

Balance of Account 219 at Beginning of Current Year 6

Current Qtr/Yr to Date Reclassifications from Acct 219 to Net Income 7

Current Quarter/Year to Date Changes in Fair Value 8

Total (lines 7 and 8) 9 Balance of Account 219 at End of Current Quarter/Year 10

FERC FORM NO. 1 (NEW 06-02) Page 122aOther Cash Flow Hedges [Specify] (g) Other Cash Flow Hedges Interest Rate Swaps (f) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Total Comprehensive Income

(j) Net Income (Carried Forward from Page 117, Line 78) (i) Totals for each category of items

recorded in Account 219 (h) 582,009 582,009 1 ( 582,009) ( 582,009) 2 3 161,709,364 161,127,355 ( 582,009) ( 582,009) 4 5 6 7 8 143,006,547 143,006,547 9 10

FERC FORM NO. 1 (NEW 06-02) Page 122bName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (b) (a) Classification Electric (c) FOR DEPRECIATION. AMORTIZATION AND DEPLETION

Total Company for the Current Year/Quarter Ended 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.

Utility Plant 1 In Service 2 6,085,957,606 6,085,957,606 Plant in Service (Classified) 3 593,667 593,667 Property Under Capital Leases 4 Plant Purchased or Sold 5 15,262,642 15,262,642 Completed Construction not Classified 6 Experimental Plant Unclassified 7 6,101,813,915 6,101,813,915 Total (3 thru 7) 8 Leased to Others 9 2,136,865 2,136,865 Held for Future Use 10 169,154,630 169,154,630 Construction Work in Progress 11 154,202,293 154,202,293 Acquisition Adjustments 12 6,427,307,703 6,427,307,703 Total Utility Plant (8 thru 12) 13 2,633,061,106 2,633,061,106 Accum Prov for Depr, Amort, & Depl 14 3,794,246,597 3,794,246,597 Net Utility Plant (13 less 14) 15 Detail of Accum Prov for Depr, Amort & Depl 16 In Service: 17 2,613,172,433 2,613,172,433 Depreciation 18Amort & Depl of Producing Nat Gas Land/Land Right 19Amort of Underground Storage Land/Land Rights 20 18,414,353 18,414,353 Amort of Other Utility Plant 21 2,631,586,786 2,631,586,786 Total In Service (18 thru 21) 22 Leased to Others 23 Depreciation 24Amortization and Depletion 25Total Leased to Others (24 & 25) 26 Held for Future Use 27 8,126 8,126 Depreciation 28Amortization 29 8,126 8,126 Total Held for Future Use (28 & 29) 30Abandonment of Leases (Natural Gas) 31 1,466,194 1,466,194 Amort of Plant Acquisition Adj 32 2,633,061,106 2,633,061,106 Total Accum Prov (equals 14) (22,26,30,31,32) 33

FERC FORM NO. 1 (ED. 12-89) Page 200(g) Common (h) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. FOR DEPRECIATION. AMORTIZATION AND DEPLETION Gas Other (Specify) (d) (e) (f) Other (Specify) Other (Specify)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33

FERC FORM NO. 1 (ED. 12-89) Page 201Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description of item Balance (c) (b) (a) Changes during Year Beginning of Year Additions 

### 1. Report below the costs incurred for nuclear fuel materials in process of fabrication, on hand, in reactor, and in cooling; owned by the respondent. 2. If the nuclear fuel stock is obtained under leasing arrangements, attach a statement showing the amount of nuclear fuel leased, the quantity used and quantity on hand, and the costs incurred under such leasing arrangements.

Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1) 1 Fabrication 2 Nuclear Materials 3 Allowance for Funds Used during Construction 4 (Other Overhead Construction Costs, provide details in footnote) 5 SUBTOTAL (Total 2 thru 5) 6 Nuclear Fuel Materials and Assemblies 7 In Stock (120.2) 8 In Reactor (120.3) 9 SUBTOTAL (Total 8 & 9) 10 Spent Nuclear Fuel (120.4) 11 Nuclear Fuel Under Capital Leases (120.6) 12 (Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5) 13 TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13) 14 Estimated net Salvage Value of Nuclear Materials in line 9 15 Estimated net Salvage Value of Nuclear Materials in line 11 16 Est Net Salvage Value of Nuclear Materials in Chemical Processing 17 Nuclear Materials held for Sale (157) 18 Uranium 19 Plutonium 20 Other (provide details in footnote): 21 TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21) 22

FERC FORM NO. 1 (ED. 12-89) Page 202Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of NUCLEAR FUEL MATERIALS (Account 120.1 through 120.6 and 157) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Balance

(f) (e) (d) Changes during Year End of Year Amortization Other Reductions (Explain in a footnote)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22

FERC FORM NO. 1 (ED. 12-89) Page 203Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account Balance Additions (c) (b) (a) Beginning of Year 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. 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)

1. INTANGIBLE PLANT 1 (301) Organization 80,900 2 (302) Franchises and Consents 2,284,193 103,539 3 (303) Miscellaneous Intangible Plant 33,441,204 4,894,303 4 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 35,806,297 4,997,842 5 2. PRODUCTION PLANT 6 A. Steam Production Plant 7 (310) Land and Land Rights 11,399,927 8 (311) Structures and Improvements 234,791,016 6,278,452 9 (312) Boiler Plant Equipment 870,975,576 20,262,381 10 (313) Engines and Engine-Driven Generators 11 (314) Turbogenerator Units 365,684,942 3,715,229 12 (315) Accessory Electric Equipment 127,359,288 951,578 13 (316) Misc. Power Plant Equipment 52,692,913 1,331,100 14 (317) Asset Retirement Costs for Steam Production 1,392,871 15 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 1,664,296,533 32,538,740 16 B. Nuclear Production Plant 17 (320) Land and Land Rights 18 (321) Structures and Improvements 19 (322) Reactor Plant Equipment 20 (323) Turbogenerator Units 21 (324) Accessory Electric Equipment 22 (325) Misc. Power Plant Equipment 23 (326) Asset Retirement Costs for Nuclear Production 24 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 25 C. Hydraulic Production Plant 26 (330) Land and Land Rights 27 (331) Structures and Improvements 28 (332) Reservoirs, Dams, and Waterways 29 (333) Water Wheels, Turbines, and Generators 30 (334) Accessory Electric Equipment 31 (335) Misc. Power PLant Equipment 32 (336) Roads, Railroads, and Bridges 33 (337) Asset Retirement Costs for Hydraulic Production 34 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 35 D. Other Production Plant 36 (340) Land and Land Rights 853,930 37 (341) Structures and Improvements 12,682,806 -4,153 38 (342) Fuel Holders, Products, and Accessories 1,288,805 39 (343) Prime Movers 260,256,279 16,218,025 40 (344) Generators 227,204,323 73,245 41 (345) Accessory Electric Equipment 23,379,507 42 (346) Misc. Power Plant Equipment 7,266,286 29,076 43 (347) Asset Retirement Costs for Other Production 918,819 44 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 533,850,755 16,316,193 45 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 2,198,147,288 48,854,933 46

Page 204 FERC FORM NO. 1 (REV. 12-05)ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account Balance Additions (c) (b) (a) Beginning of Year

3. TRANSMISSION PLANT 47 (350) Land and Land Rights 28,181,017 1,294,772 48 (352) Structures and Improvements 3,279,887 194,348 49 (353) Station Equipment 263,525,599 38,470,794 50 (354) Towers and Fixtures 54,375,607 666,643 51 (355) Poles and Fixtures 200,106,407 17,328,625 52 (356) Overhead Conductors and Devices 173,580,323 4,782,994 53 (357) Underground Conduit 54 (358) Underground Conductors and Devices 110,494 55 (359) Roads and Trails 56 (359.1) Asset Retirement Costs for Transmission Plant 57 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 723,159,334 62,738,176 58 4. DISTRIBUTION PLANT 59 (360) Land and Land Rights 9,081,022 492,319 60 (361) Structures and Improvements 3,425,243 1,266,582 61 (362) Station Equipment 354,703,920 41,584,269 62 (363) Storage Battery Equipment 63 (364) Poles, Towers, and Fixtures 388,705,467 33,426,228 64 (365) Overhead Conductors and Devices 301,276,761 23,937,403 65 (366) Underground Conduit 111,052,903 12,363,123 66 (367) Underground Conductors and Devices 443,941,064 46,040,871 67 (368) Line Transformers 270,573,851 23,865,534 68 (369) Services 187,925,832 15,187,704 69 (370) Meters 80,438,800 6,420,464 70 (371) Installations on Customer Premises 25,247 71 (372) Leased Property on Customer Premises 593,667 72 (373) Street Lighting and Signal Systems 153,945,836 13,125,473 73 (374) Asset Retirement Costs for Distribution Plant 74 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 2,305,070,699 218,328,884 75 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 76 (380) Land and Land Rights 77 (381) Structures and Improvements 78 (382) Computer Hardware 79 (383) Computer Software 80 (384) Communication Equipment 81 (385) Miscellaneous Regional Transmission and Market Operation Plant 82 (386) Asset Retirement Costs for Regional Transmission and Market Oper 83 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 84 6. GENERAL PLANT 85 (389) Land and Land Rights 3,089,771 86 (390) Structures and Improvements 100,146,535 2,321,197 87 (391) Office Furniture and Equipment 12,538,756 16,966 88 (392) Transportation Equipment 52,447,852 11,395,881 89 (393) Stores Equipment 1,137,033 51,265 90 (394) Tools, Shop and Garage Equipment 5,640,680 737,552 91 (395) Laboratory Equipment 8,097,158 196,633 92 (396) Power Operated Equipment 5,603,352 659,277 93 (397) Communication Equipment 2,148,415 18,158 94 (398) Miscellaneous Equipment 5,245,810 41,114 95 SUBTOTAL (Enter Total of lines 86 thru 95) 196,095,362 15,438,043 96 (399) Other Tangible Property 97 (399.1) Asset Retirement Costs for General Plant 98 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 196,095,362 15,438,043 99 TOTAL (Accounts 101 and 106) 5,458,278,980 350,357,878 100 (102) Electric Plant Purchased (See Instr. 8) 852,919,406 101 (Less) (102) Electric Plant Sold (See Instr. 8) 102 (103) Experimental Plant Unclassified 103 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 5,458,278,980 1,203,277,284 104

Page 206 FERC FORM NO. 1 (REV. 12-05)(f) Transfers Balance at End of Year Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (g) Adjustments (e) Retirements (d) ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued) 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 (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of 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 (f) only the offset to the debits or credits distributed in column (f) to primary account classifications. 8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing subaccount classification of such plant conforming to the requirement of these pages. 9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date

1 80,900 2 2,369,793 17,939 3 23,599,504 888,554 15,624,557 4 26,050,197 888,554 15,642,496 5 6 7 11,399,927 8 240,508,063 561,405 9 886,326,078 6,606 4,918,485 10 11 367,677,028 1,723,143 12 128,112,862 198,004 13 53,583,507 -326,099 114,407 14 1,391,299 1,572 15 1,688,998,764 -319,493 7,517,016 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 1,180,820 326,890 37 52,047,207 39,368,554 38 16,535,859 15,247,054 39 519,041,585 242,567,281 40 227,246,395 -29,373 1,800 41 62,927,623 39,548,116 42 9,043,070 1,747,708 43 900,332 -18,487 44 888,922,891 338,757,743 1,800 45 2,577,921,655 338,438,250 7,518,816 46

Page 205 FERC FORM NO. 1 (REV. 12-05)(f) Transfers Balance at End of Year Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (g) Adjustments (e) Retirements (d) ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)

47 29,442,133 -33,656 48 3,474,235 49 306,207,961 4,401,048 189,480 50 55,564,169 521,919 51 211,639,272 -5,566,896 228,864 52 183,314,319 5,044,977 93,975 53 54 110,494 55 56 18,487 18,487 57 789,771,070 4,385,879 512,319 58 59 9,560,506 -12,835 60 4,701,830 10,005 61 393,559,480 -1,757,824 970,885 62 63 418,728,352 3,403,343 64 322,462,661 2,751,503 65 123,208,686 207,340 66 488,256,645 1,725,290 67 288,939,242 5,500,143 68 203,102,007 11,529 69 85,919,799 939,465 70 25,247 71 593,667 72 166,099,939 971,370 73 74 2,505,158,061 -1,760,654 16,480,868 75 76 77 78 79 80 81 82 83 84 85 3,015,821 -73,950 86 100,653,907 -802,693 1,011,132 87 11,684,861 58,029 928,890 88 57,833,808 -1,300,798 4,709,127 89 1,086,513 101,785 90 6,663,923 395,883 110,192 91 7,988,359 -248,170 57,262 92 7,170,233 1,304,657 397,053 93 2,300,954 162,258 27,877 94 4,514,553 -735,440 36,931 95 202,912,932 -1,240,224 7,380,249 96 97 98 202,912,932 -1,240,224 7,380,249 99 6,101,813,915 340,711,805 47,534,748 100 -342,584,151 -510,335,255 101 102 103 6,101,813,915 -1,872,346 -510,335,255 47,534,748 104

Page 207 FERC FORM NO. 1 (REV. 12-05)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC PLANT LEASED TO OTHERS (Account 104) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name of Lessee Description of (b) (a) (Designate associated companies with a double asterisk) Property Leased Commission Authorization (c) Expiration Date of Lease

(d) Balance at End of Year (e) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-95) Page213

47 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC PLANT HELD FOR FUTURE USE (Account 105) Oklahoma Gas and Electric Company X / / 2008/Q4

Line Description and Location Date Originally Included Balance at End of Year (c) (b) (a) Of Property in This Account Date Expected to be used in Utility Service (d) No. 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 property 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 required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.

Land and Rights: 1 various 30 Distribution Substation Land Sites 1,316,487 various 2 various 4 Distribution Substation Easement Sites 44,493 various 3 various 13 Transmission Substation Land and Line Easements 775,885 various 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Other Property: 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-96) Page 214 47 Total 2,136,865Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description of Project Construction work in progress - (b) (a) 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.

35,794,112 OU Spirit Wind Farm Construction 1 3,448,838 SO Transformer Rewind 2 3,287,320 MK4 Replace Stator Coils & Rewind Generator 3 1,973,297 RB2 Hot Gas Path Components Replacement 4 1,861,969 RB3 Hot Gas Path Components Replacement 5 1,500,682 MK Radial Stacker Boom Replacement 6 999,532 MK6 Bowl Mill Partial Replacement 7 450,588 MK6 Cooling Tower Fill Replacement 8 432,293 SM1 FA High Pressure Feedwater Heater Replacement 9 342,409 MT Low Volume Waste Pond Liner Replacement 10 325,484 MK3 Traveling Screens and Racks Replacement 11 313,440 MK6 Cooling Tower Inlet Traveling Screens Replacement 12 278,556 MK6 Emergency Make-Up Piping Replacement at Settling Basin 13 206,627 SO Install Dust Suppression at Plant Surge Bin 14 205,683 MK4/5 Boiler Enclosure Vent Fan Replacement 15 163,250 MK6 Install Platform above Hot Air Ducts 16 162,048 SO2 Install Reheat Safety Valve 17 157,852 SM Administration Roof Replacement 18 157,852 SM Electric Building Roof Replacement 19 157,850 MC Install Piping from Plant to River for Discharge from Injection Well 20 154,496 MK Water Wagon Conversion 21 149,898 MK6 Install Heavy Duty Bowl Mill Bottom 22 148,653 OU Spirit - Generation Lead Construction 23 145,725 SO Modify River Pump Forebay 24 141,038 SO 9 Ton Mobile Crane Replacement 25 135,596 MK6 Crusher Rotor Assembly Replacement 26 128,106 MK 4-5 Tripper Gallery Drain Piping Replacement 27 125,592 OU Spirit - Substation Construction 28 124,139 SO Main Warehouse Roof Replacement 29 115,636 SO 20,000 Pound Forklift Replacement 30 111,621 MK5 Replace Hydro-Bin Gate and Actuators 31 6,667,014 Add Distribution Line capacity and Construct Liberty Lake Substation 32 3,315,851 Construct Blue Bird Substation 33 2,770,629 Construct Chisholm Creek Substation 34 2,395,511 Replace Underground Cable in various locations 35 1,405,934 Relocate Distribution Lines for I-40 Relocation 36 1,111,130 Fort Smith District Office Construction 37 1,062,400 Purchase (7) Heavy Duty Single Axle Trucks 38 900,624 Construct new Service Center in Metro Campus 39 814,014 Purchase (7) 45' Digger Derrick Trucks 40 789,246 Install underground Distribution Lines for downtown OKC apartment complex 41 787,350 Replace Breakers at Dewey Substation 42

FERC FORM NO. 1 (ED. 12-87) Page 216

43 TOTAL 169,154,630Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description of Project Construction work in progress - (b) (a) 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.

718,706 Replace Poles and Transformers to convert from Single Phase to Three Phase Lines 1 631,506 Construct Barnes Substation 2 626,518 Reconductor Spring Hill to Lexington Distribution Line 3 613,460 Construct New Dominion Substation 4 553,575 Replace Breakers at Maud Tap 5 520,330 Relocate Distribution Lines for Hwy 70 Relocation 6 519,466 Purchase two 95' rear mounted Material Handler Baskets 7 490,874 Install Distribution Lines for housing project at Tinker Air Force Base 8 483,063 Install 4,000 feet of Underground Copper Conductor 9 463,827 Replace 9,500 square foot roof at Metro Service Center 10 1,490,426 Replace Transformer for Mobile 7 Substation 11 418,130 Remodel System Resources Office 12 415,664 Install Underground Distribution Lines & Backup Feeder for medical facility in OKC 13 402,532 Convert system north of Mountainburg to 34.5 kV Distribution Lines 14 397,989 Install Distribution Lines and Transformers for apartment complex 15 393,944 Relocate Underground Distribution Lines for medical facility in Muskogee 16 389,094 Install 34.5 to 12.5 kV Step-down Transformer and overhead distribution phases 17 357,647 Convert 6 miles of Distribution Line also install Transformer & Primary Meter 18 356,858 Replace various Oil Circuit Reclosers with Vacuum Reclosures 19 354,200 Relocate Distribution Lines for 36th & Main in Norman 20 350,337 Upgrade downtown OKC underground Distribution Lines 21 342,120 Reconductor 2 miles of Distribution Line Logan County 22 337,601 Replace Roof at Sapulpa Service Center 23 318,488 Install Distribution services for retail development in Ardmore 24 309,188 Install Drainage System at Metro Service Center 25 265,840 Install Underground Distribution lines for residential development in OKC 26 259,553 Rebuild Meeker 4kV Conversion 27 254,714 Relocate Distribution Lines at I-235 & I-44 in OKC 28 248,541 Relocate Distribution Lines between NW150th & NW164th 29 247,830 Add Transmission Lines for Carl Albert Health Facility 30 246,022 Relocate Underground Distribution Lines at I-40 and Gaylord in OKC 31 232,771 Install Distribution Lines for Fountain Lake apartment complex 32 228,584 Install Transformer for Oklahoma Heart Hospital 33 223,353 Reconductor, add poles and conductor to serve new pumping station 34 219,206 Purchase 80' Digger Derrick Truck 35 214,485 Install Underground Distribution lines for commercial development in OKC 36 207,426 Convert 1.5 miles of 12.5kV Distribution Line for housing addition 37 207,226 Install Distribution Lines to serve Spiro Coal Mine 38 201,753 Rewind Transformer at Crossroads Substation 39 187,059 Install Cottage Apartment Lights on Poles 40 184,646 Install Distribution services for Heritage Crossing business complex 41 183,741 Purchase Software: Distribution Asset Analysis on Demand 42

FERC FORM NO. 1 (ED. 12-87) Page 216.1

43 TOTAL 169,154,630Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description of Project Construction work in progress - (b) (a) 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.

180,465 Distribution Underbuild Earlywine to Penn 1 175,504 Install Underground Cable/Transformer Pads/Cubicle Bases for customer 2 174,920 Install Underground Utilities to serve 60 unit retirement village 3 165,447 Purchase 80' Digger Derrick Truck 4 151,519 Install Underground Distribution system for Valenica II Housing Addition 5 150,443 Expand Relay Tech Room at Metro 6 146,954 Install Transformers, Pedestals, and Underground Lines for 81 residential lots 7 143,032 Install additional Underground Distribution facilities at SE 149th & Sooner 8 142,487 Install 2.5 miles Distribution Lines/Poles/Step-Down Transformer for customer 9 135,002 Install Pedestals, Transformers and Underground Lines for 33 new residential lots 10 132,370 Extend 2 miles of Overhead Distribution Line for ONEOK plant 11 130,362 Add Transformer, Reconductor for Madill Industrial 12 128,998 Purchase land for 84th Street Substation 13 121,726 Replace Breaker at Roman Nose Substation 14 117,192 Install Distribution Facilities to serve 63 residential lots 15 112,322 Install Underground Distribution System for Gateway Industrial Park 16 108,762 Install Underground Distribution Facilities to serve 23 residential lots 17 107,474 Install Underground Distribution Facilities to serve 54 residential lots 18 105,823 Relocate Distribution Lines for widening of Rodgers Ave 19 105,091 Purchase Heavy Duty Tandem Axle Trailer 20 167,981 Purchase PROMOD IV, PowerBase and MarketVision Software 21 188,288 OMS/CADS Software Upgrade 22 18,433,180 Construct 120 miles of 345kV Transmission Line, Northwest to Woodward 23 5,931,308 Purchase two Transformers for EEI STEP Program 24 4,857,870 Construct 138kV Transmission Line from McClain Substation to SW149th & Portland 25 4,559,457 Purchase High Side Integrated Transmission Facilities for Spring Creek Substation 26 2,827,779 Construct 10 miles of Transmission Line including crossing over Arkansas River 27 1,940,565 Construct 5 miles of 138 kV Transmission Line to serve Blue Bird Substation 28 993,089 Construct Liberty Lake Substation 29 922,923 Purchase Right of Way for Transmission Line from Garber to Chitwood 30 875,555 Reconductor 1.91 miles of 138 kV Transmission Line, Stillwater to McElroy 31 871,974 Loop the Cottonwood 138kV Line to new Liberty Lake Substation 32 743,448 Replace H Frames, Poles, and Crossarms for Woodring - Morrison Tap 33 700,868 Construct Woodward Substation 34 652,303 Relocate 3/4 mile of 69kV Transmission Lines, Ahloso - Hardin City 35 633,751 Replace Relays at Conoco North Substation 36 589,981 Purchase 11 miles of Right of Way, Warwick to Bell Cow 37 564,856 Purchase 5.5 miles of Right of Way, Bell Cow to Horseshow Lake - Bristow 38 542,062 Construct new 161kV Transmission Line, Simmons - Mountainburg II 39 492,821 Rebuild the 138 kV Transmission Line from Springhill Tap - Rosedale 40 491,403 Reconductor 2.69 miles of 138 kV Transmission Line, Beeline - AEP Riverside 41 455,980 Replace Breakers at Van Buren Substation 42

FERC FORM NO. 1 (ED. 12-87) Page 216.2

43 TOTAL 169,154,630Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description of Project Construction work in progress - (b) (a) 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.

444,898 Purchase Tatonga Substation Site 1 427,557 Install Breakers at Various Substations 2 409,950 Relocate 138kV Transmission Line over new I-40 Cross-town 3 404,037 Replace 138 kV Poles from Chikaskia - Deer Creek 4 329,639 Replace Protective Relays at Ft. Smith Substation 5 327,392 Relocate Line Terminal at McClain Substation 6 313,232 Construct New Dominion Substation 7 303,527 Replace Poles, Crossarms on Transmission Line: Muskogee - Ft. Smith 8 289,376 Purchase Right of Way for McClain to Earlywine Transmission Line 9 288,593 Install Terminal and Breaker at Chitwood Substation 10 271,469 Replace Relay at Muskogee Substation 11 262,208 Relocate 1/2 mile of Transmission Line at SW 5th & Classen 12 254,749 Purchase Right of Way for Earlywine to Pennsylvania 13 254,505 Replace Relays at White Eagle Substation 14 251,649 Install on-line Substation Monitoring and Diagnostics system 15 245,338 Distribution Underbuild Earlywine to Penn 16 241,803 Replace Battery/Charger/Relay at Cimarron Substation 17 239,729 Replace Relays at Park Lane Substation 18 233,903 Install line Terminals and Breakers for the Division Ave Substation 19 228,834 Install Transmission Breakers in the Hollywood Substation 20 221,794 Replace Relays in the S. 4th Street Substation 21 219,004 Purchase 4 miles of Right of Way for Earlywine to SW134th & Western 22 184,191 Transmission Plant Critical Spares 23 167,166 Replace Poles and Crossarms on the Sulphur - Pauls Valley Transmission Line 24 163,874 Install New Line Terminal and Breaker at Arcadia Substation 25 163,761 Construct 138kV Transmission Line from McClain Substation to SW134th & Penn Tap 26 161,272 Install Double Circuit with Division - Piedmont 138kV 27 160,378 Replace Structure Frames with Distribution under build for 69kV Transmission line 28 157,766 Construct Sooner - Rose Hill 345kV Transmission Line 29 147,979 Construct new Line Terminal at Woodward Substation 30 145,760 Replace Breakers in various Substations 31 145,089 Install new Line Terminal rack on Hollywood Transmission Line 32 137,818 Replace Relays at various Substation locations 33 101,075 Replace Relays at Memorial Substation 34 35 3,179,003 Approximately 110 projects covering additions & betterments to Generating Stations 36 37 10,851,637 Approximately 580 projects covering additions, betterments & miscellaneous 38 rebuilds to distribution lines and substations 39 40 444,783 Approximately 7 projects covering additions & betterments to General Plant items 41 42

FERC FORM NO. 1 (ED. 12-87) Page 216.3

43 TOTAL 169,154,630Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description of Project Construction work in progress - (b) (a) 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.

3,418,379 Approximately 307 projects covering additions, betterments & miscellaneous 1 rebuilds to transmission lines & substations 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42

FERC FORM NO. 1 (ED. 12-87) Page 216.4

43 TOTAL 169,154,630Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item Total (c) (b) (a) (d) Section A. Balances and Changes During Year (c+d+e) Electric Plant in Service Electric Plant Held for Future Use Electric Plant Leased to Others (e) 

### 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 electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property. 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. If the 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 preliminary closing entries to tentatively functionalize the book cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional classifications. 4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.

Balance Beginning of Year 1 2,460,639,640 2,460,639,640 Depreciation Provisions for Year, Charged to 2(403) Depreciation Expense 3 145,532,587 145,532,587 (403.1) Depreciation Expense for Asset Retirement Costs 4 45,247 45,247

(413) Exp. of Elec. Plt. Leas. to Others 5Transportation Expenses-Clearing 6Other Clearing Accounts 7Other Accounts (Specify, details in footnote): 8 55,398,283 55,398,283 Transportation Expense Capitalized 9 4,864,784 4,864,784 TOTAL Deprec. Prov for Year (Enter Total of lines 3 thru 9) 10 205,840,901 205,840,901

Net Charges for Plant Retired: 11 Book Cost of Plant Retired 12 31,891,207 31,891,207 Cost of Removal 13 31,447,440 31,447,440 Salvage (Credit) 14 10,038,665 10,038,665 TOTAL Net Chrgs. for Plant Ret. (Enter Total of lines 12 thru 14) 15 53,299,982 53,299,982

Other Debit or Cr. Items (Describe, details in footnote): 16 8,126 -8,126

17Book Cost or Asset Retirement Costs Retired 18Balance End of Year (Enter Totals of lines 1, 10, 15, 16, and 18) 19 8,126 2,613,180,559 2,613,172,433

Steam Production 20 Section B. Balances at End of Year According to Functional Classification 1,134,151,454 1,134,151,454 Nuclear Production 21 Hydraulic Production-Conventional 22Hydraulic Production-Pumped Storage 23Other Production 24 251,867,936 251,867,936 Transmission 25 314,201,751 314,201,751 Distribution 26 835,245,654 835,245,654 Regional Transmission and Market Operation 27General 28 77,713,764 77,713,764 TOTAL (Enter Total of lines 20 thru 28) 29 2,613,180,559 2,613,180,559

Page 219 FERC FORM NO. 1 (REV. 12-05)

### Schedule Page: 219 Line No.: 8 Column: c

Record Redbud Plant Acquisition Accumulated Depreciation 58,872,102 McClain Plant Regulatory Asset Depreciation Expense (2,358,085) Reclassification of Tangible Assets to Intangible (566,334) Asset Retirement Obligation Accretion Expense (298,247) Transfer to Non-Utility Property (264,956) Amortization of Capital Lease 42,051 Transfer Utility Assets to Holding Company (32,222) Reduction to ARO Liability for ARO Asset Retired 4,865 Miscellaneous Adjustments (891)

TOTAL 55,398,283 Schedule Page: 219 Line: 16 Column: c Transfer of Accumulated Depreciation to Future Use from Plant in Service 8,126 Schedule Page: 219 Line: 12 Column: c Difference Between Plant in Service and Accumulated depreciation Retirements
Plant in Service 31,892,251 Accumulated Depreciation 31,891,207 Difference (Loss on Retirement of ARO) 1,044 Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description of Investment Date Acquired (c) (b) (a) Amount of Investment at Beginning of Year Date Of Maturity (d) 1. Report below investments in Accounts 123.1, investments in Subsidiary Companies. 2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in columns (e),(f),(g) and (h) (a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate. (b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity date, and specifying whether note is a renewal. 3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for Account 418.1.

The Arklahoma Corporation 1 17,000 12/03/47 24 Shares of Common Stock 2 3 57 4.8% of Equity Earnings 4 5 17,057 Subtotal 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41

FERC FORM NO. 1 (ED. 12-89) Page224

42 Total Cost of Account 123.1 $ TOTAL 17,057 16,718Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Equity in Subsidiary

Earnings of Year Revenues for Year Amount of Investment at End of Year Gain or Loss from Investment Disposed of (e) (f) (g) (h) 4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee and purpose of the pledge. 5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission, date of authorization, and case or docket number. 6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year. 7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible in column (f). 8. Report on Line 42, column (a) the TOTAL cost of Account 123.1

1 17,000 2 3 -282 -339 4 5 16,718 -339 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41

FERC FORM NO. 1 (ED. 12-89) Page 225 42 -339 16,718Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of
MATERIALS AND SUPPLIES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account Balance Balance

(c) (b) (a) Department or Departments which (d) Beginning of Year End of Year Use Material 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.

44,342,665 56,640,508

1 Fuel Stock (Account 151) 2 Fuel Stock Expenses Undistributed (Account 152) 3 Residuals and Extracted Products (Account 153) 4 Plant Materials and Operating Supplies (Account 154) 44,827,517 T&D/Power Prod. 44,450,285 5 Assigned to - Construction (Estimated) 6 Assigned to - Operations and Maintenance 13,105,718 Power Production 20,946,297 7 Production Plant (Estimated) 242,629 T&D 232,238 8 Transmission Plant (Estimated) 1,698,407 T&D 1,765,006 9 Distribution Plant (Estimated) 10 Regional Transmission and Market Operation Plant (Estimated) 11 Assigned to - Other (provide details in footnote) 59,874,271 67,393,826 12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 13 Merchandise (Account 155) 14 Other Materials and Supplies (Account 156) 15 Nuclear Materials Held for Sale (Account 157) (Not applic to Gas Util) 16 Stores Expense Undistributed (Account 163) 17 18 19 104,216,936 124,034,334 20 TOTAL Materials and Supplies (Per Balance Sheet)

Page227 FERC FORM NO. 1 (REV. 12-05)

### Schedule Page: 227 Line No.: 5 Column: c The estimated breakdown of the construction amount of $44,450,285 by functional classification is as follows: Production $ Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Allowances (Accounts 158.1 and 158.2) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Allowances Inventory Current Year (b) (a) (Account 158.1) No. Amt. (c) No. (d) Amt. (e) 

### 1. Report below the particulars (details) called for concerning allowances. 2. Report all acquisitions of allowances at cost. 3. Report allowances in accordance with a weighted average cost allocation method and other accounting as prescribed by General Instruction No. 21 in the Uniform System of Accounts. 4. Report the allowances transactions by the period they are first eligible for use: the current year’s allowances in columns (b)-(c), allowances for the three succeeding years in columns (d)-(i), starting with the following year, and allowances for the remaining succeeding years in columns (j)-(k). 5. Report on line 4 the Environmental Protection Agency (EPA) issued allowances. Report withheld portions Lines 36-40. 2009

Balance-Beginning of Year 1 2 Acquired During Year: 3 Issued (Less Withheld Allow) 4 Returned by EPA 5 6 7 Purchases/Transfers: 8 9 10 11 12 13 14 Total 15 16 Relinquished During Year: 17 Charges to Account 509 18 Other: 19 20 Cost of Sales/Transfers: 21 22 23 24 25 26 27 Total 28 Balance-End of Year 29 30 Sales: 31 Net Sales Proceeds(Assoc. Co.) 32 Net Sales Proceeds (Other) 33 Gains 34 Losses 35 Allowances Withheld (Acct 158.2) Balance-Beginning of Year 36 Add: Withheld by EPA 37 Deduct: Returned by EPA 38 Cost of Sales 39 Balance-End of Year 40 41 Sales: 42 Net Sales Proceeds (Assoc. Co.) 43 Net Sales Proceeds (Other) 44 Gains 45 Losses 46

FERC FORM NO. 1 (ED. 12-95) Page228Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Allowances (Accounts 158.1 and 158.2) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (f) (j) No. Amt. (g) No. (h) Amt. (i) No. Amt. No. Amt. (k) (l) (m) Future Years Totals (Continued) 

### 6. Report on Lines 5 allowances returned by the EPA. Report on Line 39 the EPA’s sales of the withheld allowances. Report on Lines 43-46 the net sales proceeds and gains/losses resulting from the EPA’s sale or auction of the withheld allowances. 7. Report on Lines 8-14 the names of vendors/transferors of allowances acquire and identify associated companies (See "associated company" under "Definitions" in the Uniform System of Accounts). 8. Report on Lines 22 - 27 the name of purchasers/ transferees of allowances disposed of an identify associated companies. 9. Report the net costs and benefits of hedging transactions on a separate line under purchases/transfers and sales/transfers. 10. Report on Lines 32-35 and 43-46 the net sales proceeds and gains or losses from allowance sales.

2010 2011

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35

36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-95) Page229Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of EXTRAORDINARY PROPERTY LOSSES (Account 182.1) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (c) (b) (a) (d) Description of Extraordinary Loss [Include in the description the date of Commission Authorization to use Acc 182.1 and period of amortization (mo, yr to mo, yr).] Total Amount of Loss Losses Recognised During Year WRITTEN OFF DURING YEAR Account Charged Amount Balance at End of Year (f) (e) 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

FERC FORM NO. 1 (ED. 12-88) Page 230a 20 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of UNRECOVERED PLANT AND REGULATORY STUDY COSTS (182.2) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No.

(c) (b) (a) (d) Description of Unrecovered Plant Total Amount of Charges Costs Recognised During Year WRITTEN OFF DURING YEAR Account Charged Amount Balance at End of Year
(f) (e) and Regulatory Study Costs [Include in the description of costs, the date of Commission Authorization to use Acc 182.2 and period of amortization (mo, yr to mo, yr)]

21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48

FERC FORM NO. 1 (ED. 12-88) Page 230b

49 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Transmission Service and Generation Interconnection Study Costs Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description Costs Incurred During (b) (a) Period Account Charged (c) Reimbursements Received During (d) Account Credited With Reimbursement (e) 1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and generator interconnection studies. 2. List each study separately. 3. In column (a) provide the name of the study. 4. In column (b) report the cost incurred to perform the study at the end of period. 5. In column (c) report the account charged with the cost of the study. 6. In column (d) report the amounts received for reimbursement of the study costs at end of period. 7. In column (e) report the account credited with the reimbursement received for performing the study.

the Period

Transmission Studies 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 Generation Studies 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

FERC FORM NO. 1/1-F/3-Q (NEW. 03-07) Page231Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of OTHER REGULATORY ASSETS (Account 182.3) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description and Purpose of Debits CREDITS Written off During the Quarter/Year Account Charged (d) (c) (a) Balance at end of Current Quarter/Year

(e) Other Regulatory Assets Written off During the Period Amount (f) 

### 1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $50,000 which ever is less), may be grouped by classes. 3. For Regulatory Assets being amortized, show period of amortization.

Balance at Beginning of

Current Quarter/Year (b)

613,284 632,546 1,257,445 928 1,276,707 Oklahoma Corporation Commission 1 Assessment Fee 2 (Expensed during Commissions fiscal year) 3 4 55,261,360 51,329,674 4,339,158 190, 283, 407,472 Deferred Tax Asset - SFAS 109 5 282,426.5 (22 year amortization period) 6 7 4,716,171 2,358,086 2,358,085 403 McClain Plant Costs - PUD 200100455 8 627,208 313,604 313,604 408.1 ( 4 year recovery period ) 9 4,983,133 2,491,567 2,491,566 427 10 1,826,734 913,367 913,367 546-554 11 98,383 49,191 49,192 927, 930.2 12 185,069 92,534 92,535 926 13 14 174,572,632 344,702,546 39,624,593 926 209,754,507 SFAS 158 15 16 24,760,567 14,623,595 10,205,673 926 68,701 Deferred Pension Expense - PUD 200500151 17 18 35,853,591 31,589,584 6,153,034 592, 593 1,889,027 Storm Expense-PUD 200500151 19 20 46,067 51,289 5,222 Red Rock-Corp. Comm. Staff Expert-PUD 200700012 21 22 254,387 253,225 ( 1,162) Red Rock-Attorney General Expert Exp-PUD 200700012 23 24 7,134,623 7,678,476 426.5 14,813,099 Red Rock - PUD 200800215 25 26 577,861 577,861 Arkansas Storm Expenses 27 28 62,407 62,407 Redbud - Staff Expert 29 30 141,736 141,736 Wind RFP - OCC Independent Evaluator 31 32 33 34 35 36 37 38 39 40 41 42 43

FERC FORM NO. 1/3-Q (REV. 02-04) Page 232

44 TOTAL 303,798,586 75,476,728 457,317,435 228,995,577Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of MISCELLANEOUS DEFFERED DEBITS (Account 186) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description of Miscellaneous Debits CREDITS Account (c) (b) (a) Balance at End of Year (d) Deferred Debits Amount (e) Balance at Beginning of Year (f) Charged 

### 1. Report below the particulars (details) called for concerning miscellaneous deferred debits. 2. For any deferred debit being amortized, show period of amortization in column (a) 3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $50,000, whichever is less) may be grouped by classes.

320,000 20,000 300,000 146 Costs associated with SFAS 106 1 2 36,214 36,214 Arklahoma Reimbursable Expenses 3 4 14,430,007 14,430,007 182.3 Red Rock - Post abandonment 5 6 45,777 45,777 181 Costs assoc. with debt offering 7 8 109,498 109,498 Power Supply Control Study 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-94) Page 233 49 TOTAL 47 Misc. Work in Progress
48 Deferred Regulatory Comm. Expenses (See pages 350 - 351) 14,795,784 165,712Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INCOME TAXES (Account 190) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description and Location Balance of Begining (c) (b) (a) Balance at End of Year of Year 

### 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes. 2. At Other (Specify), include deferrals relating to other income and deductions.

Electric 1 4,270,719 3,918,073 Accrued Vacation 2 1,095,142 1,425,958 Bad Debts 3 20,911,405 4,494,599 Oklahoma Tax Credit Carryover 4 14,552,076 12,643,250 Medicare Part D Subsidy 5 23,510,542 20,369,093 Post-Retirement Benefits 6 18,696,117 17,716,957 Other (See note below) 7 83,036,001 60,567,930 TOTAL Electric (Enter Total of lines 2 thru 7) 8 Gas 9 10 11 12 13 14 Other 15 TOTAL Gas (Enter Total of lines 10 thru 15 16 Other (Specify) 17 83,036,001 60,567,930 TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18 Notes "Other" on line 7 above includes the following:

Regulatory Liabilities 449,891 6,401 Accrued Interest 1,136,032 1,284,510 Accrued Liabilities-Employee-Related 496,689 427,918 Deferred Federal Investment Tax Credits 8,523,427 6,717,190 Income Taxes Refundable/Recoverable 5,716,651 5,640,519 in Future Rates Other 1,394,267 4,619,579

------------ ------------
Total Other 17,716,957 18,696,117

============ ============

FERC FORM NO. 1 (ED. 12-88) Page234Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CAPITAL STOCKS (Account 201 and 204) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Class and Series of Stock and Number of shares

(c) (b) (a) Call Price at End of Year Par or Stated Value per share (d) Name of Stock Series Authorized by Charter 

### 1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible. 2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.

1 2.50 100,000,000 Common Stock 2 3 100,000,000 Total Common Stock 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42

FERC FORM NO. 1 (ED. 12-91) Page 250AS REACQUIRED STOCK (Account 217) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CAPITAL STOCKS (Account 201 and 204) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT IN SINKING AND OTHER FUNDS Shares

(g) Cost (h) Shares Shares Amount (Total amount outstanding without reduction for amounts held by respondent) Amount

(e) (f) (i) (j) 

### 3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission which have not yet been issued. 4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or non-cumulative. 5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year. Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which is pledged, stating name of pledgee and purposes of pledge.

1 100,946,863 40,378,745 2 3 100,946,863 40,378,745 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42

FERC FORM NO. 1 (ED. 12-88) Page 251

### Schedule Page: 250 Line No.: 2 Column: a The estimated breakdown of the construction amount of $44,827,517 by functional classification is as follows: Production $ 1,318,999 Transmission 7,123,532 Distribution 36,384,986 Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line Item Amount (b) (a) OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)

No. Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such change. (a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation. (b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to amounts reported under this caption including identification with the class and series of stock to which related. (c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related. (d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations, disclose the general nature of the transactions which gave rise to the reported amounts.

1 Account 208 - Donations Received from Stockholders 2 3 153,000,000 Balance January 1, 2008 4 5 293,000,000 Contribution Received from Parent Company 6 ( Purpose was for purchase of Redbud Plant ) 7 8 9 10 Balance December 31, 2008 446,000,000 11 12 13 14 Account 210 - Gain on Resale or Cancellation of Reacquired 15 Capital Stock 16 17 Balance January 1, 2008 1,997,342 18 19 20 21 22 1,997,342 Balance December 31, 2008 23 24 447,997,342 SUBTOTAL Balance December 31, 2008 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39

FERC FORM NO. 1 (ED. 12-87) Page 253 40 TOTAL 447,997,342Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of CAPITAL STOCK EXPENSE (Account 214) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Class and Series of Stock Balance at End of Year (b) (a) 

### 1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock. 2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars (details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

FERC FORM NO. 1 (ED. 12-87) Page 254b

22 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of LONG-TERM DEBT (Account 221, 222, 223 and 224) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Class and Series of Obligation, Coupon Rate (c) (b) (a) Total expense, Premium or Discount Principal Amount Of Debt issued (For new issue, give commission Authorization numbers and dates) 

### 1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222, Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt. 2. In column (a), for new issues, give Commission authorization numbers and dates. 3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds. 4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate demand notes as such. Include in column (a) names of associated companies from which advances were received. 5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were issued. 6. In column (b) show the principal amount of bonds or other long-term debt originally issued. 7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued. 8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount. Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted. 9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as specified by the Uniform System of Accounts.

Account 224 - Other Long Term Debt 1 2 918,434 110,000,000 Senior Notes Series Due 2016 - 5.15% 3 358,600 Senior Notes Series Due 2016 - 5.15% 4 D 1,174,985 125,000,000 Senior Notes Series Due 2017 - 6.50% 5 116,250 Senior Notes Series Due 2017 - 6.50% 6 D 1,895,080 250,000,000 Senior Notes Series Due 2018 - 6.35% 7 887,500 Senior Notes Series Due 2018 - 6.35% 8 D 1,694,608 250,000,000 Senior Notes Series Due 2019 - 8.25% 9 45,000 Senior Notes Series Due 2019 - 8.25% 10 D 1,221,235 125,000,000 Senior Notes Series Due 2027 - 6.65% 11 1,058,756 100,000,000 Senior Notes Series Due 2028 - 6.50% 12 1,569,000 Senior Notes Series Due 2028 - 6.50% 13 D 1,433,833 140,000,000 Senior Notes Series Due 2034 - 6.50% 14 180,600 Senior Notes Series Due 2034 - 6.50% 15 D 1,160,184 110,000,000 Senior Notes Series Due 2036 - 5.75% 16 453,200 Senior Notes Series Due 2036 - 5.75% 17 D 2,041,573 200,000,000 Senior Notes Series Due 2038 - 6.45% 18 1,078,000 Senior Notes Series Due 2038 - 6.45% 19 D 20 Account 221 - Bonds 21 22 303,286 47,000,000 Pollution Control Series A, due 2025 Garfield County - variable 23 267,768 32,400,000 Pollution Control Series A, due 2025 Muskogee Ind. - variable 24 272,062 56,000,000 Pollution Control Series A, due 2027 Muskogee Ind. - variable 25 26 27 28 29 30 31 32

FERC FORM NO. 1 (ED. 12-96) Page 256

33 TOTAL 1,545,400,000 18,129,954Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Nominal Date

of Issue Date of Maturity AMORTIZATION PERIOD Date From Date To Outstanding (Total amount outstanding without

reduction for amounts held by respondent) Interest for Year Amount (d) (e) (f) (g) (h) (i) 

### 10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years. 11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium on Debt - Credit. 12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid during year. Give Commission authorization numbers and dates. 13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee and purpose of the pledge. 14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year, describe such securities in a footnote. 15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on Long-Term Debt and Account 430, Interest on Debt to Associated Companies. 16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.

1 2 110,000,000 5,665,000 01/15/2016 01/15/2006 01/15/2016 01/15/2006 3 01/15/2016 01/15/2006 4 125,000,000 8,125,000 07/15/2017 07/15/1997 07/15/2017 07/15/1997 5 07/15/2017 07/15/1997 6 250,000,000 4,938,889 09/01/2018 09/01/2008 09/01/2018 09/01/2008 7 09/01/2018 09/01/2008 8 250,000,000 1,203,125 01/15/2019 01/15/2009 01/15/2019 01/15/2009 9 01/15/2019 01/15/2009 10 124,950,000 8,307,651 07/15/2027 07/15/1997 07/15/2027 07/15/1997 11 100,000,000 6,500,000 04/15/2028 04/15/1998 04/15/2028 04/15/1998 12 04/15/2028 04/15/1998 13 140,000,000 9,100,000 08/01/2034 08/01/2004 08/01/2034 08/01/2004 14 08/01/2034 08/01/2004 15 110,000,000 6,325,000 01/15/2036 01/15/2006 01/15/2036 01/15/2006 16 01/15/2036 01/15/2006 17 200,000,000 11,860,833 02/01/2038 02/01/2008 2/01/2038 02/01/2008 18 02/01/2038 02/01/2008 19 20 21 22 47,000,000 1,136,603 01/01/2025 01/01/1995 01/01/2025 01/01/1995 23 32,400,000 766,553 01/01/2025 01/01/1995 01/01/2025 01/01/1995 24 55,900,000 1,361,782 06/01/2027 06/01/1997 06/01/2027 06/01/1997 25 26 27 28 29 30 31 32

FERC FORM NO. 1 (ED. 12-96) Page 257 33 1,545,250,000 65,290,436

### Schedule Page: 256 Line No.: 11 Column: h OG&E's $125 million principle amount 6.65 percent Senior Notes due July 15, 2027, were repayable on July 15, 2007, at the option of the holders, at 100 percent of the principle amount, together with accrued and unpaid interest to July 15, 2007. Only holders who submitted requests for repayment between May 15, 2007 and June 15, 2007 were entitled to such repayments. In June 2007, OG&E received a request for repayment of $50,000 of the Senior Notes. This amount was subsequently paid on July 15, 2007. Schedule Page: 256 Line No.: 25 Column: h In September 2008, the Company received a request for repayment of approximately $0.1 million. In September 2008, approximately $0.1 million of principal and accrued interest were paid to the bondholder. The $0.1 million of variable-rate industrial authority bonds is being remarketed by the remarketing agent. Schedule Page: 256 Line No.: 32 Column: i The difference between the total of column (i) and the total of Account 427 is $2,491,566 of interest that is being amortized out of a regulatory asset. The interest in Account 430 is classified as short-term. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES Oklahoma Gas and Electric Company X / / 2008/Q4

Particulars (Details) (b) (a) Amount Line No. 1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount. 2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members. 3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.

143,006,547 Net Income for the Year (Page 117) 1 2 3Taxable Income Not Reported on Books 4 2,268,872 Contributions in Aid of Construction 5 4,108,305 Salvage 6 7 8Deductions Recorded on Books Not Deducted for Return 9 -31,129,736 Provision for Current Federal Income Taxes 10 91,903,022 Provision for Deferred Income Taxes 11 -4,640,304 Investment Tax Credit, Net 12 30,265,846 Other Items 13Income Recorded on Books Not Included in Return 14 1,338,936 Amortization of Regulatory Liabilities 15 2,619,304 Allowance for Borrowed Funds Used During Construction 16 17 18Deductions on Return Not Charged Against Book Income 19 25,067,000 Pension Plan 20 -385,678 RAR Settlement Interest 21 211,292,219 Excess Tax Over Book Depreciation 22 31,366,831 Removal Expense 23 12,849,226 Repair Allowance 24 -300,000 Provision for Rate Refund 25 10,832,318 Other Items 26 -58,897,604 Federal Tax Net Income 27Show Computation of Tax: 28 -20,614,161 Tax at 35% 29 30 -20,614,161 Total Federal Income Tax 31 -10,515,575 Add Adjustments of Prior Years' Federal Tax 32 -31,129,736 Current Federal Income Tax Per Books 33 34 35 36 37 38 39 40 41 42 43 44

FERC FORM NO. 1 (ED. 12-96) Page 261Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Kind of Tax (See instruction 5) BALANCE AT BEGINNING OF YEAR Taxes Accrued (Account 236) Prepaid Taxes (Include in Account 165) Taxes Charged

During Year Taxes Paid During Adjustments Year (a) (b) (c) (d) (e) (f) 1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts. 2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.) Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes. 3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued, (b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than accrued and prepaid tax accounts. 4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.

-31,129,736 -31,129,736 Federal Income 1 11,351,731 11,351,614 Insurance Contribution 2 128,088 129,077 2,720 Unemployment 3 4 -19,649,917 -19,649,045 2,720 Total Federal 5 6 7 -3,756,605 -3,756,605 Oklahoma Income 8 31,017 30,944 1,050 Unemployment 9 20,000 20,000 Corporate License 10 160,039 160,039 Motor Vehicle Registration 11 61,470 61,491 5,118 Sales Tax 12 Use Tax 13 14 -3,484,079 -3,484,131 6,168 Total Oklahoma 15 16 17 -65,731 26,666 -248,903 Arkansas Income 18 6,647 6,635 47 Unemployment 19 15,083 15,083 Franchise 20 7,752 7,752 Sales Use and Excise Tax 21 -36,249 56,136 -248,856 Total Arkansas 22 23 24 Oklahoma - Local 25 49,370,106 52,192,549 23,199,492 Ad Valorem - Property 26 27 49,370,106 52,192,549 23,199,492 Total - Oklahoma Local 28 29 30Arkansas - Local 31 1,929,647 2,037,342 1,921,687 Ad Valorem - Property 32 33 1,929,647 2,037,342 1,921,687 Total - Arkansas - Local 34 35 36 37 38 39 40

FERC FORM NO. 1 (ED. 12-96) Page 262 TOTAL 41 31,152,851 28,129,508 24,881,211Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (Taxes accrued BALANCE AT END OF YEAR Prepaid Taxes Electric (Account 408.1, 409.1) Extraordinary Items (Account 409.3) Adjustments to Ret. Other Earnings (Account 439) (g) (h) (i) (j) (k) (l) Account 236) (Incl. in Account 165) DISTRIBUTION OF TAXES CHARGED 5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying the year in column (a). 6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments by parentheses. 7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending transmittal of such taxes to the taxing authority. 8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1 pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts. 9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.

-1,231,498 -29,898,238 1 3,116,271 8,387,692 -117 2 35,177 94,563 3,709 3 4 1,919,950 -21,415,983 3,592 5 6 7 68,569 -3,825,174 8 7,882 23,154 977 9 20,000 10 160,039 11 61,489 5,139 12 13 14 236,490 -3,720,531 6,116 15 16 17 26,666 -156,506 18 1,677 4,958 35 19 15,083 20 7,752 21 1,677 54,459 -156,471 22 23 24 25 49,299,984 26,021,935 26 27 49,299,984 26,021,935 28 29 30 31 2,037,342 2,029,382 32 33 2,037,342 2,029,382 34 35 36 37 38 39 40

FERC FORM NO. 1 (ED. 12-96) Page 263 41 26,255,271 2,158,117 27,904,554Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account Balance at Beginning (c) (b) (a) of Year Subdivisions Adjustments Deferred for Year Allocations to Current Year's Income Account No. Amount Account No. Amount (d) (e) (f) (g) 

### Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i) the average period over which the tax credits are amortized.

Electric Utility 13% 24% 37% 410% 21,970,123 411.4 4,640,304 5 6 7TOTAL 21,970,123 4,640,304 8Other (List separately and show 3%, 4%, 7%, 10% and TOTAL) 9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48

FERC FORM NO. 1 (ED. 12-89) Page 266Balance at End (i) (h) of Year Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. ADJUSTMENT EXPLANATION Average Period

of Allocation

to Income

1 2 3 4 17,329,819 30.9 Years 5 6 7 17,329,819 8 9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48

FERC FORM NO. 1 (ED. 12-89) Page 267Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of OTHER DEFFERED CREDITS (Account 253) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description and Other DEBITS Credits Account (c) (b) (a) Balance at End of Year (d) Deferred Credits Amount (e) Balance at Beginning of Year Contra (f) 1. Report below the particulars (details) called for concerning other deferred credits. 2. For any deferred credit being amortized, show the period of amortization. 3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $10,000, whichever is greater) may be grouped by classes.

1 4,477,434 GE Long Term Service Agreement 10,810,346 7,507,778 1,174,866 131 2 3 8,689,769 Kaw Water Storage Agreement 9,174,328 749,708 265,149 131 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (ED. 12-94) Page 269 47 TOTAL 8,257,486 1,440,015 19,984,674 13,167,203Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INCOME TAXES - ACCELERATED AMORTIZATION PROPERTY (Account 281) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account

(a) (b) (c) (d) Balance at Beginning of Year CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.1 to Account 411.1 

### 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to amortizable property. 2. For other (Specify),include deferrals relating to other income and deductions.

1 Accelerated Amortization (Account 281) 2Electric 3Defense Facilities 4Pollution Control Facilities 5Other (provide details in footnote): 6 7 8TOTAL Electric (Enter Total of lines 3 thru 7) 9Gas 10Defense Facilities 11 Pollution Control Facilities 12Other (provide details in footnote): 13 14 15TOTAL Gas (Enter Total of lines 10 thru 14) 16 17TOTAL (Acct 281) (Total of 8, 15 and 16) 18Classification of TOTAL 19Federal Income Tax 20State Income Tax 21 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page 272 NOTESName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INCOME TAXES _ ACCELERATED AMORTIZATION PROPERTY (Account 281) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. CHANGES DURING YEAR ADJUSTMENTS Balance at End of Year Debits Credits Amounts Debited to Account 410.2 Amounts Credited to Account 411.2 Account Credited Amount Debited Account Amount (e) (f) (h) (j) (k) (g) (i) 

### 3. Use footnotes as required.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21

FERC FORM NO. 1 (ED. 12-96) Page 273 NOTES (Continued)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account

(a) (b) (c) (d) Balance at Beginning of Year CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.1 to Account 411.1 

### 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not subject to accelerated amortization 2. For other (Specify),include deferrals relating to other income and deductions.

Account 282 1 Electric 591,683,261 98,594,423 8,752,451 2Gas 3 4TOTAL (Enter Total of lines 2 thru 4) 591,683,261 98,594,423 8,752,451 5 6 7 8TOTAL Account 282 (Enter Total of lines 5 thru 591,683,261 98,594,423 8,752,451 9Classification of TOTAL 10Federal Income Tax 534,215,793 94,268,078 7,903,217 11 State Income Tax 57,467,468 4,326,345 849,234 12Local Income Tax 13

FERC FORM NO. 1 (ED. 12-96) Page 274 NOTESName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. CHANGES DURING YEAR ADJUSTMENTS Balance at End of Year Debits Credits Amounts Debited to Account 410.2 Amounts Credited to Account 411.2 Account Credited Amount Debited Account Amount (e) (f) (h) (j) (k) (g) (i) 

### 3. Use footnotes as required.

1 182.3 686,981,063 3,474,076190 8,929,906 2 3 4 686,981,063 3,474,076 8,929,906 5 6 7 8 686,981,063 3,474,076 8,929,906 9 10 625,507,114 3,136,993 8,063,453 11 61,473,949 337,083 866,453 12 13

FERC FORM NO. 1 (ED. 12-96) Page 275 NOTES (Continued)

### Schedule Page: 274 Line No.: 2 Column: b The end of year balance includes the following: Total Other Property, net $657,826,688 Income Taxes Recoverable/Refundable, net _29,154,375 Total $686,981,063 Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account (a) (b) (c) (d) Balance at Beginning of Year CHANGES DURING YEAR Amounts Debited Amounts Credited to Account 410.1 to Account 411.1 

### 1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts recorded in Account 283. 2. For other (Specify),include deferrals relating to other income and deductions.

Account 283 1 Electric 2 21,439,131 90,542,049 3 4 5 6 7 8 21,439,131 90,542,049 TOTAL Electric (Total of lines 3 thru 8) 9Gas 10 11 12 13 14 15 16TOTAL Gas (Total of lines 11 thru 16) 17 18 21,439,131 90,542,049 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19Classification of TOTAL 20 19,358,931 81,683,926 Federal Income Tax 21 2,080,200 8,858,123 State Income Tax 22Local Income Tax 23

FERC FORM NO. 1 (ED. 12-96) Page 276NOTESName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. CHANGES DURING YEAR ADJUSTMENTS Balance at End of Year Debits Credits Amounts Debited to Account 410.2 Amounts Credited to Account 411.2 Account Credited Amount Debited Account Amount (e) (f) (h) (j) (k) (g) (i) 

### 3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other. 4. Use footnotes as required.

1 2 106,117,039 26,243 409.1 282 5,890,384 3 4 5 6 7 8 106,117,039 26,243 5,890,384 9 10 11 12 13 14 15 16 17 18 106,117,039 26,243 5,890,384 19 20 95,820,754 26,243 5,248,346 21 10,296,285 642,038 22 23

FERC FORM NO. 1 (ED. 12-96) Page 277 NOTES (Continued)

### Schedule Page: 276 Line No.: 3 Column: b End of the Year balance consists of the following: Prepaid Expenses $2,794,744 Pension Plans 77,607,819 Unamortized Bond Redemption Costs 5,655,239 Regulatory Assets 17,761,510 LIFO Inventory Adjustments2,297,727 Total $106,117,039 Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of OTHER REGULATORY LIABILITIES (Account 254) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description and Purpose of DEBITS Credits Account (d)

(c) (a) Balance at End of Current Quarter/Year (e) Other Regulatory Liabilities Amount (f) Credited 

### 1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable. 2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $50,000 which ever is less), may be grouped by classes. 3. For Regulatory Liabilities being amortized, show period of amortization. Balance at Begining of Current Quarter/Year (b)26,710,090 3,446,726 26,385,184 3,121,820 Deferred Tax Liability 283 1 ( 22 year amortization period ) 2 3 1,355,450 1,338,937 16,513 Deferred Gain on Sale of Assets 421.1 4 ( PUD 200500151 ) 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

FERC FORM NO. 1/3-Q (REV 02-04) Page 278 41 TOTAL 3,121,820 4,785,663 26,401,697 28,065,540Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC OPERATING REVENUES (Account 400) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Title of Account (c) (b) (a) Operating Revenues Year to Date Quarterly/Annual 1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH related to unbilled revenues need not be reported separately as required in the annual version of these pages. 2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total. 3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of each month. 4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.

Operating Revenues Previous year (no Quarterly) Sales of Electricity 1 706,416,931 (440) Residential Sales 751,165,773 2 (442) Commercial and Industrial Sales 3 450,040,859 Small (or Comm.) (See Instr. 4) 478,962,880 4 362,334,506 Large (or Ind.) (See Instr. 4) 371,712,125 5 9,103,632 (444) Public Street and Highway Lighting 8,692,703 6 172,336,362 (445) Other Sales to Public Authorities 181,642,128 7 (446) Sales to Railroads and Railways 8 (448) Interdepartmental Sales 9 1,700,232,290 TOTAL Sales to Ultimate Consumers 1,792,175,609 10 107,242,712 (447) Sales for Resale 135,198,689 11 1,807,475,002 TOTAL Sales of Electricity 1,927,374,298 12 -62,459 (Less) (449.1) Provision for Rate Refunds 403,441 13 1,807,537,461 TOTAL Revenues Net of Prov. for Refunds 1,926,970,857 14 Other Operating Revenues 15 4,636,367 (450) Forfeited Discounts 4,874,726 16 7,864,733 (451) Miscellaneous Service Revenues 8,061,586 17 (453) Sales of Water and Water Power 18 1,146,823 (454) Rent from Electric Property 1,082,673 19 (455) Interdepartmental Rents 20 64,853,142 (456) Other Electric Revenues 76,731,571 21 16,612,531 (456.1) Revenues from Transmission of Electricity of Others 18,492,145 22 (457.1) Regional Control Service Revenues 23 (457.2) Miscellaneous Revenues 24 25 95,113,596 TOTAL Other Operating Revenues 109,242,701 26 1,902,651,057 TOTAL Electric Operating Revenues 2,036,213,558 27

Page 300 FERC FORM NO. 1/3-Q (REV. 12-05)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of ELECTRIC OPERATING REVENUES (Account 400) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. MEGAWATT HOURS SOLD Previous Year (no Quarterly) Current Year (no Quarterly) AVG.NO. CUSTOMERS PER MONTH Year to Date Quarterly/Annual Amount Previous year (no Quarterly) (d) (e) (f) (g) 5. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification in a footnote.) 6. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases. 7. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts. 8. Include unmetered sales. Provide details of such Sales in a footnote.

1 8,667,389 651,482 657,391 8,962,158 2 3 6,317,091 83,537 84,491 6,471,249 4 7,036,938 9,495 9,480 6,966,677 5 66,705 249 250 62,758 6 2,883,076 14,812 15,274 2,943,338 7 8 9 24,971,199 759,575 766,886 25,406,180 10 2,095,094 49 49 2,756,249 11 27,066,293 759,624 766,935 28,162,429 12 13 27,066,293 759,624 766,935 28,162,429 14

Page 301 Line 12, column (b) includes $ of unbilled revenues. Line 12, column (d) includes MWH relating to unbilled revenues 1,230,043

74,509

FERC FORM NO. 1/3-Q (REV. 12-05)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description of Service (a) REGIONAL TRANSMISSION SERVICE REVENUES (Account 457.1) 

### 1. The respondent shall report below the revenue collected for each service (i.e., control area administration, market administration, etc.) performed pursuant to a Commission approved tariff. All amounts separately billed must be detailed below.

Balance at End of (c) (b) Balance at End of Quarter 1 Quarter 2 Balance at End of Quarter 3 (d) (e) Balance at End of Year

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45

FERC FORM NO. 1/3-Q (NEW. 12-05) Page 302 46 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

SALES OF ELECTRICITY BY RATE SCHEDULES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number and Title of Rate schedule MWh Sold (b) (a) Revenue (c) Average Number of Customers (d) KWh of Sales Per Customer (e) Revenue Per KWh Sold (f) 1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.

1OKLAHOMA 2Residential 23,737 1,247 19,035 0.0801 1,902,245 3Residential -TOU 7,739,086 576,281 13,429 0.0857 663,106,354 4Residential 387,523 26,108 14,843 0.0785 30,415,813 5Residentail LIHEAP 36,907 52,522 703 0.1512 5,579,733 6Security Lights 45,969 0.0174 800,000 7Unbilled-Net -4,081,514 8Over/Under Recoveries -52,522 9Duplicate Customer Adjustment 8,233,222 603,636 13,639 0.0847 697,722,631 10Total 11 12Commercial 45,522 1,115 40,827 0.0887 4,039,119 13GS-TOU 1,276,175 65,350 19,528 0.1019 130,015,000 14GS-1 268 1 268,000 0.0692 18,548 15PL-LEV 18,425 1 18,425,000 0.0490 903,263 16LPL-TOU-CR 415,201 17 24,423,588 0.0547 22,695,719 17LPL-TOU 4,760 1 4,760,000 0.0590 280,694 18PL-TOU-CR 972,066 901 1,078,875 0.0674 65,473,025 19PL-TOU 2,428,845 8,101 299,820 0.0715 173,613,143 20PL-1 49,613 14,718 3,371 0.1503 7,457,506 21Security Lights 284,569 120 2,371,408 0.0631 17,943,199 22PL-TOU-CAAR 194,059 239 811,962 0.0636 12,349,009 23PL-1-CAAR 16,938 1 16,938,000 0.0523 885,038 24RTP LPL-TOU-CR 9,783 1 9,783,000 0.0559 547,288 25RTP PL-TOU-CR 19,967 0.0250 500,000 26Unbilled-Net -3,276,920 27Over/Under Recoveries -14,718 28Duplicate Customer Adjustment 5,736,191 75,848 75,627 0.0756 433,443,631 29Total 30 31 Industrial 23,908 162 147,580 0.0843 2,016,543 32GS-TOU 106,888 2,982 35,844 0.0931 9,948,232 33GS-1 8,729 14 623,500 0.0713 622,620 34Oil & Gas 162,829 4,388 37,108 0.0759 12,353,014 35Oil & Gas-LEV 4,898 109 44,936 0.0755 369,716 36OGP-TOU 245,328 282 869,957 0.0601 14,752,988 37PL-OGP 92,596 1 92,596,000 0.0427 3,951,557 38LPL-TOU-IR 513,919 12 42,826,583 0.0463 23,789,298 39LPL-TOU-CR 3,232,024 54 59,852,296 0.0490 158,308,848 40LPL-TOU

25,406,180 1,792,175,609 766,886 33,129 0.0705 66,441 1,818,812 0 0 0.0274 25,339,739 1,790,356,797 766,886 33,042 0.0707

FERC FORM NO. 1 (ED. 12-95) Page 304

41 TOTAL Billed 42 Total Unbilled Rev.(See Instr. 6) 43 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

SALES OF ELECTRICITY BY RATE SCHEDULES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number and Title of Rate schedule MWh Sold (b) (a) Revenue (c) Average Number of Customers (d) KWh of Sales Per Customer (e) Revenue Per KWh Sold (f) 1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.

2,477 2 1,238,500 0.0752 186,298 1PL-LEV 80,986 14 5,784,714 0.0563 4,558,624 2PL-TOU-CR 715,055 328 2,180,046 0.0661 47,266,946 3PL-TOU 384,342 630 610,067 0.0689 26,485,995 4PL-1 2,714 702 3,866 0.1416 384,221 5Security Lights 47,514 14 3,393,857 0.0581 2,760,202 6PL-TOU-CAAR 7PL-OGP-CAAR 19,690 3 6,563,333 0.0569 1,119,450 8PL-TOU-CAAR-CR 53,851 38 1,417,132 0.0569 3,061,595 9PL-1-CAAR 40,773 1 40,773,000 0.0343 1,399,871 10RTP LPL-TOU 90,370 3 30,123,333 0.0468 4,224,856 11RTP LPL-TOU-CR 1,328 1 1,328,000 0.0453 60,158 12RTP PL-TOU 11,220 1 11,220,000 0.0601 674,123 13RTP PL-TOU-CR -9,066 0.0110 -100,000 14Unbilled - Net -3,455,949 15Over/Under Recoveries -702 16Duplicate Customer Adjustment 5,832,373 9,039 645,245 0.0540 314,739,206 17Total 18 19Public Street & Highway Lighting 53,568 224 239,143 0.1395 7,471,605 20Municipal Street Lights 413 0.2421 100,000 21Unbilled - Net -47,120 22Over/Under Recoveries 53,981 224 240,987 0.1394 7,524,485 23Total 24 25Other Sales to Public Authorities 4,014 66 60,818 0.0832 334,016 26GS-TOU 151,265 7,322 20,659 0.0880 13,315,125 27GS-1 9,411 1,296 7,262 0.0914 860,350 28Residential 126,358 1,505 83,959 0.0656 8,282,840 29PM-1 1,015,568 16 63,473,000 0.0501 50,907,130 30LPL-TOU 310,348 143 2,170,266 0.0648 20,121,038 31PL-TOU 12,307 1 12,307,000 0.0551 678,640 32PL-TOU-CR 571,572 906 630,874 0.0675 38,569,034 33PL-1 13,042 1,895 6,882 0.1479 1,929,133 34Security Lights 14,746 6 2,457,667 0.0657 968,485 35PL-TOU-CAAR 36PL-1-CAAR 145,262 2,021 71,876 0.0858 12,463,358 37PS-ND 90,312 333 271,207 0.0790 7,136,897 38PS-ND-TOU 1,814 17 106,706 0.0813 147,480 39PS_ND-C-TOU 68,522 129 531,178 0.0729 4,998,397 40PS-D

25,406,180 1,792,175,609 766,886 33,129 0.0705 66,441 1,818,812 0 0 0.0274 25,339,739 1,790,356,797 766,886 33,042 0.0707

FERC FORM NO. 1 (ED. 12-95) Page 304.1

41 TOTAL Billed 42 Total Unbilled Rev.(See Instr. 6) 43 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

SALES OF ELECTRICITY BY RATE SCHEDULES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number and Title of Rate schedule MWh Sold (b) (a) Revenue (c) Average Number of Customers (d) KWh of Sales Per Customer (e) Revenue Per KWh Sold (f) 1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.

50,740 48 1,057,083 0.0714 3,624,269 1PS-D-TOU 94 1 94,000 0.0900 8,456 2PS-D-C-TOU 5,981 2 2,990,500 0.0618 369,703 3PS-D-1-CAAR 35,870 40 896,750 0.0663 2,379,456 4PS-D-TOU-CAAR 147,011 1 147,011,000 0.0440 6,473,871 5RTP LPL-TOU-CR 16,828 2 8,414,000 0.0635 1,069,409 6RTP PL-TOU 19,934 0.0260 518,812 7Unbilled -Net -2,341,859 8Over/Under Recoveries -1,895 9Duplicate Customer Adjustment 2,810,999 13,855 202,887 0.0615 172,814,040 10Total 11 12 13ARKANSAS 14Residential 721,927 53,755 13,430 0.0754 54,412,690 15Residential 4,032 5,800 695 0.1553 626,014 16Security Lights 2,977 17Unbilled-Net 18TCR -1,595,562 19Over/Under Recoveries -5,800 20Duplicate Customer Adjustment 728,936 53,755 13,560 0.0733 53,443,142 21Total 22 23Commercial 185,229 7,933 23,349 0.0742 13,742,616 24GS-1 197 8 24,625 0.0837 16,492 25Athletic Fld Lighting 190,582 39 4,886,718 0.0517 9,847,022 26PL-TOU 346,660 663 522,866 0.0629 21,792,917 27PL-1 12,630 2,131 5,927 0.1142 1,442,923 28Security Lights -240 29Unbilled-Net 30TCR -1,322,721 31Over/Under Recoveries -2,131 32Duplicate Customer Adjustment 735,058 8,643 85,047 0.0619 45,519,249 33Total 34 35Industrial 9,625 290 33,190 0.0698 672,108 36GS-1 844,576 38 22,225,684 0.0499 42,119,249 37PL-TOU 281,610 113 2,492,124 0.0547 15,410,890 38PL-1 1,255 127 9,882 0.1118 140,267 39Security Lights -2,762 40Unbilled-Net

25,406,180 1,792,175,609 766,886 33,129 0.0705 66,441 1,818,812 0 0 0.0274 25,339,739 1,790,356,797 766,886 33,042 0.0707

FERC FORM NO. 1 (ED. 12-95) Page 304.2

41 TOTAL Billed 42 Total Unbilled Rev.(See Instr. 6) 43 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

SALES OF ELECTRICITY BY RATE SCHEDULES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number and Title of Rate schedule MWh Sold (b) (a) Revenue (c) Average Number of Customers (d) KWh of Sales Per Customer (e) Revenue Per KWh Sold (f) 1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311. 2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page 300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each applicable revenue account subheading. 3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported customers. 4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if all billings are made monthly). 5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto. 6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.

1TCR -1,369,595 2Over/Under Recoveries -127 3Duplicate Customer Adjustment 1,134,304 441 2,572,118 0.0502 56,972,919 4Total 5 6Public Street & Highway Lighting 8,785 26 337,885 0.1354 1,189,175 7Municipal Street Lights -8 8Unbilled-Net 9TCR -20,957 10Over/Under Recoveries 8,777 26 337,577 0.1331 1,168,218 11Total 12 13Other Sales to Public Authorities 20,741 903 22,969 0.0742 1,538,315 14GS-1 2,413 240 10,054 0.0758 182,937 15Residential 681 23 29,609 0.0816 55,600 16Athletic Fld Lighting 1,434 73 19,644 0.0737 105,621 17PM-1 2,065 2 1,032,500 0.0678 139,957 18PL-TOU 104,149 178 585,107 0.0663 6,906,258 19PL-1 1,001 187 5,353 0.1332 133,310 20Security Lights -145 21Unbilled - Net 22TCR -233,910 23Over/Under Recoveries -187 24Duplicate Customer Adjustment 132,339 1,419 93,262 0.0667 8,828,088 25Total 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

25,406,180 1,792,175,609 766,886 33,129 0.0705 66,441 1,818,812 0 0 0.0274 25,339,739 1,790,356,797 766,886 33,042 0.0707

FERC FORM NO. 1 (ED. 12-95) Page 304.3

41 TOTAL Billed 42 Total Unbilled Rev.(See Instr. 6) 43 TOTAL

### Schedule Page: 304 Line No.: 41 Column: c FUEL ADJUSTMENT CLAUSE - ESTIMATED ADDITIONAL REVENUE BILLED CLASSIFICATION AND RATE SCHEDULE

Residential Oklahoma Arkansas Residential-TOU 143,710.77 Residential 46,588,648.33 27,525,010.85 RES LIHEAP 2,254,839.97 Security Lights 207,582.51 153,483.30 Total 49,194,781.58 27,678,494.15
Commercial GS-TOU 286,997.85 GS-1 7,713,001.15 8,251,531.34 Ahtletic Field Lighting 7,546.92 PL-LEV 1,585.13 LPL-TOU-CR 65,758.44 LPL-TOU 1,870,210.47 PL-TOU-CR 27,666.45 PL-TOU 5,524,807.54 5,957,075.98 PL-1 14,227,170.81 13,211,567.60 Security Lights 280,660.85 481,037.18 PL-TOU-CAAR 1,851,307.58 PL-1-CAAR 999,717.70 RTP LPL TOU-CR 129,667.17 RTP PL-TOU-CR 59,427.62 Total 33,037,978.76 27,908,759.02
Industiral/Oilfield GS-TOU 144,558.50 GS-1 613,128.59 367,018.70 OIL & GAS 913,424.40 OGP-TOU 27,203.57 PL-OGP 1,058,754.97 LPL-TOU-IR 317,374.22 LPL-TOU-CR 1,774,212.36 LPL-TOU 11,237,298.51 PL-TOU-CR 260,788.10 PL-TOU 3,444,284.83 30,486,606.38 PL-1 1,984,767.80 10,400,642.91 PL-LEV 14,969.08 PL-OGP-CAAR SECURITY LIGHTS 15,484.96 47,343.18 PL-TOU-CAAR 124,383.26 PL-TOU-CAAR-CR 163,530.14 PL-1-CAAR 222,353.01 RTP LPL-TOU 113,924.54 RTP PL-TOU 29,153.39 RTP LPL-TOU-CR 373,759.19 RTP PL-TOU-CR 4,900.03 TOTAL 22,838,253.45 41,301,611.17 Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1

### Public Street & Highway 301,832.10 334,658.82

Public Authorities GS-TOU 20,757.89 GS-1 1,334,679.53 798,259.04 RESIDENTIAL 56,535.90 91,210.67 ATHLETIC FIELD 26,366.07 PM-1 684,217.37 54,166.48 LPL-TOU 9,809,371.81 PL-TOU 1,673,964.88 84,916.12 PL-TOU-CR 100,151.84 PL-1 3,216,326.35 3,975,260.61 SECURITY LIGHTS 73,788.60 38,225.30 PL-TOU-CAAR 84,589.96 PL-1-CAAR PS-ND 868,301.61 PS-ND-TOU 545,639.67 PS-ND-C-TOU 10,673.86 PS-D-1 376,017.49 PS-D-TOU 278,456.51 PS-D-C-TOU 581.74 PS-D-1-CAAR 34,598.70 PS-D-TOU-CAAR 208,045.37 RTP LPL-TOU-CR 583,585.75 RTP PL-TOU 82,817.81 TOTAL 20,043,102.64 5,068,404.29
Grand Total 125,415,948.53 102,291,927.45 Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand 

### 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years.

Geary, Oklahoma 1.5 1.6 1.6 1 RQ 1 Orlando, Oklahoma 0.2 0.3 0.3 1 RQ 2 Paris, Arkansas 0.3 0.4 0.1 1 RQ 3 Watonga, Oklahoma 4.9 5.2 5.4 1 RQ 4 Arkansas Valley Electric Cooperative 161.5 170.9 193.8 1 RQ 5 Mississippi Delta Energy Agency 20 20 20 RQ 6 Oklahoma Municipal Power Authority 25 25 25 RQ 7 Southwestern Power Administration 20.7 22.2 24.1 RQ 8 9 Unbilled Sales for Resale RQ 10 Over(Under) Recoveries RQ 11 12 American Electric Power Company OS 13 Aquila Networks OS 14

FERC FORM NO. 1 (ED. 12-90) Page 310 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand 

### 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years.

Associated Electric Cooperative, Inc OS 1 Cleco Utility Group, Inc. OS 2 Constellation Energy Commodities Group OS 3 Empire District Electric Company OS 4 Entergy Services, Inc. OS 5 Grand River Dam Authority OS 6 Independence Power & Light Company OS 7 Kansas City Board of Public Utilities OS 8 Kansas City Power and Light Co. OS 9 Lafayette Utilities System OS 10 Louisiana Energy & Power Authority OS 11 NRG Energy Inc. OS 12 Oklahoma Municipal Power Authority OS 13 South Mississippi Electric Power Assoc OS 14

FERC FORM NO. 1 (ED. 12-90) Page 310.1 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand 

### 1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the Purchased Power schedule (Page 326-327). 2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the purchaser. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the same as, or second only to, the supplier's service to its own ultimate consumers. LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or setter can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less than five years. SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one year or less. LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means Longer than one year but Less than five years.

Southwest Power Pool OS 1 Southwestern Power Administration OS 2 Southwestern Public Service OS 3 Sunflower Electric Power Corporation OS 4 Western Farmers Electric Coop. OS 5 Westar Energy OS 6 Southwest Power Pool/Redbud OS 7 8 9 10 11 12 13 14

FERC FORM NO. 1 (ED. 12-90) Page 310.2 0 0
0 Subtotal RQ Subtotal non-RQ
Total 0 0 0
0 0
0Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data.

334,962 41,344 6,720 383,026 8,699 1 52,018 20,929 6,720 79,667 1,368 2 21,184 13,030 3,645 37,859 512 3 1,133,487 431,554 6,720 1,571,761 29,242 4 35,860,119 13,605,427 -1,345,117 48,120,429 988,207 5 4,806,503 1,200,000 4,800 6,011,303 129,260 6 2,549,909 2,124,758 573,971 5,248,638 217,877 7 522,000 581,654 42,040 1,145,694 11,766 8 9 -588,769 -588,769 -2,540 10 303,701 303,701 11 12 38,058 38,058 350 13 10,782 10,782 128 14

FERC FORM NO. 1 (ED. 12-90) Page 311 45,280,182 69,045,349 114,325,531 1,384,391 1,371,858 2,756,249 -985,569 62,313,309 3,840,031 2,854,462 72,885,380 135,198,689 18,018,696 0 18,018,696Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data.

37,697 37,697 444 1 18,002 18,002 228 2 5,180 5,180 85 3 1,840 1,840 22 4 16,112 16,112 167 5 17,852 17,852 265 6 1,816 1,816 22 7 23,660 23,660 248 8 70,751 70,751 972 9 4,818 4,818 49 10 5,407 5,407 80 11 5,098 5,098 74 12 158,436 158,436 2,672 13 9,402 9,402 109 14

FERC FORM NO. 1 (ED. 12-90) Page 311.1 45,280,182 69,045,349 114,325,531 1,384,391 1,371,858 2,756,249 -985,569 62,313,309 3,840,031 2,854,462 72,885,380 135,198,689 18,018,696 0 18,018,696Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SALES FOR RESALE (Account 447) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Sold (h+i+j) Total ($) REVENUE ($) ($) ($) 

### OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote. AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k) 5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under which service, as identified in column (b), is provided. 6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser. 8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k) the total charge shown on bills rendered to the purchaser. 9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24. 10. Footnote entries as required and provide explanations following all required data.

68,474,036 3,840,031 72,314,067 1,364,189 1 4,284 4,284 48 2 16,540 16,540 211 3 26,000 26,000 275 4 2,314 2,314 34 5 30,074 30,074 434 6 67,190 67,190 752 7 8 9 10 11 12 13 14

FERC FORM NO. 1 (ED. 12-90) Page 311.2 45,280,182 69,045,349 114,325,531 1,384,391 1,371,858 2,756,249 -985,569 62,313,309 3,840,031 2,854,462 72,885,380 135,198,689 18,018,696 0 18,018,696

### Schedule Page: 310 Line No.: 1 Column: j Line 1 - Line 8, column j are charges for ancillary services. Schedule Page: 310 Line No.: 8 Column: a As of September 2008, Purcell is no longer an OGE customer. Schedule Page: 310 Line No.: 10 Column: j Unbilled revenue. Average cost of billed RQ customers. Average cost includes demand charges, energy charges, ancillary services, etc. Schedule Page: 310 Line No.: 11 Column: j Over and under fuel recoveries. Schedule Page: 310.2 Line No.: 1 Column: g The MWH include EIS Over-Scheduling and Under-Scheduling. Schedule Page: 310.2 Line No.: 1 Column: j These charges include SPP voltage control fees and over and under scheduling from the Energy Imbalance Service Market. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1ELECTRIC OPERATION AND MAINTENANCE EXPENSES Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

1. POWER PRODUCTION EXPENSES 1 A. Steam Power Generation 2 Operation 3 (500) Operation Supervision and Engineering 4 5,103,859 9,288,525 (501) Fuel 5 638,010,994 730,717,465 (502) Steam Expenses 6 6,257,483 6,865,922 (503) Steam from Other Sources 7 (Less) (504) Steam Transferred-Cr. 8 (505) Electric Expenses 9 4,941,446 5,344,296 (506) Miscellaneous Steam Power Expenses 10 22,342,024 23,794,487 (507) Rents 11 (509) Allowances 12 TOTAL Operation (Enter Total of Lines 4 thru 12) 13 676,655,806 776,010,695 Maintenance 14 (510) Maintenance Supervision and Engineering 15 5,513,884 5,611,322 (511) Maintenance of Structures 16 1,860,872 2,288,980 (512) Maintenance of Boiler Plant 17 25,323,192 25,094,925 (513) Maintenance of Electric Plant 18 17,531,930 18,144,946 (514) Maintenance of Miscellaneous Steam Plant 19 332,418 462,131 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 50,562,296 51,602,304 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 727,218,102 827,612,999 B. Nuclear Power Generation 22 Operation 23 (517) Operation Supervision and Engineering 24 (518) Fuel 25 (519) Coolants and Water 26 (520) Steam Expenses 27 (521) Steam from Other Sources 28 (Less) (522) Steam Transferred-Cr. 29 (523) Electric Expenses 30 (524) Miscellaneous Nuclear Power Expenses 31 (525) Rents 32 TOTAL Operation (Enter Total of lines 24 thru 32) 33 Maintenance 34 (528) Maintenance Supervision and Engineering 35 (529) Maintenance of Structures 36 (530) Maintenance of Reactor Plant Equipment 37 (531) Maintenance of Electric Plant 38 (532) Maintenance of Miscellaneous Nuclear Plant 39 TOTAL Maintenance (Enter Total of lines 35 thru 39) 40 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41 C. Hydraulic Power Generation 42 Operation 43 (535) Operation Supervision and Engineering 44 (536) Water for Power 45 (537) Hydraulic Expenses 46 (538) Electric Expenses 47 (539) Miscellaneous Hydraulic Power Generation Expenses 48 (540) Rents 49 TOTAL Operation (Enter Total of Lines 44 thru 49) 50 C. Hydraulic Power Generation (Continued) 51 Maintenance 52 (541) Mainentance Supervision and Engineering 53 (542) Maintenance of Structures 54 (543) Maintenance of Reservoirs, Dams, and Waterways 55 (544) Maintenance of Electric Plant 56 (545) Maintenance of Miscellaneous Hydraulic Plant 57 TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59

FERC FORM NO. 1 (ED. 12-93) Page320ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

D. Other Power Generation 60 Operation 61 (546) Operation Supervision and Engineering 62 247,837 360,503 (547) Fuel 63 125,338,296 135,007,801 (548) Generation Expenses 64 1,982,370 4,190,746 (549) Miscellaneous Other Power Generation Expenses 65 1,068,522 1,341,438 (550) Rents 66 415,000 437,575 TOTAL Operation (Enter Total of lines 62 thru 66) 67 129,052,025 141,338,063 Maintenance 68 (551) Maintenance Supervision and Engineering 69 392,773 368,939 (552) Maintenance of Structures 70 1,291,015 520,524 (553) Maintenance of Generating and Electric Plant 71 5,604,805 8,043,938 (554) Maintenance of Miscellaneous Other Power Generation Plant 72 434,694 536,251 TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 7,723,287 9,469,652 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 136,775,312 150,807,715 E. Other Power Supply Expenses 75 (555) Purchased Power 76 268,629,185 257,005,065 (556) System Control and Load Dispatching 77 64,379,760 74,339,866 (557) Other Expenses 78 22,341 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 333,008,945 331,367,272 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 1,197,002,359 1,309,787,986 2. TRANSMISSION EXPENSES 81 Operation 82 (560) Operation Supervision and Engineering 83 2,875,787 2,746,595 (561) Load Dispatching 84 (561.1) Load Dispatch-Reliability 85 527,547 844,071 (561.2) Load Dispatch-Monitor and Operate Transmission System 86 123,874 575,357 (561.3) Load Dispatch-Transmission Service and Scheduling 87 4,582,487 4,414,355 (561.4) Scheduling, System Control and Dispatch Services 88 3,306,659 3,366,840 (561.5) Reliability, Planning and Standards Development 89 2,075 15,897 (561.6) Transmission Service Studies 90 (561.7) Generation Interconnection Studies 91 (561.8) Reliability, Planning and Standards Development Services 92 461,394 439,153 (562) Station Expenses 93 1,143,867 1,168,592 (563) Overhead Lines Expenses 94 90,014 138,902 (564) Underground Lines Expenses 95 (565) Transmission of Electricity by Others 96 187,595 709,113 (566) Miscellaneous Transmission Expenses 97 581,265 52,790 (567) Rents 98 800 1,418 TOTAL Operation (Enter Total of lines 83 thru 98) 99 13,883,364 14,473,083 Maintenance 100 (568) Maintenance Supervision and Engineering 101 151,927 154,305 (569) Maintenance of Structures 102 (569.1) Maintenance of Computer Hardware 103 23,703 8,391 (569.2) Maintenance of Computer Software 104 356,363 205,605 (569.3) Maintenance of Communication Equipment 105 (569.4) Maintenance of Miscellaneous Regional Transmission Plant 106 (570) Maintenance of Station Equipment 107 4,662,168 5,207,168 (571) Maintenance of Overhead Lines 108 4,705,385 7,666,403 (572) Maintenance of Underground Lines 109 (573) Maintenance of Miscellaneous Transmission Plant 110 22,007 TOTAL Maintenance (Total of lines 101 thru 110) 111 9,921,553 13,241,872 TOTAL Transmission Expenses (Total of lines 99 and 111) 112 23,804,917 27,714,955

FERC FORM NO. 1 (ED. 12-93) Page321ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

3. REGIONAL MARKET EXPENSES 113 Operation 114 (575.1) Operation Supervision 115 (575.2) Day-Ahead and Real-Time Market Facilitation 116 (575.3) Transmission Rights Market Facilitation 117 (575.4) Capacity Market Facilitation 118 (575.5) Ancillary Services Market Facilitation 119 (575.6) Market Monitoring and Compliance 120 (575.7) Market Facilitation, Monitoring and Compliance Services 121 3,921,851 3,513,224 (575.8) Rents 122 Total Operation (Lines 115 thru 122) 123 3,921,851 3,513,224 Maintenance 124 (576.1) Maintenance of Structures and Improvements 125 (576.2) Maintenance of Computer Hardware 126 (576.3) Maintenance of Computer Software 127 (576.4) Maintenance of Communication Equipment 128 (576.5) Maintenance of Miscellaneous Market Operation Plant 129 Total Maintenance (Lines 125 thru 129) 130 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 131 3,921,851 3,513,224 4. DISTRIBUTION EXPENSES 132 Operation 133 (580) Operation Supervision and Engineering 134 1,465,844 2,426,911 (581) Load Dispatching 135 9,598 (582) Station Expenses 136 362,577 620,924 (583) Overhead Line Expenses 137 788,686 1,499,791 (584) Underground Line Expenses 138 1,790,155 2,692,343 (585) Street Lighting and Signal System Expenses 139 158,295 407,034 (586) Meter Expenses 140 1,126,976 2,658,227 (587) Customer Installations Expenses 141 1,123,056 1,049,364 (588) Miscellaneous Expenses 142 52,162 343,959 (589) Rents 143 93,752 68,628 TOTAL Operation (Enter Total of lines 134 thru 143) 144 6,971,101 11,767,181 Maintenance 145 (590) Maintenance Supervision and Engineering 146 27,668 5,491 (591) Maintenance of Structures 147 (592) Maintenance of Station Equipment 148 6,778,934 6,070,066 (593) Maintenance of Overhead Lines 149 25,656,029 32,912,610 (594) Maintenance of Underground Lines 150 1,377,528 2,277,958 (595) Maintenance of Line Transformers 151 4,848 58,887 (596) Maintenance of Street Lighting and Signal Systems 152 4,382,084 6,521,515 (597) Maintenance of Meters 153 86 (598) Maintenance of Miscellaneous Distribution Plant 154 TOTAL Maintenance (Total of lines 146 thru 154) 155 38,227,177 47,846,527 TOTAL Distribution Expenses (Total of lines 144 and 155) 156 45,198,278 59,613,708 5. CUSTOMER ACCOUNTS EXPENSES 157 Operation 158 (901) Supervision 159 262,361 577,417 (902) Meter Reading Expenses 160 6,881,984 8,486,606 (903) Customer Records and Collection Expenses 161 13,819,550 15,729,003 (904) Uncollectible Accounts 162 6,000,311 2,943,714 (905) Miscellaneous Customer Accounts Expenses 163 471,682 481,216 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 27,435,888 28,217,956

FERC FORM NO. 1 (ED. 12-93) Page322ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account Amount for (c) (b) (a) Current Year Previous Year Amount for 

### If the amount for previous year is not derived from previously reported figures, explain in footnote.

6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 165 Operation 166 (907) Supervision 167 352,213 215,729 (908) Customer Assistance Expenses 168 5,583,185 6,061,299 (909) Informational and Instructional Expenses 169 1,268,505 1,375,792 (910) Miscellaneous Customer Service and Informational Expenses 170 445,975 498,379 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 7,649,878 8,151,199 7. SALES EXPENSES 172 Operation 173 (911) Supervision 174 77,293 129,145 (912) Demonstrating and Selling Expenses 175 2,353,285 3,369,862 (913) Advertising Expenses 176 2,025,467 1,036,129 (916) Miscellaneous Sales Expenses 177 260,597 855,595 TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178 4,716,642 5,390,731 8. ADMINISTRATIVE AND GENERAL EXPENSES 179 Operation 180 (920) Administrative and General Salaries 181 13,362,977 8,979,732 (921) Office Supplies and Expenses 182 3,720,639 2,188,700 (Less) (922) Administrative Expenses Transferred-Credit 183 307,020 330,720 (923) Outside Services Employed 184 3,934,775 4,321,978 (924) Property Insurance 185 2,090,861 1,803,920 (925) Injuries and Damages 186 6,109,778 6,562,299 (926) Employee Pensions and Benefits 187 42,387,480 40,124,258 (927) Franchise Requirements 188 3,939,726 8,675,145 (928) Regulatory Commission Expenses 189 3,979,821 3,491,791 (929) (Less) Duplicate Charges-Cr. 190 3,939,726 8,675,145 (930.1) General Advertising Expenses 191 25,504 10,386 (930.2) Miscellaneous General Expenses 192 29,820,355 36,921,841 (931) Rents 193 83,310 -131,724 TOTAL Operation (Enter Total of lines 181 thru 193) 194 105,208,480 103,942,461 Maintenance 195 (935) Maintenance of General Plant 196 9,542 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 105,218,022 103,942,461 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 1,414,947,835 1,546,332,220

FERC FORM NO. 1 (ED. 12-93) Page323Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER (Account 555) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand (Including power exchanges) 

### 1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment.

Associated Electric Cooperative, Inc 1 OS 1 American Electric Power Company 1 OS 2 Aquila Networks 1 OS 3 Constellation Energy Commodities Group 1 OS 4 Cleco Utility Group, Inc. 1 OS 5 Empire District Electric Company 1 OS 6 Entergy Services, Inc. 1 OS 7 FPL Energy Sooner Wind, LLC 1 LF 8 Grand River Dam Authority 1 OS 9 Independence Power & Light Company 1 OS 10 Kansas City Board of Public Utilities 1 OS 11 Kansas City Power and Light Co. 1 OS 12 Lafayette Utilities System 1 OS 13 Louisiana Energy and Power Authority 1 OS 14

FERC FORM NO. 1 (ED. 12-90) Page 326 

### TotalName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER (Account 555) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name of Company or Public Authority

(c) (b) (a) FERC Rate Monthly Billing Average

(d) Statistical

cation Classifi- Schedule or Tariff Number Demand (MW) (e) (f) (Footnote Affiliations) Actual Demand (MW) Average Average Monthly NCP DemandMonthly CP Demand (Including power exchanges) 

### 1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges. 2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller. 3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows: RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the same as, or second only to, the supplier’s service to its own ultimate consumers. LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the earliest date that either buyer or seller can unilaterally get out of the contract. IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less than five years. SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one year or less. LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of service, aside from transmission constraints, must match the availability and reliability of the designated unit. IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means longer than one year but less than five years. EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc. and any settlements for imbalanced exchanges. OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of the service in a footnote for each adjustment.

NRG Energy Inc. 1 OS 1 Oklahoma Municipal Power Authority 1 OS 2 Sunflower Electric Power Company 1 OS 3 South Mississippi Electric Power Assoc 1 OS 4 Southwestern Power Administration 1 OS 5 Southwestern Public Service 1 OS 6 Western Farmers Electric Coop. 71 OS 7 Westar Energy 1 OS 8 AES Shady Point, LLC N/A LU 9 Powersmith Cogeneration N/A LU 10 Inadvertent Energy Exchange - Net N/A EX 11 Purcell Public Works Authority 1 OS 12 13 Southwest Power Pool N/A RQ 14

FERC FORM NO. 1 (ED. 12-90) Page 326.1 

### TotalName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER(Account 555) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total COST/SETTLEMENT OF POWER ($) ($) ($) (Including power exchanges)

POWER EXCHANGES MegaWatt Hours Received MegaWatt Hours Delivered (l) (m) of Settlement ($) 

### AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data.

37,337 37,337 1 475 62,778 62,778 2 898 10,293 10,293 3 132 10,043 10,043 4 122 12,393 12,393 5 118 5,331 5,331 6 96 221,899 17,671 239,570 7 2,282 4,392,136 4,392,136 8 177,995 12,191 12,191 9

120 1,183 1,183 10 17 4,063 4,063 11 53 27,017 27,017 12 377 2,972 2,972 13 25 1,932 1,932 14 19

FERC FORM NO. 1 (ED. 12-90) Page 327 4,344,974 149,901,371 107,103,693 257,005,064Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PURCHASED POWER(Account 555) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. MegaWatt Hours

(i) (h) (g) (j) Demand Charges Energy Charges Other Charges (k) Purchased (j+k+l) Total COST/SETTLEMENT OF POWER ($) ($) ($) (Including power exchanges)

POWER EXCHANGES MegaWatt Hours Received MegaWatt Hours Delivered (l) (m) of Settlement ($) 

### AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting years. Provide an explanation in a footnote for each adjustment. 4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as identified in column (b), is provided. 5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts. Footnote any demand not stated on a megawatt basis and explain. 6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange. 7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m) the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l) include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the agreement, provide an explanatory footnote. 8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13. 9. Footnote entries as required and provide explanations following all required data.

16,533 16,533 1 220 -4,707 -4,707 2 -53 9,539 9,539 3 84 14,913 14,913 4 149 20,265 631,479 651,744 5 269 42,253 42,253 6 598 11,394 11,394 7 124 45,471,150 10,462,500 55,933,650 8 680,782 26,857,153 85,057,757 111,914,910 9 2,249,796 28,794,589 12,058,383 40,852,972 10 428,278 11 -19,931 59,130 59,130 12 2,831 13 43,862,014 -1,178,520 42,683,494 14 819,098

FERC FORM NO. 1 (ED. 12-90) Page 327.1 4,344,974 149,901,371 107,103,693 257,005,064

### Schedule Page: 326 Line No.: 7 Column: l Transmission Charges Schedule Page: 326.1 Line No.: 5 Column: l Transmission Charges. Schedule Page: 326.1 Line No.: 7 Column: c The estimated breakdown of the construction amount of $44,827,517 by functional classification is as follows: Production $ 1,318,999 Transmission 7,123,532 Distribution 36,384,986 Schedule Page: 326.1 Line No.: 8 Column: k Includes charges for Redbud Purchase Power Agreement. Schedule Page: 326.1 Line No.: 8 Column: l Includes Redbud Capacity & Start-Up Charges. Schedule Page: 326.1 Line No.: 9 Column: l Includes capacity and O&M charges. Schedule Page: 326.1 Line No.: 10 Column: l Includes capacity and O&M charges. Schedule Page: 326.1 Line No.: 12 Column: l Refund of unused banked energy. Schedule Page: 326.1 Line No.: 14 Column: l Charges include EIS Uninstructured Deviation, Revenue Neutrality, Losses,and Miscellaneous. Also includes transmission charges. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Payment By

(c) (b) (a) (d) Statistical

cation Classifi- (Footnote Affiliation) (Including transactions referred to as 'wheeling')

(Company of Public Authority) (Footnote Affiliation) (Company of Public Authority) (Footnote Affiliation) (Company of Public Authority) Energy Received From Energy Delivered To 

### 1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c). 3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to. Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c) 4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission Reservation, NF - non-firm transmission service, OS - Other Transmission Service and 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. See General Instruction for definitions of codes.

Southwestern Power Administration Southwestern Power Administration Southwestern Power Administration LFP 1 Southwest Power Pool Southwest Power Pool Southwest Power Pool OS 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

FERC FORM NO. 1 (ED. 12-90) Page 328 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (Including transactions reffered to as 'wheeling')

FERC Rate Schedule of Tariff Number (e) Point of Receipt (Subsatation or Other Designation) (f) Point of Delivery (Substation or Other (g) Billing Demand

(MW)

(h) TRANSFER OF ENERGY MegaWatt Hours Received (i) Delivered (j) MegaWatt Hours Designation) 

### 5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (d), is provided. 6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column (g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the contract. 7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain. 8. Report in column (i) and (j) the total megawatthours received and delivered.

Various 106 Various 111,663 108,313 1 Various SPP Tariff Various 1,590,002 4,120,507 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

FERC FORM NO. 1 (ED. 12-90) Page 329 0 1,701,665 4,228,820Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (m) (l) (k) (n) (k+l+m) Total Revenues ($) (Including transactions reffered to as 'wheeling')

($) Energy Charges ($) (Other Charges) Demand Charges ($) REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS 

### 9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report purposes only on Page 401, Lines 16 and 17, respectively. 11. Footnote entries and provide explanations following all required data.

319,913 319,913 1 14,385,322 18,172,232 3,786,910 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34

FERC FORM NO. 1 (ED. 12-90) Page 330 14,705,235 18,492,145 3,786,910 0

### Schedule Page: 328 Line No.: 2 Column: i Columns i and j do not necessarily reflect actual MW wheeled, but rather MW's for which OG&E was paid impacts for wheeling through the SPP Tariff. Schedule Page: 328 Line No.: 2 Column: m Other Charges - Includes losses, scheduling and voltage control (reactive). Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

TRANSMISSION OF ELECTRICITY BY ISO/RTOs Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Payment Received by Statistical (b) (a) (Transmission Owner Name) Classification FERC Rate Schedule or Tariff Number (c) Total Revenue by Rate Schedule or Tarirff (d) Total Revenue (e) 1. Report in Column (a) the Transmission Owner receiving revenue for the transmission of electricity by the ISO/RTO. 2. Use a separate line of data for each distinct type of transmission service involving the entities listed in Column (a). 3. In Column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNO – Firm Network Service for Others, FNS – Firm Network Transmission Service for Self, LFP – Long-Term Firm Point-to-Point Transmission Service, OLF – Other Long-Term Firm Transmission Service, SFP – Short-Term Firm Point-to-Point Transmission Reservation, NF – Non-Firm Transmission Service, OS – Other Transmission Service and 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. See General Instruction for definitions of codes. 4. In column (c) identify the FERC Rate Schedule or tariff Number, on separate lines, list all FERC rate schedules or contract designations under which service, as identified in column (b) was provided. 5. In column (d) report the revenue amounts as shown on bills or vouchers. 6. Report in column (e) the total revenues distributed to the entity listed in column (a).

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39

Page331

40 TOTAL

FERC FORM NO. 1/3-Q (REV 03-07)Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name of Company or Public (d) (c) (a) Authority (Footnote Affiliations) TRANSFER OF ENERGY Magawatt-

hours Received MagawattDelivered

hours EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS Demand Charges

($) (e) Energy Charges

(f) ($) Other Charges

($) (g) ($) Total Cost of Transmission (h) (Including transactions referred to as "wheeling") 

### 1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public authorities, qualifying facilities, and others for the quarter. 2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company, abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided transmission service for the quarter reported. 3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows: FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications. 4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service. 5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered. 6. Enter "TOTAL" in column (a) as the last line. 7. Footnote entries and provide explanations following all required data.

Statistical Classification (b) FNS 709,113 709,113 602,583 602,583 Westar Energy 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16

FERC FORM NO. 1/3-Q (REV. 02-04) Page 332 602,583 602,583 709,113 709,113 TOTAL

### Schedule Page: 332 Line No.: 1 Column: c Column c and column d MWH's reflect the MWH's that flow through facilities owned by Westar Energy from & to facilities owned by OG&E. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC) Oklahoma Gas and Electric Company X / / 2008/Q4

Line Description Amount (b) (a) No. 632,373 Industry Association Dues 1 Nuclear Power Research Expenses 2 90,924 Other Experimental and General Research Expenses 3 567,963 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5 6 34,240,720 OGE Energy Corp (Parent) Cost Allocations 7 8 618,780 Moving Expense 9 10 5,499 Unused Free Service 11 12 857,938 Sponserships 13 14 50,726 Conventions and Meetings 15 16 -143,082 Other 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45

36,921,841

FERC FORM NO. 1 (ED. 12-94) Page 335

46 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Functional Classification Depreciation (d) (b) (a) Amortization of Total (Except amortization of aquisition adjustments)

A. Summary of Depreciation and Amortization Charges

Expense (Account 403) Limited Term Electric Plant Amortization of Other Electric Plant (Acc 405) (e) (f) 

### 1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric Plant (Account 405). 2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to compute charges and whether any changes have been made in the basis or rates used from the preceding report year. 3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes to columns (c) through (g) from the complete report of the preceding year. Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount, account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included in any sub-account used. In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the method of averaging used. For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column (a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis. 4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the bottom of section C the amounts and nature of the provisions and the plant items to which related.

(Account 404) (c) Depreciation Expense for Asset Retirement Costs (Account 403.1) 3,804,341 3,804,341 1Intangible Plant 24,679,019 24,643,060 2Steam Production Plant 35,959 3Nuclear Production Plant 4Hydraulic Production Plant-Conventional 5Hydraulic Production Plant-Pumped Storage 24,100,990 24,091,702 6Other Production Plant 9,288 20,099,612 20,099,612 7Transmission Plant 64,980,831 64,980,831 8Distribution Plant 9Regional Transmission and Market Operation 11,717,382 11,717,382 10General Plant 11Common Plant-Electric 149,382,175 145,532,587 3,804,341 12TOTAL 45,247

1. Amortization of Limited-term Franchises over their respective lives, generally over 25 years. 2. Amortization of Residential/Commercial Developer Incentives over a 3 year term. 3. Software amortization generally over a 3 year term.

FERC FORM NO. 1 (REV. 12-03) Page 336 B. Basis for Amortization ChargesName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account No. (c) (b) (a) (d) (e) C. Factors Used in Estimating Depreciation Charges Depreciable Plant Base (In Thousands) Estimated Avg. Service Life Net Salvage (Percent) Applied Depr. rates Mortality Curve Type Average Remaining Life (f) (g) (Percent)

Steam Production-Coal 12Muskogee 13Unit 4 197,274 14Unit 5 143,600 15Unit 6 381,702 16ARO Cost 167 17Sooner 18Unit 1 321,420 19Unit 2 203,441 20ARO Cost 123 21 Subtotal Coal 1,247,727 22 23Steam Production-Gas 24Mustang 25Unit 1 16,677 26Unit 2 9,027 27Unit 3 17,861 28Unit 4 36,851 29ARO Cost 214 30Muskogee 3 25,859 31ARO Cost 440 32Seminole 33Unit 1 72,712 34Unit 2 47,747 35Unit 3 80,199 36GT 1,589 37ARO Cost 209 38Horseshoe Lake 39Unit 6 33,498 40Unit 7 35,132 41 Unit 8 38,936 42ARO Cost 238 43Subtotal Gas 417,189 44 45Other Production 46Horseshoe 9 Gas 24,217 47Horseshoe 10 Gas 20,020 48Centennial Wind Farm 189,390 49Woodward Gas 1,216 50

FERC FORM NO. 1 (REV. 12-03) Page 337Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account No. (c) (b) (a) (d) (e) C. Factors Used in Estimating Depreciation Charges Depreciable Plant Base (In Thousands) Estimated Avg. Service Life Net Salvage (Percent) Applied Depr. rates Mortality Curve Type Average Remaining Life (f) (g) (Percent)

ARO Cost-Other 900 12Tinker Gas 10,100 13McClain Gas 1 93,800 14McClain Gas 2 85,722 15McClain Steam 1 56,184 16McClain HRSG 1 31,118 17McClain HRSG 2 31,085 18Enid 5,263 19Redbud Unit 1 141,160 20Redbud Unit 2 65,855 21 Redbud Unit 3 65,855 22Redbud Unit 4 65,855 23Subtotal Other 887,740 24 25Transmission Plant 26350 28,712 27352 3,474 28353 306,208 29354 55,564 30355 211,639 31356 183,314 32358 110 33359 19 34Subtotal Transmission 789,040 35 36Distribution Plant 37360 4,065 38361 4,702 39362 393,559 40364 418,728 41365 322,463 42366 123,209 43367 488,257 44368 288,939 45369 203,102 46370 85,920 47371 25 48372 594 49373 166,100 50

FERC FORM NO. 1 (REV. 12-03) Page 337.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Account No. (c) (b) (a) (d) (e) C. Factors Used in Estimating Depreciation Charges Depreciable Plant Base (In Thousands) Estimated Avg. Service Life Net Salvage (Percent) Applied Depr. rates Mortality Curve Type Average Remaining Life (f) (g) (Percent)

Subtotal Distrbution 2,499,663 12 13General Plant 14389 148 15390 100,654 16391 11,685 17392 57,834 18393 1,086 19394 6,664 20395 7,988 21396 7,170 22397 2,301 23398 4,515 24 25Subtotal General Plant 200,045 26 27Intangibles 25,969 28 29Total Depr. Plant 6,067,373 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50

FERC FORM NO. 1 (REV. 12-03) Page 337.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

REGULATORY COMMISSION EXPENSES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description Assessed by

(c) (b) (a) Total Expense for Expenses of (d) (Furnish name of regulatory commission or body the Regulatory docket or case number and a description of the case) Commission Utility Current Year (b) + (c) Deferred in Account 182.3 at Beginning of Year (e) 

### 1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party. 2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts deferred in previous years.

FERC Assessment for Annual Charges 1,026,147 1,026,147 1 2Arkansas Public Service Commission 3for Annual Charges 291,845 291,845 4 5 Oklahoma Corporation Commission for Annual 6 613,284 Charges 12 month Amortization Period 1,257,445 1,257,445 7 8 9Arkansas Rate Case 2008 10(08-103-U) 97,464 97,464 11 12 Red Rock Recovery 13( PUD 2007-447) 30,300 30,300 14 15 FERC Transmission Rate Case 422,874 422,874 16(ER08-281-000) 17 18 Renewables 19 (PUD 2008-148) 24,778 24,778 20 21 Oklahoma Rate Case 2009 22 PUD (2008-398) 40,975 40,975 23 24 Oklahoma Fuel Audit 25 (PUD 2008-299) 22,700 22,700 26 27 Integrated Resource Planning 5,767 5,767 28 29Arkansas Energy Efficiency Programs 30 (06-004-R) 18,241 18,241 31 32 Security 33 (PUD 2006-402) 5,678 5,678 34 35 Oklahoma DSM & Energy Efficiency Programs 36 (PUD 2008-59) 31,783 31,783 37 38 System Hardening Project 210,735 210,735 39 40Minor Items 5,059 5,059 41 42 43 44 45

FERC FORM NO. 1 (ED. 12-96) Page 350 46 TOTAL 2,575,437 916,354 3,491,791 613,284Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of REGULATORY COMMISSION EXPENSES (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (j) (i) (f) (k) (l) EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR CURRENTLY CHARGED TO Department Account No. (g) Amount (h) Deferred to Account 182.3 Contra Account Amount Deferred in Account 182.3

End of Year 

### 3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization. 4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts. 5. Minor items (less than $25,000) may be grouped.

Electric 1 1,026,147 928 2 3 Electric 4 291,845 928 5 6 632,546 613,284 928 632,546 Electric 7 671,655 928 8 9 10 Electric 11 97,464 928 12 13 Electric 14 30,300 928 15 Electric 16 422,874 928 17 18 19 Electric 20 24,778 928 21 22 Electric 23 40,975 928 24 25 Electric 26 22,700 928 27 Electric 28 5,767 928 29 30 Electric 31 18,241 928 32 33 Electric 34 5,678 928 35 36 Electric 37 31,783 928 38 Electric 39 210,735 928 40 Electric 41 5,059 928 42 43 44 45

FERC FORM NO. 1 (ED. 12-96) Page 351 46 2,906,001 632,546 613,284 632,546Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description (b) (a) Classification 1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D & D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to others (See definition of research, development, and demonstration in Uniform System of Accounts). 2. Indicate in column (a) the applicable classification, as shown below:

Classifications: A. Electric R, D & D Performed Internally: a. Overhead (1) Generation b. Underground a. hydroelectric (3) Distribution i. Recreation fish and wildlife (4) Regional Transmission and Market Operation ii Other hydroelectric (5) Environment (other than equipment) b. Fossil-fuel steam (6) Other (Classify and include items in excess of $5,000.) c. Internal combustion or gas turbine (7) Total Cost Incurred d. Nuclear B. Electric, R, D & D Performed Externally: e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric f. Siting and heat rejection Power Research Institute (2) Transmission

A. Electric R, D & D Performed Internally 1 (1) Generation 2 3(2) System Planning, Engineering 4and Operation 5 6(3) Transmission 7 8(4) Distribution 9 10(5) Environmental (other than equipment) 11 12(6) Other 13 14(7) Total Internal Cost Incurred 15 16 17 B. Electric, R, D & D Performed Externally 18(1) Research Support to the Electrical 19Research Council or the Electric 20Power Research Institute 21 22(2) Research Support to Edison Electric 23Institute 24 25(3) Research Support to Nuclear Power 26Groups 27 28 University of Oklahoma-Diversity of Output Power (4) Research Support to Others 29 National Regulatory Research Institute-Renewables 30 31 (5) Total External Cost Incurred 32 33 34 35 36 37 38

FERC FORM NO. 1 (ED. 12-87) Page 352Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. AMOUNTS CHARGED IN CURRENT YEAR (e) (c) Costs Incurred Internally Current Year Costs Incurred Externally Current Year (d) Account Amount (f) Unamortized Accumulation (g) (2) Research Support to Edison Electric Institute (3) Research Support to Nuclear Power Groups (4) Research Support to Others (Classify) (5) Total Cost Incurred 3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $5,000 or more, briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.). Group items under $5,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D & D activity. 4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year, listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e) 5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research, Development, and Demonstration Expenditures, Outstanding at the end of the year. 6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by "Est." 7. Report separately research and related testing facilities operated by the respondent.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 85,924 930.2 85,924 30 5,000 930.2 5,000 31 32 90,924 90,924 33 34 35 36 37 38

FERC FORM NO. 1 (ED. 12-87) Page 353Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

DISTRIBUTION OF SALARIES AND WAGES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Classification (c) (b) (a) Direct Payroll Allocation of Total (d) Distribution Payroll charged for Clearing Accounts 

### Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation giving substantially correct results may be used.

Electric 1 Operation 2 26,821,862 Production 3 3,136,707 Transmission 4 Regional Market 5 9,849,495 Distribution 6 15,785,173 Customer Accounts 7 3,032,128 Customer Service and Informational 8 3,294,736 Sales 9 7,948,633 Administrative and General 10 69,868,734 TOTAL Operation (Enter Total of lines 3 thru 10) 11 Maintenance 12 20,221,214 Production 13 3,658,536 Transmission 14 Regional Market 15 19,079,278 Distribution 16 Administrative and General 17 42,959,028 TOTAL Maintenance (Total of lines 13 thru 17) 18 Total Operation and Maintenance 19 47,043,076 Production (Enter Total of lines 3 and 13) 20 6,795,243 Transmission (Enter Total of lines 4 and 14) 21 Regional Market (Enter Total of Lines 5 and 15) 22 28,928,773 Distribution (Enter Total of lines 6 and 16) 23 15,785,173 Customer Accounts (Transcribe from line 7) 24 3,032,128 Customer Service and Informational (Transcribe from line 8) 25 3,294,736 Sales (Transcribe from line 9) 26 7,948,633 Administrative and General (Enter Total of lines 10 and 17) 27 112,827,762 112,827,762 TOTAL Oper. and Maint. (Total of lines 20 thru 27) 28 Gas 29 Operation 30 Production-Manufactured Gas 31 Production-Nat. Gas (Including Expl. and Dev.) 32 Other Gas Supply 33 Storage, LNG Terminaling and Processing 34 Transmission 35 Distribution 36 Customer Accounts 37 Customer Service and Informational 38 Sales 39 Administrative and General 40 TOTAL Operation (Enter Total of lines 31 thru 40) 41 Maintenance 42 Production-Manufactured Gas 43 Production-Natural Gas (Including Exploration and Development) 44 Other Gas Supply 45 Storage, LNG Terminaling and Processing 46 Transmission 47

FERC FORM NO. 1 (ED. 12-88) Page 354Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Classification (c) (b) (a) Direct Payroll Allocation of Total (d) Distribution Payroll charged for Clearing Accounts DISTRIBUTION OF SALARIES AND WAGES (Continued)

Distribution 48 Administrative and General 49 TOTAL Maint. (Enter Total of lines 43 thru 49) 50 Total Operation and Maintenance 51 Production-Manufactured Gas (Enter Total of lines 31 and 43) 52 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 53 Other Gas Supply (Enter Total of lines 33 and 45) 54 Storage, LNG Terminaling and Processing (Total of lines 31 thru 55 Transmission (Lines 35 and 47) 56 Distribution (Lines 36 and 48) 57 Customer Accounts (Line 37) 58 Customer Service and Informational (Line 38) 59 Sales (Line 39) 60 Administrative and General (Lines 40 and 49) 61 TOTAL Operation and Maint. (Total of lines 52 thru 61) 62 Other Utility Departments 63 Operation and Maintenance 64 112,827,762 112,827,762 TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65 Utility Plant 66 Construction (By Utility Departments) 67 32,996,493 32,996,493 Electric Plant 68 Gas Plant 69 Other (provide details in footnote): 70 32,996,493 32,996,493 TOTAL Construction (Total of lines 68 thru 70) 71 Plant Removal (By Utility Departments) 72 5,595,152 5,595,152 Electric Plant 73 Gas Plant 74 Other (provide details in footnote): 75 5,595,152 5,595,152 TOTAL Plant Removal (Total of lines 73 thru 75) 76 Other Accounts (Specify, provide details in footnote): 77 700,357 700,357 Expenses of Jobbing and Contract Work 78 7,262 7,262 Accounts Receivable from Associated Companies 79 973,469 973,469 Other Accounts Receivable 80 81 880 880 Other 82 83 84 85 86 87 88 89 90 91 92 93 94 1,681,968 1,681,968 TOTAL Other Accounts 95 153,101,375 153,101,375 TOTAL SALARIES AND WAGES 96

FERC FORM NO. 1 (ED. 12-88) Page 355

### Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report

End of

COMMON UTILITY PLANT AND EXPENSES 

### Oklahoma Gas and Electric Company 

### X / / 2008/Q4

1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors. 2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including explanation of basis of allocation and factors used. 3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such expenses are related. Explain the basis of allocation used and give the factors of allocation. 4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other authorization.

FERC FORM NO. 1 (ED. 12-87) Page 356Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Description of Item(s) Balance at End of (c) (b) (a) Balance at End of AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS

Quarter 1 Quarter 2 Balance at End of Quarter 3 (d) (e) 1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for Resale, for items shown on ISO/RTO Settlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determining whether a net purchase or sale has occurred. In each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.

Balance at End of Year Energy 1 Net Purchases (Account 555) 2 43,862,014 12,919,854 16,938,870 39,326,224 Net Sales (Account 447) 3 ( 68,474,036) ( 12,123,754) ( 45,247,334) ( 58,547,585) Transmission Rights 4Ancillary Services 5Other Items (list separately) 6Uninstructured Resource Deviation (URD) 7 217,969 45,258 108,992 174,508 Revenue Neutrality Uplift (RNU) 8 ( 1,420,040) ( 1,017,482) ( 2,553,637) ( 2,142,259) Losses 9 ( 11,454) ( 13,290) 1,578 ( 7,737) Under-Scheduling 10 58,198 2,076 16,824 51,433 Over-Scheduling 11 98,106 476 58,083 89,947 Miscellaneous Charge 12 ( 704) ( 704) ( 704) ( 704) 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45

( 25,669,947) ( 187,566) ( 30,677,328) ( 21,056,173) FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397 46 TOTALName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

PURCHASES AND SALES OF ANCILLARY SERVICES Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Type of Ancillary Service (a) 

### Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the respondents Open Access Transmission Tariff. In columns for usage, report usage-related billing determinant and the unit of measure. (1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year. (2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold during the year. (3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold during the year. (4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year. (5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services purchased and sold during the period. (6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during the year. Include in a footnote and specify the amount for each type of other ancillary service provided.

Number of Units Unit of Measure Dollars (b) (c) (d) Number of Units Unit of Measure Dollars (e) (f) (g) Usage - Related Billing Determinant Usage - Related Billing Determinant Amount Purchased for the Year Amount Sold for the Year

21,359 KW 263,044 15,318 MW 185,459 Scheduling, System Control and Dispatch 1 16,019 KW 263,044 8,324 MW 185,459 Reactive Supply and Voltage 2 24,725 KW 6,786 Regulation and Frequency Response 3Energy Imbalance 4 25,547 KW 7,018 Operating Reserve - Spinning 5 6,231 KW 3,886 Operating Reserve - Supplement 6Other 7 93,881 543,778 23,642 370,918 Total (Lines 1 thru 7) 8

FERC FORM NO. 1 (New 2-04) Page 398Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of MONTHLY TRANSMISSION SYSTEM PEAK LOAD Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Monthly Peak MW - Total

(c) (b) (a) Month NAME OF SYSTEM: Day of Monthly

Peak (1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. (2) Report on Column (b) by month the transmission system's peak load. (3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). (4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the definition of each statistical classification.

(d) Hour of Monthly Peak (e) Firm Network Service for Self

(f) Firm Network Service for

Others (g) Long-Term Firm

Point-to-point Reservations (h)Other LongTerm Firm

Service (i) Short-Term Firm

Point-to-point Reservation (j) Other Service

333 22 4,147 800 23 4,502 January 1 322 21 3,971 800 1 4,314 February 2 315 20 3,787 2000 3 4,122 March 3 970 63 11,905 12,938 Total for Quarter 1 4 318 20 3,665 1800 21 4,003 April 5 435 29 4,705 1700 30 5,169 May 6 486 31 5,232 1700 26 5,749 June 7 1,239 80 13,602 14,921 Total for Quarter 2 8 546 36 5,765 1700 22 6,347 July 9 571 37 5,982 1700 4 6,590 August 10 448 13 4,747 1600 2 5,208 September 11 1,565 86 16,494 18,145 Total for Quarter 3 12 321 12 3,821 1700 1 4,154 October 13 288 11 3,538 800 21 3,837 November 14 388 12 4,400 1900 15 4,800 December 15 997 35 11,759 12,791 Total for Quarter 4 16

4,771 264 53,760 58,795 Total Year to Date/Year 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of MONTHLY ISO/RTO TRANSMISSION SYSTEM PEAK LOAD Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Monthly Peak MW - Total

(c) (b) (a) Month NAME OF SYSTEM: Day of Monthly

Peak (1) Report the monthly peak load on the respondent's transmission system. If the Respondent has two or more power systems which are not physically integrated, furnish the required information for each non-integrated system. (2) Report on Column (b) by month the transmission system's peak load. (3) Report on Column (c) and (d) the specified information for each monthly transmission - system peak load reported on Column (b). (4) Report on Columns (e) through (i) by month the system’s transmission usage by classification. Amounts reported as Through and Out Service in Column (g) are to be excluded from those amounts reported in Columns (e) and (f). (5) Amounts reported in Column (j) for Total Usage is the sum of Columns (h) and (i).

(d) Hour of Monthly Peak (e) Imports into ISO/RTO

(f) Exports from

ISO/RTO

(g) Through and Out Service

(h) Network Service Usage

(i) Point-to-Point Service Usage

(j) Total Usage

January 1 February 2March 3Total for Quarter 1 4April 5May 6June 7Total for Quarter 2 8July 9August 10September 11 Total for Quarter 3 12October 13November 14December 15Total for Quarter 4 16Total Year to Date/Year 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400aName of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

ELECTRIC ENERGY ACCOUNT Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (a) (b) (a) (b) Line No. MegaWatt Hours Item MegaWatt Hours Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.

SOURCES OF ENERGY 1 Generation (Excluding Station Use): 2 22,726,264

Steam 3Nuclear 4Hydro-Conventional 5Hydro-Pumped Storage 6 2,970,573

Other 7Less Energy for Pumping 8 25,696,837

Net Generation (Enter Total of lines 3 through 8) 9

4,344,974

Purchases 10Power Exchanges: 11 Received 12Delivered 13Net Exchanges (Line 12 minus line 13) 14Transmission For Other (Wheeling) 15 1,701,665 Received 16 4,228,820 Delivered 17 -2,527,155 Net Transmission for Other (Line 16 minus line 17) 18

2,527,155 Transmission By Others Losses 19 30,041,811 TOTAL (Enter Total of lines 9, 10, 14, 18 and 19) 20 DISPOSITION OF ENERGY 21 25,406,180 Sales to Ultimate Consumers (Including Interdepartmental Sales) 22

1,384,391 Requirements Sales for Resale (See instruction 4, page 311.) 23

1,371,858 Non-Requirements Sales for Resale (See instruction 4, page 311.) 24

75,447 Energy Furnished Without Charge 25 44,971 Energy Used by the Company (Electric Dept Only, Excluding Station Use) 26

1,758,964 Total Energy Losses 27 30,041,811 TOTAL (Enter Total of Lines 22 Through 27) (MUST EQUAL LINE 20) 28

FERC FORM NO. 1 (ED. 12-90) Page 401a(d) Day of Month Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of MONTHLY PEAKS AND OUTPUT Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Total Monthly Energy Megawatts (c) (b) (a) Hour (e) MONTHLY PEAK Month NAME OF SYSTEM: Monthly Non-Requirments Sales for Resale & Associated Losses (See Instr. 4) (1) Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required information for each non- integrated system. (2) Report on line 2 by month the system's output in Megawatt hours for each month. (3) Report on line 3 by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales. (4) Report on line 4 by month the system's monthly maximum megawatt load (60 minute integration) associated with the system. (5) Report on lines 5 and 6 the specified information for each monthly peak load reported on line 4.

(f) January 29 23 4,387 77,555 800 2,493,868 February 30 1 4,208 26,046 800 2,233,075 March 31 3 4,020 118,195 2000 2,282,856 April 32 21 3,931 135,640 1800 2,131,625 May 33 30 5,070 141,923 1700 2,442,735 June 34 26 5,647 230,066 1700 2,935,464 July 35 22 6,232 124,770 1700 3,188,514 August 36 4 6,472 111,095 1700 3,020,861 September 37 2 5,121 40,001 1600 2,407,511 October 38 1 4,075 120,438 1700 2,223,568 November 39 21 3,738 156,115 800 2,210,881 December 40 15 4,679 90,014 1900 2,470,853

FERC FORM NO. 1 (ED. 12-90) Page 401b 41 TOTAL 30,041,811 1,371,858HORSESHOE LAKE WOODWARD Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

STEAM & GAS TURBINE GAS TURBINE 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear CON & OB FO 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 1958 1963 3Year Originally Constructed 2000 1963 4Year Last Unit was Installed 973.90 11.50 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 898 12 6 Net Peak Demand on Plant - MW (60 minutes) 4033 11 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 60 0 11 Average Number of Employees 896249000 107000 12 Net Generation, Exclusive of Plant Use - KWh 144708 0 13 Cost of Plant: Land and Land Rights 18349707 20608 14Structures and Improvements 133570080 1195597 15Equipment Costs 238321 320 16Asset Retirement Costs 152302816 1216525 17Total Cost 156.3845 105.7848 18 Cost per KW of Installed Capacity (line 17/5) Including 723232 0 19 Production Expenses: Oper, Supv, & Engr 96724558 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 941082 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 805352 11 25Electric Expenses 4078427 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 552580 6002 29Maintenance Supervision and Engineering 276892 0 30Maintenance of Structures 1266219 0 31 Maintenance of Boiler (or reactor) Plant 1404598 2428 32 Maintenance of Electric Plant 31578 0 33Maintenance of Misc Steam (or Nuclear) Plant 106804518 8441 34Total Production Expenses 0.1192 0.0789 35Expenses per Net KWh Gas Gas 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) MCF MCF 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 1989 0 0 9854405 0 0 38Quantity (Units) of Fuel Burned 1037000 0 0 1037000 0 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 9.815 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.009 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.108 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 19084.000 0.000 0.000 11407.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402MUSTANG MUSKOGEE Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

STEAM & GAS TURBINE STEAM 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear OB CON & OB 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 1950 1956 3Year Originally Constructed 1971 1984 4Year Last Unit was Installed 613.60 1890.60 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 440 1771 6 Net Peak Demand on Plant - MW (60 minutes) 5168 7810 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 25 188 11 Average Number of Employees 775709000 10040730000 12 Net Generation, Exclusive of Plant Use - KWh 129878 1977193 13 Cost of Plant: Land and Land Rights 12129457 80926223 14Structures and Improvements 92225609 669389898 15Equipment Costs 214088 607053 16Asset Retirement Costs 104699032 752900367 17Total Cost 170.6308 398.2336 18 Cost per KW of Installed Capacity (line 17/5) Including 812014 1507061 19 Production Expenses: Oper, Supv, & Engr 73498838 146405532 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 81343 2592301 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 162852 2010948 25Electric Expenses 1697192 9162098 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 770089 912629 29Maintenance Supervision and Engineering 277696 1157743 30Maintenance of Structures 1206852 12239853 31 Maintenance of Boiler (or reactor) Plant 523688 9616856 32Maintenance of Electric Plant 34876 186620 33Maintenance of Misc Steam (or Nuclear) Plant 79065440 185791641 34Total Production Expenses 0.1019 0.0185 35Expenses per Net KWh Coal Gas Gas Oil 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Tons MCF MCF BBLS 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 5836557 3682025 0 7969730 59 0 38Quantity (Units) of Fuel Burned 17582000 5368698 0 1037000 5324914 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 20.920 6.601 0.000 9.219 373.723 0.000 41 Average Cost of Fuel per Unit Burned 0.001 0.007 0.000 0.009 0.072 0.000 42Average Cost of Fuel Burned per Million BTU 0.018 0.104 0.000 0.095 0.711 0.000 43Average Cost of Fuel Burned per KWh Net Gen 10459.000 15951.000 0.000 10763.000 9935.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.3Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.4Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.5Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.6Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.7Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.8Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.9Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.10Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.11Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (b) (a) (c) Plant Name: Plant Name: STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) 1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one fuel is burned in a plant furnish only the composite heat rate for all fuels burned.

1 Kind of Plant (Internal Comb, Gas Turb, Nuclear 2 Type of Constr (Conventional, Outdoor, Boiler, etc) 3Year Originally Constructed 4Year Last Unit was Installed 0.00 0.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0 0 6 Net Peak Demand on Plant - MW (60 minutes) 0 0 7 Plant Hours Connected to Load 0 0 8 Net Continuous Plant Capability (Megawatts) 0 0 9When Not Limited by Condenser Water 0 0 10When Limited by Condenser Water 0 0 11 Average Number of Employees 0 0 12 Net Generation, Exclusive of Plant Use - KWh 0 0 13 Cost of Plant: Land and Land Rights 0 0 14Structures and Improvements 0 0 15Equipment Costs 0 0 16Asset Retirement Costs 0 0 17Total Cost 0.0000 0.0000 18 Cost per KW of Installed Capacity (line 17/5) Including 0 0 19 Production Expenses: Oper, Supv, & Engr 0 0 20Fuel 0 0 21 Coolants and Water (Nuclear Plants Only) 0 0 22Steam Expenses 0 0 23Steam From Other Sources 0 0 24Steam Transferred (Cr) 0 0 25Electric Expenses 0 0 26Misc Steam (or Nuclear) Power Expenses 0 0 27Rents 0 0 28Allowances 0 0 29Maintenance Supervision and Engineering 0 0 30Maintenance of Structures 0 0 31 Maintenance of Boiler (or reactor) Plant 0 0 32Maintenance of Electric Plant 0 0 33Maintenance of Misc Steam (or Nuclear) Plant 0 0 34Total Production Expenses 0.0000 0.0000 35Expenses per Net KWh 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) 37Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) 00 0 00 0 38Quantity (Units) of Fuel Burned 00 0 00 0 39Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0.000 0.000 0.000 0.000 0.000 0.000 40Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000 42Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000 43Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000 44Average BTU per KWh Net Generation

FERC FORM NO. 1 (REV. 12-03) Page402.129. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

ENID SOONER SEMINOLE Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

GAS TURBINE STEAM & GAS TURBINE STEAM 1 FO CON & OB CON & OB 2 1965 1971 1979 3 1965 1975 1980 4 60.00 1724.60 1137.60 5 35 1475 1074 6 13 7291 8457 7 0 0 0 8 0 0 0 9 0 0 0 10 0 73 127 11 200000 3336026000 7708494000 12 0 1318360 7829788 13 62485 26170641 103938175 14 5200660 177315254 427928980 15 320 208795 123042 16 5263465 205013050 539819985 17 87.7244 118.8757 474.5253 18 325 961559 1106452 19 41209 328507645 88415968 20 0 0 0 21 0 1037792 2213402 22 0 0 0 23 0 0 0 24 0 918503 1447168 25 0 4334073 4458866 26 0 0 0 27 0 0 0 28 2083 976559 2407163 29 0 240813 335835 30 0 3077254 7276562 31 2939 3176593 3650898 32 0 49464 159593 33 46556 343280255 111471907 34 0.2328 0.1029 0.0145 35 Gas Gas Coal Oil 36 MCF MCF Tons BBLS 37 37163017 0 0 4003 0 0 4510024 12813 0 38 1037000 0 0 1037000 0 0 17584000 5368698 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 8.840 0.000 0.000 10.295 0.000 0.000 19.349 89.706 0.000 41 0.008 0.000 0.000 0.010 0.000 0.000 0.001 0.015 0.000 42 0.098 0.000 0.000 0.206 0.000 0.000 0.011 0.149 0.000 43 11594.000 0.000 0.000 20135.000 0.000 0.000 10299.000 9668.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page4039. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant.

REDBUD MCCLAIN Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

COMBINED CYCLE COMBINED CYCLE 1 2 2001 2003 3 2001 2003 4 0.00 424.50 1200.00 5 0 543 1303 6 0 6211 1805 7 0 0 0 8 0 0 0 9 0 0 0 10 0 24 25 11 0 1893134000 616653000 12 0 489856 326890 13 0 5406142 39368554 14 0 171643384 299407676 15 0 0 0 16 0 177539382 339103120 17 0.0000 418.2318 282.5859 18 0 4473006 65379 19 0 115203618 16927898 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 3652176 435165 25 0 1203273 161418 26 0 0 0 27 0 0 0 28 0 293449 59706 29 0 520524 0 30 0 0 0 31 0 4304338 473952 32 0 535803 448 33 0 130186187 18123966 34 0.0000 0.0688 0.0294 35 Gas Gas 36 MCF MCF 37 13147501 0 0 000 4316949 0 0 38 1037000 0 0 000 1037000 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 8.762 0.000 0.000 0.000 0.000 0.000 3.921 0.000 0.000 41 0.009 0.000 0.000 0.000 0.000 0.000 0.004 0.000 0.000 42 0.061 0.000 0.000 0.000 0.000 0.000 0.027 0.000 0.000 43 7108.000 0.000 0.000 0.000 0.000 0.000 7305.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.19. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.29. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.39. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.49. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.59. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.69. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.79. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.89. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.99. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.109. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.119. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos. 547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the report period and other physical and operating characteristics of plant. Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (e) (f) Plant Name: Plant Name: (d) Plant Name: (Continued)

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 0 0 0 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 0 0 0 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0.0000 0.0000 0.0000 18 0 0 0 19 0 0 0 20 0 0 0 21 0 0 0 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35 36 37 0 0 0 000 0 0 0 38 0 0 0 000 0 0 0 39 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page403.12

### Schedule Page: 402 Line No.: 11 Column: b Personnel assigned as required. Schedule Page: 402 Line No.: 11 Column: f Operated by remote control from Sooner Station. Schedule Page: 402.1 Line No.: 2 Column: d The McClain Plant is a jointly owned power plant of which 77% is owned by Oklahoma Gas and Electric Company. Schedule Page: 402.1 Line No.: 2 Column: e The Redbud Plant is a jointly owned power plant of which 51% is owned by Oklahoma Gas and Electric Company. Name of Respondent

Oklahoma Gas and Electric Company 

### This Report is: (1)XAn Original (2) A Resubmission Date of Report (Mo, Da, Yr) / / 

### Year/Period of Report

2008/Q4 FOOTNOTE DATA



### FERC FORM NO. 1 (ED. 12-87) Page 450.10 0 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item FERC Licensed Project No. (b) (a) (c) Plant Name: FERC Licensed Project No. Plant Name: 1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. If licensed project, give project number. 3. If net peak demand for 60 minutes is not available, give that which is available specifying period. 4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each plant.

Kind of Plant (Run-of-River or Storage)

1 Plant Construction type (Conventional or Outdoor) 2 Year Originally Constructed 3Year Last Unit was Installed 4Total installed cap (Gen name plate Rating in MW) 5 0.00 0.00 Net Peak Demand on Plant-Megawatts (60 minutes) 6 0 0 Plant Hours Connect to Load 7 0 0 Net Plant Capability (in megawatts) 8(a) Under Most Favorable Oper Conditions 9 0 0 (b) Under the Most Adverse Oper Conditions 10 0 0 Average Number of Employees 11 0 0 Net Generation, Exclusive of Plant Use - Kwh 12 0 0 Cost of Plant 13Land and Land Rights 14 0 0 Structures and Improvements 15 0 0 Reservoirs, Dams, and Waterways 16 0 0 Equipment Costs 17 0 0 Roads, Railroads, and Bridges 18 0 0 Asset Retirement Costs 19 0 0 TOTAL cost (Total of 14 thru 19) 20 0 0 Cost per KW of Installed Capacity (line 20 / 5) 21 0.0000 0.0000 Production Expenses 22Operation Supervision and Engineering 23 0 0 Water for Power 24 0 0 Hydraulic Expenses 25 0 0 Electric Expenses 26 0 0 Misc Hydraulic Power Generation Expenses 27 0 0 Rents 28 0 0 Maintenance Supervision and Engineering 29 0 0 Maintenance of Structures 30 0 0 Maintenance of Reservoirs, Dams, and Waterways 31 0 0 Maintenance of Electric Plant 32 0 0 Maintenance of Misc Hydraulic Plant 33 0 0 Total Production Expenses (total 23 thru 33) 34 0 0 Expenses per net KWh 35 0.0000 0.0000

FERC FORM NO. 1 (REV. 12-03) Page4060 0 0 Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

FERC Licensed Project No. (e) (d) (f) Plant Name: FERC Licensed Project No. Plant Name: FERC Licensed Project No. Plant Name: Line No. 5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses." 6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.

1 2 3 4 0.00 0.00 0.00 5 0 0 0 6 0 0 0 7 8 0 0 0 9 0 0 0 10 0 0 0 11 0 0 0 12 13 0 0 0 14 0 0 0 15 0 0 0 16 0 0 0 17 0 0 0 18 0 0 0 19 0 0 0 20 0.0000 0.0000 0.0000 21 22 0 0 0 23 0 0 0 24 0 0 0 25 0 0 0 26 0 0 0 27 0 0 0 28 0 0 0 29 0 0 0 30 0 0 0 31 0 0 0 32 0 0 0 33 0 0 0 34 0.0000 0.0000 0.0000 35

FERC FORM NO. 1 (REV. 12-03) Page407FERC Licensed Project No. Plant Name: (b) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Item (a) 1. Large plants and pumped storage plants of 10,000 Kw or more of installed capacity (name plate ratings) 2. If any plant is leased, operating under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a footnote. Give project number. 3. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 4. If a group of employees attends more than one generating plant, report on line 8 the approximate average number of employees assignable to each plant. 5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses do not include Purchased Power System Control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."

1 Type of Plant Construction (Conventional or Outdoor) 2 Year Originally Constructed 3Year Last Unit was Installed 4Total installed cap (Gen name plate Rating in MW) 5 Net Peak Demaind on Plant-Megawatts (60 minutes) 6 Plant Hours Connect to Load While Generating 7 Net Plant Capability (in megawatts) 8 Average Number of Employees 9 Generation, Exclusive of Plant Use - Kwh 10 Energy Used for Pumping 11 Net Output for Load (line 9 - line 10) - Kwh 12 Cost of Plant 13Land and Land Rights 14Structures and Improvements 15Reservoirs, Dams, and Waterways 16Water Wheels, Turbines, and Generators 17Accessory Electric Equipment 18Miscellaneous Powerplant Equipment 19Roads, Railroads, and Bridges 20Asset Retirement Costs 21 Total cost (total 13 thru 20) 22Cost per KW of installed cap (line 21 / 4) 23 Production Expenses 24Operation Supervision and Engineering 25Water for Power 26Pumped Storage Expenses 27Electric Expenses 28Misc Pumped Storage Power generation Expenses 29Rents 30Maintenance Supervision and Engineering 31 Maintenance of Structures 32Maintenance of Reservoirs, Dams, and Waterways 33Maintenance of Electric Plant 34Maintenance of Misc Pumped Storage Plant 35Production Exp Before Pumping Exp (24 thru 34) 36Pumping Expenses 37Total Production Exp (total 35 and 36) 38Expenses per KWh (line 37 / 9)

FERC FORM NO. 1 (REV. 12-03) Page408FERC Licensed Project No. Plant Name: FERC Licensed Project No. Plant Name: (d) Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of PUMPED STORAGE GENERATING PLANT STATISTICS (Large Plants) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. FERC Licensed Project No. Plant Name: (e) (c) 6. Pumping energy (Line 10) is that energy measured as input to the plant for pumping purposes. 7. Include on Line 36 the cost of energy used in pumping into the storage reservoir. When this item cannot be accurately computed leave Lines 36, 37 and 38 blank and describe at the bottom of the schedule the company's principal sources of pumping power, the estimated amounts of energy from each station or other source that individually provides more than 10 percent of the total energy used for pumping, and production expenses per net MWH as reported herein for each source described. Group together stations and other resources which individually provide less than 10 percent of total pumping energy. If contracts are made with others to purchase power for pumping, give the supplier contract number, and date of contract.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38

FERC FORM NO. 1 (REV. 12-03) Page409Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of GENERATING PLANT STATISTICS (Small Plants) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name of Plant Installed Capacity

(c) (b) (a) Cost of Plant Net Peak Demand

(d) Year Orig. Const. Name Plate Rating (In MW) MW (60 min.) Net Generation Excluding Plant Use (e) (f) 1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give project number in footnote.

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (REV. 12-03) Page 410Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of GENERATING PLANT STATISTICS (Small Plants) (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (i) (h) (g) (j) (k) (l) Operation Exc'l. Fuel Production Expenses Fuel Maintenance Kind of Fuel Fuel Costs (in cents (per Million Btu) 3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11, Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset Retire. Costs) Per MW

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46

FERC FORM NO. 1 (REV. 12-03) Page 411Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

TRANSMISSION LINE STATISTICS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No.

(c) (b) (a) (d) (e) DESIGNATION

From To (f) (g) VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase)

Operating Designed Type of Supporting Structure LENGTH (Pole miles) (In the case of underground lines report circuit miles) On Structure of Line Designated On Structures of Another Line Number Of Circuits

(h) 1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated.

(3) Tower 500.00 500.00 46.85 1 1 Blue Mtn Lake Ft Smith 2 (3) Tower 345.00 345.00 44.29 210.39 1 3Pittsburgh Muskogee (3) Tower 345.00 345.00 64.29 1 4Kendrick Cimarron (3) Tower 345.00 345.00 2.68 89.11 1 5Cimarron Draper Lake (3) Wood 345.00 345.00 106.57 1 6Cimarron Kansas Border (3) Tower 345.00 345.00 44.46 44.46 1 7Draper Lake Seminole (3) Wood 345.00 345.00 40.29 1 8Seminole Plant Ashland (3) Tower 345.00 345.00 15.86 1 9Draper Lake Horseshoe Lake (3) Tower 345.00 345.00 55.30 69.64 1 10Seminole Plant Horseshoe Lake (3) Tower 345.00 345.00 3.61 32.02 1 11 Pecan Creek Riverside (3) Wood 345.00 345.00 43.18 1 12Sooner Woodring (3) Tower 345.00 345.00 69.58 2 13Northwest Sooner (3) Tower 345.00 345.00 5.09 1 14RedBud Arcadia 15 16 (2) Wood 161.00 161.00 48.86 1 17AES Cogen Fort Smith (2) Wood 161.00 161.00 28.30 1 18Muskogee Pecan Creek (2) Wood 161.00 161.00 24.30 1 19Muskogee Boudinot Tap (2) Wood 161.00 161.00 4.73 1 20Muskogee SPA Tap (2) Wood 161.00 161.00 9.17 1 21 VBI Massard (1) Wood 161.00 161.00 9.24 1 22VBI Third Street (1) Wood 161.00 161.00 6.86 1 23Fort Smith Third Street (1) Wood 161.00 161.00 15.79 1 24Fort Smith Massard (1) Steel 161.00 161.00 0.55 1 25Macksteel Tap Macksteel #2 (1) Wood 161.00 161.00 4.38 1 26Fort Smith Quanex (1) Wood 161.00 161.00 0.84 1 27Muskogee Tie North/South (1) Wood 161.00 161.00 0.13 1 28Grand Prairie Tap Grand Prairie (AVEC) (1) Wood 161.00 161.00 31.32 1 29VBI Helberg (1) Steel 161.00 161.00 5.96 1 30Little Spadra Spadra Clarkesville (1) Steel 161.00 161.00 1.78 1 31 Muskogee Port Tap Muskogee Port (1) Steel 161.00 161.00 0.40 1 32Gerber Tap Gerber Rd Tap 33 (2) Wood 154.00 154.00 34Arklahoma Danville 35

FERC FORM NO. 1 (ED. 12-87) Page 422

36 TOTAL 4,306.43 343.63 63Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

TRANSMISSION LINE STATISTICS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No.

(c) (b) (a) (d) (e) DESIGNATION

From To (f) (g) VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase)

Operating Designed Type of Supporting Structure LENGTH (Pole miles) (In the case of underground lines report circuit miles) On Structure of Line Designated On Structures of Another Line Number Of Circuits

(h) 1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated.

(2) Wood 138.00 138.00 49.00 1 1 Osage S 4th St Enid (2) Wood 138.00 138.00 50.38 380.02 1 2Horseshoe Lake Draper (2) Wood 138.00 138.00 39.48 1 3Horseshoe Lake Maud Tap (2) Wood 138.00 138.00 6.34 63.75 1 4Arbuckle Seminole (2) Wood 138.00 138.00 32.08 234.50 1 5Horseshoe Lake Sooner (2) Wood 138.00 138.00 34.26 1 6Osage KG&E (2) Wood 138.00 138.00 5.74 134.08 1 7Horseshoe Lake Pecan Creek (2) Wood 138.00 138.00 5.06 48.15 1 8Bristow Riverside (2) Wood 138.00 138.00 1.43 223.60 1 9Earlywine Sunnyside (2) Wood 138.00 138.00 31.28 1 10Arbuckle Chickasaw (2) Wood 138.00 138.00 2.72 8.70 1 11 Cimarron Cornville (2) Wood 138.00 138.00 38.54 1 12Chicasaw Russet (2) Wood 138.00 138.00 19.67 1 13Osage Shidler (2) Wood 138.00 138.00 58.44 1 14Maud Tap Paoli (2) Wood 138.00 138.00 61.76 1 15Arbuckle Brown Tap (2) Wood 138.00 138.00 4.30 57.00 1 16Woodward District Cleo Corner (2) Wood 138.00 138.00 26.06 1 17Bristow Cushing (2) Wood 138.00 138.00 41.35 1 18Brown Durant Area (1) Wood 138.00 138.00 1.43 1 19Seminole PSO Fixico Sub (2) Wood 138.00 138.00 80.07 1 20El Reno WFEC@Taloga (2) Wood 138.00 138.00 22.73 1 21 Park Lane Arbuckle (2) Wood 138.00 138.00 30.96 1 22Cleo Sub S 4th St Sub (2) Wood 138.00 138.00 16.50 1 23Glenwood Woodring (2) Steel 138.00 138.00 6.73 1 24Breckinridge Tap NE Enid Sub (1) Wood 138.00 138.00 23.47 1 25Dewey Iodine (2) Steel 138.00 138.00 1.55 1 26Polecat Creek Tap Polecat Creek Sub (2) Steel 138.00 138.00 2.05 1 27SE 15th Glendale Sub (1) Steel 138.00 138.00 8.07 1 28NE Enid Glenwood (1) Steel 138.00 138.00 7.99 1 29Richards Piedmont (1) Steel 138.00 138.00 1.27 17.77 1 30Woodward Iodine (1) Steel 138.00 138.00 33.17 1 31 Centennial Woodward (1) Steel 138.00 138.00 5.39 1 32Arcadia Tap Louis Garber (1) Steel 138.00 138.00 2.71 1 33Enid Industrial Tap Enid Industrial 34 69.00 69.00 83.97 1,466.26 3569 KV

FERC FORM NO. 1 (ED. 12-87) Page 422.1

36 TOTAL 4,306.43 343.63 63Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

TRANSMISSION LINE STATISTICS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No.

(c) (b) (a) (d) (e) DESIGNATION

From To (f) (g) VOLTAGE (KV) (Indicate where other than 60 cycle, 3 phase)

Operating Designed Type of Supporting Structure LENGTH (Pole miles) (In the case of underground lines report circuit miles) On Structure of Line Designated On Structures of Another Line Number Of Circuits

(h) 1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132 kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage. 2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report substation costs and expenses on this page. 3. Report data by individual lines for all voltages if so required by a State commission. 4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property. 5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder of the line. 6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with respect to such structures are included in the expenses reported for the line designated.

1 Undistributed Rents 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35

FERC FORM NO. 1 (ED. 12-87) Page 422.2

36 TOTAL 4,306.43 343.63 63Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION LINE STATISTICS (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material Land rights, and clearing right-of-way) EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation Expenses Maintenance Rents Total Land Construction and Other Costs Total Cost (i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. 9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. 10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.

3,289,556 1024500ACSR 3,109,820 179,736 217,226 84,344 132,882 1 2 37,003,153 2167000ACSR 33,459,325 3,543,828 3,665,148 1,423,090 2,242,058 3 4,877,093 2167000ACSR 4,435,094 441,999 4 14,490,198 795000ACSR 11,846,095 2,644,103 5 22,986,982 795000ACSR 22,638,629 348,353 6 4,240,816 795000ACSR 4,015,837 224,979 7 3,119,521 795000ACSR 2,968,550 150,971 8 2,205,513 795000ACSR 1,889,128 316,385 9 6,465,568 795000ACSR 6,109,989 355,579 10 7,184,792 795000ACSR 6,766,743 418,049 11 15,095,313 795000ACSR 14,703,831 391,482 12 18,562,816 795000ACSR 17,438,108 1,124,708 13 175,274 795000ACSR 12,352 162,922 14 15 16 4,769,738 477000ACSR 4,329,961 439,777 893,060 346,754 546,306 17 3,229,909 795000ACSR 3,060,769 169,140 18 784,425 636000ACSR 753,655 30,770 19 180,890 636000ACSR 173,280 7,610 20 988,895 636000ACSR 926,300 62,595 21 2,136,765 636000ACSR 2,122,819 13,946 22 1,177,352 795000ACSR 1,141,655 35,697 23 1,189,145 795000ACSR 1,119,645 69,500 24 333,245 795AS22ACSR 330,740 2,505 25 3,180,372 1590000ACSR 2,376,604 803,768 26 230,287 477AS33ACSR 230,287 27 161,550 477000ACSR 161,550 28 5,914,453 795AS33ACSR 5,328,682 585,771 29 4,330,450 795AS33ACSR 3,699,297 631,153 30 1,453,603 795AS33ACSR 1,345,848 107,755 31 156,952 477AS33 156,952 32 33 505,136 250V12CU 505,035 101 34 35

FERC FORM NO. 1 (ED. 12-87) Page 423 36 27,700,255 450,442,883 478,143,138 12,226,088 7,760,203 1,418 19,987,709Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION LINE STATISTICS (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material Land rights, and clearing right-of-way) EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation Expenses Maintenance Rents Total Land Construction and Other Costs Total Cost (i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. 9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. 10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.

3,073,890 3364000ACSR 2,853,491 220,399 8,412,363 3,266,321 5,146,042 1 56,873,508 795000ACSR 54,574,343 2,299,165 2 2,616,502 336400ACSR 2,526,687 89,815 3 3,251,180 336400ACSR 3,167,636 83,544 4 34,057,813 477000ACSR 32,947,613 1,110,200 5 1,726,409 477000ACSR 1,650,747 75,662 6 8,226,848 636000ACSR 7,908,632 318,216 7 8,671,529 795000ACSR 7,951,791 719,738 8 20,819,533 795000ACSR 19,734,574 1,084,959 9 2,541,355 477000ACSR 2,367,904 173,451 10 296,345 795000ACSR 259,870 36,475 11 3,020,298 477000ACSR 2,875,556 144,742 12 664,539 477000ACSR 641,761 22,778 13 3,501,237 795000ACSR 3,303,782 197,455 14 3,033,540 477000ACSR 2,900,658 132,882 15 1,199,037 266800ACSR 1,150,200 48,837 16 1,168,428 477000ACSR 1,106,913 61,515 17 2,484,156 477000ACSR 2,394,666 89,490 18 160,413 477000ACSR 71,610 88,803 19 5,672,102 477000ACSR 5,265,569 406,533 20 835,140 795000ACSR 821,150 13,990 21 1,658,700 795000ACSR 1,595,192 63,508 22 2,543,636 795000ACSR 2,350,428 193,208 23 1,373,381 795000ACSR 1,318,080 55,301 24 1,142,156 795000ACSR 1,059,872 82,284 25 733,341 477000ACSR 732,828 513 26 792,404 795000ACSR 558,618 233,786 27 2,778,639 795000ACSR 2,761,879 16,760 28 4,291,440 795000ACSR 2,865,011 1,426,429 29 6,080,750 795000ACSR 5,457,032 623,718 30 9,593,053 47700ACSR 9,391,133 201,920 31 242,812 795000ACSR 242,812 32 1,311,719 795000ACSR 1,240,584 71,135 33 34 111,287,543 107,237,681 4,049,862 6,798,494 2,639,694 4,158,800 35

FERC FORM NO. 1 (ED. 12-87) Page 423.1 36 27,700,255 450,442,883 478,143,138 12,226,088 7,760,203 1,418 19,987,709Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION LINE STATISTICS (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. COST OF LINE (Include in Column (j) Land, Size of Conductor and Material Land rights, and clearing right-of-way) EXPENSES, EXCEPT DEPRECIATION AND TAXES

Operation Expenses Maintenance Rents Total Land Construction and Other Costs Total Cost (i) (j) (k) (l) (m) (n) (o) (p) Expenses Expenses 7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g) 8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company. 9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how determined. Specify whether lessee is an associated company. 10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.

1,418 1,418 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35

FERC FORM NO. 1 (ED. 12-87) Page 423.2 36 27,700,255 450,442,883 478,143,138 12,226,088 7,760,203 1,418 19,987,709Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of

TRANSMISSION LINES ADDED DURING YEAR Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (c) (b) (a) (d) (e) LINE DESIGNATION From To Line Length

in Miles SUPPORTING STRUCTURE Type Average Number per Miles CIRCUITS PER STRUCTURE Present Ultimate

(f) (g) 

### 1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report minor revisions of lines. 2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the

15.04 Steel 1 1 1Various 69 KV Lines 15.44 12.45 Steel 1 1 2Enid Industrial Tap Enid Industrial 2.71 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43

18.15 27.49 2 2 FERC FORM NO. 1 (REV. 12-03) Page 424 44 TOTALTotal Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of TRANSMISSION LINES ADDED DURING YEAR (Continued) Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. (k) (j) (h) (l) (m) CONDUCTORS Size Configuration Voltage KV LINE COST Land and Poles, Towers and Fixtures Conductors (n) (p) Specification and Spacing (Operating) Land Rights and Devices (i) 

### costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m). 3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate such other characteristic.

Asset (o) Retire. Costs
ACSR Various 2,366,895 7,785,072 5,399,575 18,602 69 1 ACSR 795AS33 735,483 1,311,719 505,101 71,135 138 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43

3,102,378 5,904,676

FERC FORM NO. 1 (REV. 12-03) Page 425 44 89,737 9,096,791Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).

RIVERSIDE NWC SW 20-15N-19E OK 12.50 69.00 Distribution-Unatten 1 FIVE TRIBES NE NE 4-14N-18E OK 69.00 161.00 13.20 Transmission-Unatten 2 TENNYSON NE SE 28-15N-18E OK 12.50 69.00 Distribution-Unatten 3 CALLERY NW SW SW 28-15N-19E OK 12.50 69.00 Distribution-Unatten 4 MUSKOGEE STA SE NW 21-15N-19E OK 69.00 161.00 13.80 Transmission-Unatten 5 HANCOCK LOT3 1-14N-18E OK 12.50 161.00 Distribution-Unatten 6 HANCOCK LOT3 1-14N-18E OK 34.50 161.00 Distribution-Unatten 7 EUCLID NW SE 14-16N-18E OK 12.50 161.00 Distribution-Unatten 8 AGENCY NE SE 17-15N-18E OK 34.50 161.00 Distribution-Unatten 9 AGENCY NE SE 17-15N-18E OK 69.00 161.00 13.20 Transmission-Unatten 10 PECAN CREEK SE 2-14N-17E OK 138.00 161.00 13.20 Transmission-Unatten 11 PECAN CREEK SE 2-14N-17E OK 161.00 345.00 13.80 Transmission-Unatten 12 SAPULPA NW NE 35-18N-11E OK 12.50 69.00 Distribution-Unatten 13 TIBBENS RD SE SW SE 33-18N-12E OK 13.09 138.00 Distribution-Unatten 14 BIXBY SE NE 33-17N-13E OK 12.50 69.00 Distribution-Unatten 15 HICKORY HILL NW SW 20-18N-12E OK 12.50 138.00 Distribution-Unatten 16 BLUEBELL SWC SE SW 26-18N-10E OK 69.00 138.00 13.20 Transmission-Unatten 17 BOWDEN NW NE 13-18N-11E OK 12.50 138.00 Distribution-Unatten 18 LONE STAR SE SE 10-17N-11E OK 12.50 138.00 Distribution-Unatten 19 BEELINE E1/2 NE NE 10-17N-12E OK 12.50 138.00 Distribution-Unatten 20 BEELINE E1/2 NE NE 10-17N-12E OK 69.00 138.00 13.80 Transmission-Unatten 21 POLECAT CREEK SW 1/4 SEC 28, T-18-N, R12E OK 6.90 138.00 Distribution-Unatten 22 KELLYVILLE PT OF NE1/4 NE1/4,SEC.12 T17N,R10E OK 12.50 138.00 Distribution-Unatten 23 CHECOTAH SWC SW 32-12N-17E OK 12.50 69.00 Distribution-Unatten 24 ROSS LAKE SW SW 13-15N-9E OK 12.50 161.00 Distribution-Unatten 25 WELLS SE NE 11-10N-16E OK 24.00 69.00 Distribution-Unatten 26 POTEAU SE SE 26-7N-25E OK 12.50 69.00 Distribution-Unatten 27 CAVANAL MTN NE SE 14-7N-25E OK 12.50 69.00 Distribution-Unatten 28 PANAMA NEC 8-8N-25E OK 12.50 69.00 Distribution-Unatten 29 PANAMA NEC 8-8N-25E OK 24.00 69.00 Distribution-Unatten 30 HEAVENER SWC SE SE 18-5N-26E OK 12.50 69.00 Distribution-Unatten 31 TARBY NE NE 2-7N-25E OK 69.00 161.00 13.20 Transmission-Unatten 32 MULDROW NE NE 30-11N-26E OK 12.50 69.00 Distribution-Unatten 33 ENID SW SE 7-22N-6W OK 4.16 69.00 Distribution-Unatten 34 ENID SW SE 7-22N-6W OK 12.50 69.00 Distribution-Unatten 35 HEMLOCK SW NW & NW SW 5-22N-6W OK 12.50 69.00 Distribution-Unatten 36 CLEVELAND AVE SW SW 12-22N-7W OK 4.16 12.50 Distribution-Unatten 37 CLEVELAND AVE SW SW 12-22N-7W OK 12.50 69.00 Distribution-Unatten 38 WOODRING NW NE 1-21N-6W OK 138.00 345.00 13.80 Transmission-Unatten 39 CHESTNUT NW NW 10-22N-6W OK 12.50 69.00 Distribution-Unatten 40

FERC FORM NO. 1 (ED. 12-96) Page 426Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).

GLENWOOD NW SW 3-22N-7W OK 12.50 138.00 Distribution-Unatten 1 SO 4TH ST SEC NE 19-22N-6W OK 13.80 69.00 Distribution-Unatten 2 SO 4TH ST SEC NE 19-22N-6W OK 12.50 138.00 Distribution-Unatten 3 SO 4TH ST SEC NE 19-22N-6W OK 69.00 138.00 13.20 Transmission-Unatten 4 IMO SW SE SEC 16-22N-7W OK 69.00 138.00 13.20 Transmission-Unatten 5 NE ENID NW,SW,SEC 26,T23N,R6W OK 12.50 138.00 Distribution-Unatten 6 NE ENID NW,SW,SEC 26,T23N,R6W OK 69.00 138.00 13.20 Transmission-Unatten 7 FAIRMONT NE NW 20-22N-5W OK 12.50 138.00 Distribution-Unatten 8 OSAGE SW SW 11-25N-2E OK 69.00 138.00 13.20 Transmission-Unatten 9 SOONER STA NE 26-23N-2E OK 138.00 345.00 13.80 Transmission-Unatten 10 CHIKASKIA SW 13-27N-1W OK 69.00 138.00 13.20 Transmission-Unatten 11 COW CREEK SW NW 35-21N-1W OK 69.00 138.00 Transmission-Unatten 12 HENNESSEY SW NW 24-19N-7W OK 12.50 138.00 Distribution-Unatten 13 CLEO CORNER NEC 24-22N-12W OK 69.00 138.00 13.80 Transmission-Unatten 14 CEDAR AVE NW NE SE 36-23N-21W OK 12.50 69.00 Distribution-Unatten 15 WOODWARD DISTRICT W1/2 NW20-22N-20W OK 69.00 138.00 13.20 Transmission-Unatten 16 NEWMAN AVE SE NW SW SW 22-21N-25W OK 12.50 24.00 Distribution-Unatten 17 NEWMAN AVE SE NW SW SW 22-21N-25W OK 24.00 69.00 Distribution-Unatten 18 CENTENNIAL NE 1/4 OF NE1/4,SEC8,T19N,R19W 34.50 138.00 Transmission-Unatten 19 IODINE NE1/4 OF NE1/4,SEC 8,T19N,R19W OK 12.50 24.00 Distribution-Unatten 20 IODINE NE1/4 OF NE1/4,SEC 8,T19N,R19W OK 12.50 138.00 Distribution-Unatten 21 ALVA SW NW NW 24-27N-14W OK 4.16 69.00 Distribution-Unatten 22 ALVA SW NW NW 24-27N-14W OK 12.50 69.00 Distribution-Unatten 23 KNOBHILL E 1/2 SE-25-27N-14W OK 12.50 69.00 Distribution-Unatten 24 KNOBHILL E 1/2 SE-25-27N-14W OK 69.00 138.00 13.20 Transmission-Unatten 25 FOUNDATION PART OF NW1/4,SW1/4,SEC27,TTS,R2E OK 12.50 138.00 Distribution-Unatten 26 ARDMORE NE NE 31-4S-2E OK 4.16 69.00 Distribution-Unatten 27 ARDMORE NE NE 31-4S-2E OK 12.50 69.00 Distribution-Unatten 28 HARRIS ST NE NW 19-4S-2E OK 12.50 69.00 Distribution-Unatten 29 TOWER HEIGHTS SE4 25-4S-1E OK 12.50 69.00 Distribution-Unatten 30 MARIETTA NE4 SEC 19-7S-2E OK 12.50 69.00 Distribution-Unatten 31 CHICKASAW NW,SEC 21-4S-2E OK 69.00 138.00 13.20 Transmission-Unatten 32 DILLARD SW SEC 27-4S-2W OK 12.50 24.00 Distribution-Unatten 33 DILLARD SW SEC 27-4S-2W OK 12.50 34.50 Distribution-Unatten 34 DILLARD SW SEC 27-4S-2W OK 12.50 138.00 Distribution-Unatten 35 BERWYN NW NW 14-3S-2E OK 12.50 138.00 Distribution-Unatten 36 LONE GROVE NE4 35-4S-1W OK 12.50 138.00 Distribution-Unatten 37 ROCKY POINT SW SW 18-5S-2E OK 69.00 138.00 13.20 Transmission-Unatten 38 SUNNYSIDE NW4 30-4S-1E OK 138.00 345.00 13.80 Transmission-Unatten 39 HEALDTON SE4 SEC 3-4S-3W OK 12.50 69.00 Distribution-Unatten 40

FERC FORM NO. 1 (ED. 12-96) Page 426.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).

COUNTY LINE SW SW 22-1S-3W OK 12.50 69.00 Distribution-Unatten 1 POOLEVILLE SW4 SEC 10-2S-2W OK 12.50 138.00 Distribution-Unatten 2 RATLIFF NW4 & NE4 22-1S-3W OK 12.50 138.00 Distribution-Unatten 3 RATLIFF NW4 & NE4 22-1S-3W OK 69.00 138.00 13.20 Transmission-Unatten 4 FOX SE4 26-2S-3W OK 12.50 138.00 Distribution-Unatten 5 HEALDTON TAP NE4 SEC 28-4S-3W OK 69.00 138.00 13.20 Transmission-Unatten 6 WILDHORSE NW4 7-1S-3W OK 12.50 69.00 Distribution-Unatten 7 DUNDEE SE NE 7-4S-3W OK 12.50 138.00 Distribution-Unatten 8 MADILL INDUSTRIAL SW 1/4,SEC 35,R5E,T5S 13.80 138.00 Distribution-Unatten 9 GLASSES SW4 26-5S-5E OK 12.50 138.00 Distribution-Unatten 10 BUTTERFIELD NE4 SEC 11,7S-8E OK 12.50 138.00 Distribution-Unatten 11 DURANT NE SE NE 32-6S-9E OK 4.16 34.50 Distribution-Unatten 12 DURANT NE SE NE 32-6S-9E OK 12.50 34.50 Distribution-Unatten 13 BODLE NEC SW NE 30-6S-9E OK 12.50 138.00 Distribution-Unatten 14 BODLE NEC SW NE 30-6S-9E OK 34.50 138.00 Distribution-Unatten 15 BROWN OG&E SWC SW 29-5S-8E OK 34.50 138.00 Distribution-Unatten 16 COLBERT NW NW 8-8S-8E OK 12.50 138.00 Distribution-Unatten 17 PAULS VALLEY SW SE 8-3N-1E OK 4.16 69.00 Distribution-Unatten 18 PAULS VALLEY SW SE 8-3N-1E OK 12.50 69.00 Distribution-Unatten 19 WALNUT CREEK SEC 14-6N-2W OK 12.50 138.00 Distribution-Unatten 20 PAOLI SEC NE NE 20-4N-1E OK 69.00 138.00 Transmission-Unatten 21 RUSH CREEK W SE SE 20-3N-1E OK 12.50 69.00 Distribution-Unatten 22 PRAIRIE POINT NWC NE 31-2N-2W OK 12.50 138.00 Distribution-Unatten 23 CHIGLEY NWC SW 24-2N-1E OK 69.00 138.00 13.20 Transmission-Unatten 24 SULPHUR SE4 34-1N-3E OK 12.50 69.00 Distribution-Unatten 25 MILL CREEK B145SW4 SEC 18-2S-5E OK 4.16 138.00 Distribution-Unatten 26 DAVIS NE NE 32-1N-2E OK 12.50 69.00 Distribution-Unatten 27 ARBUCKLE STA SE SE 27-1N-3E OK 69.00 138.00 13.20 Transmission-Unatten 28 JOLLYVILLE SW4 SEC9 1S-2E OK 12.50 34.50 Distribution-Unatten 29 JOLLYVILLE SW4 SEC9 1S-2E OK 34.50 138.00 Distribution-Unatten 30 VALLEY VIEW NW SW 26-4N-6E OK 12.50 69.00 Distribution-Unatten 31 AHLOSO NWC NW 11-3N-6E OK 12.50 69.00 Distribution-Unatten 32 HARDEN CITY NEC SE SE 30-2N-7E OK 4.16 69.00 Distribution-Unatten 33 HARDEN CITY NEC SE SE 30-2N-7E OK 12.50 69.00 Distribution-Unatten 34 PARK LANE NE SE SE 31-4N-6E OK 12.50 138.00 Distribution-Unatten 35 PARK LANE NE SE SE 31-4N-6E OK 69.00 138.00 13.20 Transmission-Unatten 36 LULA NW CORNER SEC 4,T-2-N,R8E OK 69.00 138.00 13.20 Transmission-Unatten 37 RUSSETT NW4 28-4S-5E OK 12.50 34.50 Distribution-Unatten 38 RUSSETT NW4 28-4S-5E OK 34.50 138.00 Distribution-Unatten 39 RUSSETT NW4 28-4S-5E OK 34.50 138.00 7.20 Distribution-Unatten 40

FERC FORM NO. 1 (ED. 12-96) Page 426.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).

CHANDLER NE NE 16-14N-4E OK 12.50 69.00 Distribution-Unatten 1 CHANDLER NE NE 16-14N-4E OK 24.00 69.00 Distribution-Unatten 2 KEY WEST NE NW NE 9-14N-6E OK 24.00 138.00 Distribution-Unatten 3 WARWICK SW SW 5-14N-3E OK 24.00 138.00 Distribution-Unatten 4 CYPRESS SW SE 1-7N-8E OK 12.50 69.00 Distribution-Unatten 5 FIXICO NE NE 21-9N-6E OK 24.00 69.00 Distribution-Unatten 6 FIXICO NE NE 21-9N-6E OK 12.50 138.00 Distribution-Unatten 7 FIXICO NE NE 21-9N-6E OK 24.00 138.00 Distribution-Unatten 8 FIXICO NE NE 21-9N-6E OK 69.00 138.00 13.20 Transmission-Unatten 9 SEMINOLE STA SE NW & SW NE 25-6N-5E OK 138.00 345.00 14.40 Transmission-Unatten 10 KOLACHE SEC SE SW 26-12N-6E OK 24.00 69.00 Distribution-Unatten 11 SHAWNEE NE SW 19-10N-4E OK 4.16 69.00 Distribution-Unatten 12 SHAWNEE NE SW 19-10N-4E OK 24.00 69.00 Distribution-Unatten 13 REMINGTON SWC NW 16-10N-4E OK 12.50 69.00 Distribution-Unatten 14 MCLOUD SEC 16-11N-2E OK 12.50 69.00 Distribution-Unatten 15 MAUD TAP SW SW 29-8N-5E OK 69.00 138.00 13.20 Transmission-Unatten 16 FOREST HILL SW SE 14-9N-3E OK 69.00 138.00 13.80 Transmission-Unatten 17 INGLEWOOD NE SW & NW SE 24-10N-3E OK 12.50 138.00 Distribution-Unatten 18 RUSHING SW NW 5-10N-4E OK 69.00 138.00 13.80 Transmission-Unatten 19 ST GREGORY SW SW NW 2-10N-3E OK 12.50 138.00 Distribution-Unatten 20 ROCK CREEK NE NE 31-11N-4E OK 12.50 138.00 Distribution-Unatten 21 WEWOKA SE 19-8N-8E OK 12.50 69.00 Distribution-Unatten 22 SASAKWA NEC NW NE 2-5N-7E OK 12.50 69.00 Distribution-Unatten 23 DRUMRIGHT SW SW 32-18N-7E OK 24.00 69.00 Distribution-Unatten 24 CUSHING TAP NW 26-18N-5E OK 69.00 138.00 13.20 Transmission-Unatten 25 TIGER CREEK SE SE 29-18N-7E OK 12.50 69.00 Distribution-Unatten 26 STILLWATER SW SW 12-19N-2E OK 69.00 138.00 2.40 Transmission-Unatten 27 PIPELINE SE SE 15-17N-5E OK 24.00 69.00 Distribution-Unatten 28 BRISTOW SE SW 32-16N-9E OK 12.50 69.00 Distribution-Unatten 29 BRISTOW SE SW 32-16N-9E 13.09 138.00 Distribution-Unatten 30 BRISTOW SE SW 32-16N-9E OK 69.00 138.00 12.50 Transmission-Unatten 31 CAPITOL HILL NW SW 10-11N-3W OK 4.16 12.50 Distribution-Unatten 32 SW 22ND ST SE NE 7-11N-3W OK 12.50 69.00 Distribution-Unatten 33 SW 64TH SEC NE NW 25-11N-4W OK 12.50 69.00 Distribution-Unatten 34 KENTUCKY NEC SE NW SW 20-11N-3W OK 12.50 69.00 Distribution-Unatten 35 SAGE SEC SW NE 21-11N-3W OK 12.50 69.00 Distribution-Unatten 36 PENNSYLVANIA SEC NE 31-11N-3W OK 12.50 138.00 Distribution-Unatten 37 PENNSYLVANIA SEC NE 31-11N-3W OK 69.00 138.00 13.20 Transmission-Unatten 38 WILL ROGERS NWC SE 28-11N-4W OK 12.50 69.00 Distribution-Unatten 39 MACARTHUR NEC SE 16-11N-4W OK 12.50 69.00 Distribution-Unatten 40

FERC FORM NO. 1 (ED. 12-96) Page 426.3Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).

SARA NE NE 27-11N-5W OK 34.50 138.00 Distribution-Unatten 1 SOUTHGATE SE SE SW SE 16-10N-3W OK 12.50 138.00 Distribution-Unatten 2 SANTA FE AVE SE NE 33-11N-3W OK 12.50 138.00 Distribution-Unatten 3 WESTMOORE NW/4, NW/4 SECTION 17, T10N, R3W OK 12.50 138.00 Distribution-Unatten 4 ROBINSON AVE NE 1/4 SEC 4, T11N, R3W OK 12.50 138.00 Distribution-Unatten 5 ROBINSON AVE NE 1/4 SEC 4, T11N, R3W OK 13.80 138.00 Distribution-Unatten 6 ROBINSON AVE NE 1/4 SEC 4, T11N, R3W OK 34.50 138.00 Distribution-Unatten 7 CLASSEN NW SW 33-12N-3W OK 12.50 138.00 Distribution-Unatten 8 CLASSEN NW SW 33-12N-3W OK 34.50 138.00 Distribution-Unatten 9 GRAND AVE NE SW SW 32-12N-3W OK 4.16 12.50 Distribution-Unatten 10 MAY AVE NE NE 25-12N-4W OK 12.50 69.00 Distribution-Unatten 11 MERIDIAN SWC 26-12N-4W OK 12.50 138.00 Distribution-Unatten 12 CZECH HALL SWC NW 33-12N-5W OK 12.50 138.00 Distribution-Unatten 13 COUNCIL SWC NW SW 32-12N-4W OK 12.50 138.00 Distribution-Unatten 14 SW 5TH ST SE NE NE 1-11N-4W OK 12.50 138.00 Distribution-Unatten 15 SW 5TH ST SE NE NE 1-11N-4W OK 34.50 138.00 Distribution-Unatten 16 SW 5TH ST SE NE NE 1-11N-4W OK 69.00 138.00 13.80 Transmission-Unatten 17 MUSTANG STA SE 36-12N-5W OK 69.00 138.00 7.20 Transmission-Unatten 18 MORGAN ROAD PART OF EAST HALF,SEC 35,T12N,R5W 12.50 138.00 Distribution-Unatten 19 WESTOAKS SW SW 28-12N-4W OK 12.50 138.00 Distribution-Unatten 20 LONE OAK SE/4 S35 T14N 4W OK 34.50 138.00 Distribution-Unatten 21 BELLE ISLE NW SE 8-12N-3W OK 12.50 138.00 Distribution-Unatten 22 HAYMAKER SE1/4 SEC 33 T13N R5W OK 34.50 138.00 Distribution-Unatten 23 SKYLINE SEC SW SE 17-13N-3W OK 12.50 138.00 Distribution-Unatten 24 NORTHWEST NWC NE 5-13N-4W OK 138.00 345.00 13.80 Transmission-Unatten 25 PIEDMONT SE SW 34-14N-5W OK 34.50 138.00 Distribution-Unatten 26 THIRTY EIGHTH ST NW SW SW18-12N-3W OK 12.50 69.00 Distribution-Unatten 27 THIRTY EIGHTH ST NW SW SW18-12N-3W OK 12.50 138.00 Distribution-Unatten 28 THIRTY EIGHTH ST NW SW SW18-12N-3W OK 69.00 138.00 13.20 Transmission-Unatten 29 RICHARDS SE 1/4 SEC 13,T13N,R5W 12.50 138.00 Distribution-Unatten 30 BETHANY NWC SE SW 15-12N-4W 12.50 69.00 Distribution-Unatten 31 TENNESSEE NEC 30-13N-3W OK 12.50 138.00 Distribution-Unatten 32 EIGHTY FOURTH ST SE NW SW 33-13N-3W OK 12.50 138.00 Distribution-Unatten 33 TULSA AVE NE SE NE SW 11-12N-4W OK 12.50 138.00 Distribution-Unatten 34 SILVER LAKE SEC NE 29-13N-4W OK 12.50 138.00 Distribution-Unatten 35 BRADEN PARK PART OF NE 1/4 OF SECTION 12.50 138.00 Distribution-Unatten 36 WILSHIRE SE SW SE 36-13N-4W OK 12.50 138.00 Distribution-Unatten 37 QUAIL CREEK SE NE 23-13N-4W OK 12.50 138.00 Distribution-Unatten 38 YUKON NWC SW 16-12N-5W OK 12.50 69.00 Distribution-Unatten 39 WOODLAWN SE NE 18-12N-4W OK 12.50 69.00 Distribution-Unatten 40

FERC FORM NO. 1 (ED. 12-96) Page 426.4Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).

WESTERN AVE SEC NE 20-12N-3W OK 12.50 138.00 Distribution-Unatten 1 LAKESIDE NE NW 3-12N-4W OK 12.50 138.00 Distribution-Unatten 2 CIMARRON SW SW 13-12N-6W OK 138.00 345.00 13.80 Transmission-Unatten 3 DIVISION AVE SW SE SW 31-13N-4W OK 12.50 138.00 Distribution-Unatten 4 ARCADIA SW NW,NW SW16-14N-1W OK 138.00 345.00 13.80 Transmission-Unatten 5 REMINGTON PARK NE 1/4, SEC 11, T12N, R3W OK 12.50 138.00 Distribution-Unatten 6 DEEP FORK NWC SW NE 11-12N-3W OK 12.50 69.00 Distribution-Unatten 7 GREEN PASTURES SE SE 6-12N-1W OK 12.50 69.00 Distribution-Unatten 8 BRYANT SE NE 25-13N-3W OK 12.50 138.00 Distribution-Unatten 9 BRYANT SE NE 25-13N-3W 13.09 138.00 Distribution-Unatten 10 MEMORIAL SWC SE 15-13N-3W OK 12.50 138.00 Distribution-Unatten 11 MEMORIAL SWC SE 15-13N-3W OK 34.50 138.00 Distribution-Unatten 12 NE 30TH ST SEC SW NE 19-12N-2W OK 12.50 69.00 Distribution-Unatten 13 STONEWALL SWC SE NW NW 23-12N-3W OK 12.50 138.00 Distribution-Unatten 14 PARK PLACE SW SW 27-12N-3W OK 13.80 138.00 Distribution-Unatten 15 NE 10TH ST SWC SW 26-12N-2W OK 12.50 138.00 Distribution-Unatten 16 MIDWAY SW SW 30-12N-1E OK 12.50 138.00 Distribution-Unatten 17 MIDWAY SW SW 30-12N-1E OK 34.50 138.00 Distribution-Unatten 18 CALIFORNIA SW SE 35-12N-3W OK 4.16 69.00 Distribution-Unatten 19 CALIFORNIA SW SE 35-12N-3W OK 12.50 69.00 Distribution-Unatten 20 OU MEDICAL CENTER NW 1/4 SEC.35,T12N,R3W 13.09 138.00 Distribution-Unatten 21 OU MEDICAL CENTER NW 1/4 SEC.35,T12N,R3W 36.20 138.00 Distribution-Unatten 22 RENO NWC 5-11N-2W OK 12.50 138.00 Distribution-Unatten 23 RENO NWC 5-11N-2W OK 69.00 138.00 13.80 Transmission-Unatten 24 HORSESHOE LAKE STA S1/2 SE 15-12N-1E OK 69.00 138.00 13.80 Transmission-Unatten 25 SUNNYLANE NWC SW SW NW 17-11N-2W OK 12.50 69.00 Distribution-Unatten 26 LIGHTNING CREEK SW NW 10-11N-3W OK 12.50 138.00 Distribution-Unatten 27 DRAPER LAKE E 1/2 NW 20-10N-1W OK 12.50 34.50 Distribution-Unatten 28 DRAPER LAKE E 1/2 NW 20-10N-1W OK 34.50 138.00 Distribution-Unatten 29 DRAPER LAKE E 1/2 NW 20-10N-1W OK 138.00 345.00 13.80 Transmission-Unatten 30 TROSPER NE SE12-11N-3W OK 12.50 138.00 Distribution-Unatten 31 GLENDALE OK 12.50 138.00 Distribution-Unatten 32 MOORE SEC SE 14-10N-3W OK 12.50 138.00 Distribution-Unatten 33 FOSTER SE SW SE 24-11N-3W OK 12.50 138.00 Distribution-Unatten 34 DISCOVERY NE NE 25-11N-3W OK 12.50 138.00 Distribution-Unatten 35 DISCOVERY NE NE 25-11N-3W OK 34.50 138.00 Distribution-Unatten 36 SE 15TH ST NEC NW NW 7-11N-1W OK 12.50 138.00 Distribution-Unatten 37 WILD MARY OK 12.50 138.00 Distribution-Unatten 38 NORMAN SE NE 30-9N-2W OK 4.16 12.50 Distribution-Unatten 39 NORMAN SE NE 30-9N-2W OK 12.50 34.50 Distribution-Unatten 40

FERC FORM NO. 1 (ED. 12-96) Page 426.5Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).

BOYD SWC SW NW 36-9N-3W OK 12.50 138.00 Distribution-Unatten 1 WILKINSON NEC NW 4-8N-2W OK 12.50 138.00 Distribution-Unatten 2 WILKINSON NEC NW 4-8N-2W OK 34.50 138.00 Distribution-Unatten 3 CEDAR LANE NW NE 18-8N-2W OK 12.50 138.00 Distribution-Unatten 4 TURNER NW NW 10-10N-3W OK 12.50 138.00 Distritution-Unatten 5 PLEASANT VALLEY NW NW 10-9N-3W OK 12.50 138.00 Distribution-Unatten 6 MILLENNIUM PART OF SW1/4,SEC16,T9N,R2W OK 12.50 138.00 Distribution-Unatten 7 INDIAN HILLS NW CORNER INDIAN OK 12.50 138.00 Distribution-Unatten 8 STUBBEMAN NW NW 19-9N-2W OK 12.50 138.00 Distribution-Unatten 9 CHERRY CREEK NWC NW 34-9N-3W OK 12.50 138.00 Distribution-Unatten 10 COTTONWOOD CREEK NE NW 20-16N-2W OK 12.50 138.00 Distribution-Unatten 11 COTTONWOOD CREEK NE NW 20-16N-2W OK 69.00 138.00 7.20 Transmission-Unatten 12 FITZGERALD CREEK SE NE 10-17N-1W OK 24.00 138.00 Distribution-Unatten 13 PINE STREET SWC SW 34-17N-2W OK 12.50 138.00 Distribution-Unatten 14 PINE STREET SWC SW 34-17N-2W OK 24.00 138.00 Distribution-Unatten 15 LIBERTY LAKE SECTION 7 T15N R3W OK 12.50 138.00 Distribution-Unatten 16 WATERLOO SW SE 31-15N-2W OK 12.50 138.00 Distribution-Unatten 17 EL RENO SW NE 9-12N-7W OK 12.50 138.00 Distribution-Unatten 18 EL RENO SW NE 9-12N-7W OK 69.00 138.00 13.20 Transmission-Unatten 19 SOUTHARD NWC NE 10-18N-12W OK 12.50 138.00 Distribution-Unatten 20 SOUTHARD NWC NE 10-18N-12W OK 24.00 138.00 Distribution-Unatten 21 ROMAN NOSE SW SW SW 24-16N-11W OK 24.00 138.00 Distribution-Unatten 22 JENSEN RD NW NE 29-12N-7W OK 12.50 34.50 Distribution-Unatten 23 JENSEN RD NW NE 29-12N-7W OK 34.50 138.00 Distribution-Unatten 24 J STREET NE 1/4 SEC 8 T8N R3 AR 12.50 161.00 Distribution-Unatten 25 THIRD ST NW SE 8-8N-32W AR 4.16 69.00 Distribution-Unatten 26 THIRD ST NW SE 8-8N-32W AR 12.50 69.00 Distribution-Unatten 27 THIRD ST NW SE 8-8N-32W AR 69.00 161.00 13.80 Transmission-Unatten 28 SOUTHSIDE SWC SE SE 28-8N-32W AR 12.50 69.00 Distribution-Unatten 29 EXPOSITION PARK SE NW 35-9N-32W AR 12.50 69.00 Distribution-Unatten 30 MASSARD SWC SE SE 19-8N-31W AR 12.50 161.00 Distribution-Unatten 31 MASSARD SWC SE SE 19-8N-31W AR 69.00 161.00 13.80 Transmission-Unatten 32 BELLE AVE SE NE SE NE 16-8N-32W 12.50 69.00 Distribution-Unatten 33 CAVANAUGH NW SW NW 4-7N-32W AR 12.50 69.00 Distribution-Unatten 34 BATTLEFIELD SE 1/4, SECTION3, T-7N-32W OK 12.50 161.00 Distribution-Unatten 35 FACTORY NW NE SW 9-8N-32W AR 12.50 69.00 Distribution-Unatten 36 BARLING S1/2 S1/2 SE1/4, SECTION 32 T8N, R31W AR 12.50 161.00 Distribution-Unatten 37 CHAFFEE SE SE SE SEC 4, T7N, R31W AR 12.50 34.50 Distribution-Unatten 38 CARNALL NEC NW NW 2-7N-32W AR 12.50 69.00 Distribution-Unatten 39 CARNALL NEC NW NW 2-7N-32W AR 34.50 69.00 Distribution-Unatten 40

FERC FORM NO. 1 (ED. 12-96) Page 426.6Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Name and Location of Substation Primary (c) (b) (a) Tertiary (d) Character of Substation (e) Secondary VOLTAGE (In MVa) 

### 1. Report below the information called for concerning substations of the respondent as of the end of the year. 2. Substations which serve only one industrial or street railway customer should not be listed below. 3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to functional character, but the number of such substations must be shown. 4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in column (f).

OAK PARK E« NE¬ Sec. 34, T 9 North, R 32 West AR 12.50 161.00 Distribution-Unatten 1 FT SMITH S1/2 S1/2 8-7N-32W AR 161.00 345.00 13.80 Transmission-Unatten 2 FT SMITH S1/2 S1/2 8-7N-32W AR 161.00 500.00 13.80 Transmission-Unatten 3 FT SMITH S1/2 S1/2 8-7N-32W AR 345.00 500.00 13.80 Transmission-Unatten 4 GERBER ROAD SW 1/4,SEC 26,T9N,R23W OK 12.50 161.00 Distribution-Unatten 5 PARK VIEW SW NE 14-8N-32W AR 12.50 69.00 Distribution-Unatten 6 ARKOMA NEC SW 20-8N-32W AR 12.50 161.00 Distribution-Unatten 7 COLONY SE SE 4-7N-32W AR 12.50 161.00 Distribution-Unatten 8 BRANCH SE NE SW 6-7N-27W AR 12.50 34.50 Distribution-Unatten 9 BRANCH SE NE SW 6-7N-27W AR 34.50 69.00 Distribution-Unatten 10 BRANCH SE NE SW 6-7N-27W AR 69.00 161.00 7.20 Transmission-Unatten 11 ETNA SW NE NE 3-8N-27W AR 34.50 69.00 6.60 Distribution-Unatten 12 SHORT MTN SW NW NW SW 11-7N-26W AR 12.50 69.00 Distribution-Unatten 13 SHORT MTN SW NW NW SW 11-7N-26W AR 34.50 69.00 13.20 Distribution-Unatten 14 ALMA NW SE 6-9N-30W AR 12.50 161.00 Distribution-Unatten 15 SIMMONS SE 35 SW 36-10N-30W AR 34.50 161.00 Distribution-Unatten 16 HELBERG NW NW 35-10N-27W AR 12.50 69.00 Distribution-Unatten 17 HELBERG NW NW 35-10N-27W AR 69.00 161.00 13.20 Transmission-Unatten 18 LITTLE SPADRA CREEK NE SE 35-10N-24W AR 34.50 69.00 Distribution-Unatten 19 LITTLE SPADRA CREEK NE SE 35-10N-24W AR 69.00 161.00 Transmission-Unatten 20 VAN BUREN SE SW NE 24-9N-32W AR 4.16 69.00 Distribution-Unatten 21 VAN BUREN SE SW NE 24-9N-32W AR 12.50 69.00 Distribution-Unatten 22 VAN BUREN INT NE SW 7-9N-31W AR 69.00 161.00 Transmission-Unatten 23 WHITESIDE SEC 30-9N-31W AR 12.50 161.00 Distribution-Unatten 24 25 Summary: 200-Substations included above Distribution 26 Summary: 56-Substations included above Transmission 27 Summary: 110 Substations <10,000 kVA not listed abo Distribution 28 Summary: 0 Substations <10,000 kVA not listed above Transmission 29 30 31 32 33 34 35 36 37 38 39 40

FERC FORM NO. 1 (ED. 12-96) Page 426.7Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

47500 3 1 200000 1 1 2 40000 2 3 35000 3 4 200000 2 5 40000 2 6 25000 1 7 27500 2 8 25000 1 9 100000 1 10 100000 1 11 700000 2 12 47500 3 13 20000 1 14 15000 2 15 15000 2 16 100000 1 17 40000 2 18 15000 2 19 40000 2 20 100000 1 21 50000 2 22 15000 2 23 15000 2 24 40000 2 25 15000 2 26 15000 2 27 15000 2 28 6000 3 29 7500 1 30 15000 2 31 200000 2 32 40000 2 33 12000 2 34 20000 1 35 40000 2 36 3000 3 37 40000 2 38 300000 3 1 39 20000 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

20000 1 1 70000 1 2 20000 1 3 100000 1 4 100000 1 5 20000 1 6 100000 1 7 57500 3 8 200000 2 9 400000 1 10 100000 1 11 50000 1 12 15000 2 13 100000 1 14 60000 3 15 100000 1 16

3500 6 1 17 7500 1 18 140000 1 19

3750 1 20 20000 1 21

833 1 22 17499 5 23 20000 1 24 100000 1 25 40000 2 26 12000 2 27 40000 2 28 15000 2 29 40000 2 30 15000 2 31 200000 2 32

7500 1 33 5000 1 34 15000 2 35 15000 2 36 15000 2 37 50000 1 38 300000 3 39 15000 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.1Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

15000 2 1 15000 2 2 27500 2 3 50000 1 4 15000 2 5 50000 1 6 15000 2 7 15000 2 8 20000 1 9 15000 2 10 20000 1 11 5000 1 12 7500 1 13 60000 3 14 25000 1 15 25000 1 16 15000 2 17 3750 1 18 42500 3 19 27500 2 20 41667 1 21 15000 2 22 11250 2 23 50000 1 24 15000 2 25 15000 2 26 15000 2 27 50000 1 28 25000 1 29 25000 1 30 40000 2 31 40000 2 32 5000 1 33 20000 2 34 20000 1 35 200000 2 36 50000 1 37 7500 1 38 25000 1 39 25000 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.2Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

15000 2 1 7500 1 2 15000 2 3 15000 2 4 15000 2 5 7500 1 6 40000 2 7 7500 1 8 50000 1 9 800000 2 10 15000 2 11 12000 2 12 5000 2 13 15000 2 14 20000 1 15 100000 1 16 100000 1 17 40000 2 18 50000 1 19 40000 2 20 35000 3 21 15000 2 22 12000 2 23 15000 2 24 100000 1 25 15000 2 26 41667 1 27 15000 2 28 15000 2 29 7500 1 30 50000 1 31 15750 7 32 40000 2 33 40000 2 34 40000 2 35 40000 2 36 80000 2 37 100000 1 38 40000 2 39 40000 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.3Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

100000 2 1 80000 2 2 60000 3 3 60000 3 4 20000 1 5 50000 2 6 50000 1 7 40000 2 8 50000 1 9 13500 2 10 40000 2 11 100000 3 12 60000 3 13 80000 2 14 20000 1 15 50000 1 16 100000 1 17 125000 1 18 15000 2 19 60000 3 20 150000 3 21 120000 3 22 50000 1 23 40000 2 24 800000 2 25 50000 1 26 20000 1 27 40000 2 28 100000 1 29 40000 2 30 40000 2 31 60000 3 32 40000 2 33 80000 2 34 80000 2 35 20000 1 36 40000 2 37 60000 3 38 40000 2 39 40000 2 40

FERC FORM NO. 1 (ED. 12-96) Page 427.4Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

80000 2 1 40000 2 2 800000 2 3 60000 3 4 800000 2 5 20000 1 6 20000 1 7 15000 2 8 7500 1 9 7500 1 10 40000 2 11 50000 1 12 15000 2 13 60000 3 14 100000 2 15 80000 2 16 40000 2 17 50000 1 18 20000 1 19 40000 2 20 20000 1 21 50000 1 22 40000 2 23 125000 1 24 125000 1 25 40000 2 26 40000 2 27 7500 1 28 50000 1 29 1200000 3 30

60000 3 31 60000 3 32 60000 3 33 60000 3 34 40000 1 35 40000 2 36 40000 2 37 20000 1 38 7500 1 39 7500 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.5Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

60000 3 1 40000 2 2 50000 1 3 40000 2 4 20000 1 5 20000 1 6 20000 1 7 20000 1 8 60000 3 9 60000 3 10 40000 2 11 25000 1 12 15000 2 13 15000 2 14 3750 1 15 20000 1 16 40000 2 17 40000 2 18 50000 1 19 7500 1 20 15000 2 21 15000 2 22 7500 1 23 41700 1 24 20000 1 25 12000 2 26 3750 1 27 200000 2 28 40000 2 29 47500 4 30 40000 2 1 31 100000 1 32 40000 2 33 47500 3 34 15000 2 35 11250 2 36 40000 2 37 15000 2 38 22500 3 39 25000 1 40

FERC FORM NO. 1 (ED. 12-96) Page 427.6Name of Respondent This Report Is: (1) An Original (2) A Resubmission Date of Report (Mo, Da, Yr) Year/Period of Report End of SUBSTATIONS Oklahoma Gas and Electric Company X / / 2008/Q4

Line No. Number of Units (g) (f) (h) CONVERSION APPARATUS AND SPECIAL EQUIPMENT

(k) Total Capacity (Continued)

Capacity of Substation (In Service) (In MVa) Number of Transformers

In Service Spare Type of Equipment Number of
Transformers (In MVa) (i) (j) 

### 5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for increasing capacity. 6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.

40000 2 1 400000 1 2 800000 4 1 3 600000 3 1 4 20000 1 5 40000 2 6 60000 3 7 60000 3 8 2000 3 9 50000 2 10 65000 6 1 11 100000 1 12

7500 1 13 31333 1 14 15000 2 15 50000 2 16 15000 2 17 100000 1 18 15000 2 19 100000 1 20

5000 1 21 15000 2 22 100000 1 23 40000 2 24 25 7720115 26 12638334 27

598244 28 29 30 31 32 33 34 35 36 37 38 39 40

FERC FORM NO. 1 (ED. 12-96) Page 427.7

### INDEX

Schedule Page No.

Accrued and prepaid taxes ........................................................................ 262-263 Accumulated Deferred Income Taxes .................................................................... 234 272-277 Accumulated provisions for depreciation of common utility plant ............................................................................. 356 utility plant .................................................................................... 219 utility plant (summary) ...................................................................... 200-201 Advances from associated companies .................................................................... 256-257 Allowances ....................................................................................... 228-229 Amortization miscellaneous .................................................................................... 340 of nuclear fuel .............................................................................. 202-203 Appropriations of Retained Earnings .............................................................. 118-119 Associated Companies advances from ................................................................................ 256-257 corporations controlled by respondent ............................................................ 103 control over respondent .......................................................................... 102 interest on debt to .......................................................................... 256-257 Attestation ............................................................................................ i Balance sheet comparative .................................................................................. 110-113 notes to ..................................................................................... 122-123 Bonds ............................................................................................ 256-257 Capital Stock ........................................................................................ 251 expense .......................................................................................... 254 premiums ......................................................................................... 252 reacquired ....................................................................................... 251 subscribed ....................................................................................... 252 Cash flows, statement of ......................................................................... 120-121 Changes important during year ........................................................................ 108-109 Construction work in progress - common utility plant .......................................................... 356 work in progress - electric ...................................................................... 216 work in progress - other utility departments ................................................. 200-201 Control corporations controlled by respondent ............................................................ 103 over respondent .................................................................................. 102 Corporation controlled by .................................................................................... 103 incorporated ..................................................................................... 101 CPA, background information on ....................................................................... 101 CPA Certification, this report form ................................................................. i-ii

FERC FORM NO. 1 (ED. 12-93) Index 1

### INDEX (continued)

Schedule Page No. Deferred credits, other ................................................................................... 269 debits, miscellaneous ............................................................................ 233 income taxes accumulated - accelerated amortization property ........................................................................ 272-273 income taxes accumulated - other property .................................................... 274-275 income taxes accumulated - other ............................................................. 276-277 income taxes accumulated - pollution control facilities .......................................... 234 Definitions, this report form ........................................................................ iii Depreciation and amortization of common utility plant .......................................................................... 356 of electric plant ................................................................................ 219 336-337 Directors ............................................................................................ 105 Discount - premium on long-term debt ............................................................. 256-257 Distribution of salaries and wages ............................................................... 354-355 Dividend appropriations .......................................................................... 118-119 Earnings, Retained ............................................................................... 118-119 Electric energy account .............................................................................. 401 Expenses electric operation and maintenance ........................................................... 320-323 electric operation and maintenance, summary ...................................................... 323 unamortized debt ................................................................................. 256 Extraordinary property losses ........................................................................ 230 Filing requirements, this report form General information .................................................................................. 101 Instructions for filing the FERC Form 1 ............................................................. i-iv Generating plant statistics hydroelectric (large) ........................................................................ 406-407 pumped storage (large) ....................................................................... 408-409 small plants ................................................................................. 410-411 steam-electric (large) ....................................................................... 402-403 Hydro-electric generating plant statistics ....................................................... 406-407 Identification ....................................................................................... 101 Important changes during year .................................................................... 108-109 Income statement of, by departments ................................................................. 114-117 statement of, for the year (see also revenues) ............................................... 114-117 deductions, miscellaneous amortization ........................................................... 340 deductions, other income deduction ............................................................... 340 deductions, other interest charges ............................................................... 340 Incorporation information ............................................................................ 101

Index 2 FERC FORM NO. 1 (ED. 12-95)

### INDEX (continued)

Schedule Page No.

Interest charges, paid on long-term debt, advances, etc ............................................... 256-257 Investments nonutility property .............................................................................. 221 subsidiary companies ......................................................................... 224-225 Investment tax credits, accumulated deferred ..................................................... 266-267 Law, excerpts applicable to this report form .......................................................... iv List of schedules, this report form .................................................................. 2-4 Long-term debt ................................................................................... 256-257 Losses-Extraordinary property ........................................................................ 230 Materials and supplies ............................................................................... 227 Miscellaneous general expenses ....................................................................... 335 Notes to balance sheet ............................................................................. 122-123 to statement of changes in financial position ................................................ 122-123 to statement of income ....................................................................... 122-123 to statement of retained earnings ............................................................ 122-123 Nonutility property .................................................................................. 221 Nuclear fuel materials ........................................................................... 202-203 Nuclear generating plant, statistics ............................................................. 402-403 Officers and officers' salaries ...................................................................... 104 Operating expenses-electric ............................................................................ 320-323 expenses-electric (summary) ...................................................................... 323 Other paid-in capital .................................................................................. 253 donations received from stockholders ............................................................. 253 gains on resale or cancellation of reacquired capital stock .................................................................................... 253 miscellaneous paid-in capital .................................................................... 253 reduction in par or stated value of capital stock ................................................ 253 regulatory assets ................................................................................ 232 regulatory liabilities ........................................................................... 278 Peaks, monthly, and output ........................................................................... 401 Plant, Common utility accumulated provision for depreciation ........................................................... 356 acquisition adjustments .......................................................................... 356 allocated to utility departments ................................................................. 356 completed construction not classified ............................................................ 356 construction work in progress .................................................................... 356 expenses ......................................................................................... 356 held for future use .............................................................................. 356 in service ....................................................................................... 356 leased to others ................................................................................. 356 Plant data ...................................................................................336-337 401-429

Index 3 FERC FORM NO. 1 (ED. 12-95)

### INDEX (continued)

Schedule Page No. Plant - electric accumulated provision for depreciation ........................................................... 219 construction work in progress .................................................................... 216 held for future use .............................................................................. 214 in service ................................................................................... 204-207 leased to others ................................................................................. 213 Plant - utility and accumulated provisions for depreciation amortization and depletion (summary) ............................................................. 201 Pollution control facilities, accumulated deferred income taxes ..................................................................................... 234 Power Exchanges .................................................................................. 326-327 Premium and discount on long-term debt ............................................................... 256 Premium on capital stock ............................................................................. 251 Prepaid taxes .................................................................................... 262-263 Property - losses, extraordinary ..................................................................... 230 Pumped storage generating plant statistics ....................................................... 408-409 Purchased power (including power exchanges) ...................................................... 326-327 Reacquired capital stock ............................................................................. 250 Reacquired long-term debt ........................................................................ 256-257 Receivers' certificates .......................................................................... 256-257 Reconciliation of reported net income with taxable income from Federal income taxes ...................................................................... 261 Regulatory commission expenses deferred .............................................................. 233 Regulatory commission expenses for year .......................................................... 350-351 Research, development and demonstration activities ............................................... 352-353 Retained Earnings amortization reserve Federal ..................................................................... 119 appropriated ................................................................................. 118-119 statement of, for the year ................................................................... 118-119 unappropriated ............................................................................... 118-119 Revenues - electric operating .................................................................... 300-301 Salaries and wages directors fees ................................................................................... 105 distribution of .............................................................................. 354-355 officers' ........................................................................................ 104 Sales of electricity by rate schedules ............................................................... 304 Sales - for resale ............................................................................... 310-311 Salvage - nuclear fuel ........................................................................... 202-203 Schedules, this report form .......................................................................... 2-4 Securities exchange registration ........................................................................ 250-251 Statement of Cash Flows .......................................................................... 120-121 Statement of income for the year ................................................................. 114-117 Statement of retained earnings for the year ...................................................... 118-119 Steam-electric generating plant statistics ....................................................... 402-403 Substations .......................................................................................... 426 Supplies - materials and ............................................................................. 227

Index 4 FERC FORM NO. 1 (ED. 12-90)

### INDEX (continued)

Schedule Page No.

Taxes accrued and prepaid ......................................................................... 262-263 charged during year ......................................................................... 262-263 on income, deferred and accumulated ............................................................. 234 272-277 reconciliation of net income with taxable income for ............................................ 261 Transformers, line - electric ....................................................................... 429 Transmission lines added during year ..................................................................... 424-425 lines statistics ............................................................................ 422-423 of electricity for others ................................................................... 328-330 of electricity by others ........................................................................ 332 Unamortized debt discount ............................................................................... 256-257 debt expense ................................................................................ 256-257 premium on debt ............................................................................. 256-257 Unrecovered Plant and Regulatory Study Costs ........................................................ 230

Index 5 FERC FORM NO. 1 (ED. 12-90)