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

Oklahoma Gas and Electric Company End of 2008/Q4
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) The following 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.pdf and

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 18th of 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

Oklahoma Gas and Electric Company End of

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 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

LIST OF SCHEDULES (Electric Utility)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Title of Schedule Reference

Page No.

Remarks

(a) (b) (c)

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".

 1 General Information 101

 2 Control Over Respondent 102

 3 Corporations Controlled by Respondent 103

 4 Officers 104

 5 Directors 105

 6 Important Changes During the Year 108-109

 7 Comparative Balance Sheet 110-113

 8 Statement of Income for the Year 114-117

 9 Statement of Retained Earnings for the Year 118-119

 10 Statement of Cash Flows 120-121

 11 Notes to Financial Statements 122-123

 12 Statement of Accum Comp Income, Comp Income, and Hedging Activities 122(a)(b)

 13 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201

 14 Nuclear Fuel Materials 202-203 N/A

 15 Electric Plant in Service 204-207

 16 Electric Plant Leased to Others 213 N/A

 17 Electric Plant Held for Future Use 214

 18 Construction Work in Progress-Electric 216

 19 Accumulated Provision for Depreciation of Electric Utility Plant 219

 20 Investment of Subsidiary Companies 224-225

 21 Materials and Supplies 227

 22 Allowances 228-229 N/A

 23 Extraordinary Property Losses 230 N/A

 24 Unrecovered Plant and Regulatory Study Costs 230 N/A

 25 Transmission Service and Generation Interconnection Study Costs 231 None

 26 Other Regulatory Assets 232

 27 Miscellaneous Deferred Debits 233

 28 Accumulated Deferred Income Taxes 234

 29 Capital Stock 250-251

 30 Other Paid-in Capital 253

 31 Capital Stock Expense 254 N/A

 32 Long-Term Debt 256-257

 33 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261

 34 Taxes Accrued, Prepaid and Charged During the Year 262-263

 35 Accumulated Deferred Investment Tax Credits 266-267

 36 Other Deferred Credits 269

FERC FORM NO. 1 (ED. 12-96) Page 2
LIST 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

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No.

Title of Schedule Reference

Page No.

Remarks

(a) (b) (c)

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".

 37 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273 N/A

 38 Accumulated Deferred Income Taxes-Other Property 274-275

 39 Accumulated Deferred Income Taxes-Other 276-277

 40 Other Regulatory Liabilities 278

 41 Electric Operating Revenues 300-301

 42 Sales of Electricity by Rate Schedules 304

 43 Sales for Resale 310-311

 44 Electric Operation and Maintenance Expenses 320-323

 45 Purchased Power 326-327

 46 Transmission of Electricity for Others 328-330

 47 Transmission of Electricity by ISO/RTOs 331 N/A

 48 Transmission of Electricity by Others 332

 49 Miscellaneous General Expenses-Electric 335

 50 Depreciation and Amortization of Electric Plant 336-337

 51 Regulatory Commission Expenses 350-351

 52 Research, Development and Demonstration Activities 352-353

 53 Distribution of Salaries and Wages 354-355

 54 Common Utility Plant and Expenses 356 N/A

 55 Amounts included in ISO/RTO Settlement Statements 397

 56 Purchase and Sale of Ancillary Services 398

 57 Monthly Transmission System Peak Load 400

 58 Monthly ISO/RTO Transmission System Peak Load 400a N/A

 59 Electric Energy Account 401

 60 Monthly Peaks and Output 401

 61 Steam Electric Generating Plant Statistics 402-403

 62 Hydroelectric Generating Plant Statistics 406-407 N/A

 63 Pumped Storage Generating Plant Statistics 408-409 N/A

 64 Generating Plant Statistics Pages 410-411 N/A

 65 Transmission Line Statistics Pages 422-423

 66 Transmission Lines Added During the Year 424-425

FERC FORM NO. 1 (ED. 12-96) Page 3
LIST 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

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No.

Title of Schedule Reference

Page No.

Remarks

(a) (b) (c)

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".

 67 Substations 426-427

 68 Footnote Data 450

Stockholders' Reports Check appropriate box:

Four copies will be submitted

X No annual report to stockholders is prepared

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) PAGE 101
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.

FERC FORM NO. 1 (ED. 12-96) Page 102
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

(a) (b) (c)

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.

 1 The Arklahoma Corporation Owner and Lessor of 4.8% (a)

 2 Transmission facilities.

 3

 4

 5

 6

 7 (a) Held Jointly with Entergy Arkansas Inc.

 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 103
Name 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

(a) (b) (c)

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.

 1 Chairman of the Board, President and Chief Peter B. Delaney 775,000

 2 Executive Officer

 3

 4 Chief Operating Officer Danny P. Harris 510,000

 5

 6 Senior Vice President and Chief Financial Officer (A) James R. Hatfield 207,187

 7

 8 Vice President, Enterprise Information and Reid V. Nuttall 216,500

 9 Performance

 10

 11 Vice President Public Affairs Paul L. Renfrow 228,000

 12

 13 Vice President and Treasurer Deborah S. Fleming 211,000

 14

 15 Vice President Administration / Corporate Secretary Carla D. Brockman 199,500

 16

 17 Vice President Utility Commercial Operations Jesse B. Langston 202,000

 18

 19 Vice President Power Delivery Melvin H. Perkins, Jr. 210,000

 20

 21 Vice President Regulatory Affairs Howard W. Motley, Jr. 210,000

 22

 23 Vice President Internal Audit Gary D. Huneryager 183,000

 24

 25 Controller / Chief Accounting Officer H. Scott Forbes 229,500

 26

 27 Chief Risk Officer Jerry A. Peace 207,000

 28

 29 Vice President Utility Operations Jean Leger, Jr. 244,800

 30

 31 Vice President Corporate Strategy S. Craig Johnston 232,000

 32 and Marketing

 33

 34 Assistant Corporate Secretary / Compliance Officer John D. Rhea 140,000

 35

 36 Vice President Power Supply John Wendling Jr. 193,500

 37

 38 Vice President Human Resources (B) Cary W. Martin 37,601

 39

 40 Vice President Human Resources (C) Robert Grasty 91,875

 41

 42 Vice President Process & Perf Improvement (D) Christina McQuistion 76,667

 43

 44

FERC FORM NO. 1 (ED. 12-96) Page 104
Name 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

(a) (b) (c)

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.

 1 (A) Resigned effective July 11th. Salary reported is

 2 salary earned for 2008.

 3

 4 (B) Resigned effective March 6th. Salary reported is

 5 salary earned for 2008.

 6

 7 (C) Employed as of August 19th. Annual salary is

 8 $245,000.

 9

 10 (D) Employed as of September 2nd. Annual salary

 11 is $230,000.

 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 104.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

DIRECTORS

Oklahoma Gas and Electric Company X

 / /

2008/Q4

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

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.

 1 Herbert H. Champlin Post Office Box 1066

 2 Enid, Oklahoma 73702

 3

 4 Luke R. Corbett (B) 2956 Via Experanze

 5 Edmond, Oklahoma 73013

 6

 7 John D. Groendyke (B) (C) Post Office Box 648

 8 Enid, Oklahoma 73702

 9

 10 Kirk D. Humphreys (A) (B) 1415 N. Hudson

 11 Oklahoma City, Oklahoma 73103

 12

 13 Robert Kelley (A) Post Office Box 1507

 14 Ardmore, Oklahoma 73402

 15

 16 Linda Petree Lambert (A) (C) 3037 NW. 63 Suite 155W

 17 Oklahoma City, Oklahoma 73116

 18

 19 Robert O. Lorenz (A) (C) 500 Heritage Boulevard

 20 Edmond, Oklahoma 73003

 21

 22 Leroy C. Richie (B) (C) 111 Willits Place-Suite 300

 23 Birmingham, Michigan 48009

 24

 25 Wayne H. Brunetti (A) (B) Post Office Box 23433

 26 Silverthorne, CO 80498

 27

 28 J. D. Williams (B) (C) 1155 21st Street N.W.

 29 Washington D.C. 20036

 30

 31 Ronald H. White, M.D. 1508 W. Wilshire

 32 Oklahoma City, Oklahoma 73116

 33

 34 Peter B. Delaney * Post Office Box 321

 35 Chairman of the Board, President and Oklahoma City, Oklahoma 73101-0321

 36 Chief Executive Officer

 37

 38 (A) Member of Audit Committee

 39 (B) Member of Compensation Committee

 40 (C) Member of Nominating and Corporate Governance

 41 Committee

 42

 43 * Mr. Delaney is a standing member of all committees

 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 

This Report is:

(1) X An 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 109.1
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 SO2 allowance 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) X An 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 109.2
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) X An 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 

This Report is:

(1) X An 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 109.4
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) X An 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 109.5
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) X An 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) X An 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) X An 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

 1 UTILITY PLANT

 2 Utility Plant (101-106, 114) 200-201 6,258,153,073 5,460,656,580

 3 Construction Work in Progress (107) 200-201 169,154,630 112,342,284

 4 TOTAL Utility Plant (Enter Total of lines 2 and 3) 6,427,307,703 5,572,998,864

 5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 200-201 2,633,061,106 2,490,303,348

 6 Net Utility Plant (Enter Total of line 4 less 5) 3,794,246,597 3,082,695,516

 7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 202-203 0 0

 8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 0 0

 9 Nuclear Fuel Assemblies in Reactor (120.3) 0 0

 10 Spent Nuclear Fuel (120.4) 0 0

 11 Nuclear Fuel Under Capital Leases (120.6) 0 0

 12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 202-203 0 0

 13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 0 0

 14 Net Utility Plant (Enter Total of lines 6 and 13) 3,794,246,597 3,082,695,516

 15 Utility Plant Adjustments (116) 122 0 0

 16 Gas Stored Underground - Noncurrent (117) 0 0

 17 OTHER PROPERTY AND INVESTMENTS

 18 Nonutility Property (121) 1,189,002 286,886

 19 (Less) Accum. Prov. for Depr. and Amort. (122) 479,003 186,805

 20 Investments in Associated Companies (123) 0 0

 21 Investment in Subsidiary Companies (123.1) 224-225 16,718 17,057

 22 (For Cost of Account 123.1, See Footnote Page 224, line 42)

 23 Noncurrent Portion of Allowances 228-229 0 0

 24 Other Investments (124) 2,838,610 3,016,037

 25 Sinking Funds (125) 0 0

 26 Depreciation Fund (126) 0 0

 27 Amortization Fund - Federal (127) 0 0

 28 Other Special Funds (128) 0 0

 29 Special Funds (Non Major Only) (129) 0 0

 30 Long-Term Portion of Derivative Assets (175) 0 0

 31 Long-Term Portion of Derivative Assets – Hedges (176) 0 0

 32 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 3,565,327 3,133,175

 33 CURRENT AND ACCRUED ASSETS

 34 Cash and Working Funds (Non-major Only) (130) 0 0

 35 Cash (131) 0 0

 36 Special Deposits (132-134) 0 0

 37 Working Fund (135) 13,750 13,150

 38 Temporary Cash Investments (136) 50,704,578 0

 39 Notes Receivable (141) 0 0

 40 Customer Accounts Receivable (142) 155,673,108 123,222,349

 41 Other Accounts Receivable (143) 17,906,957 15,061,902

 42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 2,290,666 3,375,491

 43 Notes Receivable from Associated Companies (145) 0 0

 44 Accounts Receivable from Assoc. Companies (146) 1,304,407 1,116,628

 45 Fuel Stock (151) 227 56,640,508 44,342,665

 46 Fuel Stock Expenses Undistributed (152) 227 0 0

 47 Residuals (Elec) and Extracted Products (153) 227 0 0

 48 Plant Materials and Operating Supplies (154) 227 67,393,826 59,874,271

 49 Merchandise (155) 227 0 0

 50 Other Materials and Supplies (156) 227 0 0

 51 Nuclear Materials Held for Sale (157) 202-203/227 0 0

 52 Allowances (158.1 and 158.2) 228-229 0 0

FERC FORM NO. 1 (REV. 12-03) Page 110
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)

 53 (Less) Noncurrent Portion of Allowances 0 0

 54 Stores Expense Undistributed (163) 227 0 0

 55 Gas Stored Underground - Current (164.1) 0 0

 56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 0 0

 57 Prepayments (165) 8,022,198 3,754,226

 58 Advances for Gas (166-167) 0 0

 59 Interest and Dividends Receivable (171) 405,832 0

 60 Rents Receivable (172) 6,271 12,168

 61 Accrued Utility Revenues (173) 46,965,283 45,735,240

 62 Miscellaneous Current and Accrued Assets (174) 26,902,938 31,580,727

 63 Derivative Instrument Assets (175) 0 0

 64 (Less) Long-Term Portion of Derivative Instrument Assets (175) 0 0

 65 Derivative Instrument Assets - Hedges (176) 0 0

 66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 0 0

 67 Total Current and Accrued Assets (Lines 34 through 66) 429,648,990 321,337,835

 68 DEFERRED DEBITS

 69 Unamortized Debt Expenses (181) 11,418,446 6,404,921

 70 Extraordinary Property Losses (182.1) 230 0 0

 71 Unrecovered Plant and Regulatory Study Costs (182.2) 230 0 0

 72 Other Regulatory Assets (182.3) 232 457,317,435 303,798,586

 73 Prelim. Survey and Investigation Charges (Electric) (183) 738,534 575,148

 74 Preliminary Natural Gas Survey and Investigation Charges 183.1) 0 0

 75 Other Preliminary Survey and Investigation Charges (183.2) 0 0

 76 Clearing Accounts (184) 0 0

 77 Temporary Facilities (185) 0 0

 78 Miscellaneous Deferred Debits (186) 233 165,712 14,795,784

 79 Def. Losses from Disposition of Utility Plt. (187) 0 0

 80 Research, Devel. and Demonstration Expend. (188) 352-353 0 0

 81 Unamortized Loss on Reaquired Debt (189) 17,719,822 18,906,520

 82 Accumulated Deferred Income Taxes (190) 234 83,036,001 60,567,930

 83 Unrecovered Purchased Gas Costs (191) 0 0

 84 Total Deferred Debits (lines 69 through 83) 570,395,950 405,048,889

 85 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 4,797,856,864 3,812,215,415

FERC FORM NO. 1 (REV. 12-03) Page 111
Name of Respondent This Report is: Year/Period of Report

(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)

 1 PROPRIETARY CAPITAL

 2 Common Stock Issued (201) 250-251 100,946,863 100,946,863

 3 Preferred Stock Issued (204) 250-251 0 0

 4 Capital Stock Subscribed (202, 205) 252 0 0

 5 Stock Liability for Conversion (203, 206) 252 0 0

 6 Premium on Capital Stock (207) 252 409,501,960 409,501,960

 7 Other Paid-In Capital (208-211) 253 447,997,342 154,997,342

 8 Installments Received on Capital Stock (212) 252 0 0

 9 (Less) Discount on Capital Stock (213) 254 0 0

 10 (Less) Capital Stock Expense (214) 254 0 0

 11 Retained Earnings (215, 215.1, 216) 118-119 865,810,410 757,803,524

 12 Unappropriated Undistributed Subsidiary Earnings (216.1) 118-119 102,502 102,841

 13 (Less) Reaquired Capital Stock (217) 250-251 0 0

 14 Noncorporate Proprietorship (Non-major only) (218) 0 0

 15 Accumulated Other Comprehensive Income (219) 122(a)(b) 0 0

 16 Total Proprietary Capital (lines 2 through 15) 1,824,359,077 1,423,352,530

 17 LONG-TERM DEBT

 18 Bonds (221) 256-257 135,300,000 135,400,000

 19 (Less) Reaquired Bonds (222) 256-257 0 0

 20 Advances from Associated Companies (223) 256-257 0 0

 21 Other Long-Term Debt (224) 256-257 1,409,950,000 709,950,000

 22 Unamortized Premium on Long-Term Debt (225) 0 0

 23 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 3,821,355 1,988,737

 24 Total Long-Term Debt (lines 18 through 23) 1,541,428,645 843,361,263

 25 OTHER NONCURRENT LIABILITIES

 26 Obligations Under Capital Leases - Noncurrent (227) 0 0

 27 Accumulated Provision for Property Insurance (228.1) 0 0

 28 Accumulated Provision for Injuries and Damages (228.2) 2,216,375 2,405,000

 29 Accumulated Provision for Pensions and Benefits (228.3) 261,842,728 118,125,206

 30 Accumulated Miscellaneous Operating Provisions (228.4) 0 0

 31 Accumulated Provision for Rate Refunds (229) 0 0

 32 Long-Term Portion of Derivative Instrument Liabilities 0 0

 33 Long-Term Portion of Derivative Instrument Liabilities - Hedges 0 0

 34 Asset Retirement Obligations (230) 5,221,787 4,928,405

 35 Total Other Noncurrent Liabilities (lines 26 through 34) 269,280,890 125,458,611

 36 CURRENT AND ACCRUED LIABILITIES

 37 Notes Payable (231) 0 757,577

 38 Accounts Payable (232) 105,043,478 164,347,799

 39 Notes Payable to Associated Companies (233) 15,836,884 278,655,539

 40 Accounts Payable to Associated Companies (234) 9,016,592 81,009,277

 41 Customer Deposits (235) 56,769,703 53,633,284

 42 Taxes Accrued (236) 262-263 27,904,554 24,881,211

 43 Interest Accrued (237) 33,155,200 21,468,057

 44 Dividends Declared (238) 0 0

 45 Matured Long-Term Debt (239) 0 0

FERC FORM NO. 1 (rev. 12-03) Page 112
Name of Respondent This Report is: Year/Period of Report

(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) (continued)

 46 Matured Interest (240) 0 0

 47 Tax Collections Payable (241) 10,664,326 8,014,719

 48 Miscellaneous Current and Accrued Liabilities (242) 47,380,419 41,847,372

 49 Obligations Under Capital Leases-Current (243) 202,804 0

 50 Derivative Instrument Liabilities (244) 0 0

 51 (Less) Long-Term Portion of Derivative Instrument Liabilities 0 0

 52 Derivative Instrument Liabilities - Hedges (245) 0 0

 53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 0 0

 54 Total Current and Accrued Liabilities (lines 37 through 53) 305,973,960 674,614,835

 55 DEFERRED CREDITS

 56 Customer Advances for Construction (252) 0 0

 57 Accumulated Deferred Investment Tax Credits (255) 266-267 17,329,819 21,970,123

 58 Deferred Gains from Disposition of Utility Plant (256) 0 0

 59 Other Deferred Credits (253) 269 19,984,674 13,167,203

 60 Other Regulatory Liabilities (254) 278 26,401,697 28,065,540

 61 Unamortized Gain on Reaquired Debt (257) 0 0

 62 Accum. Deferred Income Taxes-Accel. Amort.(281) 272-277 0 0

 63 Accum. Deferred Income Taxes-Other Property (282) 686,981,063 591,683,261

 64 Accum. Deferred Income Taxes-Other (283) 106,117,039 90,542,049

 65 Total Deferred Credits (lines 56 through 64) 856,814,292 745,428,176

 66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 4,797,856,864 3,812,215,415

FERC FORM NO. 1 (rev. 12-03) Page 113
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 INCOME

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

(a) (b) (c)

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

 1 UTILITY OPERATING INCOME

 2 Operating Revenues (400) 300-301 2,036,213,558 1,902,651,057

 3 Operating Expenses

 4 Operation Expenses (401) 320-323 1,424,171,865 1,308,503,980

 5 Maintenance Expenses (402) 320-323 122,160,355 106,443,855

 6 Depreciation Expense (403) 336-337 145,532,587 135,906,613

 7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337 45,247 45,250

 8 Amort. & Depl. of Utility Plant (404-405) 336-337 3,804,341 2,829,927

 9 Amort. of Utility Plant Acq. Adj. (406) 336-337

 10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)

 11 Amort. of Conversion Expenses (407)

 12 Regulatory Debits (407.3)

 13 (Less) Regulatory Credits (407.4)

 14 Taxes Other Than Income Taxes (408.1) 262-263 59,952,017 56,286,140

 15 Income Taxes - Federal (409.1) 262-263 -29,898,238 68,251,058

 16 - Other (409.1) 262-263 -3,798,508 633,069

 17 Provision for Deferred Income Taxes (410.1) 234, 272-277 120,753,646 62,538,134

 18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 28,850,624 54,199,551

 19 Investment Tax Credit Adj. - Net (411.4) 266 -4,640,304 -4,812,540

 20 (Less) Gains from Disp. of Utility Plant (411.6)

 21 Losses from Disp. of Utility Plant (411.7)

 22 (Less) Gains from Disposition of Allowances (411.8) 389,346 472,993

 23 Losses from Disposition of Allowances (411.9)

 24 Accretion Expense (411.10)

 25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 1,808,843,038 1,681,952,942

 26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 227,370,520 220,698,115

FERC FORM NO. 1/3-Q (REV. 02-04) Page 114
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 INCOME FOR THE YEAR (Continued)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

 Previous Year to Date Line

(in dollars)

(g) (j) (k)

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 115
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 INCOME FOR THE YEAR (continued)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 Previous Year

(a) (b) (c)

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)

 27 Net Utility Operating Income (Carried forward from page 114) 227,370,520 220,698,115

 28 Other Income and Deductions

 29 Other Income

 30 Nonutilty Operating Income

 31 Revenues From Merchandising, Jobbing and Contract Work (415) 2,265,348 2,331,821

 32 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 2,258,170 2,338,029

 33 Revenues From Nonutility Operations (417) 134,319 143,624

 34 (Less) Expenses of Nonutility Operations (417.1) 2,410 8,292

 35 Nonoperating Rental Income (418) 254,015 474,823

 36 Equity in Earnings of Subsidiary Companies (418.1) 119 -339 -110

 37 Interest and Dividend Income (419) 4,423,218 25,677

 38 Allowance for Other Funds Used During Construction (419.1)

 39 Miscellaneous Nonoperating Income (421) 3,220,212 4,347,422

 40 Gain on Disposition of Property (421.1) 1,367,436 1,339,484

 41 TOTAL Other Income (Enter Total of lines 31 thru 40) 9,403,629 6,316,420

 42 Other Income Deductions

 43 Loss on Disposition of Property (421.2) 3,562 3,834,803

 44 Miscellaneous Amortization (425) 340 1,466,194

 45 Donations (426.1) 340 1,789,047 2,210,503

 46 Life Insurance (426.2)

 47 Penalties (426.3) 11,467 226,278

 48 Exp. for Certain Civic, Political & Related Activities (426.4) 647,053 685,178

 49 Other Deductions (426.5) 9,424,173 196,399

 50 TOTAL Other Income Deductions (Total of lines 43 thru 49) 13,341,496 7,153,161

 51 Taxes Applic. to Other Income and Deductions

 52 Taxes Other Than Income Taxes (408.2) 262-263

 53 Income Taxes-Federal (409.2) 262-263 -1,231,498 716,804

 54 Income Taxes-Other (409.2) 262-263 68,569 25,569

 55 Provision for Deferred Inc. Taxes (410.2) 234, 272-277

 56 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 234, 272-277

 57 Investment Tax Credit Adj.-Net (411.5)

 58 (Less) Investment Tax Credits (420)

 59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) -1,162,929 742,373

 60 Net Other Income and Deductions (Total of lines 41, 50, 59) -2,774,938 -1,579,114

 61 Interest Charges

 62 Interest on Long-Term Debt (427) 67,782,003 51,528,035

 63 Amort. of Debt Disc. and Expense (428) 796,829 637,225

 64 Amortization of Loss on Reaquired Debt (428.1) 1,186,698 1,186,698

 65 (Less) Amort. of Premium on Debt-Credit (429)

 66 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)

 67 Interest on Debt to Assoc. Companies (430) 340 2,076,649 6,091,528

 68 Other Interest Expense (431) 340 13,697,074 1,955,558

 69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 3,950,218 3,989,407

 70 Net Interest Charges (Total of lines 62 thru 69) 81,589,035 57,409,637

 71 Income Before Extraordinary Items (Total of lines 27, 60 and 70) 143,006,547 161,709,364

 72 Extraordinary Items

 73 Extraordinary Income (434)

 74 (Less) Extraordinary Deductions (435)

 75 Net Extraordinary Items (Total of line 73 less line 74)

 76 Income Taxes-Federal and Other (409.3) 262-263

 77 Extraordinary Items After Taxes (line 75 less line 76)

 78 Net Income (Total of line 71 and 77) 143,006,547 161,709,364

FERC FORM NO. 1/3-Q (REV. 02-04) Page 117
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 RETAINED EARNINGS

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

Current

Quarter/Year

Year to Date

Balance

(a) (b) (c)

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)

 1 Balance-Beginning of Period 757,803,524 655,935,570

 2 Changes

 3 Adjustments to Retained Earnings (Account 439)

 4 FIN 48 Interest Adjustment ( 6,267,420)

 5

 6

 7

 8

 9 TOTAL Credits to Retained Earnings (Acct. 439) ( 6,267,420)

 10 Federal income tax effect of FIN 48 2,068,510

 11 State income tax effect of FIN 48 357,390

 12

 13

 14

 15 TOTAL Debits to Retained Earnings (Acct. 439) 2,425,900

 16 Balance Transferred from Income (Account 433 less Account 418.1) 143,006,886 161,709,474

 17 Appropriations of Retained Earnings (Acct. 436)

 18

 19

 20

 21

 22 TOTAL Appropriations of Retained Earnings (Acct. 436)

 23 Dividends Declared-Preferred Stock (Account 437)

 24

 25

 26

 27

 28

 29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)

 30 Dividends Declared-Common Stock (Account 438)

 31 -35,000,000 ( 56,000,000)

 32

 33

 34

 35

 36 TOTAL Dividends Declared-Common Stock (Acct. 438) -35,000,000 ( 56,000,000)

 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings

 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37) 865,810,410 757,803,524

APPROPRIATED RETAINED EARNINGS (Account 215)

 39

 40

FERC FORM NO. 1/3-Q (REV. 02-04) Page 118
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 RETAINED EARNINGS

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

Current

Quarter/Year

Year to Date

Balance

(a) (b) (c)

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

 45 TOTAL Appropriated Retained Earnings (Account 215)

APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)

 46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)

 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)

 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1) 865,810,410 757,803,524

UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account

Report only on an Annual Basis, no Quarterly

 49 Balance-Beginning of Year (Debit or Credit) 102,841 102,951

 50 Equity in Earnings for Year (Credit) (Account 418.1) -339 ( 110)

 51 (Less) Dividends Received (Debit)

 52

 53 Balance-End of Year (Total lines 49 thru 52) 102,502 102,841

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:

 2 Net Income (Line 78(c) on page 117) 143,006,547 161,709,364

 3 Noncash Charges (Credits) to Income:

 4 Depreciation and Depletion 145,577,834 135,951,863

 5 Amortization of

 6 Limited-Term Electric Plant 3,804,341 2,829,927

 7

 8 Deferred Income Taxes (Net) 91,903,022 8,338,583

 9 Investment Tax Credit Adjustment (Net) -4,640,304 -4,812,540

 10 Net (Increase) Decrease in Receivables -36,968,353 2,345,773

 11 Net (Increase) Decrease in Inventory -19,817,398 -19,667,944

 12 Net (Increase) Decrease in Allowances Inventory

 13 Net Increase (Decrease) in Payables and Accrued Expenses -105,267,447 38,319,255

 14 Net (Increase) Decrease in Other Regulatory Assets -153,518,849 21,078,445

 15 Net Increase (Decrease) in Other Regulatory Liabilities -1,663,843 8,484,181

 16 (Less) Allowance for Other Funds Used During Construction

 17 (Less) Undistributed Earnings from Subsidiary Companies -339 -110

 18 Other (provide details in footnote):

 19 Net (Increase) Decrease in Accrued Utility Revenues -1,230,043 -6,000,000

 20 Net (Increase) Decrease in Other Current Assets 409,817 -15,947,004

 21 Net (Decrease) Increase in Other Operating Activities 142,256,106 -98,148,769

 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 203,851,769 234,481,244

 23

 24 Cash Flows from Investment Activities:

 25 Construction and Acquisition of Plant (including land):

 26 Gross Additions to Utility Plant (less nuclear fuel) -840,090,803 -377,360,532

 27 Gross Additions to Nuclear Fuel

 28 Gross Additions to Common Utility Plant

 29 Gross Additions to Nonutility Plant -908,897 -410

 30 (Less) Allowance for Other Funds Used During Construction

 31 Other (provide details in footnote):

 32

 33

 34 Cash Outflows for Plant (Total of lines 26 thru 33) -840,999,700 -377,360,942

 35

 36 Acquisition of Other Noncurrent Assets (d)

 37 Proceeds from Disposal of Noncurrent Assets (d)

 38 Proceeds from Sale of Fixed Assets 539,841 930,693

 39 Investments in and Advances to Assoc. and Subsidiary Companies

 40 Contributions and Advances from Assoc. and Subsidiary Companies 30,181,345 197,239,528

 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

 57 Total of lines 34 thru 55) -810,278,514 -179,190,721

 58

 59 Cash Flows from Financing Activities:

 60 Proceeds from Issuance of:

 61 Long-Term Debt (b) 742,989,500

 62 Preferred Stock

 63 Common Stock

 64 Other (provide details in footnote):

 65

 66 Net Increase in Short-Term Debt (c) 757,577

 67 Other (provide details in footnote):

 68

 69

 70 Cash Provided by Outside Sources (Total 61 thru 69) 742,989,500 757,577

 71

 72 Payments for Retirement of:

 73 Long-term Debt (b) -50,100,000 -50,000

 74 Preferred Stock

 75 Common Stock

 76 Other (provide details in footnote):

 77

 78 Net Decrease in Short-Term Debt (c) -757,577

 79

 80 Dividends on Preferred Stock

 81 Dividends on Common Stock -35,000,000 -56,000,000

 82 Net Cash Provided by (Used in) Financing Activities

 83 (Total of lines 70 thru 81) 657,131,923 -55,292,423

 84

 85 Net Increase (Decrease) in Cash and Cash Equivalents

 86 (Total of lines 22,57 and 83) 50,705,178 -1,900

 87

 88 Cash and Cash Equivalents at Beginning of Period 13,150 15,050

 89

 90 Cash and Cash Equivalents at End of period 50,718,328 13,150

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) X An 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 a Company

rate case with the OCC, the Company had 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 in the 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) X An 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) X An 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) X An 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

General

The Company reads its customers’ meters and sends bills to its customers throughout each month. As a result, there is a

significant amount of customers’ electricity consumption that has not been billed at the end of each month. An amount is accrued as a

receivable for this unbilled revenue based on estimates of usage and prices during the period. The estimates that management uses in

this calculation could vary from the actual amounts to be paid by customers. 

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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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 the Economic 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) X An 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) X An 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) X An 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 with Lehman, 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’s commercial paper arrangement. Also, the Company has a commercial paper

arrangement with Wachovia 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) X An 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 these charges 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) X An 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’s defined benefit pension plan and defined contribution plans were 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’s defined benefit pension plan and defined contribution plans were 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) X An 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 123.21
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) X An 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 123.22
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) X An 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 123.23
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) X An 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 123.24
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) X An 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 123.25
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) X An 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 123.26
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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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) X An 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 quarterly its 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) X An 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) X An 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) X An 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 an RFP to 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) X An 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. A procedural schedule has

not been established in this matter.

Name of Respondent

Oklahoma Gas and Electric Company 

This Report is:

(1) X An 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. A procedural

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 Company and OERI submitted a compliance filing to the

FERC on February 7, 2005 that applied the interim tests to the Company and OERI. In the compliance filing, the Company and OERI

passed the pivotal supplier screen but did not pass the market share screen in the Company’s control area. The Company and OERI

provided an explanation as to why their failure of the market share screen in the Company’s control area should not be viewed as an

indication that they can exercise generation market power. 

On June 7, 2005, the FERC issued an order on the Company’s and OERI’s market-based rate filing. Because the Company

and OERI failed the market share screen for the Company’s control area, the FERC established hearing procedures to investigate

whether the Company and OERI may continue to sell power at market-based rates in the Company’s control area. The order

established a rebuttable presumption that the Company and OERI have the ability to exercise market power in the Company’s control

area. The Company and OERI were requested 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 allows the Company and OERI to sell power

in first-tier markets subject to the Company and OERI providing additional information that clearly shows that they pass the market

share screen for the first-tier markets. The Company and OERI provided that additional information on July 7, 2005. On August 8,

2005, the Company and OERI informed the FERC that they will: (i) adopt the FERC default rate mechanism for sales of one week or

less to loads that sink in the 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 that sink in the Company’s control area. The Company and OERI also informed the FERC that any new

agreements for long-term sales (one year or longer in duration) to loads that sink in the Company’s control area will be filed with the

FERC and that the Company and OERI will not make such sales under their respective market-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 that the 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) X An 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) X An 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 provides for 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) X An 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 123.41
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.

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 and

Losses 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

 4 Total (lines 2 and 3)

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

 9 Total (lines 7 and 8)

Balance of Account 219 at End of Current

Quarter/Year

 10

FERC FORM NO. 1 (NEW 06-02) Page 122a
Other 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)

 1 582,009 582,009

 2 ( 582,009) ( 582,009)

 3

 4 ( 582,009) ( 582,009) 161,709,364 161,127,355

 5

 6

 7

 8

 9 143,006,547 143,006,547

 10

FERC FORM NO. 1 (NEW 06-02) Page 122b
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. (a) (b)

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.

 1 Utility Plant

 2 In Service

 3 Plant in Service (Classified) 6,085,957,606 6,085,957,606

 4 Property Under Capital Leases 593,667 593,667

 5 Plant Purchased or Sold

 6 Completed Construction not Classified 15,262,642 15,262,642

 7 Experimental Plant Unclassified

 8 Total (3 thru 7) 6,101,813,915 6,101,813,915

 9 Leased to Others

 10 Held for Future Use 2,136,865 2,136,865

 11 Construction Work in Progress 169,154,630 169,154,630

 12 Acquisition Adjustments 154,202,293 154,202,293

 13 Total Utility Plant (8 thru 12) 6,427,307,703 6,427,307,703

 14 Accum Prov for Depr, Amort, & Depl 2,633,061,106 2,633,061,106

 15 Net Utility Plant (13 less 14) 3,794,246,597 3,794,246,597

 16 Detail of Accum Prov for Depr, Amort & Depl

 17 In Service:

 18 Depreciation 2,613,172,433 2,613,172,433

 19 Amort & Depl of Producing Nat Gas Land/Land Right

 20 Amort of Underground Storage Land/Land Rights

 21 Amort of Other Utility Plant 18,414,353 18,414,353

 22 Total In Service (18 thru 21) 2,631,586,786 2,631,586,786

 23 Leased to Others

 24 Depreciation

 25 Amortization and Depletion

 26 Total Leased to Others (24 & 25)

 27 Held for Future Use

 28 Depreciation 8,126 8,126

 29 Amortization

 30 Total Held for Future Use (28 & 29) 8,126 8,126

 31 Abandonment of Leases (Natural Gas)

 32 Amort of Plant Acquisition Adj 1,466,194 1,466,194

 33 Total Accum Prov (equals 14) (22,26,30,31,32) 2,633,061,106 2,633,061,106

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 201
Name 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

(a) (b) (c)

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.

 1 Nuclear Fuel in process of Refinement, Conv, Enrichment & Fab (120.1)

 2 Fabrication

 3 Nuclear Materials

 4 Allowance for Funds Used during Construction

 5 (Other Overhead Construction Costs, provide details in footnote)

 6 SUBTOTAL (Total 2 thru 5)

 7 Nuclear Fuel Materials and Assemblies

 8 In Stock (120.2)

 9 In Reactor (120.3)

 10 SUBTOTAL (Total 8 & 9)

 11 Spent Nuclear Fuel (120.4)

 12 Nuclear Fuel Under Capital Leases (120.6)

 13 (Less) Accum Prov for Amortization of Nuclear Fuel Assem (120.5)

 14 TOTAL Nuclear Fuel Stock (Total 6, 10, 11, 12, less 13)

 15 Estimated net Salvage Value of Nuclear Materials in line 9

 16 Estimated net Salvage Value of Nuclear Materials in line 11

 17 Est Net Salvage Value of Nuclear Materials in Chemical Processing

 18 Nuclear Materials held for Sale (157)

 19 Uranium

 20 Plutonium

 21 Other (provide details in footnote):

 22 TOTAL Nuclear Materials held for Sale (Total 19, 20, and 21)

FERC FORM NO. 1 (ED. 12-89) Page 202
Name 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

(d) (e) (f)

Changes during Year

Amortization Other Reductions (Explain in a footnote) 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

FERC FORM NO. 1 (ED. 12-89) Page 203
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 IN SERVICE (Account 101, 102, 103 and 106)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Account Balance Additions

(a) (b) (c)

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 1. INTANGIBLE PLANT

 2 (301) Organization 80,900

 3 (302) Franchises and Consents 2,284,193 103,539

 4 (303) Miscellaneous Intangible Plant 33,441,204 4,894,303

 5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 35,806,297 4,997,842

 6 2. PRODUCTION PLANT

 7 A. Steam Production Plant

 8 (310) Land and Land Rights 11,399,927

 9 (311) Structures and Improvements 234,791,016 6,278,452

 10 (312) Boiler Plant Equipment 870,975,576 20,262,381

 11 (313) Engines and Engine-Driven Generators

 12 (314) Turbogenerator Units 365,684,942 3,715,229

 13 (315) Accessory Electric Equipment 127,359,288 951,578

 14 (316) Misc. Power Plant Equipment 52,692,913 1,331,100

 15 (317) Asset Retirement Costs for Steam Production 1,392,871

 16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 1,664,296,533 32,538,740

 17 B. Nuclear Production Plant

 18 (320) Land and Land Rights

 19 (321) Structures and Improvements

 20 (322) Reactor Plant Equipment

 21 (323) Turbogenerator Units

 22 (324) Accessory Electric Equipment

 23 (325) Misc. Power Plant Equipment

 24 (326) Asset Retirement Costs for Nuclear Production

 25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)

 26 C. Hydraulic Production Plant

 27 (330) Land and Land Rights

 28 (331) Structures and Improvements

 29 (332) Reservoirs, Dams, and Waterways

 30 (333) Water Wheels, Turbines, and Generators

 31 (334) Accessory Electric Equipment

 32 (335) Misc. Power PLant Equipment

 33 (336) Roads, Railroads, and Bridges

 34 (337) Asset Retirement Costs for Hydraulic Production

 35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34)

 36 D. Other Production Plant

 37 (340) Land and Land Rights 853,930

 38 (341) Structures and Improvements 12,682,806 -4,153

 39 (342) Fuel Holders, Products, and Accessories 1,288,805

 40 (343) Prime Movers 260,256,279 16,218,025

 41 (344) Generators 227,204,323 73,245

 42 (345) Accessory Electric Equipment 23,379,507

 43 (346) Misc. Power Plant Equipment 7,266,286 29,076

 44 (347) Asset Retirement Costs for Other Production 918,819

 45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 533,850,755 16,316,193

 46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 2,198,147,288 48,854,933

FERC FORM NO. 1 (REV. 12-05) Page 204
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

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No.

Account Balance Additions

(a) (b) (c)

Beginning of Year

 47 3. TRANSMISSION PLANT

 48 (350) Land and Land Rights 28,181,017 1,294,772

 49 (352) Structures and Improvements 3,279,887 194,348

 50 (353) Station Equipment 263,525,599 38,470,794

 51 (354) Towers and Fixtures 54,375,607 666,643

 52 (355) Poles and Fixtures 200,106,407 17,328,625

 53 (356) Overhead Conductors and Devices 173,580,323 4,782,994

 54 (357) Underground Conduit

 55 (358) Underground Conductors and Devices 110,494

 56 (359) Roads and Trails

 57 (359.1) Asset Retirement Costs for Transmission Plant

 58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 723,159,334 62,738,176

 59 4. DISTRIBUTION PLANT

 60 (360) Land and Land Rights 9,081,022 492,319

 61 (361) Structures and Improvements 3,425,243 1,266,582

 62 (362) Station Equipment 354,703,920 41,584,269

 63 (363) Storage Battery Equipment

 64 (364) Poles, Towers, and Fixtures 388,705,467 33,426,228

 65 (365) Overhead Conductors and Devices 301,276,761 23,937,403

 66 (366) Underground Conduit 111,052,903 12,363,123

 67 (367) Underground Conductors and Devices 443,941,064 46,040,871

 68 (368) Line Transformers 270,573,851 23,865,534

 69 (369) Services 187,925,832 15,187,704

 70 (370) Meters 80,438,800 6,420,464

 71 (371) Installations on Customer Premises 25,247

 72 (372) Leased Property on Customer Premises 593,667

 73 (373) Street Lighting and Signal Systems 153,945,836 13,125,473

 74 (374) Asset Retirement Costs for Distribution Plant

 75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 2,305,070,699 218,328,884

 76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT

 77 (380) Land and Land Rights

 78 (381) Structures and Improvements

 79 (382) Computer Hardware

 80 (383) Computer Software

 81 (384) Communication Equipment

 82 (385) Miscellaneous Regional Transmission and Market Operation Plant

 83 (386) Asset Retirement Costs for Regional Transmission and Market Oper

 84 TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)

 85 6. GENERAL PLANT

 86 (389) Land and Land Rights 3,089,771

 87 (390) Structures and Improvements 100,146,535 2,321,197

 88 (391) Office Furniture and Equipment 12,538,756 16,966

 89 (392) Transportation Equipment 52,447,852 11,395,881

 90 (393) Stores Equipment 1,137,033 51,265

 91 (394) Tools, Shop and Garage Equipment 5,640,680 737,552

 92 (395) Laboratory Equipment 8,097,158 196,633

 93 (396) Power Operated Equipment 5,603,352 659,277

 94 (397) Communication Equipment 2,148,415 18,158

 95 (398) Miscellaneous Equipment 5,245,810 41,114

 96 SUBTOTAL (Enter Total of lines 86 thru 95) 196,095,362 15,438,043

 97 (399) Other Tangible Property

 98 (399.1) Asset Retirement Costs for General Plant

 99 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 196,095,362 15,438,043

 100 TOTAL (Accounts 101 and 106) 5,458,278,980 350,357,878

 101 (102) Electric Plant Purchased (See Instr. 8) 852,919,406

 102 (Less) (102) Electric Plant Sold (See Instr. 8)

 103 (103) Experimental Plant Unclassified

 104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 5,458,278,980 1,203,277,284

FERC FORM NO. 1 (REV. 12-05) Page 206
(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

Oklahoma Gas and Electric Company End of 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

 17,939 2,369,793 3

 15,624,557 888,554 23,599,504 4

 15,642,496 888,554 26,050,197 5

 6

 7

 11,399,927 8

 561,405 240,508,063 9

 4,918,485 6,606 886,326,078 10

 11

 1,723,143 367,677,028 12

 198,004 128,112,862 13

 114,407 -326,099 53,583,507 14

 1,572 1,391,299 15

 7,517,016 -319,493 1,688,998,764 16

 17

 18

 19

 20

 21

 22

 23

 24

 25

 26

 27

 28

 29

 30

 31

 32

 33

 34

 35

 36

 326,890 1,180,820 37

 39,368,554 52,047,207 38

 15,247,054 16,535,859 39

 242,567,281 519,041,585 40

 1,800 -29,373 227,246,395 41

 39,548,116 62,927,623 42

 1,747,708 9,043,070 43

 -18,487 900,332 44

 1,800 338,757,743 888,922,891 45

 7,518,816 338,438,250 2,577,921,655 46

FERC FORM NO. 1 (REV. 12-05) Page 205
(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

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No. (g)

Adjustments

(e)

Retirements

(d)

ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)

 47

 -33,656 29,442,133 48

 3,474,235 49

 189,480 4,401,048 306,207,961 50

 521,919 55,564,169 51

 228,864 -5,566,896 211,639,272 52

 93,975 5,044,977 183,314,319 53

 54

 110,494 55

 56

 18,487 18,487 57

 512,319 4,385,879 789,771,070 58

 59

 -12,835 9,560,506 60

 10,005 4,701,830 61

 970,885 -1,757,824 393,559,480 62

 63

 3,403,343 418,728,352 64

 2,751,503 322,462,661 65

 207,340 123,208,686 66

 1,725,290 488,256,645 67

 5,500,143 288,939,242 68

 11,529 203,102,007 69

 939,465 85,919,799 70

 25,247 71

 593,667 72

 971,370 166,099,939 73

 74

 16,480,868 -1,760,654 2,505,158,061 75

 76

 77

 78

 79

 80

 81

 82

 83

 84

 85

 -73,950 3,015,821 86

 1,011,132 -802,693 100,653,907 87

 928,890 58,029 11,684,861 88

 4,709,127 -1,300,798 57,833,808 89

 101,785 1,086,513 90

 110,192 395,883 6,663,923 91

 57,262 -248,170 7,988,359 92

 397,053 1,304,657 7,170,233 93

 27,877 162,258 2,300,954 94

 36,931 -735,440 4,514,553 95

 7,380,249 -1,240,224 202,912,932 96

 97

 98

 7,380,249 -1,240,224 202,912,932 99

 47,534,748 340,711,805 6,101,813,915 100

 -510,335,255 -342,584,151 101

 102

 103

 47,534,748 -510,335,255 -1,872,346 6,101,813,915 104

FERC FORM NO. 1 (REV. 12-05) Page 207
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

(a) (b)

(Designate associated companies with a double asterisk) Property LeasedCommission

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) Page 213

47 TOTAL
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 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

(a) (b) (c) 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.

 1 Land and Rights:

 2 30 Distribution Substation Land Sites various various 1,316,487

 3 4 Distribution Substation Easement Sites various various 44,493

 4 13 Transmission Substation Land and Line Easements various various 775,885

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Other Property:

 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 2,136,865
Name 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 - 

(a) (b)

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.

 1 OU Spirit Wind Farm Construction 35,794,112

 2 SO Transformer Rewind 3,448,838

 3 MK4 Replace Stator Coils & Rewind Generator 3,287,320

 4 RB2 Hot Gas Path Components Replacement 1,973,297

 5 RB3 Hot Gas Path Components Replacement 1,861,969

 6 MK Radial Stacker Boom Replacement 1,500,682

 7 MK6 Bowl Mill Partial Replacement 999,532

 8 MK6 Cooling Tower Fill Replacement 450,588

 9 SM1 FA High Pressure Feedwater Heater Replacement 432,293

 10 MT Low Volume Waste Pond Liner Replacement 342,409

 11 MK3 Traveling Screens and Racks Replacement 325,484

 12 MK6 Cooling Tower Inlet Traveling Screens Replacement 313,440

 13 MK6 Emergency Make-Up Piping Replacement at Settling Basin 278,556

 14 SO Install Dust Suppression at Plant Surge Bin 206,627

 15 MK4/5 Boiler Enclosure Vent Fan Replacement 205,683

 16 MK6 Install Platform above Hot Air Ducts 163,250

 17 SO2 Install Reheat Safety Valve 162,048

 18 SM Administration Roof Replacement 157,852

 19 SM Electric Building Roof Replacement 157,852

 20 MC Install Piping from Plant to River for Discharge from Injection Well 157,850

 21 MK Water Wagon Conversion 154,496

 22 MK6 Install Heavy Duty Bowl Mill Bottom 149,898

 23 OU Spirit - Generation Lead Construction 148,653

 24 SO Modify River Pump Forebay 145,725

 25 SO 9 Ton Mobile Crane Replacement 141,038

 26 MK6 Crusher Rotor Assembly Replacement 135,596

 27 MK 4-5 Tripper Gallery Drain Piping Replacement 128,106

 28 OU Spirit - Substation Construction 125,592

 29 SO Main Warehouse Roof Replacement 124,139

 30 SO 20,000 Pound Forklift Replacement 115,636

 31 MK5 Replace Hydro-Bin Gate and Actuators 111,621

 32 Add Distribution Line capacity and Construct Liberty Lake Substation 6,667,014

 33 Construct Blue Bird Substation 3,315,851

 34 Construct Chisholm Creek Substation 2,770,629

 35 Replace Underground Cable in various locations 2,395,511

 36 Relocate Distribution Lines for I-40 Relocation 1,405,934

 37 Fort Smith District Office Construction 1,111,130

 38 Purchase (7) Heavy Duty Single Axle Trucks 1,062,400

 39 Construct new Service Center in Metro Campus 900,624

 40 Purchase (7) 45' Digger Derrick Trucks 814,014

 41 Install underground Distribution Lines for downtown OKC apartment complex 789,246

 42 Replace Breakers at Dewey Substation 787,350

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

43 TOTAL 169,154,630
Name 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 - 

(a) (b)

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.

 1 Replace Poles and Transformers to convert from Single Phase to Three Phase Lines 718,706

 2 Construct Barnes Substation 631,506

 3 Reconductor Spring Hill to Lexington Distribution Line 626,518

 4 Construct New Dominion Substation 613,460

 5 Replace Breakers at Maud Tap 553,575

 6 Relocate Distribution Lines for Hwy 70 Relocation 520,330

 7 Purchase two 95' rear mounted Material Handler Baskets 519,466

 8 Install Distribution Lines for housing project at Tinker Air Force Base 490,874

 9 Install 4,000 feet of Underground Copper Conductor 483,063

 10 Replace 9,500 square foot roof at Metro Service Center 463,827

 11 Replace Transformer for Mobile 7 Substation 1,490,426

 12 Remodel System Resources Office 418,130

 13 Install Underground Distribution Lines & Backup Feeder for medical facility in OKC 415,664

 14 Convert system north of Mountainburg to 34.5 kV Distribution Lines 402,532

 15 Install Distribution Lines and Transformers for apartment complex 397,989

 16 Relocate Underground Distribution Lines for medical facility in Muskogee 393,944

 17 Install 34.5 to 12.5 kV Step-down Transformer and overhead distribution phases 389,094

 18 Convert 6 miles of Distribution Line also install Transformer & Primary Meter 357,647

 19 Replace various Oil Circuit Reclosers with Vacuum Reclosures 356,858

 20 Relocate Distribution Lines for 36th & Main in Norman 354,200

 21 Upgrade downtown OKC underground Distribution Lines 350,337

 22 Reconductor 2 miles of Distribution Line Logan County 342,120

 23 Replace Roof at Sapulpa Service Center 337,601

 24 Install Distribution services for retail development in Ardmore 318,488

 25 Install Drainage System at Metro Service Center 309,188

 26 Install Underground Distribution lines for residential development in OKC 265,840

 27 Rebuild Meeker 4kV Conversion 259,553

 28 Relocate Distribution Lines at I-235 & I-44 in OKC 254,714

 29 Relocate Distribution Lines between NW150th & NW164th 248,541

 30 Add Transmission Lines for Carl Albert Health Facility 247,830

 31 Relocate Underground Distribution Lines at I-40 and Gaylord in OKC 246,022

 32 Install Distribution Lines for Fountain Lake apartment complex 232,771

 33 Install Transformer for Oklahoma Heart Hospital 228,584

 34 Reconductor, add poles and conductor to serve new pumping station 223,353

 35 Purchase 80' Digger Derrick Truck 219,206

 36 Install Underground Distribution lines for commercial development in OKC 214,485

 37 Convert 1.5 miles of 12.5kV Distribution Line for housing addition 207,426

 38 Install Distribution Lines to serve Spiro Coal Mine 207,226

 39 Rewind Transformer at Crossroads Substation 201,753

 40 Install Cottage Apartment Lights on Poles 187,059

 41 Install Distribution services for Heritage Crossing business complex 184,646

 42 Purchase Software: Distribution Asset Analysis on Demand 183,741

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

43 TOTAL 169,154,630
Name 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 - 

(a) (b)

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.

 1 Distribution Underbuild Earlywine to Penn 180,465

 2 Install Underground Cable/Transformer Pads/Cubicle Bases for customer 175,504

 3 Install Underground Utilities to serve 60 unit retirement village 174,920

 4 Purchase 80' Digger Derrick Truck 165,447

 5 Install Underground Distribution system for Valenica II Housing Addition 151,519

 6 Expand Relay Tech Room at Metro 150,443

 7 Install Transformers, Pedestals, and Underground Lines for 81 residential lots 146,954

 8 Install additional Underground Distribution facilities at SE 149th & Sooner 143,032

 9 Install 2.5 miles Distribution Lines/Poles/Step-Down Transformer for customer 142,487

 10 Install Pedestals, Transformers and Underground Lines for 33 new residential lots 135,002

 11 Extend 2 miles of Overhead Distribution Line for ONEOK plant 132,370

 12 Add Transformer, Reconductor for Madill Industrial 130,362

 13 Purchase land for 84th Street Substation 128,998

 14 Replace Breaker at Roman Nose Substation 121,726

 15 Install Distribution Facilities to serve 63 residential lots 117,192

 16 Install Underground Distribution System for Gateway Industrial Park 112,322

 17 Install Underground Distribution Facilities to serve 23 residential lots 108,762

 18 Install Underground Distribution Facilities to serve 54 residential lots 107,474

 19 Relocate Distribution Lines for widening of Rodgers Ave 105,823

 20 Purchase Heavy Duty Tandem Axle Trailer 105,091

 21 Purchase PROMOD IV, PowerBase and MarketVision Software 167,981

 22 OMS/CADS Software Upgrade 188,288

 23 Construct 120 miles of 345kV Transmission Line, Northwest to Woodward 18,433,180

 24 Purchase two Transformers for EEI STEP Program 5,931,308

 25 Construct 138kV Transmission Line from McClain Substation to SW149th & Portland 4,857,870

 26 Purchase High Side Integrated Transmission Facilities for Spring Creek Substation 4,559,457

 27 Construct 10 miles of Transmission Line including crossing over Arkansas River 2,827,779

 28 Construct 5 miles of 138 kV Transmission Line to serve Blue Bird Substation 1,940,565

 29 Construct Liberty Lake Substation 993,089

 30 Purchase Right of Way for Transmission Line from Garber to Chitwood 922,923

 31 Reconductor 1.91 miles of 138 kV Transmission Line, Stillwater to McElroy 875,555

 32 Loop the Cottonwood 138kV Line to new Liberty Lake Substation 871,974

 33 Replace H Frames, Poles, and Crossarms for Woodring - Morrison Tap 743,448

 34 Construct Woodward Substation 700,868

 35 Relocate 3/4 mile of 69kV Transmission Lines, Ahloso - Hardin City 652,303

 36 Replace Relays at Conoco North Substation 633,751

 37 Purchase 11 miles of Right of Way, Warwick to Bell Cow 589,981

 38 Purchase 5.5 miles of Right of Way, Bell Cow to Horseshow Lake - Bristow 564,856

 39 Construct new 161kV Transmission Line, Simmons - Mountainburg II 542,062

 40 Rebuild the 138 kV Transmission Line from Springhill Tap - Rosedale 492,821

 41 Reconductor 2.69 miles of 138 kV Transmission Line, Beeline - AEP Riverside 491,403

 42 Replace Breakers at Van Buren Substation 455,980

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

43 TOTAL 169,154,630
Name 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 - 

(a) (b)

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.

 1 Purchase Tatonga Substation Site 444,898

 2 Install Breakers at Various Substations 427,557

 3 Relocate 138kV Transmission Line over new I-40 Cross-town 409,950

 4 Replace 138 kV Poles from Chikaskia - Deer Creek 404,037

 5 Replace Protective Relays at Ft. Smith Substation 329,639

 6 Relocate Line Terminal at McClain Substation 327,392

 7 Construct New Dominion Substation 313,232

 8 Replace Poles, Crossarms on Transmission Line: Muskogee - Ft. Smith 303,527

 9 Purchase Right of Way for McClain to Earlywine Transmission Line 289,376

 10 Install Terminal and Breaker at Chitwood Substation 288,593

 11 Replace Relay at Muskogee Substation 271,469

 12 Relocate 1/2 mile of Transmission Line at SW 5th & Classen 262,208

 13 Purchase Right of Way for Earlywine to Pennsylvania 254,749

 14 Replace Relays at White Eagle Substation 254,505

 15 Install on-line Substation Monitoring and Diagnostics system 251,649

 16 Distribution Underbuild Earlywine to Penn 245,338

 17 Replace Battery/Charger/Relay at Cimarron Substation 241,803

 18 Replace Relays at Park Lane Substation 239,729

 19 Install line Terminals and Breakers for the Division Ave Substation 233,903

 20 Install Transmission Breakers in the Hollywood Substation 228,834

 21 Replace Relays in the S. 4th Street Substation 221,794

 22 Purchase 4 miles of Right of Way for Earlywine to SW134th & Western 219,004

 23 Transmission Plant Critical Spares 184,191

 24 Replace Poles and Crossarms on the Sulphur - Pauls Valley Transmission Line 167,166

 25 Install New Line Terminal and Breaker at Arcadia Substation 163,874

 26 Construct 138kV Transmission Line from McClain Substation to SW134th & Penn Tap 163,761

 27 Install Double Circuit with Division - Piedmont 138kV 161,272

 28 Replace Structure Frames with Distribution under build for 69kV Transmission line 160,378

 29 Construct Sooner - Rose Hill 345kV Transmission Line 157,766

 30 Construct new Line Terminal at Woodward Substation 147,979

 31 Replace Breakers in various Substations 145,760

 32 Install new Line Terminal rack on Hollywood Transmission Line 145,089

 33 Replace Relays at various Substation locations 137,818

 34 Replace Relays at Memorial Substation 101,075

 35

 36 Approximately 110 projects covering additions & betterments to Generating Stations 3,179,003

 37

 38 Approximately 580 projects covering additions, betterments & miscellaneous 10,851,637

 39 rebuilds to distribution lines and substations

 40

 41 Approximately 7 projects covering additions & betterments to General Plant items 444,783

 42

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

43 TOTAL 169,154,630
Name 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 - 

(a) (b)

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.

 1 Approximately 307 projects covering additions, betterments & miscellaneous 3,418,379

 2 rebuilds to transmission lines & substations

 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 169,154,630
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 PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Item Total

(a) (b) (c) (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.

 1 Balance Beginning of Year 2,460,639,640 2,460,639,640

 2 Depreciation Provisions for Year, Charged to

 3 (403) Depreciation Expense 145,532,587 145,532,587

(403.1) Depreciation Expense for Asset

Retirement Costs

 4 45,247 45,247

 5 (413) Exp. of Elec. Plt. Leas. to Others

 6 Transportation Expenses-Clearing

 7 Other Clearing Accounts

 8 Other Accounts (Specify, details in footnote): 55,398,283 55,398,283

 9 Transportation Expense Capitalized 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

 11 Net Charges for Plant Retired:

 12 Book Cost of Plant Retired 31,891,207 31,891,207

 13 Cost of Removal 31,447,440 31,447,440

 14 Salvage (Credit) 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

 17

 18 Book Cost or Asset Retirement Costs Retired

Balance End of Year (Enter Totals of lines 1,

10, 15, 16, and 18)

 19 2,613,180,559 2,613,172,433 8,126

 20 Steam Production

Section B. Balances at End of Year According to Functional Classification

 1,134,151,454 1,134,151,454

 21 Nuclear Production

 22 Hydraulic Production-Conventional

 23 Hydraulic Production-Pumped Storage

 24 Other Production 251,867,936 251,867,936

 25 Transmission 314,201,751 314,201,751

 26 Distribution 835,245,654 835,245,654

 27 Regional Transmission and Market Operation

 28 General 77,713,764 77,713,764

 29 TOTAL (Enter Total of lines 20 thru 28) 2,613,180,559 2,613,180,559

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

(a) (b) (c)

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.

 1 The Arklahoma Corporation

 2 24 Shares of Common Stock 12/03/47 17,000

 3

 4 4.8% of Equity Earnings 57

 5

 6 Subtotal 17,057

 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 224

42 Total Cost of Account 123.1 $ 16,718 TOTAL 17,057
Name 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

 -339 -282 4

 5

 -339 16,718 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 16,718
Name 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

(a) (b) (c)

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.

 1 Fuel Stock (Account 151) 44,342,665 56,640,508

 2 Fuel Stock Expenses Undistributed (Account 152)

 3 Residuals and Extracted Products (Account 153)

 4 Plant Materials and Operating Supplies (Account 154)

 5 Assigned to - Construction (Estimated) 44,827,517 44,450,285 T&D/Power Prod.

 6 Assigned to - Operations and Maintenance

 7 Production Plant (Estimated) 13,105,718 20,946,297 Power Production

 8 Transmission Plant (Estimated) 242,629 232,238 T&D

 9 Distribution Plant (Estimated) 1,698,407 1,765,006 T&D

 10 Regional Transmission and Market Operation Plant

(Estimated)

 11 Assigned to - Other (provide details in footnote)

 12 TOTAL Account 154 (Enter Total of lines 5 thru 11) 59,874,271 67,393,826

 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

 20 TOTAL Materials and Supplies (Per Balance Sheet) 104,216,936 124,034,334

FERC FORM NO. 1 (REV. 12-05) Page 227
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) X An 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
Name 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

(a) (b)

(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

 1 Balance-Beginning of Year

 2

 3 Acquired During Year:

 4 Issued (Less Withheld Allow)

 5 Returned by EPA

 6

 7

 8 Purchases/Transfers:

 9

 10

 11

 12

 13

 14

 15 Total

 16

 17 Relinquished During Year:

 18 Charges to Account 509

 19 Other:

 20

 21 Cost of Sales/Transfers:

 22

 23

 24

 25

 26

 27

 28 Total

 29 Balance-End of Year

 30

 31 Sales:

 32 Net Sales Proceeds(Assoc. Co.)

 33 Net Sales Proceeds (Other)

 34 Gains

 35 Losses

Allowances Withheld (Acct 158.2)

 36 Balance-Beginning of Year

 37 Add: Withheld by EPA

 38 Deduct: Returned by EPA

 39 Cost of Sales

 40 Balance-End of Year

 41

 42 Sales:

 43 Net Sales Proceeds (Assoc. Co.)

 44 Net Sales Proceeds (Other)

 45 Gains

 46 Losses

FERC FORM NO. 1 (ED. 12-95) Page 228
Name 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) Page 229
Name 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.

(a) (b) (c) (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

(e) (f)

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 TOTAL
Name 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.

(a) (b) (c) (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

(e) (f)

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 TOTAL
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 Service and Generation Interconnection Study Costs

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No. Description

Costs Incurred During

(a) (b)

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

 1 Transmission Studies

 2

 3

 4

 5

 6

 7

 8

 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 19

 20

 21 Generation Studies

 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) Page 231
Name 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

(a) (c) (d)

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)

 1 Oklahoma Corporation Commission 613,284 1,276,707 928 1,257,445 632,546

 2 Assessment Fee

 3 (Expensed during Commissions fiscal year)

 4

 5 Deferred Tax Asset - SFAS 109 55,261,360 407,472 190, 283, 4,339,158 51,329,674

 6 (22 year amortization period) 282,426.5

 7

 8 McClain Plant Costs - PUD 200100455 4,716,171 403 2,358,085 2,358,086

 9 ( 4 year recovery period ) 627,208 408.1 313,604 313,604

 10 4,983,133 427 2,491,566 2,491,567

 11 1,826,734 546-554 913,367 913,367

 12 98,383 927, 930.2 49,192 49,191

 13 185,069 926 92,535 92,534

 14

 15 SFAS 158 174,572,632 209,754,507 926 39,624,593 344,702,546

 16

 17 Deferred Pension Expense - PUD 200500151 24,760,567 68,701 926 10,205,673 14,623,595

 18

 19 Storm Expense-PUD 200500151 35,853,591 1,889,027 592, 593 6,153,034 31,589,584

 20

 21 Red Rock-Corp. Comm. Staff Expert-PUD 200700012 46,067 5,222 51,289

 22

 23 Red Rock-Attorney General Expert Exp-PUD 200700012 254,387 ( 1,162) 253,225

 24

 25 Red Rock - PUD 200800215 14,813,099 426.5 7,678,476 7,134,623

 26

 27 Arkansas Storm Expenses 577,861 577,861

 28

 29 Redbud - Staff Expert 62,407 62,407

 30

 31 Wind RFP - OCC Independent Evaluator 141,736 141,736

 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 303,798,586 228,995,577 75,476,728 457,317,435
Name 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

(a) (b) (c)

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.

 1 Costs associated with SFAS 106 320,000 146 300,000 20,000

 2

 3 Arklahoma Reimbursable Expenses 36,214 36,214

 4

 5 Red Rock - Post abandonment 14,430,007 182.3 14,430,007

 6

 7 Costs assoc. with debt offering 45,777 181 45,777

 8

 9 Power Supply Control Study 109,498 109,498

 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)

 14,795,784 165,712
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 INCOME TAXES (Account 190)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Description and Location Balance of Begining

(a) (b) (c)

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.

 1 Electric

 2 Accrued Vacation 3,918,073 4,270,719

 3 Bad Debts 1,425,958 1,095,142

 4 Oklahoma Tax Credit Carryover 4,494,599 20,911,405

 5 Medicare Part D Subsidy 12,643,250 14,552,076

 6 Post-Retirement Benefits 20,369,093 23,510,542

 7 Other (See note below) 17,716,957 18,696,117

 8 TOTAL Electric (Enter Total of lines 2 thru 7) 60,567,930 83,036,001

 9 Gas

 10

 11

 12

 13

 14

 15 Other

 16 TOTAL Gas (Enter Total of lines 10 thru 15

 17 Other (Specify)

 18 TOTAL (Acct 190) (Total of lines 8, 16 and 17) 60,567,930 83,036,001

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) Page 234
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)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Class and Series of Stock and Number of shares

(a) (b) (c)

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 Common Stock 100,000,000 2.50

 3

 4 Total Common Stock 100,000,000

 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 250
AS 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 Amount Shares

(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

 40,378,745 100,946,863 2

 3

 40,378,745 100,946,863 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) X An 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
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line Item Amount (a) (b)

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

 2 Account 208 - Donations Received from Stockholders

 3

 4 Balance January 1, 2008 153,000,000

 5

 6 Contribution Received from Parent Company 293,000,000

 7 ( Purpose was for purchase of Redbud Plant )

 8

 9

 10

 11 Balance December 31, 2008 446,000,000

 12

 13

 14

 15 Account 210 - Gain on Resale or Cancellation of Reacquired

 16 Capital Stock

 17

 18 Balance January 1, 2008 1,997,342

 19

 20

 21

 22

 23 Balance December 31, 2008 1,997,342

 24

 25 SUBTOTAL Balance December 31, 2008 447,997,342

 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 447,997,342
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 STOCK EXPENSE (Account 214)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Class and Series of Stock Balance at End of Year

(a) (b)

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 TOTAL
Name 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 

(b) (c) (a)

Total expense, 

Premium or Discount

Principal Amount

(For new issue, give commission Authorization numbers and dates) Of Debt issued

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.

 1 Account 224 - Other Long Term Debt

 2

 3 Senior Notes Series Due 2016 - 5.15% 110,000,000 918,434

 4 Senior Notes Series Due 2016 - 5.15% 358,600 D

 5 Senior Notes Series Due 2017 - 6.50% 125,000,000 1,174,985

 6 Senior Notes Series Due 2017 - 6.50% 116,250 D

 7 Senior Notes Series Due 2018 - 6.35% 250,000,000 1,895,080

 8 Senior Notes Series Due 2018 - 6.35% 887,500 D

 9 Senior Notes Series Due 2019 - 8.25% 250,000,000 1,694,608

 10 Senior Notes Series Due 2019 - 8.25% 45,000 D

 11 Senior Notes Series Due 2027 - 6.65% 125,000,000 1,221,235

 12 Senior Notes Series Due 2028 - 6.50% 100,000,000 1,058,756

 13 Senior Notes Series Due 2028 - 6.50% 1,569,000 D

 14 Senior Notes Series Due 2034 - 6.50% 140,000,000 1,433,833

 15 Senior Notes Series Due 2034 - 6.50% 180,600 D

 16 Senior Notes Series Due 2036 - 5.75% 110,000,000 1,160,184

 17 Senior Notes Series Due 2036 - 5.75% 453,200 D

 18 Senior Notes Series Due 2038 - 6.45% 200,000,000 2,041,573

 19 Senior Notes Series Due 2038 - 6.45% 1,078,000 D

 20

 21 Account 221 - Bonds

 22

 23 Pollution Control Series A, due 2025 Garfield County - variable 47,000,000 303,286

 24 Pollution Control Series A, due 2025 Muskogee Ind. - variable 32,400,000 267,768

 25 Pollution Control Series A, due 2027 Muskogee Ind. - variable 56,000,000 272,062

 26

 27

 28

 29

 30

 31

 32

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

33 TOTAL 1,545,400,000 18,129,954
Name 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

01/15/2006 01/15/2016 01/15/2006 01/15/2016 110,000,000 5,665,000 3

01/15/2006 01/15/2016 4

07/15/1997 07/15/2017 07/15/1997 07/15/2017 125,000,000 8,125,000 5

07/15/1997 07/15/2017 6

09/01/2008 09/01/2018 09/01/2008 09/01/2018 250,000,000 4,938,889 7

09/01/2008 09/01/2018 8

01/15/2009 01/15/2019 01/15/2009 01/15/2019 250,000,000 1,203,125 9

01/15/2009 01/15/2019 10

07/15/1997 07/15/2027 07/15/1997 07/15/2027 124,950,000 8,307,651 11

04/15/1998 04/15/2028 04/15/1998 04/15/2028 100,000,000 6,500,000 12

04/15/1998 04/15/2028 13

08/01/2004 08/01/2034 08/01/2004 08/01/2034 140,000,000 9,100,000 14

08/01/2004 08/01/2034 15

01/15/2006 01/15/2036 01/15/2006 01/15/2036 110,000,000 6,325,000 16

01/15/2006 01/15/2036 17

02/01/2008 2/01/2038 02/01/2008 02/01/2038 200,000,000 11,860,833 18

02/01/2008 02/01/2038 19

 20

 21

 22

01/01/1995 01/01/2025 01/01/1995 01/01/2025 47,000,000 1,136,603 23

01/01/1995 01/01/2025 01/01/1995 01/01/2025 32,400,000 766,553 24

06/01/1997 06/01/2027 06/01/1997 06/01/2027 55,900,000 1,361,782 25

 26

 27

 28

 29

 30

 31

 32

FERC FORM NO. 1 (ED. 12-96) Page 257

 1,545,250,000 65,290,436 33
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) X An 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
Name 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)

(a) (b)

Line Amount 

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.

 1 Net Income for the Year (Page 117) 143,006,547

 2

 3

 4 Taxable Income Not Reported on Books

 5 Contributions in Aid of Construction 2,268,872

 6 Salvage 4,108,305

 7

 8

 9 Deductions Recorded on Books Not Deducted for Return

 10 Provision for Current Federal Income Taxes -31,129,736

 11 Provision for Deferred Income Taxes 91,903,022

 12 Investment Tax Credit, Net -4,640,304

 13 Other Items 30,265,846

 14 Income Recorded on Books Not Included in Return

 15 Amortization of Regulatory Liabilities 1,338,936

 16 Allowance for Borrowed Funds Used During Construction 2,619,304

 17

 18

 19 Deductions on Return Not Charged Against Book Income

 20 Pension Plan 25,067,000

 21 RAR Settlement Interest -385,678

 22 Excess Tax Over Book Depreciation 211,292,219

 23 Removal Expense 31,366,831

 24 Repair Allowance 12,849,226

 25 Provision for Rate Refund -300,000

 26 Other Items 10,832,318

 27 Federal Tax Net Income -58,897,604

 28 Show Computation of Tax:

 29 Tax at 35% -20,614,161

 30

 31 Total Federal Income Tax -20,614,161

 32 Add Adjustments of Prior Years' Federal Tax -10,515,575

 33 Current Federal Income Tax Per Books -31,129,736

 34

 35

 36

 37

 38

 39

 40

 41

 42

 43

 44

FERC FORM NO. 1 (ED. 12-96) Page 261
Name 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.

 1 Federal Income -31,129,736 -31,129,736

 2 Insurance Contribution 11,351,614 11,351,731

 3 Unemployment 2,720 129,077 128,088

 4

 5 Total Federal 2,720 -19,649,045 -19,649,917

 6

 7

 8 Oklahoma Income -3,756,605 -3,756,605

 9 Unemployment 1,050 30,944 31,017

 10 Corporate License 20,000 20,000

 11 Motor Vehicle Registration 160,039 160,039

 12 Sales Tax 5,118 61,491 61,470

 13 Use Tax

 14

 15 Total Oklahoma 6,168 -3,484,131 -3,484,079

 16

 17

 18 Arkansas Income -248,903 26,666 -65,731

 19 Unemployment 47 6,635 6,647

 20 Franchise 15,083 15,083

 21 Sales Use and Excise Tax 7,752 7,752

 22 Total Arkansas -248,856 56,136 -36,249

 23

 24

 25 Oklahoma - Local

 26 Ad Valorem - Property 23,199,492 52,192,549 49,370,106

 27

 28 Total - Oklahoma Local 23,199,492 52,192,549 49,370,106

 29

 30

 31 Arkansas - Local

 32 Ad Valorem - Property 1,921,687 2,037,342 1,929,647

 33

 34 Total - Arkansas - Local 1,921,687 2,037,342 1,929,647

 35

 36

 37

 38

 39

 40

FERC FORM NO. 1 (ED. 12-96) Page 262

41 TOTAL 24,881,211 31,152,851 28,129,508
Name 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.

 -29,898,238 -1,231,498 1

 -117 8,387,692 3,116,271 2

 3,709 94,563 35,177 3

 4

 3,592 -21,415,983 1,919,950 5

 6

 7

 -3,825,174 68,569 8

 977 23,154 7,882 9

 20,000 10

 160,039 11

 5,139 61,489 12

 13

 14

 6,116 -3,720,531 236,490 15

 16

 17

 -156,506 26,666 18

 35 4,958 1,677 19

 15,083 20

 7,752 21

 -156,471 54,459 1,677 22

 23

 24

 25

 26,021,935 49,299,984 26

 27

 26,021,935 49,299,984 28

 29

 30

 31

 2,029,382 2,037,342 32

 33

 2,029,382 2,037,342 34

 35

 36

 37

 38

 39

 40

FERC FORM NO. 1 (ED. 12-96) Page 263

 27,904,554 26,255,271 2,158,117 41
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)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Account Balance at Beginning

(c) (a) (b)

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.

 1 Electric Utility

 2 3%

 3 4%

 4 7%

 5 10% 21,970,123 411.4 4,640,304

 6

 7

 8 TOTAL 21,970,123 4,640,304

Other (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 266
Balance at End

(h) (i)

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 267
Name 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

(a) (b) (c)

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

 2 GE Long Term Service Agreement 4,477,434 131 1,174,866 7,507,778 10,810,346

 3

 4 Kaw Water Storage Agreement 8,689,769 131 265,149 749,708 9,174,328

 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 13,167,203 1,440,015 8,257,486 19,984,674
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 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)

 2 Electric

 3 Defense Facilities

 4 Pollution Control Facilities

 5 Other (provide details in footnote):

 6

 7

 8 TOTAL Electric (Enter Total of lines 3 thru 7)

 9 Gas

 10 Defense Facilities

 11 Pollution Control Facilities

 12 Other (provide details in footnote):

 13

 14

 15 TOTAL Gas (Enter Total of lines 10 thru 14)

 16

 17 TOTAL (Acct 281) (Total of 8, 15 and 16)

 18 Classification of TOTAL

 19 Federal Income Tax

 20 State Income Tax

 21 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page 272

NOTES
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 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

Amounts Debited Debits Credits

to Account 410.2

Amounts Credited 

to Account 411.2 Account

Credited

Amount

Debited

Account Amount

(e) (f) (h) (j) (g) (k) (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.

 1 Account 282

 2 Electric 591,683,261 98,594,423 8,752,451

 3 Gas

 4

 5 TOTAL (Enter Total of lines 2 thru 4) 591,683,261 98,594,423 8,752,451

 6

 7

 8

 9 TOTAL Account 282 (Enter Total of lines 5 thru 591,683,261 98,594,423 8,752,451

 10 Classification of TOTAL

 11 Federal Income Tax 534,215,793 94,268,078 7,903,217

 12 State Income Tax 57,467,468 4,326,345 849,234

 13 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page 274

NOTES
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 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

Amounts Debited Debits Credits

to Account 410.2

Amounts Credited 

to Account 411.2 Account

Credited

Amount

Debited

Account Amount

(e) (f) (h) (j) (g) (k) (i)

3. Use footnotes as required.

 1

182.3 3,474,076190 8,929,906 686,981,063 2

 3

 4

 3,474,076 8,929,906 686,981,063 5

 6

 7

 8

 3,474,076 8,929,906 686,981,063 9

 10

 3,136,993 8,063,453 625,507,114 11

 337,083 866,453 61,473,949 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) X An 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
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 (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.

 1 Account 283

 2 Electric

 3 90,542,049 21,439,131

 4

 5

 6

 7

 8

 9 TOTAL Electric (Total of lines 3 thru 8) 90,542,049 21,439,131

 10 Gas

 11

 12

 13

 14

 15

 16

TOTAL Gas (Total of lines 11 thru 16) 17

 18

 19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 90,542,049 21,439,131

 20 Classification of TOTAL

 21 Federal Income Tax 81,683,926 19,358,931

 22 State Income Tax 8,858,123 2,080,200

 23 Local Income Tax

FERC FORM NO. 1 (ED. 12-96) Page 276

NOTES
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 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

Amounts Debited Debits Credits

to Account 410.2

Amounts Credited 

to Account 411.2 Account

Credited

Amount

Debited

Account Amount

(e) (f) (g) (h) (i) (j) (k)

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

282 5,890,384 409.1 26,243 106,117,039 3

 4

 5

 6

 7

 8

 5,890,384 26,243 106,117,039 9

 10

 11

 12

 13

 14

 15

 16

 17

 18

 5,890,384 26,243 106,117,039 19

 20

 5,248,346 26,243 95,820,754 21

 642,038 10,296,285 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 Adjustments 2,297,727

 Total $106,117,039 

Name of Respondent

Oklahoma Gas and Electric Company 

This Report is:

(1) X An 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
Name 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

Account Credits

(a) (c) (d)

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)

 1 Deferred Tax Liability 26,710,090 283 3,446,726 3,121,820 26,385,184

 2 ( 22 year amortization period )

 3

 4 Deferred Gain on Sale of Assets 1,355,450 421.1 1,338,937 16,513

 5 ( PUD 200500151 )

 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 28,065,540 4,785,663 3,121,820 26,401,697
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.

Title of Account

(a) (b) (c)

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)

 1 Sales of Electricity

 2 (440) Residential Sales 751,165,773 706,416,931

 3 (442) Commercial and Industrial Sales

 4 Small (or Comm.) (See Instr. 4) 478,962,880 450,040,859

 5 Large (or Ind.) (See Instr. 4) 371,712,125 362,334,506

 6 (444) Public Street and Highway Lighting 8,692,703 9,103,632

 7 (445) Other Sales to Public Authorities 181,642,128 172,336,362

 8 (446) Sales to Railroads and Railways

 9 (448) Interdepartmental Sales

 10 TOTAL Sales to Ultimate Consumers 1,792,175,609 1,700,232,290

 11 (447) Sales for Resale 135,198,689 107,242,712

 12 TOTAL Sales of Electricity 1,927,374,298 1,807,475,002

 13 (Less) (449.1) Provision for Rate Refunds 403,441 -62,459

 14 TOTAL Revenues Net of Prov. for Refunds 1,926,970,857 1,807,537,461

 15 Other Operating Revenues

 16 (450) Forfeited Discounts 4,874,726 4,636,367

 17 (451) Miscellaneous Service Revenues 8,061,586 7,864,733

 18 (453) Sales of Water and Water Power

 19 (454) Rent from Electric Property 1,082,673 1,146,823

 20 (455) Interdepartmental Rents

 21 (456) Other Electric Revenues 76,731,571 64,853,142

 22 (456.1) Revenues from Transmission of Electricity of Others 18,492,145 16,612,531

 23 (457.1) Regional Control Service Revenues

 24 (457.2) Miscellaneous Revenues

 25

 26 TOTAL Other Operating Revenues 109,242,701 95,113,596

 27 TOTAL Electric Operating Revenues 2,036,213,558 1,902,651,057

FERC FORM NO. 1/3-Q (REV. 12-05) Page 300
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

Current Year (no Quarterly) Previous 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

 8,962,158 8,667,389 657,391 651,482 2

 3

 6,471,249 6,317,091 84,491 83,537 4

 6,966,677 7,036,938 9,480 9,495 5

 62,758 66,705 250 249 6

 2,943,338 2,883,076 15,274 14,812 7

 8

 9

 25,406,180 24,971,199 766,886 759,575 10

 2,756,249 2,095,094 49 49 11

 28,162,429 27,066,293 766,935 759,624 12

 13

 28,162,429 27,066,293 766,935 759,624 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

Oklahoma Gas and Electric Company End of 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

(b) (c)

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 TOTAL
Name 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

(a) (b)

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.

 1 OKLAHOMA

 2 Residential

 3 Residential -TOU 23,737 1,902,245 1,247 19,035 0.0801

 4 Residential 7,739,086 663,106,354 576,281 13,429 0.0857

 5 Residentail LIHEAP 387,523 30,415,813 26,108 14,843 0.0785

 6 Security Lights 36,907 5,579,733 52,522 703 0.1512

 7 Unbilled-Net 45,969 800,000 0.0174

 8 Over/Under Recoveries -4,081,514

 9 Duplicate Customer Adjustment -52,522

 10 Total 8,233,222 697,722,631 603,636 13,639 0.0847

 11

 12 Commercial

 13 GS-TOU 45,522 4,039,119 1,115 40,827 0.0887

 14 GS-1 1,276,175 130,015,000 65,350 19,528 0.1019

 15 PL-LEV 268 18,548 1 268,000 0.0692

 16 LPL-TOU-CR 18,425 903,263 1 18,425,000 0.0490

 17 LPL-TOU 415,201 22,695,719 17 24,423,588 0.0547

 18 PL-TOU-CR 4,760 280,694 1 4,760,000 0.0590

 19 PL-TOU 972,066 65,473,025 901 1,078,875 0.0674

 20 PL-1 2,428,845 173,613,143 8,101 299,820 0.0715

 21 Security Lights 49,613 7,457,506 14,718 3,371 0.1503

 22 PL-TOU-CAAR 284,569 17,943,199 120 2,371,408 0.0631

 23 PL-1-CAAR 194,059 12,349,009 239 811,962 0.0636

 24 RTP LPL-TOU-CR 16,938 885,038 1 16,938,000 0.0523

 25 RTP PL-TOU-CR 9,783 547,288 1 9,783,000 0.0559

 26 Unbilled-Net 19,967 500,000 0.0250

 27 Over/Under Recoveries -3,276,920

 28 Duplicate Customer Adjustment -14,718

 29 Total 5,736,191 433,443,631 75,848 75,627 0.0756

 30

 31 Industrial

 32 GS-TOU 23,908 2,016,543 162 147,580 0.0843

 33 GS-1 106,888 9,948,232 2,982 35,844 0.0931

 34 Oil & Gas 8,729 622,620 14 623,500 0.0713

 35 Oil & Gas-LEV 162,829 12,353,014 4,388 37,108 0.0759

 36 OGP-TOU 4,898 369,716 109 44,936 0.0755

 37 PL-OGP 245,328 14,752,988 282 869,957 0.0601

 38 LPL-TOU-IR 92,596 3,951,557 1 92,596,000 0.0427

 39 LPL-TOU-CR 513,919 23,789,298 12 42,826,583 0.0463

 40 LPL-TOU 3,232,024 158,308,848 54 59,852,296 0.0490

 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 TOTAL
Name 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

(a) (b)

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.

 1 PL-LEV 2,477 186,298 2 1,238,500 0.0752

 2 PL-TOU-CR 80,986 4,558,624 14 5,784,714 0.0563

 3 PL-TOU 715,055 47,266,946 328 2,180,046 0.0661

 4 PL-1 384,342 26,485,995 630 610,067 0.0689

 5 Security Lights 2,714 384,221 702 3,866 0.1416

 6 PL-TOU-CAAR 47,514 2,760,202 14 3,393,857 0.0581

 7 PL-OGP-CAAR

 8 PL-TOU-CAAR-CR 19,690 1,119,450 3 6,563,333 0.0569

 9 PL-1-CAAR 53,851 3,061,595 38 1,417,132 0.0569

 10 RTP LPL-TOU 40,773 1,399,871 1 40,773,000 0.0343

 11 RTP LPL-TOU-CR 90,370 4,224,856 3 30,123,333 0.0468

 12 RTP PL-TOU 1,328 60,158 1 1,328,000 0.0453

 13 RTP PL-TOU-CR 11,220 674,123 1 11,220,000 0.0601

 14 Unbilled - Net -9,066 -100,000 0.0110

 15 Over/Under Recoveries -3,455,949

 16 Duplicate Customer Adjustment -702

 17 Total 5,832,373 314,739,206 9,039 645,245 0.0540

 18

 19 Public Street & Highway Lighting

 20 Municipal Street Lights 53,568 7,471,605 224 239,143 0.1395

 21 Unbilled - Net 413 100,000 0.2421

 22 Over/Under Recoveries -47,120

 23 Total 53,981 7,524,485 224 240,987 0.1394

 24

 25 Other Sales to Public Authorities

 26 GS-TOU 4,014 334,016 66 60,818 0.0832

 27 GS-1 151,265 13,315,125 7,322 20,659 0.0880

 28 Residential 9,411 860,350 1,296 7,262 0.0914

 29 PM-1 126,358 8,282,840 1,505 83,959 0.0656

 30 LPL-TOU 1,015,568 50,907,130 16 63,473,000 0.0501

 31 PL-TOU 310,348 20,121,038 143 2,170,266 0.0648

 32 PL-TOU-CR 12,307 678,640 1 12,307,000 0.0551

 33 PL-1 571,572 38,569,034 906 630,874 0.0675

 34 Security Lights 13,042 1,929,133 1,895 6,882 0.1479

 35 PL-TOU-CAAR 14,746 968,485 6 2,457,667 0.0657

 36 PL-1-CAAR

 37 PS-ND 145,262 12,463,358 2,021 71,876 0.0858

 38 PS-ND-TOU 90,312 7,136,897 333 271,207 0.0790

 39 PS_ND-C-TOU 1,814 147,480 17 106,706 0.0813

 40 PS-D 68,522 4,998,397 129 531,178 0.0729

 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 TOTAL
Name 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

(a) (b)

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.

 1 PS-D-TOU 50,740 3,624,269 48 1,057,083 0.0714

 2 PS-D-C-TOU 94 8,456 1 94,000 0.0900

 3 PS-D-1-CAAR 5,981 369,703 2 2,990,500 0.0618

 4 PS-D-TOU-CAAR 35,870 2,379,456 40 896,750 0.0663

 5 RTP LPL-TOU-CR 147,011 6,473,871 1 147,011,000 0.0440

 6 RTP PL-TOU 16,828 1,069,409 2 8,414,000 0.0635

 7 Unbilled -Net 19,934 518,812 0.0260

 8 Over/Under Recoveries -2,341,859

 9 Duplicate Customer Adjustment -1,895

 10 Total 2,810,999 172,814,040 13,855 202,887 0.0615

 11

 12

 13 ARKANSAS

 14 Residential

 15 Residential 721,927 54,412,690 53,755 13,430 0.0754

 16 Security Lights 4,032 626,014 5,800 695 0.1553

 17 Unbilled-Net 2,977

 18 TCR

 19 Over/Under Recoveries -1,595,562

 20 Duplicate Customer Adjustment -5,800

 21 Total 728,936 53,443,142 53,755 13,560 0.0733

 22

 23 Commercial

 24 GS-1 185,229 13,742,616 7,933 23,349 0.0742

 25 Athletic Fld Lighting 197 16,492 8 24,625 0.0837

 26 PL-TOU 190,582 9,847,022 39 4,886,718 0.0517

 27 PL-1 346,660 21,792,917 663 522,866 0.0629

 28 Security Lights 12,630 1,442,923 2,131 5,927 0.1142

 29 Unbilled-Net -240

 30 TCR

 31 Over/Under Recoveries -1,322,721

 32 Duplicate Customer Adjustment -2,131

 33 Total 735,058 45,519,249 8,643 85,047 0.0619

 34

 35 Industrial

 36 GS-1 9,625 672,108 290 33,190 0.0698

 37 PL-TOU 844,576 42,119,249 38 22,225,684 0.0499

 38 PL-1 281,610 15,410,890 113 2,492,124 0.0547

 39 Security Lights 1,255 140,267 127 9,882 0.1118

 40 Unbilled-Net -2,762

 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 TOTAL
Name 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

(a) (b)

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.

 1 TCR

 2 Over/Under Recoveries -1,369,595

 3 Duplicate Customer Adjustment -127

 4 Total 1,134,304 56,972,919 441 2,572,118 0.0502

 5

 6 Public Street & Highway Lighting

 7 Municipal Street Lights 8,785 1,189,175 26 337,885 0.1354

 8 Unbilled-Net -8

 9 TCR

 10 Over/Under Recoveries -20,957

 11 Total 8,777 1,168,218 26 337,577 0.1331

 12

 13 Other Sales to Public Authorities

 14 GS-1 20,741 1,538,315 903 22,969 0.0742

 15 Residential 2,413 182,937 240 10,054 0.0758

 16 Athletic Fld Lighting 681 55,600 23 29,609 0.0816

 17 PM-1 1,434 105,621 73 19,644 0.0737

 18 PL-TOU 2,065 139,957 2 1,032,500 0.0678

 19 PL-1 104,149 6,906,258 178 585,107 0.0663

 20 Security Lights 1,001 133,310 187 5,353 0.1332

 21 Unbilled - Net -145

 22 TCR

 23 Over/Under Recoveries -233,910

 24 Duplicate Customer Adjustment -187

 25 Total 132,339 8,828,088 1,419 93,262 0.0667

 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) X An 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) X An 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 450.2
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 Geary, Oklahoma RQ 1 1.6 1.6 1.5

 2 Orlando, Oklahoma RQ 1 0.3 0.3 0.2

 3 Paris, Arkansas RQ 1 0.1 0.4 0.3

 4 Watonga, Oklahoma RQ 1 5.4 5.2 4.9

 5 Arkansas Valley Electric Cooperative RQ 1 193.8 170.9 161.5

 6 Mississippi Delta Energy Agency RQ 20 20 20

 7 Oklahoma Municipal Power Authority RQ 25 25 25

 8 Southwestern Power Administration RQ 24.1 22.2 20.7

 9

 10 Unbilled Sales for Resale RQ

 11 Over(Under) Recoveries RQ

 12

 13 American Electric Power Company OS

 14 Aquila Networks OS

FERC FORM NO. 1 (ED. 12-90) Page 310

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 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

SALES FOR RESALE (Account 447)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

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 Demand Monthly 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.

 1 Associated Electric Cooperative, Inc OS

 2 Cleco Utility Group, Inc. OS

 3 Constellation Energy Commodities Group OS

 4 Empire District Electric Company OS

 5 Entergy Services, Inc. OS

 6 Grand River Dam Authority OS

 7 Independence Power & Light Company OS

 8 Kansas City Board of Public Utilities OS

 9 Kansas City Power and Light Co. OS

 10 Lafayette Utilities System OS

 11 Louisiana Energy & Power Authority OS

 12 NRG Energy Inc. OS

 13 Oklahoma Municipal Power Authority OS

 14 South Mississippi Electric Power Assoc OS

FERC FORM NO. 1 (ED. 12-90) Page 310.1

 0

 0

 0

Subtotal RQ

Subtotal non-RQ

Total

 0 0

 0

 0

 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

SALES FOR RESALE (Account 447)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Name of Company or Public Authority

(a) (b) (c)

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 Demand Monthly 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.

 1 Southwest Power Pool OS

 2 Southwestern Power Administration OS

 3 Southwestern Public Service OS

 4 Sunflower Electric Power Corporation OS

 5 Western Farmers Electric Coop. OS

 6 Westar Energy OS

 7 Southwest Power Pool/Redbud OS

 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

 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

SALES FOR RESALE (Account 447) (Continued)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

MegaWatt Hours

(g) (h) (i) (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.

 8,699 41,344 334,962 6,720 383,026 1

 1,368 20,929 52,018 6,720 79,667 2

 512 13,030 21,184 3,645 37,859 3

 29,242 431,554 1,133,487 6,720 1,571,761 4

 988,207 13,605,427 35,860,119 -1,345,117 48,120,429 5

 129,260 1,200,000 4,806,503 4,800 6,011,303 6

 217,877 2,124,758 2,549,909 573,971 5,248,638 7

 11,766 581,654 522,000 42,040 1,145,694 8

 9

 -2,540 -588,769 -588,769 10

 303,701 303,701 11

 12

 350 38,058 38,058 13

 128 10,782 10,782 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

 18,018,696
Name 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

(g) (h) (i) (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.

 444 37,697 37,697 1

 228 18,002 18,002 2

 85 5,180 5,180 3

 22 1,840 1,840 4

 167 16,112 16,112 5

 265 17,852 17,852 6

 22 1,816 1,816 7

 248 23,660 23,660 8

 972 70,751 70,751 9

 49 4,818 4,818 10

 80 5,407 5,407 11

 74 5,098 5,098 12

 2,672 158,436 158,436 13

 109 9,402 9,402 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

 18,018,696
Name 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

(g) (h) (i) (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.

 1,364,189 68,474,036 3,840,031 72,314,067 1

 48 4,284 4,284 2

 211 16,540 16,540 3

 275 26,000 26,000 4

 34 2,314 2,314 5

 434 30,074 30,074 6

 752 67,190 67,190 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) X An 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
ELECTRIC 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

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

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

 1 1. POWER PRODUCTION EXPENSES

 2 A. Steam Power Generation

 3 Operation

 4 (500) Operation Supervision and Engineering 9,288,525 5,103,859

 5 (501) Fuel 730,717,465 638,010,994

 6 (502) Steam Expenses 6,865,922 6,257,483

 7 (503) Steam from Other Sources

 8 (Less) (504) Steam Transferred-Cr.

 9 (505) Electric Expenses 5,344,296 4,941,446

 10 (506) Miscellaneous Steam Power Expenses 23,794,487 22,342,024

 11 (507) Rents

 12 (509) Allowances

 13 TOTAL Operation (Enter Total of Lines 4 thru 12) 776,010,695 676,655,806

 14 Maintenance

 15 (510) Maintenance Supervision and Engineering 5,611,322 5,513,884

 16 (511) Maintenance of Structures 2,288,980 1,860,872

 17 (512) Maintenance of Boiler Plant 25,094,925 25,323,192

 18 (513) Maintenance of Electric Plant 18,144,946 17,531,930

 19 (514) Maintenance of Miscellaneous Steam Plant 462,131 332,418

 20 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 51,602,304 50,562,296

 21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 827,612,999 727,218,102

 22 B. Nuclear Power Generation

 23 Operation

 24 (517) Operation Supervision and Engineering

 25 (518) Fuel

 26 (519) Coolants and Water

 27 (520) Steam Expenses

 28 (521) Steam from Other Sources

 29 (Less) (522) Steam Transferred-Cr.

 30 (523) Electric Expenses

 31 (524) Miscellaneous Nuclear Power Expenses

 32 (525) Rents

 33 TOTAL Operation (Enter Total of lines 24 thru 32)

 34 Maintenance

 35 (528) Maintenance Supervision and Engineering

 36 (529) Maintenance of Structures

 37 (530) Maintenance of Reactor Plant Equipment

 38 (531) Maintenance of Electric Plant

 39 (532) Maintenance of Miscellaneous Nuclear Plant

 40 TOTAL Maintenance (Enter Total of lines 35 thru 39)

 41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)

 42 C. Hydraulic Power Generation

 43 Operation

 44 (535) Operation Supervision and Engineering

 45 (536) Water for Power

 46 (537) Hydraulic Expenses

 47 (538) Electric Expenses

 48 (539) Miscellaneous Hydraulic Power Generation Expenses

 49 (540) Rents

 50 TOTAL Operation (Enter Total of Lines 44 thru 49)

 51 C. Hydraulic Power Generation (Continued)

 52 Maintenance

 53 (541) Mainentance Supervision and Engineering

 54 (542) Maintenance of Structures

 55 (543) Maintenance of Reservoirs, Dams, and Waterways

 56 (544) Maintenance of Electric Plant

 57 (545) Maintenance of Miscellaneous Hydraulic Plant

 58 TOTAL Maintenance (Enter Total of lines 53 thru 57)

 59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)

FERC FORM NO. 1 (ED. 12-93) Page 320
ELECTRIC 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

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

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

 60 D. Other Power Generation

 61 Operation

 62 (546) Operation Supervision and Engineering 360,503 247,837

 63 (547) Fuel 135,007,801 125,338,296

 64 (548) Generation Expenses 4,190,746 1,982,370

 65 (549) Miscellaneous Other Power Generation Expenses 1,341,438 1,068,522

 66 (550) Rents 437,575 415,000

 67 TOTAL Operation (Enter Total of lines 62 thru 66) 141,338,063 129,052,025

 68 Maintenance

 69 (551) Maintenance Supervision and Engineering 368,939 392,773

 70 (552) Maintenance of Structures 520,524 1,291,015

 71 (553) Maintenance of Generating and Electric Plant 8,043,938 5,604,805

 72 (554) Maintenance of Miscellaneous Other Power Generation Plant 536,251 434,694

 73 TOTAL Maintenance (Enter Total of lines 69 thru 72) 9,469,652 7,723,287

 74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 150,807,715 136,775,312

 75 E. Other Power Supply Expenses

 76 (555) Purchased Power 257,005,065 268,629,185

 77 (556) System Control and Load Dispatching 74,339,866 64,379,760

 78 (557) Other Expenses 22,341

 79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 331,367,272 333,008,945

 80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 1,309,787,986 1,197,002,359

 81 2. TRANSMISSION EXPENSES

 82 Operation

 83 (560) Operation Supervision and Engineering 2,746,595 2,875,787

 84 (561) Load Dispatching

 85 (561.1) Load Dispatch-Reliability 844,071 527,547

 86 (561.2) Load Dispatch-Monitor and Operate Transmission System 575,357 123,874

 87 (561.3) Load Dispatch-Transmission Service and Scheduling 4,414,355 4,582,487

 88 (561.4) Scheduling, System Control and Dispatch Services 3,366,840 3,306,659

 89 (561.5) Reliability, Planning and Standards Development 15,897 2,075

 90 (561.6) Transmission Service Studies

 91 (561.7) Generation Interconnection Studies

 92 (561.8) Reliability, Planning and Standards Development Services 439,153 461,394

 93 (562) Station Expenses 1,168,592 1,143,867

 94 (563) Overhead Lines Expenses 138,902 90,014

 95 (564) Underground Lines Expenses

 96 (565) Transmission of Electricity by Others 709,113 187,595

 97 (566) Miscellaneous Transmission Expenses 52,790 581,265

 98 (567) Rents 1,418 800

 99 TOTAL Operation (Enter Total of lines 83 thru 98) 14,473,083 13,883,364

 100 Maintenance

 101 (568) Maintenance Supervision and Engineering 154,305 151,927

 102 (569) Maintenance of Structures

 103 (569.1) Maintenance of Computer Hardware 8,391 23,703

 104 (569.2) Maintenance of Computer Software 205,605 356,363

 105 (569.3) Maintenance of Communication Equipment

 106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant

 107 (570) Maintenance of Station Equipment 5,207,168 4,662,168

 108 (571) Maintenance of Overhead Lines 7,666,403 4,705,385

 109 (572) Maintenance of Underground Lines

 110 (573) Maintenance of Miscellaneous Transmission Plant 22,007

 111 TOTAL Maintenance (Total of lines 101 thru 110) 13,241,872 9,921,553

 112 TOTAL Transmission Expenses (Total of lines 99 and 111) 27,714,955 23,804,917

FERC FORM NO. 1 (ED. 12-93) Page 321
ELECTRIC 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

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

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

 113 3. REGIONAL MARKET EXPENSES

 114 Operation

 115 (575.1) Operation Supervision

 116 (575.2) Day-Ahead and Real-Time Market Facilitation

 117 (575.3) Transmission Rights Market Facilitation

 118 (575.4) Capacity Market Facilitation

 119 (575.5) Ancillary Services Market Facilitation

 120 (575.6) Market Monitoring and Compliance

 121 (575.7) Market Facilitation, Monitoring and Compliance Services 3,513,224 3,921,851

 122 (575.8) Rents

 123 Total Operation (Lines 115 thru 122) 3,513,224 3,921,851

 124 Maintenance

 125 (576.1) Maintenance of Structures and Improvements

 126 (576.2) Maintenance of Computer Hardware

 127 (576.3) Maintenance of Computer Software

 128 (576.4) Maintenance of Communication Equipment

 129 (576.5) Maintenance of Miscellaneous Market Operation Plant

 130 Total Maintenance (Lines 125 thru 129)

 131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 3,513,224 3,921,851

 132 4. DISTRIBUTION EXPENSES

 133 Operation

 134 (580) Operation Supervision and Engineering 2,426,911 1,465,844

 135 (581) Load Dispatching 9,598

 136 (582) Station Expenses 620,924 362,577

 137 (583) Overhead Line Expenses 1,499,791 788,686

 138 (584) Underground Line Expenses 2,692,343 1,790,155

 139 (585) Street Lighting and Signal System Expenses 407,034 158,295

 140 (586) Meter Expenses 2,658,227 1,126,976

 141 (587) Customer Installations Expenses 1,049,364 1,123,056

 142 (588) Miscellaneous Expenses 343,959 52,162

 143 (589) Rents 68,628 93,752

 144 TOTAL Operation (Enter Total of lines 134 thru 143) 11,767,181 6,971,101

 145 Maintenance

 146 (590) Maintenance Supervision and Engineering 5,491 27,668

 147 (591) Maintenance of Structures

 148 (592) Maintenance of Station Equipment 6,070,066 6,778,934

 149 (593) Maintenance of Overhead Lines 32,912,610 25,656,029

 150 (594) Maintenance of Underground Lines 2,277,958 1,377,528

 151 (595) Maintenance of Line Transformers 58,887 4,848

 152 (596) Maintenance of Street Lighting and Signal Systems 6,521,515 4,382,084

 153 (597) Maintenance of Meters 86

 154 (598) Maintenance of Miscellaneous Distribution Plant

 155 TOTAL Maintenance (Total of lines 146 thru 154) 47,846,527 38,227,177

 156 TOTAL Distribution Expenses (Total of lines 144 and 155) 59,613,708 45,198,278

 157 5. CUSTOMER ACCOUNTS EXPENSES

 158 Operation

 159 (901) Supervision 577,417 262,361

 160 (902) Meter Reading Expenses 8,486,606 6,881,984

 161 (903) Customer Records and Collection Expenses 15,729,003 13,819,550

 162 (904) Uncollectible Accounts 2,943,714 6,000,311

 163 (905) Miscellaneous Customer Accounts Expenses 481,216 471,682

 164 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 28,217,956 27,435,888

FERC FORM NO. 1 (ED. 12-93) Page 322
ELECTRIC 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

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No.

Account Amount for

(a) (b) (c)

Current Year Previous Year

Amount for

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

 165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES

 166 Operation

 167 (907) Supervision 215,729 352,213

 168 (908) Customer Assistance Expenses 6,061,299 5,583,185

 169 (909) Informational and Instructional Expenses 1,375,792 1,268,505

 170 (910) Miscellaneous Customer Service and Informational Expenses 498,379 445,975

 171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 8,151,199 7,649,878

 172 7. SALES EXPENSES

 173 Operation

 174 (911) Supervision 129,145 77,293

 175 (912) Demonstrating and Selling Expenses 3,369,862 2,353,285

 176 (913) Advertising Expenses 1,036,129 2,025,467

 177 (916) Miscellaneous Sales Expenses 855,595 260,597

 178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 5,390,731 4,716,642

 179 8. ADMINISTRATIVE AND GENERAL EXPENSES

 180 Operation

 181 (920) Administrative and General Salaries 8,979,732 13,362,977

 182 (921) Office Supplies and Expenses 2,188,700 3,720,639

 183 (Less) (922) Administrative Expenses Transferred-Credit 330,720 307,020

 184 (923) Outside Services Employed 4,321,978 3,934,775

 185 (924) Property Insurance 1,803,920 2,090,861

 186 (925) Injuries and Damages 6,562,299 6,109,778

 187 (926) Employee Pensions and Benefits 40,124,258 42,387,480

 188 (927) Franchise Requirements 8,675,145 3,939,726

 189 (928) Regulatory Commission Expenses 3,491,791 3,979,821

 190 (929) (Less) Duplicate Charges-Cr. 8,675,145 3,939,726

 191 (930.1) General Advertising Expenses 10,386 25,504

 192 (930.2) Miscellaneous General Expenses 36,921,841 29,820,355

 193 (931) Rents -131,724 83,310

 194 TOTAL Operation (Enter Total of lines 181 thru 193) 103,942,461 105,208,480

 195 Maintenance

 196 (935) Maintenance of General Plant 9,542

 197 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 103,942,461 105,218,022

 198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 1,546,332,220 1,414,947,835

FERC FORM NO. 1 (ED. 12-93) Page 323
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 Associated Electric Cooperative, Inc OS 1

 2 American Electric Power Company OS 1

 3 Aquila Networks OS 1

 4 Constellation Energy Commodities Group OS 1

 5 Cleco Utility Group, Inc. OS 1

 6 Empire District Electric Company OS 1

 7 Entergy Services, Inc. OS 1

 8 FPL Energy Sooner Wind, LLC LF 1

 9 Grand River Dam Authority OS 1

 10 Independence Power & Light Company OS 1

 11 Kansas City Board of Public Utilities OS 1

 12 Kansas City Power and Light Co. OS 1

 13 Lafayette Utilities System OS 1

 14 Louisiana Energy and Power Authority OS 1

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

Total
Name 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

(a) (b) (c)

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 Demand Monthly 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.

 1 NRG Energy Inc. OS 1

 2 Oklahoma Municipal Power Authority OS 1

 3 Sunflower Electric Power Company OS 1

 4 South Mississippi Electric Power Assoc OS 1

 5 Southwestern Power Administration OS 1

 6 Southwestern Public Service OS 1

 7 Western Farmers Electric Coop. OS 71

 8 Westar Energy OS 1

 9 AES Shady Point, LLC LU N/A

 10 Powersmith Cogeneration LU N/A

 11 Inadvertent Energy Exchange - Net EX N/A

 12 Purcell Public Works Authority OS 1

 13

 14 Southwest Power Pool RQ N/A

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

Total
Name 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

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

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.

 475 37,337 37,337 1

 898 62,778 62,778 2

 132 10,293 10,293 3

 122 10,043 10,043 4

 118 12,393 12,393 5

 96 5,331 5,331 6

 2,282 221,899 17,671 239,570 7

 177,995 4,392,136 4,392,136 8

 120 12,191 12,191 9

 17 1,183 1,183 10

 53 4,063 4,063 11

 377 27,017 27,017 12

 25 2,972 2,972 13

 19 1,932 1,932 14

FERC FORM NO. 1 (ED. 12-90) Page 327

 4,344,974 149,901,371 107,103,693 257,005,064
Name 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

(g) (h) (i) (j)

Demand Charges Energy Charges Other Charges

(k)

Purchased Total (j+k+l)

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.

 220 16,533 16,533 1

 -53 -4,707 -4,707 2

 84 9,539 9,539 3

 149 14,913 14,913 4

 269 20,265 631,479 651,744 5

 598 42,253 42,253 6

 124 11,394 11,394 7

 680,782 45,471,150 10,462,500 55,933,650 8

 2,249,796 26,857,153 85,057,757 111,914,910 9

 428,278 28,794,589 12,058,383 40,852,972 10

 -19,931 11

 2,831 59,130 59,130 12

 13

 819,098 43,862,014 -1,178,520 42,683,494 14

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) X An 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
TRANSMISSION 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

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No.

Payment By

(a) (b) (c) (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.

 1 Southwestern Power Administration Southwestern Power Administration Southwestern Power Administration LFP

 2 Southwest Power Pool Southwest Power Pool Southwest Power Pool OS

 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

TOTAL
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 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.

106 Various Various 111,663 108,313 1

SPP Tariff Various 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 4,228,820
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 FOR OTHERS (Account 456) (Continued)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

(k) (l) (m) (n)

(k+l+m)

Total Revenues ($)

(Including transactions reffered to as 'wheeling')

($)

Energy Charges

($)

Demand Charges (Other 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 3,786,910 18,172,232 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 0 3,786,910 18,492,145
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) X An 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
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 ISO/RTOs

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Payment Received by Statistical

(a) (b)

(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

Page 331

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

(a) (c) (d)

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)

 1 Westar Energy FNS 602,583 602,583 709,113 709,113

 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

TOTAL 602,583 602,583 709,113 709,113
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) X An 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
Name 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

No. (a) (b)

 1 Industry Association Dues 632,373

 2 Nuclear Power Research Expenses

 3 Other Experimental and General Research Expenses 90,924

 4 Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 567,963

 5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000

 6

 7 OGE Energy Corp (Parent) Cost Allocations 34,240,720

 8

 9 Moving Expense 618,780

 10

 11 Unused Free Service 5,499

 12

 13 Sponserships 857,938

 14

 15 Conventions and Meetings 50,726

 16

 17 Other -143,082

 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 TOTAL
Name 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

(a) (b) (d)

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)

 1 Intangible Plant 3,804,341 3,804,341

 2 Steam Production Plant 24,643,060 35,959 24,679,019

 3 Nuclear Production Plant

 4 Hydraulic Production Plant-Conventional

 5 Hydraulic Production Plant-Pumped Storage

 6 Other Production Plant 24,091,702 9,288 24,100,990

 7 Transmission Plant 20,099,612 20,099,612

 8 Distribution Plant 64,980,831 64,980,831

 9 Regional Transmission and Market Operation

 10 General Plant 11,717,382 11,717,382

 11 Common Plant-Electric

 12 TOTAL 145,532,587 45,247 3,804,341 149,382,175

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 Charges
Name 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.

(a) (b) (c) (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)

 12 Steam Production-Coal

 13 Muskogee

 14 Unit 4 197,274

 15 Unit 5 143,600

 16 Unit 6 381,702

 17 ARO Cost 167

 18 Sooner

 19 Unit 1 321,420

 20 Unit 2 203,441

 21 ARO Cost 123

 22 Subtotal Coal 1,247,727

 23

 24 Steam Production-Gas

 25 Mustang

 26 Unit 1 16,677

 27 Unit 2 9,027

 28 Unit 3 17,861

 29 Unit 4 36,851

 30 ARO Cost 214

 31 Muskogee 3 25,859

 32 ARO Cost 440

 33 Seminole

 34 Unit 1 72,712

 35 Unit 2 47,747

 36 Unit 3 80,199

 37 GT 1,589

 38 ARO Cost 209

 39 Horseshoe Lake

 40 Unit 6 33,498

 41 Unit 7 35,132

 42 Unit 8 38,936

 43 ARO Cost 238

 44 Subtotal Gas 417,189

 45

 46 Other Production

 47 Horseshoe 9 Gas 24,217

 48 Horseshoe 10 Gas 20,020

 49 Centennial Wind Farm 189,390

 50 Woodward Gas 1,216

FERC FORM NO. 1 (REV. 12-03) Page 337
Name 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.

(a) (b) (c) (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)

 12 ARO Cost-Other 900

 13 Tinker Gas 10,100

 14 McClain Gas 1 93,800

 15 McClain Gas 2 85,722

 16 McClain Steam 1 56,184

 17 McClain HRSG 1 31,118

 18 McClain HRSG 2 31,085

 19 Enid 5,263

 20 Redbud Unit 1 141,160

 21 Redbud Unit 2 65,855

 22 Redbud Unit 3 65,855

 23 Redbud Unit 4 65,855

 24 Subtotal Other 887,740

 25

 26 Transmission Plant

 27 350 28,712

 28 352 3,474

 29 353 306,208

 30 354 55,564

 31 355 211,639

 32 356 183,314

 33 358 110

 34 359 19

 35 Subtotal Transmission 789,040

 36

 37 Distribution Plant

 38 360 4,065

 39 361 4,702

 40 362 393,559

 41 364 418,728

 42 365 322,463

 43 366 123,209

 44 367 488,257

 45 368 288,939

 46 369 203,102

 47 370 85,920

 48 371 25

 49 372 594

 50 373 166,100

FERC FORM NO. 1 (REV. 12-03) Page 337.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No. Account No.

(a) (b) (c) (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)

 12 Subtotal Distrbution 2,499,663

 13

 14 General Plant

 15 389 148

 16 390 100,654

 17 391 11,685

 18 392 57,834

 19 393 1,086

 20 394 6,664

 21 395 7,988

 22 396 7,170

 23 397 2,301

 24 398 4,515

 25

 26 Subtotal General Plant 200,045

 27

 28 Intangibles 25,969

 29

 30 Total Depr. Plant 6,067,373

 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 337.2
Name 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

(a) (b) (c)

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.

 1 FERC Assessment for Annual Charges 1,026,147 1,026,147

 2

 3 Arkansas Public Service Commission

 4 for Annual Charges 291,845 291,845

 5

 6 Oklahoma Corporation Commission for Annual

 7 Charges 12 month Amortization Period 1,257,445 1,257,445 613,284

 8

 9

 10 Arkansas Rate Case 2008

 11 (08-103-U) 97,464 97,464

 12

 13 Red Rock Recovery

 14 ( PUD 2007-447) 30,300 30,300

 15

 16 FERC Transmission Rate Case 422,874 422,874

 17 (ER08-281-000)

 18

 19 Renewables

 20 (PUD 2008-148) 24,778 24,778

 21

 22 Oklahoma Rate Case 2009

 23 PUD (2008-398) 40,975 40,975

 24

 25 Oklahoma Fuel Audit

 26 (PUD 2008-299) 22,700 22,700

 27

 28 Integrated Resource Planning 5,767 5,767

 29

 30 Arkansas Energy Efficiency Programs

 31 (06-004-R) 18,241 18,241

 32

 33 Security

 34 (PUD 2006-402) 5,678 5,678

 35

 36 Oklahoma DSM & Energy Efficiency Programs

 37 (PUD 2008-59) 31,783 31,783

 38

 39 System Hardening Project 210,735 210,735

 40

 41 Minor Items 5,059 5,059

 42

 43

 44

 45

FERC FORM NO. 1 (ED. 12-96) Page 350

46 TOTAL 2,575,437 916,354 3,491,791 613,284
Name 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.

(f) (i) (j) (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 928 1,026,147 1

 2

 3

Electric 928 291,845 4

 5

 6

Electric 928 671,655 632,546 928 613,284 632,546 7

 8

 9

 10

Electric 928 97,464 11

 12

 13

Electric 928 30,300 14

 15

Electric 928 422,874 16

 17

 18

 19

Electric 928 24,778 20

 21

 22

Electric 928 40,975 23

 24

 25

Electric 928 22,700 26

 27

Electric 928 5,767 28

 29

 30

Electric 928 18,241 31

 32

 33

Electric 928 5,678 34

 35

 36

Electric 928 31,783 37

 38

Electric 928 210,735 39

 40

Electric 928 5,059 41

 42

 43

 44

 45

FERC FORM NO. 1 (ED. 12-96) Page 351

 2,906,001 632,546 613,284 632,546 46
Name 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

(a) (b)

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

 1 A. Electric R, D & D Performed Internally

 2 (1) Generation

 3

 4 (2) System Planning, Engineering

 5 and Operation

 6

 7 (3) Transmission

 8

 9 (4) Distribution

 10

 11 (5) Environmental (other than equipment)

 12

 13 (6) Other

 14

 15 (7) Total Internal Cost Incurred

 16

 17

 18 B. Electric, R, D & D Performed Externally

 19 (1) Research Support to the Electrical

 20 Research Council or the Electric

 21 Power Research Institute

 22

 23 (2) Research Support to Edison Electric

 24 Institute

 25

 26 (3) Research Support to Nuclear Power

 27 Groups

 28

 29 (4) Research Support to Others University of Oklahoma-Diversity of Output Power

 30 National Regulatory Research Institute-Renewables

 31

 32 (5) Total External Cost Incurred

 33

 34

 35

 36

 37

 38

FERC FORM NO. 1 (ED. 12-87) Page 352
Name 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

 85,924 930.2 85,924 29

 5,000 930.2 5,000 30

 31

 90,924 90,924 32

 33

 34

 35

 36

 37

 38

FERC FORM NO. 1 (ED. 12-87) Page 353
Name 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

(a) (b) (c)

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.

 1 Electric

 2 Operation

 3 Production 26,821,862

 4 Transmission 3,136,707

 5 Regional Market

 6 Distribution 9,849,495

 7 Customer Accounts 15,785,173

 8 Customer Service and Informational 3,032,128

 9 Sales 3,294,736

 10 Administrative and General 7,948,633

 11 TOTAL Operation (Enter Total of lines 3 thru 10) 69,868,734

 12 Maintenance

 13 Production 20,221,214

 14 Transmission 3,658,536

 15 Regional Market

 16 Distribution 19,079,278

 17 Administrative and General

 18 TOTAL Maintenance (Total of lines 13 thru 17) 42,959,028

 19 Total Operation and Maintenance

 20 Production (Enter Total of lines 3 and 13) 47,043,076

 21 Transmission (Enter Total of lines 4 and 14) 6,795,243

 22 Regional Market (Enter Total of Lines 5 and 15)

 23 Distribution (Enter Total of lines 6 and 16) 28,928,773

 24 Customer Accounts (Transcribe from line 7) 15,785,173

 25 Customer Service and Informational (Transcribe from line 8) 3,032,128

 26 Sales (Transcribe from line 9) 3,294,736

 27 Administrative and General (Enter Total of lines 10 and 17) 7,948,633

 28 TOTAL Oper. and Maint. (Total of lines 20 thru 27) 112,827,762 112,827,762

 29 Gas

 30 Operation

 31 Production-Manufactured Gas

 32 Production-Nat. Gas (Including Expl. and Dev.)

 33 Other Gas Supply

 34 Storage, LNG Terminaling and Processing

 35 Transmission

 36 Distribution

 37 Customer Accounts

 38 Customer Service and Informational

 39 Sales

 40 Administrative and General

 41 TOTAL Operation (Enter Total of lines 31 thru 40)

 42 Maintenance

 43 Production-Manufactured Gas

 44 Production-Natural Gas (Including Exploration and Development)

 45 Other Gas Supply

 46 Storage, LNG Terminaling and Processing

 47 Transmission

FERC FORM NO. 1 (ED. 12-88) Page 354
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No.

Classification

(a) (b) (c)

Direct Payroll Allocation of Total 

(d)

Distribution Payroll charged for

Clearing Accounts

DISTRIBUTION OF SALARIES AND WAGES (Continued)

 48 Distribution

 49 Administrative and General

 50 TOTAL Maint. (Enter Total of lines 43 thru 49)

 51 Total Operation and Maintenance

 52 Production-Manufactured Gas (Enter Total of lines 31 and 43)

 53 Production-Natural Gas (Including Expl. and Dev.) (Total lines 32,

 54 Other Gas Supply (Enter Total of lines 33 and 45)

 55 Storage, LNG Terminaling and Processing (Total of lines 31 thru

 56 Transmission (Lines 35 and 47)

 57 Distribution (Lines 36 and 48)

 58 Customer Accounts (Line 37)

 59 Customer Service and Informational (Line 38)

 60 Sales (Line 39)

 61 Administrative and General (Lines 40 and 49)

 62 TOTAL Operation and Maint. (Total of lines 52 thru 61)

 63 Other Utility Departments

 64 Operation and Maintenance

 65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 112,827,762 112,827,762

 66 Utility Plant

 67 Construction (By Utility Departments)

 68 Electric Plant 32,996,493 32,996,493

 69 Gas Plant

 70 Other (provide details in footnote):

 71 TOTAL Construction (Total of lines 68 thru 70) 32,996,493 32,996,493

 72 Plant Removal (By Utility Departments)

 73 Electric Plant 5,595,152 5,595,152

 74 Gas Plant

 75 Other (provide details in footnote):

 76 TOTAL Plant Removal (Total of lines 73 thru 75) 5,595,152 5,595,152

 77 Other Accounts (Specify, provide details in footnote):

 78 Expenses of Jobbing and Contract Work 700,357 700,357

 79 Accounts Receivable from Associated Companies 7,262 7,262

 80 Other Accounts Receivable 973,469 973,469

 81

 82 Other 880 880

 83

 84

 85

 86

 87

 88

 89

 90

 91

 92

 93

 94

 95 TOTAL Other Accounts 1,681,968 1,681,968

 96 TOTAL SALARIES AND WAGES 153,101,375 153,101,375

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 356
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of X

 / /

2008/Q4

Line

 No.

Description of Item(s) Balance at End of

(a) (b) (c)

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

 1 Energy

 2 Net Purchases (Account 555) 12,919,854 16,938,870 39,326,224 43,862,014

 3 Net Sales (Account 447) ( 12,123,754) ( 45,247,334) ( 58,547,585) ( 68,474,036)

 4 Transmission Rights

 5 Ancillary Services

 6 Other Items (list separately)

 7 Uninstructured Resource Deviation (URD) 45,258 108,992 174,508 217,969

 8 Revenue Neutrality Uplift (RNU) ( 1,017,482) ( 2,553,637) ( 2,142,259) ( 1,420,040)

 9 Losses ( 13,290) 1,578 ( 7,737) ( 11,454)

 10 Under-Scheduling 2,076 16,824 51,433 58,198

 11 Over-Scheduling 476 58,083 89,947 98,106

 12 Miscellaneous Charge ( 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

( 187,566) ( 30,677,328) ( 21,056,173) ( 25,669,947)

FERC FORM NO. 1/3-Q (NEW. 12-05) Page 397

46 TOTAL
Name 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

 1 Scheduling, System Control and Dispatch 185,459 MW 15,318 263,044 KW 21,359

 2 Reactive Supply and Voltage 185,459 MW 8,324 263,044 KW 16,019

 3 Regulation and Frequency Response 6,786 KW 24,725

 4 Energy Imbalance

 5 Operating Reserve - Spinning 7,018 KW 25,547

 6 Operating Reserve - Supplement 3,886 KW 6,231

 7 Other

 8 Total (Lines 1 thru 7) 370,918 23,642 543,778 93,881

FERC FORM NO. 1 (New 2-04) Page 398
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 TRANSMISSION SYSTEM PEAK LOAD

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Monthly Peak

MW - Total

(a) (b) (c)

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

 1 January 4,502 23 800 4,147 22 333

 2 February 4,314 1 800 3,971 21 322

 3 March 4,122 3 2000 3,787 20 315

 4 Total for Quarter 1 12,938 11,905 63 970

 5 April 4,003 21 1800 3,665 20 318

 6 May 5,169 30 1700 4,705 29 435

 7 June 5,749 26 1700 5,232 31 486

 8 Total for Quarter 2 14,921 13,602 80 1,239

 9 July 6,347 22 1700 5,765 36 546

 10 August 6,590 4 1700 5,982 37 571

 11 September 5,208 2 1600 4,747 13 448

 12 Total for Quarter 3 18,145 16,494 86 1,565

 13 October 4,154 1 1700 3,821 12 321

 14 November 3,837 21 800 3,538 11 288

 15 December 4,800 15 1900 4,400 12 388

 16 Total for Quarter 4 12,791 11,759 35 997

 58,795 53,760 264 4,771

Total Year to

Date/Year

 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400
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 ISO/RTO TRANSMISSION SYSTEM PEAK LOAD

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

Monthly Peak

MW - Total

(a) (b) (c)

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

 1 January

 2 February

 3 March

 4 Total for Quarter 1

 5 April

 6 May

 7 June

 8 Total for Quarter 2

 9 July

 10 August

 11 September

 12 Total for Quarter 3

 13 October

 14 November

 15 December

 16 Total for Quarter 4

Total Year to

Date/Year

 17

FERC FORM NO. 1/3-Q (NEW. 07-04) Page 400a
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 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.

1 SOURCES OF ENERGY

2 Generation (Excluding Station Use):

3 Steam 22,726,264

4 Nuclear

5 Hydro-Conventional

6 Hydro-Pumped Storage

7 Other 2,970,573

8 Less Energy for Pumping

Net Generation (Enter Total of lines 3 25,696,837

through 8)

9

10 Purchases 4,344,974

11 Power Exchanges:

12 Received

13 Delivered

14 Net Exchanges (Line 12 minus line 13)

15 Transmission For Other (Wheeling)

16 Received 1,701,665

17 Delivered 4,228,820

Net Transmission for Other (Line 16 minus -2,527,155

line 17)

18

19 Transmission By Others Losses 2,527,155

TOTAL (Enter Total of lines 9, 10, 14, 18 30,041,811

and 19)

20

21 DISPOSITION OF ENERGY

Sales to Ultimate Consumers (Including 25,406,180

Interdepartmental Sales)

22

Requirements Sales for Resale (See 1,384,391

instruction 4, page 311.)

23

Non-Requirements Sales for Resale (See 1,371,858

instruction 4, page 311.)

24

25 Energy Furnished Without Charge 75,447

Energy Used by the Company (Electric 44,971

Dept Only, Excluding Station Use)

26

27 Total Energy Losses 1,758,964

TOTAL (Enter Total of Lines 22 Through 30,041,811

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

(a) (b) (c)

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)

 29 January 2,493,868 77,555 4,387 23 800

 30 February 2,233,075 26,046 4,208 1 800

 31 March 2,282,856 118,195 4,020 3 2000

 32 April 2,131,625 135,640 3,931 21 1800

 33 May 2,442,735 141,923 5,070 30 1700

 34 June 2,935,464 230,066 5,647 26 1700

 35 July 3,188,514 124,770 6,232 22 1700

 36 August 3,020,861 111,095 6,472 4 1700

 37 September 2,407,511 40,001 5,121 2 1600

 38 October 2,223,568 120,438 4,075 1 1700

 39 November 2,210,881 156,115 3,738 21 800

 40 December 2,470,853 90,014 4,679 15 1900

FERC FORM NO. 1 (ED. 12-90) Page 401b

41 TOTAL 30,041,811 1,371,858
WOODWARD HORSESHOE LAKE

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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.

 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear GAS TURBINE STEAM & GAS TURBINE

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) FO CON & OB

 3 Year Originally Constructed 1963 1958

 4 Year Last Unit was Installed 1963 2000

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 11.50 973.90

 6 Net Peak Demand on Plant - MW (60 minutes) 12 898

 7 Plant Hours Connected to Load 11 4033

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 0 0

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 0 60

 12 Net Generation, Exclusive of Plant Use - KWh 107000 896249000

 13 Cost of Plant: Land and Land Rights 0 144708

 14 Structures and Improvements 20608 18349707

 15 Equipment Costs 1195597 133570080

 16 Asset Retirement Costs 320 238321

 17 Total Cost 1216525 152302816

 18 Cost per KW of Installed Capacity (line 17/5) Including 105.7848 156.3845

 19 Production Expenses: Oper, Supv, & Engr 0 723232

 20 Fuel 0 96724558

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 941082

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 11 805352

 26 Misc Steam (or Nuclear) Power Expenses 0 4078427

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 6002 552580

 30 Maintenance of Structures 0 276892

 31 Maintenance of Boiler (or reactor) Plant 0 1266219

 32 Maintenance of Electric Plant 2428 1404598

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 31578

 34 Total Production Expenses 8441 106804518

 35 Expenses per Net KWh 0.0789 0.1192

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Gas Gas

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) MCF MCF

 38 Quantity (Units) of Fuel Burned 1989 0 0 9854405 0 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1037000 0 0 1037000 0 0

 40 Avg 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 9.815 0.000 0.000

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.009 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.108 0.000 0.000

 44 Average BTU per KWh Net Generation 19084.000 0.000 0.000 11407.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402
MUSKOGEE MUSTANG

Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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 STEAM STEAM & GAS TURBINE

 2 Type of Constr (Conventional, Outdoor, Boiler, etc) CON & OB OB

 3 Year Originally Constructed 1956 1950

 4 Year Last Unit was Installed 1984 1971

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 1890.60 613.60

 6 Net Peak Demand on Plant - MW (60 minutes) 1771 440

 7 Plant Hours Connected to Load 7810 5168

 8 Net Continuous Plant Capability (Megawatts) 0 0

 9 When Not Limited by Condenser Water 0 0

 10 When Limited by Condenser Water 0 0

 11 Average Number of Employees 188 25

 12 Net Generation, Exclusive of Plant Use - KWh 10040730000 775709000

 13 Cost of Plant: Land and Land Rights 1977193 129878

 14 Structures and Improvements 80926223 12129457

 15 Equipment Costs 669389898 92225609

 16 Asset Retirement Costs 607053 214088

 17 Total Cost 752900367 104699032

 18 Cost per KW of Installed Capacity (line 17/5) Including 398.2336 170.6308

 19 Production Expenses: Oper, Supv, & Engr 1507061 812014

 20 Fuel 146405532 73498838

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 2592301 81343

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 2010948 162852

 26 Misc Steam (or Nuclear) Power Expenses 9162098 1697192

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 912629 770089

 30 Maintenance of Structures 1157743 277696

 31 Maintenance of Boiler (or reactor) Plant 12239853 1206852

 32 Maintenance of Electric Plant 9616856 523688

 33 Maintenance of Misc Steam (or Nuclear) Plant 186620 34876

 34 Total Production Expenses 185791641 79065440

 35 Expenses per Net KWh 0.0185 0.1019

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Coal Gas Gas Oil

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) Tons MCF MCF BBLS

 38 Quantity (Units) of Fuel Burned 5836557 3682025 0 7969730 59 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 17582000 5368698 0 1037000 5324914 0

 40 Avg 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 20.920 6.601 0.000 9.219 373.723 0.000

 42 Average Cost of Fuel Burned per Million BTU 0.001 0.007 0.000 0.009 0.072 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.018 0.104 0.000 0.095 0.711 0.000

 44 Average BTU per KWh Net Generation 10459.000 15951.000 0.000 10763.000 9935.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.2
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.3
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.4
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.5
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.6
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.7
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.8
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.9
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.10
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.11
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

Oklahoma Gas and Electric Company End of

X

 / / 2008/Q4

Line

 No.

Item

(a) (b) (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)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00

 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

 9 When Not Limited by Condenser Water 0 0

 10 When 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

 14 Structures and Improvements 0 0

 15 Equipment Costs 0 0

 16 Asset Retirement Costs 0 0

 17 Total Cost 0 0

 18 Cost per KW of Installed Capacity (line 17/5) Including 0.0000 0.0000

 19 Production Expenses: Oper, Supv, & Engr 0 0

 20 Fuel 0 0

 21 Coolants and Water (Nuclear Plants Only) 0 0

 22 Steam Expenses 0 0

 23 Steam From Other Sources 0 0

 24 Steam Transferred (Cr) 0 0

 25 Electric Expenses 0 0

 26 Misc Steam (or Nuclear) Power Expenses 0 0

 27 Rents 0 0

 28 Allowances 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Boiler (or reactor) Plant 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Steam (or Nuclear) Plant 0 0

 34 Total Production Expenses 0 0

 35 Expenses per Net KWh 0.0000 0.0000

 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)

 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)

 38 Quantity (Units) of Fuel Burned 00 0 00 0

 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 00 0 00 0

 40 Avg 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

 42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000

 43 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000

 44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000

FERC FORM NO. 1 (REV. 12-03) Page 402.12
9. 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.

SEMINOLE SOONER ENID

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)

STEAM & GAS TURBINE STEAM GAS TURBINE 1

CON & OB CON & OB FO 2

1971 1979 1965 3

1975 1980 1965 4

1724.60 1137.60 60.00 5

1475 1074 35 6

7291 8457 13 7

0 0 0 8

0 0 0 9

0 0 0 10

73 127 0 11

3336026000 7708494000 200000 12

1318360 7829788 0 13

26170641 103938175 62485 14

177315254 427928980 5200660 15

208795 123042 320 16

205013050 539819985 5263465 17

118.8757 474.5253 87.7244 18

961559 1106452 325 19

328507645 88415968 41209 20

0 0 0 21

1037792 2213402 0 22

0 0 0 23

0 0 0 24

918503 1447168 0 25

4334073 4458866 0 26

0 0 0 27

0 0 0 28

976559 2407163 2083 29

240813 335835 0 30

3077254 7276562 0 31

3176593 3650898 2939 32

49464 159593 0 33

343280255 111471907 46556 34

0.1029 0.0145 0.2328 35

Gas Coal Oil Gas 36

MCF Tons BBLS MCF 37

37163017 0 0 4510024 12813 0 4003 0 0 38

1037000 0 0 17584000 5368698 0 1037000 0 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 19.349 89.706 0.000 10.295 0.000 0.000 41

0.008 0.000 0.000 0.001 0.015 0.000 0.010 0.000 0.000 42

0.098 0.000 0.000 0.011 0.149 0.000 0.206 0.000 0.000 43

11594.000 0.000 0.000 10299.000 9668.000 0.000 20135.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page 403
9. 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.

MCCLAIN REDBUD

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

424.50 1200.00 0.00 5

543 1303 0 6

6211 1805 0 7

0 0 0 8

0 0 0 9

0 0 0 10

24 25 0 11

1893134000 616653000 0 12

489856 326890 0 13

5406142 39368554 0 14

171643384 299407676 0 15

0 0 0 16

177539382 339103120 0 17

418.2318 282.5859 0.0000 18

4473006 65379 0 19

115203618 16927898 0 20

0 0 0 21

0 0 0 22

0 0 0 23

0 0 0 24

3652176 435165 0 25

1203273 161418 0 26

0 0 0 27

0 0 0 28

293449 59706 0 29

520524 0 0 30

0 0 0 31

4304338 473952 0 32

535803 448 0 33

130186187 18123966 0 34

0.0688 0.0294 0.0000 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 3.921 0.000 0.000 0.000 0.000 0.000 41

0.009 0.000 0.000 0.004 0.000 0.000 0.000 0.000 0.000 42

0.061 0.000 0.000 0.027 0.000 0.000 0.000 0.000 0.000 43

7108.000 0.000 0.000 7305.000 0.000 0.000 0.000 0.000 0.000 44

FERC FORM NO. 1 (REV. 12-03) Page 403.1
9. 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) Page 403.2
9. 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) Page 403.3
9. 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) Page 403.4
9. 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) Page 403.5
9. 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) Page 403.6
9. 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) Page 403.7
9. 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) Page 403.8
9. 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) Page 403.9
9. 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) Page 403.10
9. 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) Page 403.11
9. 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) Page 403.12
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) X An 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
 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)

Oklahoma Gas and Electric Company X

 / / 2008/Q4

Line

 No.

Item FERC Licensed Project No.

(a) (b) (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.

 1 Kind of Plant (Run-of-River or Storage)

 2 Plant Construction type (Conventional or Outdoor)

 3 Year Originally Constructed

 4 Year Last Unit was Installed

 5 Total installed cap (Gen name plate Rating in MW) 0.00 0.00

 6 Net Peak Demand on Plant-Megawatts (60 minutes) 0 0

 7 Plant Hours Connect to Load 0 0

 8 Net Plant Capability (in megawatts)

 9 (a) Under Most Favorable Oper Conditions 0 0

 10 (b) Under the Most Adverse Oper Conditions 0 0

 11 Average Number of Employees 0 0

 12 Net Generation, Exclusive of Plant Use - Kwh 0 0

 13 Cost of Plant

 14 Land and Land Rights 0 0

 15 Structures and Improvements 0 0

 16 Reservoirs, Dams, and Waterways 0 0

 17 Equipment Costs 0 0

 18 Roads, Railroads, and Bridges 0 0

 19 Asset Retirement Costs 0 0

 20 TOTAL cost (Total of 14 thru 19) 0 0

 21 Cost per KW of Installed Capacity (line 20 / 5) 0.0000 0.0000

 22 Production Expenses

 23 Operation Supervision and Engineering 0 0

 24 Water for Power 0 0

 25 Hydraulic Expenses 0 0

 26 Electric Expenses 0 0

 27 Misc Hydraulic Power Generation Expenses 0 0

 28 Rents 0 0

 29 Maintenance Supervision and Engineering 0 0

 30 Maintenance of Structures 0 0

 31 Maintenance of Reservoirs, Dams, and Waterways 0 0

 32 Maintenance of Electric Plant 0 0

 33 Maintenance of Misc Hydraulic Plant 0 0

 34 Total Production Expenses (total 23 thru 33) 0 0

 35 Expenses per net KWh 0.0000 0.0000

FERC FORM NO. 1 (REV. 12-03) Page 406
 0 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.

(d) (e) (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) Page 407
FERC 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

 3 Year Last Unit was Installed

 4 Total 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

 13 Land and Land Rights

 14 Structures and Improvements

 15 Reservoirs, Dams, and Waterways

 16 Water Wheels, Turbines, and Generators

 17 Accessory Electric Equipment

 18 Miscellaneous Powerplant Equipment

 19 Roads, Railroads, and Bridges

 20 Asset Retirement Costs

 21 Total cost (total 13 thru 20)

 22 Cost per KW of installed cap (line 21 / 4)

 23 Production Expenses

 24 Operation Supervision and Engineering

 25 Water for Power

 26 Pumped Storage Expenses

 27 Electric Expenses

 28 Misc Pumped Storage Power generation Expenses

 29 Rents

 30 Maintenance Supervision and Engineering

 31 Maintenance of Structures

 32 Maintenance of Reservoirs, Dams, and Waterways

 33 Maintenance of Electric Plant

 34 Maintenance of Misc Pumped Storage Plant

 35 Production Exp Before Pumping Exp (24 thru 34)

 36 Pumping Expenses

 37 Total Production Exp (total 35 and 36)

 38 Expenses per KWh (line 37 / 9)

FERC FORM NO. 1 (REV. 12-03) Page 408
FERC 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:

(c) (e)

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) Page 409
Name 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

(a) (b) (c)

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 410
Name 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. (g) (h) (i) (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 411
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 LINE STATISTICS

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

(a) (b) (c) (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 Blue Mtn Lake Ft Smith 500.00 500.00 (3) Tower 46.85 1

 2

 3 Pittsburgh Muskogee 345.00 345.00 (3) Tower 210.39 44.29 1

 4 Kendrick Cimarron 345.00 345.00 (3) Tower 64.29 1

 5 Cimarron Draper Lake 345.00 345.00 (3) Tower 89.11 2.68 1

 6 Cimarron Kansas Border 345.00 345.00 (3) Wood 106.57 1

 7 Draper Lake Seminole 345.00 345.00 (3) Tower 44.46 44.46 1

 8 Seminole Plant Ashland 345.00 345.00 (3) Wood 40.29 1

 9 Draper Lake Horseshoe Lake 345.00 345.00 (3) Tower 15.86 1

 10 Seminole Plant Horseshoe Lake 345.00 345.00 (3) Tower 69.64 55.30 1

 11 Pecan Creek Riverside 345.00 345.00 (3) Tower 32.02 3.61 1

 12 Sooner Woodring 345.00 345.00 (3) Wood 43.18 1

 13 Northwest Sooner 345.00 345.00 (3) Tower 69.58 2

 14 RedBud Arcadia 345.00 345.00 (3) Tower 5.09 1

 15

 16

 17 AES Cogen Fort Smith 161.00 161.00 (2) Wood 48.86 1

 18 Muskogee Pecan Creek 161.00 161.00 (2) Wood 28.30 1

 19 Muskogee Boudinot Tap 161.00 161.00 (2) Wood 24.30 1

 20 Muskogee SPA Tap 161.00 161.00 (2) Wood 4.73 1

 21 VBI Massard 161.00 161.00 (2) Wood 9.17 1

 22 VBI Third Street 161.00 161.00 (1) Wood 9.24 1

 23 Fort Smith Third Street 161.00 161.00 (1) Wood 6.86 1

 24 Fort Smith Massard 161.00 161.00 (1) Wood 15.79 1

 25 Macksteel Tap Macksteel #2 161.00 161.00 (1) Steel 0.55 1

 26 Fort Smith Quanex 161.00 161.00 (1) Wood 4.38 1

 27 Muskogee Tie North/South 161.00 161.00 (1) Wood 0.84 1

 28 Grand Prairie Tap Grand Prairie (AVEC) 161.00 161.00 (1) Wood 0.13 1

 29 VBI Helberg 161.00 161.00 (1) Wood 31.32 1

 30 Little Spadra Spadra Clarkesville 161.00 161.00 (1) Steel 5.96 1

 31 Muskogee Port Tap Muskogee Port 161.00 161.00 (1) Steel 1.78 1

 32 Gerber Tap Gerber Rd Tap 161.00 161.00 (1) Steel 0.40 1

 33

 34 Arklahoma Danville 154.00 154.00 (2) Wood

 35

FERC FORM NO. 1 (ED. 12-87) Page 422

36 TOTAL 4,306.43 343.63 63
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 LINE STATISTICS

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

(a) (b) (c) (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 Osage S 4th St Enid 138.00 138.00 (2) Wood 49.00 1

 2 Horseshoe Lake Draper 138.00 138.00 (2) Wood 380.02 50.38 1

 3 Horseshoe Lake Maud Tap 138.00 138.00 (2) Wood 39.48 1

 4 Arbuckle Seminole 138.00 138.00 (2) Wood 63.75 6.34 1

 5 Horseshoe Lake Sooner 138.00 138.00 (2) Wood 234.50 32.08 1

 6 Osage KG&E 138.00 138.00 (2) Wood 34.26 1

 7 Horseshoe Lake Pecan Creek 138.00 138.00 (2) Wood 134.08 5.74 1

 8 Bristow Riverside 138.00 138.00 (2) Wood 48.15 5.06 1

 9 Earlywine Sunnyside 138.00 138.00 (2) Wood 223.60 1.43 1

 10 Arbuckle Chickasaw 138.00 138.00 (2) Wood 31.28 1

 11 Cimarron Cornville 138.00 138.00 (2) Wood 8.70 2.72 1

 12 Chicasaw Russet 138.00 138.00 (2) Wood 38.54 1

 13 Osage Shidler 138.00 138.00 (2) Wood 19.67 1

 14 Maud Tap Paoli 138.00 138.00 (2) Wood 58.44 1

 15 Arbuckle Brown Tap 138.00 138.00 (2) Wood 61.76 1

 16 Woodward District Cleo Corner 138.00 138.00 (2) Wood 57.00 4.30 1

 17 Bristow Cushing 138.00 138.00 (2) Wood 26.06 1

 18 Brown Durant Area 138.00 138.00 (2) Wood 41.35 1

 19 Seminole PSO Fixico Sub 138.00 138.00 (1) Wood 1.43 1

 20 El Reno WFEC@Taloga 138.00 138.00 (2) Wood 80.07 1

 21 Park Lane Arbuckle 138.00 138.00 (2) Wood 22.73 1

 22 Cleo Sub S 4th St Sub 138.00 138.00 (2) Wood 30.96 1

 23 Glenwood Woodring 138.00 138.00 (2) Wood 16.50 1

 24 Breckinridge Tap NE Enid Sub 138.00 138.00 (2) Steel 6.73 1

 25 Dewey Iodine 138.00 138.00 (1) Wood 23.47 1

 26 Polecat Creek Tap Polecat Creek Sub 138.00 138.00 (2) Steel 1.55 1

 27 SE 15th Glendale Sub 138.00 138.00 (2) Steel 2.05 1

 28 NE Enid Glenwood 138.00 138.00 (1) Steel 8.07 1

 29 Richards Piedmont 138.00 138.00 (1) Steel 7.99 1

 30 Woodward Iodine 138.00 138.00 (1) Steel 17.77 1.27 1

 31 Centennial Woodward 138.00 138.00 (1) Steel 33.17 1

 32 Arcadia Tap Louis Garber 138.00 138.00 (1) Steel 5.39 1

 33 Enid Industrial Tap Enid Industrial 138.00 138.00 (1) Steel 2.71 1

 34

 35 69 KV 69.00 69.00 1,466.26 83.97

FERC FORM NO. 1 (ED. 12-87) Page 422.1

36 TOTAL 4,306.43 343.63 63
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 LINE STATISTICS

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

(a) (b) (c) (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 63
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 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

Land Construction and Maintenance Rents Total

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.

1024500ACSR 179,736 3,109,820 3,289,556 132,882 84,344 217,226 1

 2

2167000ACSR 3,543,828 33,459,325 37,003,153 2,242,058 1,423,090 3,665,148 3

2167000ACSR 441,999 4,435,094 4,877,093 4

795000ACSR 2,644,103 11,846,095 14,490,198 5

795000ACSR 348,353 22,638,629 22,986,982 6

795000ACSR 224,979 4,015,837 4,240,816 7

795000ACSR 150,971 2,968,550 3,119,521 8

795000ACSR 316,385 1,889,128 2,205,513 9

795000ACSR 355,579 6,109,989 6,465,568 10

795000ACSR 418,049 6,766,743 7,184,792 11

795000ACSR 391,482 14,703,831 15,095,313 12

795000ACSR 1,124,708 17,438,108 18,562,816 13

795000ACSR 162,922 12,352 175,274 14

 15

 16

477000ACSR 439,777 4,329,961 4,769,738 546,306 346,754 893,060 17

795000ACSR 169,140 3,060,769 3,229,909 18

636000ACSR 30,770 753,655 784,425 19

636000ACSR 7,610 173,280 180,890 20

636000ACSR 62,595 926,300 988,895 21

636000ACSR 13,946 2,122,819 2,136,765 22

795000ACSR 35,697 1,141,655 1,177,352 23

795000ACSR 69,500 1,119,645 1,189,145 24

795AS22ACSR 2,505 330,740 333,245 25

1590000ACSR 803,768 2,376,604 3,180,372 26

477AS33ACSR 230,287 230,287 27

477000ACSR 161,550 161,550 28

795AS33ACSR 585,771 5,328,682 5,914,453 29

795AS33ACSR 631,153 3,699,297 4,330,450 30

795AS33ACSR 107,755 1,345,848 1,453,603 31

477AS33 156,952 156,952 32

 33

250V12CU 101 505,035 505,136 34

 35

FERC FORM NO. 1 (ED. 12-87) Page 423

 27,700,255 450,442,883 478,143,138 12,226,088 7,760,203 1,418 19,987,709 36
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 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

Land Construction and Maintenance Rents Total

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.

3364000ACSR 220,399 2,853,491 3,073,890 5,146,042 3,266,321 8,412,363 1

795000ACSR 2,299,165 54,574,343 56,873,508 2

336400ACSR 89,815 2,526,687 2,616,502 3

336400ACSR 83,544 3,167,636 3,251,180 4

477000ACSR 1,110,200 32,947,613 34,057,813 5

477000ACSR 75,662 1,650,747 1,726,409 6

636000ACSR 318,216 7,908,632 8,226,848 7

795000ACSR 719,738 7,951,791 8,671,529 8

795000ACSR 1,084,959 19,734,574 20,819,533 9

477000ACSR 173,451 2,367,904 2,541,355 10

795000ACSR 36,475 259,870 296,345 11

477000ACSR 144,742 2,875,556 3,020,298 12

477000ACSR 22,778 641,761 664,539 13

795000ACSR 197,455 3,303,782 3,501,237 14

477000ACSR 132,882 2,900,658 3,033,540 15

266800ACSR 48,837 1,150,200 1,199,037 16

477000ACSR 61,515 1,106,913 1,168,428 17

477000ACSR 89,490 2,394,666 2,484,156 18

477000ACSR 88,803 71,610 160,413 19

477000ACSR 406,533 5,265,569 5,672,102 20

795000ACSR 13,990 821,150 835,140 21

795000ACSR 63,508 1,595,192 1,658,700 22

795000ACSR 193,208 2,350,428 2,543,636 23

795000ACSR 55,301 1,318,080 1,373,381 24

795000ACSR 82,284 1,059,872 1,142,156 25

477000ACSR 513 732,828 733,341 26

795000ACSR 233,786 558,618 792,404 27

795000ACSR 16,760 2,761,879 2,778,639 28

795000ACSR 1,426,429 2,865,011 4,291,440 29

795000ACSR 623,718 5,457,032 6,080,750 30

47700ACSR 201,920 9,391,133 9,593,053 31

795000ACSR 242,812 242,812 32

795000ACSR 71,135 1,240,584 1,311,719 33

 34

 4,049,862 107,237,681 111,287,543 4,158,800 2,639,694 6,798,494 35

FERC FORM NO. 1 (ED. 12-87) Page 423.1

 27,700,255 450,442,883 478,143,138 12,226,088 7,760,203 1,418 19,987,709 36
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 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

Land Construction and Maintenance Rents Total

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

 27,700,255 450,442,883 478,143,138 12,226,088 7,760,203 1,418 19,987,709 36
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

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No.

(a) (b) (c) (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

 1 Various 69 KV Lines 15.44 Steel 15.04 1 1

 2 Enid Industrial Tap Enid Industrial 2.71 Steel 12.45 1 1

 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 TOTAL
Total

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.

(h) (j) (k) (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

Various ACSR 69 18,602 5,399,575 2,366,895 7,785,072 1

795AS33 ACSR 138 71,135 505,101 735,483 1,311,719 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

 5,904,676 3,102,378

FERC FORM NO. 1 (REV. 12-03) Page 425

 89,737 9,096,791 44
Name 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

(a) (b) (c)

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).

 1 RIVERSIDE NWC SW 20-15N-19E OK Distribution-Unatten 69.00 12.50

 2 FIVE TRIBES NE NE 4-14N-18E OK Transmission-Unatten 161.00 69.00 13.20

 3 TENNYSON NE SE 28-15N-18E OK Distribution-Unatten 69.00 12.50

 4 CALLERY NW SW SW 28-15N-19E OK Distribution-Unatten 69.00 12.50

 5 MUSKOGEE STA SE NW 21-15N-19E OK Transmission-Unatten 161.00 69.00 13.80

 6 HANCOCK LOT3 1-14N-18E OK Distribution-Unatten 161.00 12.50

 7 HANCOCK LOT3 1-14N-18E OK Distribution-Unatten 161.00 34.50

 8 EUCLID NW SE 14-16N-18E OK Distribution-Unatten 161.00 12.50

 9 AGENCY NE SE 17-15N-18E OK Distribution-Unatten 161.00 34.50

 10 AGENCY NE SE 17-15N-18E OK Transmission-Unatten 161.00 69.00 13.20

 11 PECAN CREEK SE 2-14N-17E OK Transmission-Unatten 161.00 138.00 13.20

 12 PECAN CREEK SE 2-14N-17E OK Transmission-Unatten 345.00 161.00 13.80

 13 SAPULPA NW NE 35-18N-11E OK Distribution-Unatten 69.00 12.50

 14 TIBBENS RD SE SW SE 33-18N-12E OK Distribution-Unatten 138.00 13.09

 15 BIXBY SE NE 33-17N-13E OK Distribution-Unatten 69.00 12.50

 16 HICKORY HILL NW SW 20-18N-12E OK Distribution-Unatten 138.00 12.50

 17 BLUEBELL SWC SE SW 26-18N-10E OK Transmission-Unatten 138.00 69.00 13.20

 18 BOWDEN NW NE 13-18N-11E OK Distribution-Unatten 138.00 12.50

 19 LONE STAR SE SE 10-17N-11E OK Distribution-Unatten 138.00 12.50

 20 BEELINE E1/2 NE NE 10-17N-12E OK Distribution-Unatten 138.00 12.50

 21 BEELINE E1/2 NE NE 10-17N-12E OK Transmission-Unatten 138.00 69.00 13.80

 22 POLECAT CREEK SW 1/4 SEC 28, T-18-N, R12E OK Distribution-Unatten 138.00 6.90

 23 KELLYVILLE PT OF NE1/4 NE1/4,SEC.12 T17N,R10E OK Distribution-Unatten 138.00 12.50

 24 CHECOTAH SWC SW 32-12N-17E OK Distribution-Unatten 69.00 12.50

 25 ROSS LAKE SW SW 13-15N-9E OK Distribution-Unatten 161.00 12.50

 26 WELLS SE NE 11-10N-16E OK Distribution-Unatten 69.00 24.00

 27 POTEAU SE SE 26-7N-25E OK Distribution-Unatten 69.00 12.50

 28 CAVANAL MTN NE SE 14-7N-25E OK Distribution-Unatten 69.00 12.50

 29 PANAMA NEC 8-8N-25E OK Distribution-Unatten 69.00 12.50

 30 PANAMA NEC 8-8N-25E OK Distribution-Unatten 69.00 24.00

 31 HEAVENER SWC SE SE 18-5N-26E OK Distribution-Unatten 69.00 12.50

 32 TARBY NE NE 2-7N-25E OK Transmission-Unatten 161.00 69.00 13.20

 33 MULDROW NE NE 30-11N-26E OK Distribution-Unatten 69.00 12.50

 34 ENID SW SE 7-22N-6W OK Distribution-Unatten 69.00 4.16

 35 ENID SW SE 7-22N-6W OK Distribution-Unatten 69.00 12.50

 36 HEMLOCK SW NW & NW SW 5-22N-6W OK Distribution-Unatten 69.00 12.50

 37 CLEVELAND AVE SW SW 12-22N-7W OK Distribution-Unatten 12.50 4.16

 38 CLEVELAND AVE SW SW 12-22N-7W OK Distribution-Unatten 69.00 12.50

 39 WOODRING NW NE 1-21N-6W OK Transmission-Unatten 345.00 138.00 13.80

 40 CHESTNUT NW NW 10-22N-6W OK Distribution-Unatten 69.00 12.50

FERC FORM NO. 1 (ED. 12-96) Page 426
Name 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

(a) (b) (c)

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).

 1 GLENWOOD NW SW 3-22N-7W OK Distribution-Unatten 138.00 12.50

 2 SO 4TH ST SEC NE 19-22N-6W OK Distribution-Unatten 69.00 13.80

 3 SO 4TH ST SEC NE 19-22N-6W OK Distribution-Unatten 138.00 12.50

 4 SO 4TH ST SEC NE 19-22N-6W OK Transmission-Unatten 138.00 69.00 13.20

 5 IMO SW SE SEC 16-22N-7W OK Transmission-Unatten 138.00 69.00 13.20

 6 NE ENID NW,SW,SEC 26,T23N,R6W OK Distribution-Unatten 138.00 12.50

 7 NE ENID NW,SW,SEC 26,T23N,R6W OK Transmission-Unatten 138.00 69.00 13.20

 8 FAIRMONT NE NW 20-22N-5W OK Distribution-Unatten 138.00 12.50

 9 OSAGE SW SW 11-25N-2E OK Transmission-Unatten 138.00 69.00 13.20

 10 SOONER STA NE 26-23N-2E OK Transmission-Unatten 345.00 138.00 13.80

 11 CHIKASKIA SW 13-27N-1W OK Transmission-Unatten 138.00 69.00 13.20

 12 COW CREEK SW NW 35-21N-1W OK Transmission-Unatten 138.00 69.00

 13 HENNESSEY SW NW 24-19N-7W OK Distribution-Unatten 138.00 12.50

 14 CLEO CORNER NEC 24-22N-12W OK Transmission-Unatten 138.00 69.00 13.80

 15 CEDAR AVE NW NE SE 36-23N-21W OK Distribution-Unatten 69.00 12.50

 16 WOODWARD DISTRICT W1/2 NW20-22N-20W OK Transmission-Unatten 138.00 69.00 13.20

 17 NEWMAN AVE SE NW SW SW 22-21N-25W OK Distribution-Unatten 24.00 12.50

 18 NEWMAN AVE SE NW SW SW 22-21N-25W OK Distribution-Unatten 69.00 24.00

 19 CENTENNIAL NE 1/4 OF NE1/4,SEC8,T19N,R19W Transmission-Unatten 138.00 34.50

 20 IODINE NE1/4 OF NE1/4,SEC 8,T19N,R19W OK Distribution-Unatten 24.00 12.50

 21 IODINE NE1/4 OF NE1/4,SEC 8,T19N,R19W OK Distribution-Unatten 138.00 12.50

 22 ALVA SW NW NW 24-27N-14W OK Distribution-Unatten 69.00 4.16

 23 ALVA SW NW NW 24-27N-14W OK Distribution-Unatten 69.00 12.50

 24 KNOBHILL E 1/2 SE-25-27N-14W OK Distribution-Unatten 69.00 12.50

 25 KNOBHILL E 1/2 SE-25-27N-14W OK Transmission-Unatten 138.00 69.00 13.20

 26 FOUNDATION PART OF NW1/4,SW1/4,SEC27,TTS,R2E OK Distribution-Unatten 138.00 12.50

 27 ARDMORE NE NE 31-4S-2E OK Distribution-Unatten 69.00 4.16

 28 ARDMORE NE NE 31-4S-2E OK Distribution-Unatten 69.00 12.50

 29 HARRIS ST NE NW 19-4S-2E OK Distribution-Unatten 69.00 12.50

 30 TOWER HEIGHTS SE4 25-4S-1E OK Distribution-Unatten 69.00 12.50

 31 MARIETTA NE4 SEC 19-7S-2E OK Distribution-Unatten 69.00 12.50

 32 CHICKASAW NW,SEC 21-4S-2E OK Transmission-Unatten 138.00 69.00 13.20

 33 DILLARD SW SEC 27-4S-2W OK Distribution-Unatten 24.00 12.50

 34 DILLARD SW SEC 27-4S-2W OK Distribution-Unatten 34.50 12.50

 35 DILLARD SW SEC 27-4S-2W OK Distribution-Unatten 138.00 12.50

 36 BERWYN NW NW 14-3S-2E OK Distribution-Unatten 138.00 12.50

 37 LONE GROVE NE4 35-4S-1W OK Distribution-Unatten 138.00 12.50

 38 ROCKY POINT SW SW 18-5S-2E OK Transmission-Unatten 138.00 69.00 13.20

 39 SUNNYSIDE NW4 30-4S-1E OK Transmission-Unatten 345.00 138.00 13.80

 40 HEALDTON SE4 SEC 3-4S-3W OK Distribution-Unatten 69.00 12.50

FERC FORM NO. 1 (ED. 12-96) Page 426.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

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).

 1 COUNTY LINE SW SW 22-1S-3W OK Distribution-Unatten 69.00 12.50

 2 POOLEVILLE SW4 SEC 10-2S-2W OK Distribution-Unatten 138.00 12.50

 3 RATLIFF NW4 & NE4 22-1S-3W OK Distribution-Unatten 138.00 12.50

 4 RATLIFF NW4 & NE4 22-1S-3W OK Transmission-Unatten 138.00 69.00 13.20

 5 FOX SE4 26-2S-3W OK Distribution-Unatten 138.00 12.50

 6 HEALDTON TAP NE4 SEC 28-4S-3W OK Transmission-Unatten 138.00 69.00 13.20

 7 WILDHORSE NW4 7-1S-3W OK Distribution-Unatten 69.00 12.50

 8 DUNDEE SE NE 7-4S-3W OK Distribution-Unatten 138.00 12.50

 9 MADILL INDUSTRIAL SW 1/4,SEC 35,R5E,T5S Distribution-Unatten 138.00 13.80

 10 GLASSES SW4 26-5S-5E OK Distribution-Unatten 138.00 12.50

 11 BUTTERFIELD NE4 SEC 11,7S-8E OK Distribution-Unatten 138.00 12.50

 12 DURANT NE SE NE 32-6S-9E OK Distribution-Unatten 34.50 4.16

 13 DURANT NE SE NE 32-6S-9E OK Distribution-Unatten 34.50 12.50

 14 BODLE NEC SW NE 30-6S-9E OK Distribution-Unatten 138.00 12.50

 15 BODLE NEC SW NE 30-6S-9E OK Distribution-Unatten 138.00 34.50

 16 BROWN OG&E SWC SW 29-5S-8E OK Distribution-Unatten 138.00 34.50

 17 COLBERT NW NW 8-8S-8E OK Distribution-Unatten 138.00 12.50

 18 PAULS VALLEY SW SE 8-3N-1E OK Distribution-Unatten 69.00 4.16

 19 PAULS VALLEY SW SE 8-3N-1E OK Distribution-Unatten 69.00 12.50

 20 WALNUT CREEK SEC 14-6N-2W OK Distribution-Unatten 138.00 12.50

 21 PAOLI SEC NE NE 20-4N-1E OK Transmission-Unatten 138.00 69.00

 22 RUSH CREEK W SE SE 20-3N-1E OK Distribution-Unatten 69.00 12.50

 23 PRAIRIE POINT NWC NE 31-2N-2W OK Distribution-Unatten 138.00 12.50

 24 CHIGLEY NWC SW 24-2N-1E OK Transmission-Unatten 138.00 69.00 13.20

 25 SULPHUR SE4 34-1N-3E OK Distribution-Unatten 69.00 12.50

 26 MILL CREEK B145SW4 SEC 18-2S-5E OK Distribution-Unatten 138.00 4.16

 27 DAVIS NE NE 32-1N-2E OK Distribution-Unatten 69.00 12.50

 28 ARBUCKLE STA SE SE 27-1N-3E OK Transmission-Unatten 138.00 69.00 13.20

 29 JOLLYVILLE SW4 SEC9 1S-2E OK Distribution-Unatten 34.50 12.50

 30 JOLLYVILLE SW4 SEC9 1S-2E OK Distribution-Unatten 138.00 34.50

 31 VALLEY VIEW NW SW 26-4N-6E OK Distribution-Unatten 69.00 12.50

 32 AHLOSO NWC NW 11-3N-6E OK Distribution-Unatten 69.00 12.50

 33 HARDEN CITY NEC SE SE 30-2N-7E OK Distribution-Unatten 69.00 4.16

 34 HARDEN CITY NEC SE SE 30-2N-7E OK Distribution-Unatten 69.00 12.50

 35 PARK LANE NE SE SE 31-4N-6E OK Distribution-Unatten 138.00 12.50

 36 PARK LANE NE SE SE 31-4N-6E OK Transmission-Unatten 138.00 69.00 13.20

 37 LULA NW CORNER SEC 4,T-2-N,R8E OK Transmission-Unatten 138.00 69.00 13.20

 38 RUSSETT NW4 28-4S-5E OK Distribution-Unatten 34.50 12.50

 39 RUSSETT NW4 28-4S-5E OK Distribution-Unatten 138.00 34.50

 40 RUSSETT NW4 28-4S-5E OK Distribution-Unatten 138.00 34.50 7.20

FERC FORM NO. 1 (ED. 12-96) Page 426.2
Name 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

(a) (b) (c)

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).

 1 CHANDLER NE NE 16-14N-4E OK Distribution-Unatten 69.00 12.50

 2 CHANDLER NE NE 16-14N-4E OK Distribution-Unatten 69.00 24.00

 3 KEY WEST NE NW NE 9-14N-6E OK Distribution-Unatten 138.00 24.00

 4 WARWICK SW SW 5-14N-3E OK Distribution-Unatten 138.00 24.00

 5 CYPRESS SW SE 1-7N-8E OK Distribution-Unatten 69.00 12.50

 6 FIXICO NE NE 21-9N-6E OK Distribution-Unatten 69.00 24.00

 7 FIXICO NE NE 21-9N-6E OK Distribution-Unatten 138.00 12.50

 8 FIXICO NE NE 21-9N-6E OK Distribution-Unatten 138.00 24.00

 9 FIXICO NE NE 21-9N-6E OK Transmission-Unatten 138.00 69.00 13.20

 10 SEMINOLE STA SE NW & SW NE 25-6N-5E OK Transmission-Unatten 345.00 138.00 14.40

 11 KOLACHE SEC SE SW 26-12N-6E OK Distribution-Unatten 69.00 24.00

 12 SHAWNEE NE SW 19-10N-4E OK Distribution-Unatten 69.00 4.16

 13 SHAWNEE NE SW 19-10N-4E OK Distribution-Unatten 69.00 24.00

 14 REMINGTON SWC NW 16-10N-4E OK Distribution-Unatten 69.00 12.50

 15 MCLOUD SEC 16-11N-2E OK Distribution-Unatten 69.00 12.50

 16 MAUD TAP SW SW 29-8N-5E OK Transmission-Unatten 138.00 69.00 13.20

 17 FOREST HILL SW SE 14-9N-3E OK Transmission-Unatten 138.00 69.00 13.80

 18 INGLEWOOD NE SW & NW SE 24-10N-3E OK Distribution-Unatten 138.00 12.50

 19 RUSHING SW NW 5-10N-4E OK Transmission-Unatten 138.00 69.00 13.80

 20 ST GREGORY SW SW NW 2-10N-3E OK Distribution-Unatten 138.00 12.50

 21 ROCK CREEK NE NE 31-11N-4E OK Distribution-Unatten 138.00 12.50

 22 WEWOKA SE 19-8N-8E OK Distribution-Unatten 69.00 12.50

 23 SASAKWA NEC NW NE 2-5N-7E OK Distribution-Unatten 69.00 12.50

 24 DRUMRIGHT SW SW 32-18N-7E OK Distribution-Unatten 69.00 24.00

 25 CUSHING TAP NW 26-18N-5E OK Transmission-Unatten 138.00 69.00 13.20

 26 TIGER CREEK SE SE 29-18N-7E OK Distribution-Unatten 69.00 12.50

 27 STILLWATER SW SW 12-19N-2E OK Transmission-Unatten 138.00 69.00 2.40

 28 PIPELINE SE SE 15-17N-5E OK Distribution-Unatten 69.00 24.00

 29 BRISTOW SE SW 32-16N-9E OK Distribution-Unatten 69.00 12.50

 30 BRISTOW SE SW 32-16N-9E Distribution-Unatten 138.00 13.09

 31 BRISTOW SE SW 32-16N-9E OK Transmission-Unatten 138.00 69.00 12.50

 32 CAPITOL HILL NW SW 10-11N-3W OK Distribution-Unatten 12.50 4.16

 33 SW 22ND ST SE NE 7-11N-3W OK Distribution-Unatten 69.00 12.50

 34 SW 64TH SEC NE NW 25-11N-4W OK Distribution-Unatten 69.00 12.50

 35 KENTUCKY NEC SE NW SW 20-11N-3W OK Distribution-Unatten 69.00 12.50

 36 SAGE SEC SW NE 21-11N-3W OK Distribution-Unatten 69.00 12.50

 37 PENNSYLVANIA SEC NE 31-11N-3W OK Distribution-Unatten 138.00 12.50

 38 PENNSYLVANIA SEC NE 31-11N-3W OK Transmission-Unatten 138.00 69.00 13.20

 39 WILL ROGERS NWC SE 28-11N-4W OK Distribution-Unatten 69.00 12.50

 40 MACARTHUR NEC SE 16-11N-4W OK Distribution-Unatten 69.00 12.50

FERC FORM NO. 1 (ED. 12-96) Page 426.3
Name 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

(a) (b) (c)

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).

 1 SARA NE NE 27-11N-5W OK Distribution-Unatten 138.00 34.50

 2 SOUTHGATE SE SE SW SE 16-10N-3W OK Distribution-Unatten 138.00 12.50

 3 SANTA FE AVE SE NE 33-11N-3W OK Distribution-Unatten 138.00 12.50

 4 WESTMOORE NW/4, NW/4 SECTION 17, T10N, R3W OK Distribution-Unatten 138.00 12.50

 5 ROBINSON AVE NE 1/4 SEC 4, T11N, R3W OK Distribution-Unatten 138.00 12.50

 6 ROBINSON AVE NE 1/4 SEC 4, T11N, R3W OK Distribution-Unatten 138.00 13.80

 7 ROBINSON AVE NE 1/4 SEC 4, T11N, R3W OK Distribution-Unatten 138.00 34.50

 8 CLASSEN NW SW 33-12N-3W OK Distribution-Unatten 138.00 12.50

 9 CLASSEN NW SW 33-12N-3W OK Distribution-Unatten 138.00 34.50

 10 GRAND AVE NE SW SW 32-12N-3W OK Distribution-Unatten 12.50 4.16

 11 MAY AVE NE NE 25-12N-4W OK Distribution-Unatten 69.00 12.50

 12 MERIDIAN SWC 26-12N-4W OK Distribution-Unatten 138.00 12.50

 13 CZECH HALL SWC NW 33-12N-5W OK Distribution-Unatten 138.00 12.50

 14 COUNCIL SWC NW SW 32-12N-4W OK Distribution-Unatten 138.00 12.50

 15 SW 5TH ST SE NE NE 1-11N-4W OK Distribution-Unatten 138.00 12.50

 16 SW 5TH ST SE NE NE 1-11N-4W OK Distribution-Unatten 138.00 34.50

 17 SW 5TH ST SE NE NE 1-11N-4W OK Transmission-Unatten 138.00 69.00 13.80

 18 MUSTANG STA SE 36-12N-5W OK Transmission-Unatten 138.00 69.00 7.20

 19 MORGAN ROAD PART OF EAST HALF,SEC 35,T12N,R5W Distribution-Unatten 138.00 12.50

 20 WESTOAKS SW SW 28-12N-4W OK Distribution-Unatten 138.00 12.50

 21 LONE OAK SE/4 S35 T14N 4W OK Distribution-Unatten 138.00 34.50

 22 BELLE ISLE NW SE 8-12N-3W OK Distribution-Unatten 138.00 12.50

 23 HAYMAKER SE1/4 SEC 33 T13N R5W OK Distribution-Unatten 138.00 34.50

 24 SKYLINE SEC SW SE 17-13N-3W OK Distribution-Unatten 138.00 12.50

 25 NORTHWEST NWC NE 5-13N-4W OK Transmission-Unatten 345.00 138.00 13.80

 26 PIEDMONT SE SW 34-14N-5W OK Distribution-Unatten 138.00 34.50

 27 THIRTY EIGHTH ST NW SW SW18-12N-3W OK Distribution-Unatten 69.00 12.50

 28 THIRTY EIGHTH ST NW SW SW18-12N-3W OK Distribution-Unatten 138.00 12.50

 29 THIRTY EIGHTH ST NW SW SW18-12N-3W OK Transmission-Unatten 138.00 69.00 13.20

 30 RICHARDS SE 1/4 SEC 13,T13N,R5W Distribution-Unatten 138.00 12.50

 31 BETHANY NWC SE SW 15-12N-4W Distribution-Unatten 69.00 12.50

 32 TENNESSEE NEC 30-13N-3W OK Distribution-Unatten 138.00 12.50

 33 EIGHTY FOURTH ST SE NW SW 33-13N-3W OK Distribution-Unatten 138.00 12.50

 34 TULSA AVE NE SE NE SW 11-12N-4W OK Distribution-Unatten 138.00 12.50

 35 SILVER LAKE SEC NE 29-13N-4W OK Distribution-Unatten 138.00 12.50

 36 BRADEN PARK PART OF NE 1/4 OF SECTION Distribution-Unatten 138.00 12.50

 37 WILSHIRE SE SW SE 36-13N-4W OK Distribution-Unatten 138.00 12.50

 38 QUAIL CREEK SE NE 23-13N-4W OK Distribution-Unatten 138.00 12.50

 39 YUKON NWC SW 16-12N-5W OK Distribution-Unatten 69.00 12.50

 40 WOODLAWN SE NE 18-12N-4W OK Distribution-Unatten 69.00 12.50

FERC FORM NO. 1 (ED. 12-96) Page 426.4
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

 No. Name and Location of Substation

Primary

(a) (b) (c)

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).

 1 WESTERN AVE SEC NE 20-12N-3W OK Distribution-Unatten 138.00 12.50

 2 LAKESIDE NE NW 3-12N-4W OK Distribution-Unatten 138.00 12.50

 3 CIMARRON SW SW 13-12N-6W OK Transmission-Unatten 345.00 138.00 13.80

 4 DIVISION AVE SW SE SW 31-13N-4W OK Distribution-Unatten 138.00 12.50

 5 ARCADIA SW NW,NW SW16-14N-1W OK Transmission-Unatten 345.00 138.00 13.80

 6 REMINGTON PARK NE 1/4, SEC 11, T12N, R3W OK Distribution-Unatten 138.00 12.50

 7 DEEP FORK NWC SW NE 11-12N-3W OK Distribution-Unatten 69.00 12.50

 8 GREEN PASTURES SE SE 6-12N-1W OK Distribution-Unatten 69.00 12.50

 9 BRYANT SE NE 25-13N-3W OK Distribution-Unatten 138.00 12.50

 10 BRYANT SE NE 25-13N-3W Distribution-Unatten 138.00 13.09

 11 MEMORIAL SWC SE 15-13N-3W OK Distribution-Unatten 138.00 12.50

 12 MEMORIAL SWC SE 15-13N-3W OK Distribution-Unatten 138.00 34.50

 13 NE 30TH ST SEC SW NE 19-12N-2W OK Distribution-Unatten 69.00 12.50

 14 STONEWALL SWC SE NW NW 23-12N-3W OK Distribution-Unatten 138.00 12.50

 15 PARK PLACE SW SW 27-12N-3W OK Distribution-Unatten 138.00 13.80

 16 NE 10TH ST SWC SW 26-12N-2W OK Distribution-Unatten 138.00 12.50

 17 MIDWAY SW SW 30-12N-1E OK Distribution-Unatten 138.00 12.50

 18 MIDWAY SW SW 30-12N-1E OK Distribution-Unatten 138.00 34.50

 19 CALIFORNIA SW SE 35-12N-3W OK Distribution-Unatten 69.00 4.16

 20 CALIFORNIA SW SE 35-12N-3W OK Distribution-Unatten 69.00 12.50

 21 OU MEDICAL CENTER NW 1/4 SEC.35,T12N,R3W Distribution-Unatten 138.00 13.09

 22 OU MEDICAL CENTER NW 1/4 SEC.35,T12N,R3W Distribution-Unatten 138.00 36.20

 23 RENO NWC 5-11N-2W OK Distribution-Unatten 138.00 12.50

 24 RENO NWC 5-11N-2W OK Transmission-Unatten 138.00 69.00 13.80

 25 HORSESHOE LAKE STA S1/2 SE 15-12N-1E OK Transmission-Unatten 138.00 69.00 13.80

 26 SUNNYLANE NWC SW SW NW 17-11N-2W OK Distribution-Unatten 69.00 12.50

 27 LIGHTNING CREEK SW NW 10-11N-3W OK Distribution-Unatten 138.00 12.50

 28 DRAPER LAKE E 1/2 NW 20-10N-1W OK Distribution-Unatten 34.50 12.50

 29 DRAPER LAKE E 1/2 NW 20-10N-1W OK Distribution-Unatten 138.00 34.50

 30 DRAPER LAKE E 1/2 NW 20-10N-1W OK Transmission-Unatten 345.00 138.00 13.80

 31 TROSPER NE SE12-11N-3W OK Distribution-Unatten 138.00 12.50

 32 GLENDALE OK Distribution-Unatten 138.00 12.50

 33 MOORE SEC SE 14-10N-3W OK Distribution-Unatten 138.00 12.50

 34 FOSTER SE SW SE 24-11N-3W OK Distribution-Unatten 138.00 12.50

 35 DISCOVERY NE NE 25-11N-3W OK Distribution-Unatten 138.00 12.50

 36 DISCOVERY NE NE 25-11N-3W OK Distribution-Unatten 138.00 34.50

 37 SE 15TH ST NEC NW NW 7-11N-1W OK Distribution-Unatten 138.00 12.50

 38 WILD MARY OK Distribution-Unatten 138.00 12.50

 39 NORMAN SE NE 30-9N-2W OK Distribution-Unatten 12.50 4.16

 40 NORMAN SE NE 30-9N-2W OK Distribution-Unatten 34.50 12.50

FERC FORM NO. 1 (ED. 12-96) Page 426.5
Name 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

(a) (b) (c)

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).

 1 BOYD SWC SW NW 36-9N-3W OK Distribution-Unatten 138.00 12.50

 2 WILKINSON NEC NW 4-8N-2W OK Distribution-Unatten 138.00 12.50

 3 WILKINSON NEC NW 4-8N-2W OK Distribution-Unatten 138.00 34.50

 4 CEDAR LANE NW NE 18-8N-2W OK Distribution-Unatten 138.00 12.50

 5 TURNER NW NW 10-10N-3W OK Distritution-Unatten 138.00 12.50

 6 PLEASANT VALLEY NW NW 10-9N-3W OK Distribution-Unatten 138.00 12.50

 7 MILLENNIUM PART OF SW1/4,SEC16,T9N,R2W OK Distribution-Unatten 138.00 12.50

 8 INDIAN HILLS NW CORNER INDIAN OK Distribution-Unatten 138.00 12.50

 9 STUBBEMAN NW NW 19-9N-2W OK Distribution-Unatten 138.00 12.50

 10 CHERRY CREEK NWC NW 34-9N-3W OK Distribution-Unatten 138.00 12.50

 11 COTTONWOOD CREEK NE NW 20-16N-2W OK Distribution-Unatten 138.00 12.50

 12 COTTONWOOD CREEK NE NW 20-16N-2W OK Transmission-Unatten 138.00 69.00 7.20

 13 FITZGERALD CREEK SE NE 10-17N-1W OK Distribution-Unatten 138.00 24.00

 14 PINE STREET SWC SW 34-17N-2W OK Distribution-Unatten 138.00 12.50

 15 PINE STREET SWC SW 34-17N-2W OK Distribution-Unatten 138.00 24.00

 16 LIBERTY LAKE SECTION 7 T15N R3W OK Distribution-Unatten 138.00 12.50

 17 WATERLOO SW SE 31-15N-2W OK Distribution-Unatten 138.00 12.50

 18 EL RENO SW NE 9-12N-7W OK Distribution-Unatten 138.00 12.50

 19 EL RENO SW NE 9-12N-7W OK Transmission-Unatten 138.00 69.00 13.20

 20 SOUTHARD NWC NE 10-18N-12W OK Distribution-Unatten 138.00 12.50

 21 SOUTHARD NWC NE 10-18N-12W OK Distribution-Unatten 138.00 24.00

 22 ROMAN NOSE SW SW SW 24-16N-11W OK Distribution-Unatten 138.00 24.00

 23 JENSEN RD NW NE 29-12N-7W OK Distribution-Unatten 34.50 12.50

 24 JENSEN RD NW NE 29-12N-7W OK Distribution-Unatten 138.00 34.50

 25 J STREET NE 1/4 SEC 8 T8N R3 AR Distribution-Unatten 161.00 12.50

 26 THIRD ST NW SE 8-8N-32W AR Distribution-Unatten 69.00 4.16

 27 THIRD ST NW SE 8-8N-32W AR Distribution-Unatten 69.00 12.50

 28 THIRD ST NW SE 8-8N-32W AR Transmission-Unatten 161.00 69.00 13.80

 29 SOUTHSIDE SWC SE SE 28-8N-32W AR Distribution-Unatten 69.00 12.50

 30 EXPOSITION PARK SE NW 35-9N-32W AR Distribution-Unatten 69.00 12.50

 31 MASSARD SWC SE SE 19-8N-31W AR Distribution-Unatten 161.00 12.50

 32 MASSARD SWC SE SE 19-8N-31W AR Transmission-Unatten 161.00 69.00 13.80

 33 BELLE AVE SE NE SE NE 16-8N-32W Distribution-Unatten 69.00 12.50

 34 CAVANAUGH NW SW NW 4-7N-32W AR Distribution-Unatten 69.00 12.50

 35 BATTLEFIELD SE 1/4, SECTION3, T-7N-32W OK Distribution-Unatten 161.00 12.50

 36 FACTORY NW NE SW 9-8N-32W AR Distribution-Unatten 69.00 12.50

 37 BARLING S1/2 S1/2 SE1/4, SECTION 32 T8N, R31W AR Distribution-Unatten 161.00 12.50

 38 CHAFFEE SE SE SE SEC 4, T7N, R31W AR Distribution-Unatten 34.50 12.50

 39 CARNALL NEC NW NW 2-7N-32W AR Distribution-Unatten 69.00 12.50

 40 CARNALL NEC NW NW 2-7N-32W AR Distribution-Unatten 69.00 34.50

FERC FORM NO. 1 (ED. 12-96) Page 426.6
Name 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

(a) (b) (c)

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).

 1 OAK PARK E« NE¬ Sec. 34, T 9 North, R 32 West AR Distribution-Unatten 161.00 12.50

 2 FT SMITH S1/2 S1/2 8-7N-32W AR Transmission-Unatten 345.00 161.00 13.80

 3 FT SMITH S1/2 S1/2 8-7N-32W AR Transmission-Unatten 500.00 161.00 13.80

 4 FT SMITH S1/2 S1/2 8-7N-32W AR Transmission-Unatten 500.00 345.00 13.80

 5 GERBER ROAD SW 1/4,SEC 26,T9N,R23W OK Distribution-Unatten 161.00 12.50

 6 PARK VIEW SW NE 14-8N-32W AR Distribution-Unatten 69.00 12.50

 7 ARKOMA NEC SW 20-8N-32W AR Distribution-Unatten 161.00 12.50

 8 COLONY SE SE 4-7N-32W AR Distribution-Unatten 161.00 12.50

 9 BRANCH SE NE SW 6-7N-27W AR Distribution-Unatten 34.50 12.50

 10 BRANCH SE NE SW 6-7N-27W AR Distribution-Unatten 69.00 34.50

 11 BRANCH SE NE SW 6-7N-27W AR Transmission-Unatten 161.00 69.00 7.20

 12 ETNA SW NE NE 3-8N-27W AR Distribution-Unatten 69.00 34.50 6.60

 13 SHORT MTN SW NW NW SW 11-7N-26W AR Distribution-Unatten 69.00 12.50

 14 SHORT MTN SW NW NW SW 11-7N-26W AR Distribution-Unatten 69.00 34.50 13.20

 15 ALMA NW SE 6-9N-30W AR Distribution-Unatten 161.00 12.50

 16 SIMMONS SE 35 SW 36-10N-30W AR Distribution-Unatten 161.00 34.50

 17 HELBERG NW NW 35-10N-27W AR Distribution-Unatten 69.00 12.50

 18 HELBERG NW NW 35-10N-27W AR Transmission-Unatten 161.00 69.00 13.20

 19 LITTLE SPADRA CREEK NE SE 35-10N-24W AR Distribution-Unatten 69.00 34.50

 20 LITTLE SPADRA CREEK NE SE 35-10N-24W AR Transmission-Unatten 161.00 69.00

 21 VAN BUREN SE SW NE 24-9N-32W AR Distribution-Unatten 69.00 4.16

 22 VAN BUREN SE SW NE 24-9N-32W AR Distribution-Unatten 69.00 12.50

 23 VAN BUREN INT NE SW 7-9N-31W AR Transmission-Unatten 161.00 69.00

 24 WHITESIDE SEC 30-9N-31W AR Distribution-Unatten 161.00 12.50

 25

 26 Summary: 200-Substations included above Distribution

 27 Summary: 56-Substations included above Transmission

 28 Summary: 110 Substations <10,000 kVA not listed abo Distribution

 29 Summary: 0 Substations <10,000 kVA not listed above Transmission

 30

 31

 32

 33

 34

 35

 36

 37

 38

 39

 40

FERC FORM NO. 1 (ED. 12-96) Page 426.7
Name 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

Number of Units No.

(f) (g) (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 427
Name 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

Number of Units No.

(f) (g) (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 427.1
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

Number of Units No.

(f) (g) (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 427.2
Name 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

Number of Units No.

(f) (g) (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 427.3
Name 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

Number of Units No.

(f) (g) (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 427.4
Name of Respondent This Report Is:

(1) An Original

(2) A Resubmission

Date of Report

(Mo, Da, Yr) Year/Period of Report

End of

SUBSTATIONS

Oklahoma Gas and Electric Company X

 / /

2008/Q4

Line

Number of Units No.

(f) (g) (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 427.5
Name 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

Number of Units No.

(f) (g) (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 427.6
Name 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

Number of Units No.

(f) (g) (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

FERC FORM NO. 1 (ED. 12-95) Index 2
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

FERC FORM NO. 1 (ED. 12-95) Index 3
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

FERC FORM NO. 1 (ED. 12-90) Index 4
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

FERC FORM NO. 1 (ED. 12-90) Index 5