<SUBMISSION>
<ACCESSION-NUMBER>0001021635-01-000010
<TYPE>10-K
<PUBLIC-DOCUMENT-COUNT>8
<PERIOD>20001231
<FILING-DATE>20010326
<FILER>
<COMPANY-DATA>
<CONFORMED-NAME>OGE ENERGY CORP
<CIK>0001021635
<ASSIGNED-SIC>4911
<IRS-NUMBER>731481638
<STATE-OF-INCORPORATION>OK
<FISCAL-YEAR-END>1231
</COMPANY-DATA>
<FILING-VALUES>
<FORM-TYPE>10-K
<ACT>34
<FILE-NUMBER>001-12579
<FILM-NUMBER>1579180
</FILING-VALUES>
<BUSINESS-ADDRESS>
<STREET1>321 N HARVEY
<STREET2>P O BOX 321
<CITY>OKLAHOMA CITY
<STATE>OK
<ZIP>73101-0321
<PHONE>4055533000
</BUSINESS-ADDRESS>
<MAIL-ADDRESS>
<STREET1>321 N HARVEY
<STREET2>P O BOX 321
<CITY>OKLAHOMA CITY
<STATE>OK
<ZIP>73101-0321
</MAIL-ADDRESS>
</FILER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>0001.htm
<DESCRIPTION>FORM 10-K
<TEXT>


<HTML>
<HEAD>
<TITLE>Form 10-K</TITLE>
</HEAD>

<BODY>

<HR SIZE=3 WIDTH=100% NOSHADE><BR><BR>

<P ALIGN=CENTER><FONT SIZE=4><B>SECURITIES AND EXCHANGE COMMISSION</B></FONT><BR>
<FONT SIZE=2>Washington, D.C. 20549</FONT></P>

<P ALIGN=CENTER><B><FONT SIZE=6>FORM 10-K</FONT></B><P>

<P ALIGN=LEFT><FONT SIZE=4>[X] &nbsp;&nbsp;ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;THE SECURITIES EXCHANGE ACT OF 1934</FONT></P>

<P ALIGN=CENTER><B><FONT SIZE=3>OR</FONT></B></P>

<P ALIGN=LEFT><FONT SIZE=4>[&nbsp;&nbsp;&nbsp;] &nbsp;&nbsp;TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;THE SECURITIES EXCHANGE ACT OF 1934</FONT></P>

<P ALIGN=LEFT><FONT SIZE=2>For the fiscal year ended December 31, 2000
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;Commission File Number 1-12579</FONT></P>

<P ALIGN=CENTER><B><FONT SIZE=5>OGE Energy Corp.</FONT></B><BR>
<FONT SIZE=2>(Exact name of registrant as specified in its charter)</FONT></P>

<P ALIGN=LEFT><FONT SIZE=2>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oklahoma&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;73-1481638</FONT><BR>
<FONT SIZE=1>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(State or other jurisdiction
of&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
(I.R.S. Employer<BR>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporation or
organization)&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
Identification No.)</FONT></P>

<P ALIGN=CENTER><FONT SIZE=2>321 North Harvey<BR>
P. O. Box 321<BR>
Oklahoma City, Oklahoma 73101-0321</FONT><BR>
<FONT SIZE=1>(Address of principal executive offices)<BR>
(Zip Code)</FONT></P>

<P ALIGN=CENTER><FONT SIZE=2>Registrant's telephone number, including area
code:&nbsp;&nbsp;405-553-3000</FONT></P>

<P ALIGN=LEFT><FONT SIZE=2>Securities registered pursuant to Section 12(b) of
the Act:</FONT></P>

<P ALIGN=LEFT><FONT SIZE=1>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Title of each class
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Name of each exchange on which<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<U>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;so registered&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</U>&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<U>&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
each class is registered&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;</U><BR>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Common Stock&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;New York Stock Exchange and Pacific Stock Exchange<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
Rights to Purchase Series A Preferred Stock&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;New York Stock Exchange and Pacific Stock Exchange</FONT></P>

<P ALIGN=LEFT><FONT SIZE=2>Securities registered pursuant to Section 12(g) of
the Act:&nbsp;&nbsp;None</FONT></P>

<P><FONT SIZE=1>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Indicate by check mark whether the
registrant (1) has filed all reports  required to be filed by Section 13 or
15(d) of the Securities Exchange Act of 1934 during the preceding 12 months
(or for such shorter  period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for the past 90
days.&nbsp;&nbsp;&nbsp;Yes<U>&nbsp;&nbsp;&nbsp;&nbsp;X&nbsp;&nbsp;&nbsp;
</U>No<U>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;</U><BR>

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Indicate by check mark if disclosure of delinquent
filers pursuant to Item 405 of regulation S-K is not contained herein, and will
not be contained, to the best of registrant's knowledge, in definitive proxy or
information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K.&nbsp;&nbsp;[&nbsp;X&nbsp;]<BR>

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As of February 28, 2001, Common Shares outstanding
were 77,921,997.  Based upon the closing price on the New York Stock Exchange on
February 28, 2001, the aggregate market value of the voting stock held by
nonaffiliates of the Company was:  Common Stock $1,809,348,770.<BR>

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The proxy statement for the 2001 annual meeting of
shareowners is incorporated by reference into Part III of this Report.
</FONT></P><BR>

<HR SIZE=3 NOSHADE>

<PRE>
                                                  TABLE OF CONTENTS
ITEM                                                                                                           PAGE
----                                                                                                           ----
                                                       PART I

Item 1.  Business.............................................................................................    1
         The Company..........................................................................................    1
         Electric Operations..................................................................................    2
                  General.....................................................................................    2
                  Regulation and Rates........................................................................    4
                  Rate Structure, Load Growth and Related Matters..............................................  11
                  Fuel Supply..................................................................................  12
         Enogex................................................................................................  14
         Finance and Construction..............................................................................  17
         Environmental Matters.................................................................................  18
         Employees.............................................................................................  19

Item 2.  Properties............................................................................................  20

Item 3.  Legal Proceedings.....................................................................................  21

Item 4.  Submission of Matters to a Vote of Security Holders...................................................  24

                                                       PART II

Item 5.  Market for Registrant's Common Equity and Related
                  Stockholder Matters..........................................................................  28

Item 6.  Selected Financial Data...............................................................................  29

Item 7.  Management's Discussion and Analysis of Financial
                  Condition and Results of Operations..........................................................  30

Item 8.  Financial Statements and Supplementary Data...........................................................  43

Item 9.  Changes in and Disagreements with Accountants
                  and Financial Disclosure.....................................................................  76

                                                      PART III

Item 10. Directors and Executive Officers of the Registrant....................................................  76

Item 11. Executive Compensation................................................................................  76

Item 12. Security Ownership of Certain Beneficial
                          Owners and Management................................................................  76

Item 13. Certain Relationships and Related Transactions........................................................  76

                                                       PART IV

Item 14. Exhibits, Financial Statement Schedules and
                  Reports on Form 8-K..........................................................................  76

                                                          i
</PRE>


<P ALIGN=CENTER><B>PART I</B></P>


<P ALIGN=LEFT><FONT SIZE=2><B><U>Item 1.  Business.</U></B></FONT></P>

<P ALIGN=CENTER><B>THE COMPANY</B></P>


<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE  Energy Corp.
(the "Company") is a public utility holding  company,  which was incorporated in
August 1995 in the State of Oklahoma.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Company
serves as the parent holding company to its two primary  subsidiaries,  Oklahoma
Gas and Electric Company ("OG&amp;E") and Enogex Inc. ("Enogex").</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Despite       the
continuing growth at Enogex,  the Company's  financial results and condition are
substantially  dependent at this time on the financial results and conditions of
OG&amp;E.  OG&amp;E is a regulated  public  utility  engaged in the  generation,
transmission and distribution of electricity to retail and wholesale  customers.
OG&amp;E was  incorporated in 1902 under the laws of the Oklahoma  Territory and
is the largest  electric  utility in the State of  Oklahoma.  OG&amp;E  sold its
retail gas business in 1928 and now owns and operates an interconnected electric
production,   transmission  and  distribution   system,   which  includes  eight
generating stations with a total capability of 5,781 megawatts.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Enogex  owns  and
operates  approximately  9,700 miles of natural gas  transmission  and gathering
pipelines,  has  interests in 13 gas  processing  plants,  markets  electricity,
natural  gas and  natural  gas  liquids  and  invests  in the  drilling  for and
production of crude oil and natural gas.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's
regulated  utility  business  has been  and  will  continue  to be  affected  by
competitive  changes to the utility industry.  Significant  changes already have
occurred in the wholesale  electric  markets at the Federal level.  In Oklahoma,
legislation was passed in 1997 to provide for the orderly  restructuring  of the
electric  industry with the goal to provide retail customers with the ability to
choose their electric suppliers by July 1, 2002. In April 1999,  Arkansas became
the 18th state to pass a law calling for  restructuring  of the electric utility
industry at the retail level.  The law  initially  targeted  customer  choice of
electricity  providers  by January 1, 2002,  but in February  2001,  the law was
amended to delay  customer  choice  until  October 1, 2003.  It now appears that
customer choice of electricity  suppliers may also be delayed in Oklahoma beyond
2002.  See  "Electric  Operations  -  Regulation  and Rates - Recent  Regulatory
Matters" for further discussion of these developments.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
executive offices are located at 321 North Harvey, P. O. Box 321, Oklahoma City,
Oklahoma 73101-0321; telephone (405) 553-3000.</P>



<P ALIGN=CENTER><B>ELECTRIC OPERATIONS</B></P>

<P ALIGN=LEFT><B>GENERAL</B></P>


<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E
furnishes  retail electric service in 280 communities and their contiguous rural
and suburban  areas.  During 2000, six other  communities and two rural electric
cooperatives  in  Oklahoma  and  western  Arkansas  purchased  electricity  from
OG&amp;E  for resale.  The service  area,  with an estimated  population  of 1.8
million,  covers  approximately  30,000  square  miles in  Oklahoma  and western
Arkansas;  including Oklahoma City, the largest city in Oklahoma, and Ft. Smith,
Arkansas,  the second largest city in that state. Of the 286 communities served,
257 are  located in Oklahoma  and 29 in  Arkansas.  Approximately  91 percent of
total electric  operating  revenues for the year ended  December 31, 2000,  were
derived from sales in Oklahoma and the remainder from sales in Arkansas.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's system
control area peak demand as reported by the system  dispatcher  for the year was
approximately 5,754 megawatts,  and occurred on August 29, 2000. OG&amp;E's load
responsibility peak demand was approximately 5,570 megawatts on August 29, 2000,
resulting in a capacity margin of  approximately  17.7 percent.  As reflected in
the table below and in the operating  statistics on page 3, total  kilowatt-hour
sales  increased 5.9 percent in 2000 as compared to a decrease of 2.2 percent in
1999 and a 4.2  percent  increase  in 1998.  Kilowatt-hour  sales to  OG&amp;E's
customers  ("system sales")  increased 6.5 percent due to more favorable weather
in the last six months of 2000.  Sales to other  utilities  and power  marketers
("off-system  sales")  decreased 31.5 percent,  48.6 percent and 39.5 percent in
2000, 1999 and 1998, respectively.  In 1999, total kilowatt-hour sales decreased
due to a  decrease  in system  sales and  off-system  sales,  both of which were
higher in 1998 because of the record heat experienced in the summer of 1998.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Variations     in
kilowatt-hour  sales  for  the  three  years  are  reflected  in  the  following
table:</P>
<PRE>
                                              SALES (Millions of Kwh)
                                            Inc/                            Inc/                           Inc/
                                2000       (Dec)                1999       (Dec)                1998       (Dec)
-----------------------------------------------------------------------------------------------------------------

System Sales                   25,002        6.5%              23,468       (0.7%)             23,642       6.6%
Off-System Sales                  256      (31.5%)                374      (48.6%)                728     (39.5%)
                        --------------                 ---------------                 ---------------
Total Sales                    25,258        5.9%              23,842       (2.2%)             24,370       4.2%
                        ==============                 ===============                 ===============
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E       is
subject  to  competition  in  various  degrees  from  government-owned  electric
systems, municipally owned electric systems, rural electric cooperatives and, in
certain   respects,   from  other  private   utilities,   power   marketers  and
cogenerators.  See Item 3 "Legal  Proceedings" for a further  discussion of this
matter. Oklahoma law forbids the granting of an exclusive franchise to a utility
for providing electricity.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Besides
competition from other suppliers or marketers of electricity,  OG&amp;E competes
with  suppliers  of other  forms of energy.  The degree of  competition  between
suppliers  may vary  depending on relative  costs and supplies of other forms of
energy.  See  "Electric  Operations - Regulation  and Rates - Recent  Regulatory
Matters" for a discussion of the potential  impact on  competition  from federal
and state legislation.</P><BR><BR>



<P ALIGN=CENTER><B>OKLAHOMA GAS AND ELECTRIC COMPANY<BR>
CERTAIN OPERATING STATISTICS</B></P>

<PRE>
                                                                                            Year Ended December 31

                                                                                   2000               1999               1998
                                                                            ---------------     --------------     --------------
ELECTRIC ENERGY:
  (Millions of Kwh)
  Generation (exclusive of station use)..............................               23,327             21,788             22,565
  Purchased..........................................................                3,634              3,795              3,984
                                                                            ---------------     --------------     --------------
      Total generated and purchased..................................               26,961             25,583             26,549
  Company use, free service and losses...............................               (1,703)            (1,741)            (2,179)
                                                                            ---------------     --------------     --------------
      Electric energy sold...........................................               25,258             23,842             24,370
                                                                            ---------------     --------------     --------------
ELECTRIC ENERGY SOLD:
  (Millions of Kwh)
  Residential........................................................                7,974              7,509              7,959
  Commercial and industrial..........................................               12,729             11,985             11,912
  Public street and highway lighting.................................                   70                 69                 68
  Other sales to public authorities..................................                2,458              2,354              2,352
  System sales for resale............................................                1,771              1,551              1,351
                                                                            ---------------     --------------     --------------
      Total system sales.............................................               25,002             23,468             23,642
  Off-system sales...................................................                  256                374                728
                                                                            ---------------     --------------     --------------
      Total sales....................................................               25,258             23,842             24,370
                                                                            ===============     ==============     ==============
ELECTRIC OPERATING REVENUES:
 (Thousands)
  Electric Revenues:
    Residential......................................................       $      575,656      $     515,299      $     537,486
    Commercial and industrial........................................              643,576            557,884            554,589
    Public street and highway lighting...............................               10,301              9,736              9,618
    Other sales to public authorities................................              124,217            108,159            110,522
    System sales for resale..........................................               58,117             42,918             38,763
                                                                            ---------------     --------------     --------------
      Total system sales.............................................            1,411,867          1,233,996          1,250,978
    Off-system sales.................................................               12,948             27,894             37,435
                                                                            ---------------     --------------     --------------
      Total Electric Revenues........................................            1,424,815          1,261,890          1,288,413
    Miscellaneous....................................................               28,770             24,954             23,665
                                                                            ---------------     --------------     --------------
      Total Operating Revenues.......................................       $    1,453,585      $   1,286,844      $   1,312,078
                                                                            ===============     ==============     ==============
NUMBER OF ELECTRIC CUSTOMERS:
 (At end of period)
  Residential........................................................              603,826            599,702            598,378
  Commercial and industrial..........................................               86,659             86,837             86,251
  Public street and highway lighting.................................                  364                249                249
  Other sales to public authorities..................................               11,501             11,151             11,183
  Sales for resale...................................................                   52                 56                 39
                                                                            ---------------     --------------     --------------
      Total..........................................................              702,402            697,995            696,100
                                                                            ===============     ==============     ==============
RESIDENTIAL ELECTRIC SERVICE:
  Average annual use (Kwh)...........................................               13,264             12,546             13,342
  Average annual revenue.............................................       $       957.54      $      860.98      $      900.94
  Average price per Kwh (cents)......................................                 7.22               6.86               6.75
</PRE>

<P ALIGN=LEFT><B>REGULATION AND RATES</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's retail
electric  tariffs  in  Oklahoma  are  regulated  by  the  Oklahoma   Corporation
Commission  ("OCC"),  and in Arkansas by the Arkansas Public Service  Commission
("APSC").  The issuance of certain  securities by OG&amp;E is also  regulated by
the  OCC  and  the  APSC.  OG&amp;E's  wholesale  electric  tariffs,  short-term
borrowing authorization and accounting practices are subject to the jurisdiction
of the Federal  Energy  Regulatory  Commission  ("FERC").  The  Secretary of the
Department of Energy has  jurisdiction  over some of OG&amp;E's  facilities  and
operations.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As  part  of  the
corporate  reorganization  whereby the Company became the holding company parent
of  OG&amp;E,  OG&amp;E  obtained  the approval of the OCC. The order of the OCC
authorizing  OG&amp;E to reorganize  into a holding company  structure  contains
certain provisions which, among other things, ensure the OCC access to the books
and records of the  Company and its  affiliates  relating to  transactions  with
OG&amp;E;  require the Company and its  subsidiaries  to employ  accounting  and
other  procedures and controls to protect against  subsidization  of non-utility
activities  by  OG&amp;E's  customers;  and prohibit  the Company from  pledging
OG&amp;E assets or income for affiliate transactions.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;For    the   year
ended December 31, 2000, approximately 88 percent of OG&amp;E's electric revenue
was subject to the  jurisdiction of the OCC, seven percent to the APSC, and five
percent to the FERC.</P>

<P ALIGN=LEFT><B>Recent Regulatory Matters</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   January  12,
2000, the OCC Staff (the "Staff") filed three  applications  to address  various
aspects of  OG&amp;E's  electric  rates.  The first  application  related to the
completion on March 1, 2000, of the recovery of the amortization premium paid by
OG&amp;E when it acquired Enogex in 1986 and the resulting removal,  pursuant to
the  Acquisition  Premium  Credit Rider ("APC  Rider"),  of $12.8 million ($10.7
million  in the  Oklahoma  Jurisdiction)  from the  amount  being  recovered  by
OG&amp;E  from  its  customers  through  currently  authorized  electric  rates.
OG&amp;E  consented  to this action and in March 2000,  the OCC approved the APC
Rider for $10.7 million annually.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The        second
application related to a review of the Generation  Efficiency  Performance Rider
("GEP  Rider"),  which,  as part of the OCC's order issued in 1997 in connection
with OG&amp;E's  last general rate review (the "1997 Order"),  was scheduled for
review in March 2000. OG&amp;E collected  approximately $9.9 million pursuant to
the GEP Rider during  2000.  The GEP Rider  initially  was designed so that when
OG&amp;E's  average  annual cost of fuel per kwh was less than 96.261 percent of
the  average  non-nuclear  fuel  cost per kwh of  certain  other  investor-owned
utilities in the region, OG&amp;E was allowed to collect, through the GEP Rider,
one-third  of the amount by which  OG&amp;E's  average  annual  cost of fuel was
below  96.261  percent  of the  average  of the other  specified  utilities.  If
OG&amp;E's fuel cost exceeded  103.739  percent of the stated average,  OG&amp;E
was not allowed to recover  one-third  of the fuel costs above that average from
Oklahoma  customers.  In April  2000  testimony,  the  Staff  stated  that  they
continued to support incentive programs that reward superior performance, but in
their view the existing  GEP Rider was not  functioning  as they had  originally
envisioned it.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In June 2000, the
OCC approved the  collection of $6.6 million  through the GEP Rider for the time
period  July 1, 2000  through  June 30, 2001 and  approved  the  following  four
modifications  to the GEP Rider:  (i) changing  OG&amp;E's peer group to include
utilities with a higher coal-to-gas  generation mix; (ii) reducing the amount of
fuel costs that can be recovered if  OG&amp;E's  costs exceed the new peer group
by changing the  percentage  above which OG&amp;E will not be allowed to recover
one-third of the fuel costs from  Oklahoma  customers  from  103.739  percent to
101.0 percent;  (iii) reducing  OG&amp;E's  share of cost savings as compared to
its new peer group from 33 percent to 30  percent;  and (iv)  limiting  to $10.0
million  the amount of any  awards  paid to  OG&amp;E  or  penalties  charged to
OG&amp;E.  The GEP  Rider  is to be  revised  effective  July 1 of each  year to
reflect  changes in the relative  annual cost of fuel reported for the preceding
calendar year.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The         final
application,  relating to fuel cost recoveries, was used by the Staff to address
the competitive bid process of OG&amp;E's gas transportation  needs. In the 1997
Order,  the OCC approved a  stipulation  wherein  OG&amp;E  agreed to initiate a
competitive  bidding  process for gas  transportation  service to its  gas-fired
plants,  with the competitive  services commencing no later than April 30, 2000.
The 1997 Order  also set annual  compensation  for the  transportation  services
provided by Enogex to OG&amp;E at $41.3 million annually until March 1, 2000, at
which time the rate would drop to $28.5 million  (reflecting  removal of the APC
Rider,  upon the completion of the recovery from  customers of the  amortization
premium  paid by OG&amp;E  when it  acquired  Enogex in 1986) and remain at that
level until  competitively-bid  gas  transportation  began. Final firm bids were
submitted  by  Enogex  and other  pipelines  on April 15,  1999.  In July  1999,
OG&amp;E   filed  an  application   with  the  OCC  requesting   approval  of  a
performance-based  rate plan for its Oklahoma  retail  customers from April 2000
until the  introduction  of customer  choice for electric power in July 2002. As
part of this  application,  OG&amp;E  stated that Enogex had  submitted the only
viable bid ($33.4  million per year) for gas  transportation  to OG&amp;E's  six
gas-fired power plants that were the subject of the competitive  bid. As part of
its application to the OCC, OG&amp;E offered to discount Enogex's bid from $33.4
million   annually  to  $25.2  million   annually.   OG&amp;E   executed  a  gas
transportation  contract  with Enogex under which Enogex  continues to serve the
needs of  OG&amp;E's  power  plants at a price to be paid by  OG&amp;E  of $33.4
million  annually  and, if  OG&amp;E's  proposal  had been  approved by the OCC,
OG&amp;E would have recovered a portion of such amount ($25.2  million) from its
customers.  OG&amp;E  negotiated  with the  Staff,  the  Office of the  Oklahoma
Attorney General and a coalition of industrial  customers in an effort to settle
all  issues  (including  the  competitive  bid  process)   associated  with  its
application for a performance-based  rate plan. When these negotiations  failed,
OG&amp;E  withdrew its application,  which withdrawal was approved by the OCC in
December 1999.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In   July   2000,
OG&amp;E  entered into a stipulation  (the  "Stipulation")  with the Staff,  the
Office of the Attorney General and a coalition of industrial customers regarding
the  competitive  bid process of  OG&amp;E's  gas  transportation  service.  The
Stipulation  (which,  with one  exception,  was  signed  by all  parties  to the
proceeding)  would permit  OG&amp;E to recover  $25.2  million  annually for gas
transportation services to be provided by Enogex pursuant to the competitive bid
process.  The  Stipulation was presented for approval to an  Administrative  Law
Judge ("ALJ") in September 2000, and the ALJ recommended its approval.  However,
at a  hearing  on  September  28,  2000,  the OCC  chose to delay  the  decision
concerning the Stipulation and two of the three commissioners  expressed concern
over the  competitive  bid process.  OG&amp;E cannot predict what further action
the OCC may  take.  OG&amp;E  believes  that the  competitive  bid  process  was
appropriate and is currently collecting $28.5 million on an annual basis through
its base rates and APC Rider for gas transportation services from Enogex for the
power plant requirements covered by the competitive bid.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On  February  13,
1998, the APSC staff filed a motion for a show cause order to review  OG&amp;E's
electric  rates in the State of Arkansas.  The Staff  recommended a $3.1 million
annual rate reduction  (based on a test year ended December 31, 1996). The Staff
and OG&amp;E  reached a settlement  for a $2.3  million  annual rate  reduction,
which was approved by the APSC in August 1999.</P>

<P ALIGN=LEFT><B>State Restructuring Initiatives</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<B>Oklahoma:</B>
&nbsp;&nbsp;As previously reported,  Oklahoma enacted in April 1997 the Electric
Restructuring Act of 1997 (the "Act") which is designed to provide for choice by
retail  customers of their electric  supplier by July 1, 2002. In 1998 and 1999,
various amendments to the Act were enacted.  Additional implementing legislation
needs to be adopted by the Oklahoma  Legislature to address many specific issues
associated with the Act and  deregulation.  If implemented as proposed,  the Act
will significantly affect OG&amp;E's future operations. The following summary of
the  Act  does  not  purport  to be  complete  and is  subject  to the  specific
provisions of the Act,  which is codified at Sections 190.2 et. seq. of Title 17
of the Oklahoma Statutes.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  Act consists
of eight  sections,  with Section 1 designating  the name of the Act.  Section 2
describes  the  purposes  of the Act,  which is  generally  to  restructure  the
electric industry to provide for more competition and, in particular, to provide
for the orderly  restructuring  of the electric utility industry in the State of
Oklahoma in order to allow direct access by retail  consumers to the competitive
market  for the  generation  of  electricity  while  maintaining  the safety and
reliability of the electric system in the state.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The primary goals
of a restructured  electric utility  industry,  as set forth in Section 2 of the
Act, are as follows:</P>
<OL>
<LI>To reduce the cost of electricity for as many consumers as possible, helping
industry to be more competitive, to create more jobs in Oklahoma and help lower
the cost of government by reducing the amount and type of regulation now paid
for by taxpayers;<BR><BR>

<LI>To encourage the development of a competitive  electricity  industry through
the unbundling of prices and services and separation of generation services from
transmission and distribution services;<BR><BR>

<LI>To enable retail electric  energy  suppliers to engage in fair and equitable
competition  through  open,  equal and  comparable  access to  transmission  and
distribution systems and to avoid wasteful duplication of facilities;<BR><BR>

<LI>To ensure that direct access by retail  consumers to the competitive  market
for generation be implemented in Oklahoma by July 1, 2002; and<BR><BR>

<LI>To  ensure  that proper  standards  of safety,  reliability  and service are
maintained in a restructured electric service industry.<BR><BR>
</OL>
<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Section  3 of the
Act sets forth various  definitions  and exempts in large part several  electric
cooperatives and  municipalities  from the Act unless they choose to be governed
by it.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Sections 4, 5 and
6 of the Act are  designed  to  implement  the goals of the Act and  provide for
various studies and task forces to assess the issues and consequences associated
with the proposed  restructuring of the electric utility industry. In Section 4,
the Joint  Electric  Utility  Task  Force (the  "Joint  Task  Force"),  which is
described  below,  was  directed  to  undertake a study of all  relevant  issues
relating to restructuring  the electric utility industry in Oklahoma  including,
but not limited to, the issues set forth in Section 4, and to develop a proposed
electric utility framework for Oklahoma. The OCC is prohibited from promulgating
orders relating to the restructuring without prior authorization of the Oklahoma
Legislature. Also, in developing a framework for a restructured electric utility
industry,  the OCC is to adhere to fourteen  principles  set forth in Section 4,
including the following:</P>
<OL>
<LI>Appropriate  rules shall be  promulgated,  ensuring  that  reliable and safe
electric service is maintained.<BR><BR>

<LI>Consumers  shall be allowed to choose among retail electric energy suppliers
to  help  ensure  competitive  and  innovative  markets.  A  process  should  be
established  whereby all retail  consumers  are permitted to choose their retail
electric energy suppliers by July 1, 2002.<BR><BR>

<LI>When  consumer  choice is  introduced,  rates shall be  unbundled to provide
clear price  information  on the  components  of  generation,  transmission  and
distribution  and any  other  ancillary  charges.  Charges  for  public  benefit
programs currently authorized by statute or the OCC, or both, shall be unbundled
and  appear  in  line  item  format  on  electric   bills  for  all  classes  of
consumers.<BR><BR>

<LI>An  entity  providing   distribution  services  shall  be  relieved  of  its
traditional  obligation to provide  electric  supply but shall have a continuing
obligation  to provide  distribution  service for all  consumers  in its service
territory.<BR><BR>

<LI>The  benefits  associated with  implementing an independent  system planning
committee  composed  of owners of electric  distribution  systems to develop and
maintain planning and reliability criteria for distribution  facilities shall be
evaluated.<BR><BR>

<LI>A defined  period for the  transition  to a  restructured  electric  utility
industry shall be  established.  The transition  period shall reflect a suitable
time frame for full compliance with the  requirements of a restructured  utility
industry.<BR><BR>

<LI>Electric  rates for all consumer classes shall not rise above current levels
throughout the transition period. If possible,  electric rates for all consumers
shall  be  lowered  when  feasible  as  markets   become  more  efficient  in  a
restructured industry.<BR><BR>

<LI>The OCC shall consider the establishment of a distribution  access fee to be
assessed to all consumers in Oklahoma connected to electric distribution systems
regulated by the OCC. This fee shall be charged to cover social  costs,  capital
costs,  operating  costs,  and  other  appropriate  costs  associated  with  the
operation  of  electric  distribution  systems  and the  provision  of  electric
services to the retail consumer.<BR><BR>

<LI>Electric  utilities have  traditionally had an obligation to provide service
to consumers within their established  service territories and have entered into
contracts,  long-term investments and federally mandated cogeneration  contracts
to meet the needs of consumers. These investments and contracts have resulted in
costs that may not be recoverable in a competitive  restructured market and thus
may be &#147;stranded.&#148; Procedures shall be established for identifying and
quantifying  stranded investments and for allocating costs; and mechanisms shall
be  proposed  for  recovery  of an  appropriate  amount of  prudently  incurred,
unmitigable  and  verifiable  stranded  costs and  investments.  As part of this
process,  each  entity  shall be  required  to  propose a  recovery  plan  which
establishes its unmitigable and verifiable  stranded costs and investments and a
limited recovery period designed to recover such costs  expeditiously,  provided
that the  recovery  period and the amount of  qualified  transition  costs shall
yield a  transition  charge  which shall not cause the total price for  electric
power,  including  transmission and distribution  services,  for any consumer to
exceed the cost per kilowatt-hour  paid on the effective date of this Act during
the transition  period.  The transition charge shall be applied to all consumers
including  direct  access  consumers,  and shall not  disadvantage  one class of
consumer or supplier over another, nor impede competition and shall be allocated
over a period  of not  less  than  three  (3)  years  nor more  than  seven  (7)
years.<BR><BR>

<LI>It is the intent that all  transition  costs shall be recovered by virtue of
the savings  generated by the increased  efficiency in markets  brought about by
restructuring of the electric utility  industry.  All classes of consumers shall
share in the transition costs.<BR><BR>
</OL>
<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Subject   to  the
principles  set forth in Section 4, the Joint Task Force was directed to prepare
a four-part  study.  This study,  which was  completed in 1999,  addressed:  (i)
technical  issues  (including  reliability,  safety,  unbundling of  generation,
transmission and  distribution  services,  transition  issues and market power);
(ii) financial issues (including rates,  charges,  access fees, transition costs
and stranded  costs);  (iii)  consumer  issues (such as the obligation to serve,
service territories, consumer choices, competition and consumer safeguards); and
(iv) tax issues  (including  sales and use taxes, ad valorem taxes and franchise
fees).</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Section  5 of the
Act  directed the Joint Task Force to study and submit a report on the impact of
the restructuring of the electric utility industry on state tax revenues and all
other facets of the current utility tax structure on the state and all political
subdivisions  of the state.  This study also was completed in 1999. The Oklahoma
Tax  Commission and the OCC are precluded from issuing any rules on such matters
without the approval of the  Oklahoma  Legislature.  Also,  the Act requires the
establishment,  on or before  July 1, 2002,  of a uniform tax policy that allows
all competitors to be taxed on a fair and equitable basis.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Section 6 created
the Joint Task Force,  which consisted of seven members from the Oklahoma Senate
and seven  members from the Oklahoma  House of  Representatives.  The Joint Task
Force was directed to undertake the studies set forth in Sections 4 and 5 of the
Act.  The Joint Task Force is  permitted  to make final  recommendations  to the
Governor and  Oklahoma  Legislature.  The Joint Task Force is also  empowered to
retain  consultants  to study the creation of an  Independent  System  Operator,
which would  coordinate the physical supply of electricity  throughout  Oklahoma
and maintain  reliability,  security and stability of the bulk power system.  In
addition,  such study shall assess the benefits of establishing a power exchange
that would operate as a power pool allowing power producers to compete on common
ground in Oklahoma.  In fulfilling  its tasks,  the Joint Task Force can appoint
advisory  councils  made  up  of  electric  utilities,  regulators,  residential
customers and other constituencies.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Section         7
provides  generally that, with respect to electric  distribution  providers,  no
customer switching will be allowed from the effective date of the Act until July
1, 2002,  except by mutual consent.  It also provides that any municipality that
fails to become subject to the Act will be prohibited from selling power outside
its municipal limits,  except from lines owned on the effective date of the Act.
Furthermore,  this section  provides  generally that  out-of-state  suppliers of
electricity  and  their  affiliates  who make  retail  sales of  electricity  in
Oklahoma,  through  the  use of  transmission  and  distribution  facilities  of
in-state  suppliers,  must  provide  equal  access  to  their  transmission  and
distribution facilities outside of Oklahoma.  Section 8 sets forth the effective
date of the Act as April 25, 1997.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The    Act    was
modified during the 1999 session of the Oklahoma  Legislature to clarify certain
ambiguities by defining key terms in the Act.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Additional
implementing  legislation  needs to be adopted by the  Oklahoma  Legislature  to
address many specific issues associated with the Act and with  deregulation.  In
May 2000, a bill addressing the specific  issues of  deregulation  was passed in
the  Oklahoma  State  Senate  and then was  defeated  in the  Oklahoma  House of
Representatives.  OG&amp;E  cannot  predict  what, if any,  legislation  will be
adopted  at the  next  legislative  session.  OG&amp;E  intends  to  participate
actively in the  legislative  process and expects the  scheduled  start date for
customer choice of July 1, 2002 to be postponed.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The    OCC    has
adopted  rules that are  designed to make the gas  utility  business in Oklahoma
more  competitive.  These  rules do not impact the  electric  industry.  Yet, if
implemented, the rules are expected to offer increased opportunities to Enogex's
pipeline and related businesses.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<B>Arkansas:
&nbsp;&nbsp;</B>In  April  1999,  Arkansas  became  the 18th state to pass a law
("the  Restructuring  Law") calling for  restructuring  of the electric  utility
industry at the retail  level.  The  Restructuring  Law,  like the Oklahoma law,
would  significantly  affect OG&amp;E's future operations.  OG&amp;E's  electric
service area  includes  parts of western  Arkansas,  including  Fort Smith,  the
second-largest metropolitan market in the state. The Restructuring Law initially
targeted  customer  choice of  electricity  providers  by January  1,  2002.  In
February 2001, the law was amended to delay the start date of customer choice of
electric  providers  in  Arkansas  until  October 1, 2003,  with the APSC having
discretion to further delay implementation to October 1, 2005. The Restructuring
Law also provides that utilities owning or controlling  transmission assets must
transfer control of such transmission  assets to an independent system operator,
independent  transmission  company or regional  transmission  group, if any such
organization   has  been  approved  by  the  FERC.   Other   provisions  of  the
Restructuring  Law permit  municipal  electric  systems to opt in or out, permit
recovery of stranded costs and transition  costs and require filing of unbundled
rates for generation, transmission,  distribution and customer service. OG&amp;E
filed preliminary business separation plans with the APSC on August 8, 2000. The
APSC has  established a timetable to establish rules  implementing  the Arkansas
restructuring statutes.</P>

<P ALIGN=LEFT><B>Automatic Fuel Adjustment Clauses</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Variances  in the
actual cost of fuel used in electric  generation  and  certain  purchased  power
costs,  as compared to that component in  cost-of-service  for  ratemaking,  are
charged to substantially all of OG&amp;E's  electric customers through automatic
fuel  adjustment  clauses,  which are subject to periodic review by the OCC, the
APSC and the  FERC.  In March  2000,  the OCC  approved  the APC Rider for $10.7
million  annually.  As  previously  discussed,  the  purpose of this rider is to
credit the Oklahoma  retail  customers for the  completion of the OCC authorized
recovery of the premium paid by OG&amp;E  when it acquired  Enogex in 1986.  The
APC  Rider  is  applicable  to each  Oklahoma  retail  rate  schedule  to  which
OG&amp;E's fuel cost adjustment clause applies.</P>

<P ALIGN=LEFT><B>National Energy Legislation</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Federal       law
imposes  numerous  responsibilities  and  requirements  on OG&amp;E.  The Public
Utility  Regulatory  Policies Act of 1978 requires electric  utilities,  such as
OG&amp;E, to purchase electric power from, and sell electric power to, qualified
cogeneration facilities and small power production facilities ("QFs"). Generally
stated, electric utilities must purchase electric energy and production capacity
made available by QFs at a rate reflecting the cost that the purchasing  utility
can avoid as a result of obtaining  energy and  production  capacity  from these
sources;  rather  than  generating  an  equivalent  amount of  energy  itself or
purchasing  the energy or capacity  from other  suppliers.  OG&amp;E has entered
into  agreements  with  four such  cogenerators.  Electric  utilities  also must
furnish electric energy to QFs on a  non-discriminatory  basis at a rate that is
just and reasonable and in the public interest and must provide certain types of
service which may be requested by QFs to supplement or back up those facilities'
own generation.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The Energy Policy
Act of 1992  ("Energy  Act") among other  things,  authorized  the FERC to order
transmitting utilities to provide transmission services to any electric utility,
Federal power marketing agency,  or any other person generating  electric energy
for sale or resale,  at transmission  rates set by the FERC. The Energy Act also
was  designed to promote  competition  in the  development  of  wholesale  power
generation in the electric industry.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Subsequently,
FERC issued Order 888 and Order 889 to facilitate third-party utilization of the
transmission  grid as the vehicle for  developing a more  competitive  wholesale
bulk power  market.  Order 888  requires  all  transmission  owners to (i) offer
comparable  open-access  transmission service for wholesale transactions under a
tariff  of  general  applicability  on file at FERC and (ii)  take  transmission
service for their own wholesale sales under their open-access tariff.  Order 889
requires  electric  utilities to functionally  separate their  transmission  and
reliability functions from their wholesale power marketing functions.  Order 889
also  required  electric  utilities  to  develop  and  maintain  an Open  Access
Same-Time  Information  System ("OASIS") to ensure that  transmission  customers
have access to transmission  information,  through  electronic  means, that will
enable them to obtain open-access  transmission service on a basis comparable to
a transmitting utility's own use of its system.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In December 1999,
FERC  issued  Order 2000 to  advance  the  formation  of  Regional  Transmission
Organizations  ("RTO").  The rule requires  that each public  utility that owns,
operates or  controls  facilities  for the  transmission  of electric  energy in
interstate commerce file by October 15, 2000, a proposal with respect to forming
and participating in an RTO. The FERC also codified minimum  characteristics and
functions that a  transmission  entity must satisfy in order to be considered an
RTO.  OG&amp;E is a member of the  Southwest  Power Pool  ("SPP"),  the regional
reliability organization for Oklahoma, Arkansas, Kansas, Louisiana, Missouri and
part of Texas. OG&amp;E participated with the SPP in the development of regional
transmission tariffs and executed an Agency Agreement with the SPP to facilitate
interstate  transmission operations within this region. In October 2000, the SPP
filed its application  with the FERC to become a RTO.  OG&amp;E  intends to meet
its obligation under Order 2000 and under the  restructuring  law in Arkansas by
joining the RTO being formed by the SPP. The transfer of operational  control of
OG&amp;E's  transmission  system  to a  FERC-approved  RTO  is not  expected  to
significantly  impact  OG&amp;E's  financial  results.  Yet,  it is  expected to
increase the markets in which  OG&amp;E can sell power at wholesale  and, at the
same time, to increase  competition  in such  wholesale  markets.  As a low-cost
producer  of  electricity  with two of the most  efficient  power  plants in the
country, OG&amp;E expects to remain a competitive supplier of electricity.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Another impact of
complying  with  FERC's  Order 888 is a  requirement  for  utilities  to offer a
transmission  tariff  that  includes  network  transmission  service  ("NTS") to
transmission  customers.  NTS allows  transmission  service  customers  to fully
integrate load and resources on an  instantaneous  basis, in a manner similar to
how OG&amp;E has  historically  integrated  its load and  resources.  Under NTS,
OG&amp;E and  participating  customers share the total annual  transmission cost
for their combined  joint-use  systems,  net of related  transmission  revenues,
based upon each  company's  share of the total system load.  Management  expects
minimal annual expenses as a result of Orders 888 and 889.</P>

<P ALIGN=LEFT><B>Regulatory Assets and Liabilities</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As      discussed
previously,  Oklahoma and Arkansas enacted legislation that will restructure the
electric utility  industry in those states,  assuming that all the conditions in
the legislation are met. This legislation would deregulate  OG&amp;E's  electric
generation  assets and the  continued  use of Statement of Financial  Accounting
Standards  ("SFAS")  No. 71,  "Accounting  for the  Effects of Certain  Types of
Regulation",  with  respect to the  related  regulatory  assets may no longer be
appropriate.  This may  result in either  full  recovery  of  generation-related
regulatory assets (net of related regulatory liabilities) or a non-cash, pre-tax
write-off  as an  extraordinary  charge of up to $29  million,  depending on the
transition  mechanisms developed by the legislature for the recovery of all or a
portion of these net regulatory assets.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       enacted
Oklahoma  and  Arkansas   legislation  does  not  affect   OG&amp;E's   electric
transmission  and distribution  assets and OG&amp;E  believes that the continued
use of SFAS No. 71 with respect to the related regulatory assets is appropriate.
However, if utility regulators in Oklahoma and Arkansas were to adopt regulatory
methodologies in the future that are not based on cost-of-service, the continued
use of SFAS No. 71 with respect to the regulatory assets related to the electric
transmission and distribution assets may no longer be appropriate.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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.</P>

<P ALIGN=LEFT><B>Summary</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  Energy  Act,
the actions of the FERC, the restructuring legislation in Oklahoma and Arkansas,
and other  factors are expected to  significantly  increase  competition  in the
electric  industry.  OG&amp;E  has taken  steps in the past and  intends to take
appropriate steps in the future to remain a competitive supplier of electricity.
While  OG&amp;E is  supportive  of  competition,  it believes  that all electric
suppliers must be required to compete on a fair and equitable basis and OG&amp;E
is advocating this position vigorously.</P><BR>


<P ALIGN=LEFT><B>RATE STRUCTURE, LOAD GROWTH AND<BR>
RELATED MATTERS</B></P><BR>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Two of OG&amp;E's
primary goals are: (i) to increase electric revenues by attracting and expanding
job-producing businesses and industries; and (ii) to encourage the efficient use
of  electrical  energy by all of  OG&amp;E's  customers.  In order to meet these
goals, OG&amp;E has reduced and restructured its rates to its customers.  At the
same time,  OG&amp;E had  implemented  numerous energy  efficiency  programs and
tariff  schedules.  In 2000,  these  programs and  schedules  included:  (i) the
"Surprise  Free  Guarantee"  program,  which  guarantees  residential  customers
comfort and annual energy consumption for heating, cooling and water heating for
new homes built to energy efficient standards;  (ii) a load curtailment rate for
industrial and commercial customers who can demonstrate a load curtailment of at
least 500  kilowatts;  and (iii) the  time-of-use  rate  schedules  for  various
commercial,  industrial and residential customers designed to shift energy usage
from peak demand periods during the hot summer afternoon to non-peak hours.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E made its
pilot Real Time Pricing ("RTP") program permanent in 1999. The program was first
implemented in 1996 for qualifying  industrial  and commercial  customers.  This
tariff gives customers  additional options on total kilowatt-hour growth and the
control  of  growth  of  peak  demand.  RTP is a  tariff  option,  which  prices
electricity so that the current price varies hourly with short notice to reflect
current  expected  costs.  The RTP technique will allow a measure of competitive
pricing, a broadening of customer choice, the balancing of electricity usage and
capacity in the short-and  long-term,  and assist customers in controlling their
costs.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's   2000
marketing efforts included geothermal heat pumps, electrotechnologies,  electric
food service promotion and a heat pump promotion in the residential,  commercial
and  industrial  markets.  OG&amp;E works closely with  individual  customers to
provide the best  information on how current  technologies  can be combined with
OG&amp;E's marketing programs to maximize the customer's benefit.</P>

<P ALIGN=LEFT><B>FUEL SUPPLY</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;During      2000,
approximately  74  percent of the  OG&amp;E-generated  energy  was  produced  by
coal-fired units and 26 percent by natural  gas-fired units. A slight decline in
the  percentage  of coal  generation  in future years is expected to result from
increases in natural gas-fired  generation required to meet growing energy needs
while coal generation will remain fairly constant. Over the last five years, the
average cost of fuel used, by type, per million Btu was as follows:</P>
<PRE>
                                         2000          1999          1998          1997           1996
--------------------------------------------------------------------------------------------------------
Coal............................        $0.87         $0.85         $0.85          $0.84          $0.83
Natural Gas.....................        $4.93         $3.14         $2.83          $3.60          $3.61
Weighted Avg....................        $1.96         $1.54         $1.48          $1.39          $1.45
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;A  portion of the
fuel cost is  included  in base rates and  differs  for each  jurisdiction.  The
portion of these costs that is not included in base rates is  recovered  through
automatic fuel  adjustment  clauses.  See "Electric  Operations - Regulation and
Rates - Automatic Fuel Adjustment Clauses."</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<U><B>Coal-Fired
Units:</B></U>  All OG&amp;E coal units,  with an aggregate  capability of 2,531
megawatts, are designed to burn low sulfur western coal. OG&amp;E purchases coal
primarily  under  long-term  contracts.  During 2000,  OG&amp;E  purchased  10.2
million tons of coal from the  following  Wyoming  suppliers:  Kennecott  Energy
Company,  Thunder Basin Coal Company, Powder River Coal Company, and Triton Coal
Company.  The  combination of all coal has a weighted  average sulfur content of
0.3 percent and can be burned in these units under existing  federal,  state and
local  environmental  standards  (maximum  of 1.2 pounds of sulfur  dioxide  per
million Btu) without the addition of sulfur dioxide removal systems.  Based upon
the average sulfur content,  OG&amp;E units have an approximate emission rate of
0.63  pounds of sulfur  dioxide per million  Btu.  In  anticipation  of the more
strict  provisions  of Phase II of The  Clean Air Act,  which  began in the year
2000,  OG&amp;E had  contracts in place to allow for a supply of very low sulfur
coal from  suppliers  in the Powder  River Basin to meet the new sulfur  dioxide
standards.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E      has
continued  its  efforts  to  maximize  the  utilization  of its  coal  units  by
optimizing  the boiler  operations  at both the Sooner and  Muskogee  generating
plants.  See  "Environmental  Matters"  for a  discussion  of  an  environmental
proposal that, if implemented as proposed,  could inhibit  OG&amp;E's ability to
use coal as its primary boiler fuel.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<U><B>Gas-Fired
Units:</B></U> For calendar year 2001, OG&amp;E utilized a Request for Bid (RFB)
to acquire natural gas supplies through June 2002. Successful bids were accepted
that  are  expected  to  supply  approximately  38%  of  OG&amp;E's  annual  gas
requirements. OG&amp;E will request bids for additional summer gas supplies. The
additional  gas  requirements  will be secured  through  monthly and  day-to-day
purchases as needed.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In 1993, OG&amp;E
began utilizing a natural gas storage facility, that allows OG&amp;E to optimize
economic  dispatch of its units.  This allows OG&amp;E to attain a fuel mix that
provides the lowest possible overall cost of fuel.</P><BR>



<P ALIGN=CENTER><B>ENOGEX</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
wholly-owned  non-utility  subsidiary,  Enogex Inc.  is an  Oklahoma  intrastate
natural gas  pipeline,  which also  conducts  operations  in related  businesses
through subsidiary companies. These businesses include gas processing operations
and natural gas liquids marketing ("Gas Processing"); exploration and production
of oil and natural gas ("Exploration and Production"); marketing of natural gas,
natural gas liquids,  and electricity  ("Marketing");  and the gas gathering and
interstate gas transmission operations ("Gas Transportation").</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;For    the   year
ended December 31, 2000, and before  elimination of  intercompany  items between
OG&amp;E  and  Enogex,  Enogex's  consolidated  revenues  and  net  income  were
approximately $2.1 billion and $19.7 million, respectively.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<U>Recent
Actions:</U> In July 2000,  Enogex entered into a new contract with OG&amp;E for
new gas  transportation  service  not  covered  by the  $33.4  million  contract
executed in October 1999 that resulted from the competitive bidding process.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Enogex  plans  to
diversify its revenue and income  sources by increasing  revenues and net income
from transmission services provided to third parties, by increasing the revenues
and net income from Enogex  subsidiaries'  natural gas gathering and processing,
by continuing  development and production  operations around our systems, and by
actively  pursuing  potential   acquisitions  of  complementary   businesses  or
assets.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  fees charged
by Ozark Pipeline ("Ozark") and by NOARK Pipeline Systems, L.P. ("NOARK") second
interstate pipeline, Arkansas Western Pipeline ("AWP") are subject to regulation
by the FERC. AWP is an eight-mile  pipeline  segment crossing the border between
eastern  Arkansas  and  Missouri.  Ozark filed a general  rate case  pursuant to
Section 4 of the  Natural Gas Act in April  2000,  seeking to increase  its base
rates for  transportation  services.  The rate case was resolved by  settlement,
which was  approved by the FERC in December  2000 for rates  effective  November
2000. The newly approved  maximum lawful rate for Ozark and NOARK is $0.2867 per
mmbtu. As a condition of the settlement  Ozark rolled the existing AWP rate into
the newly approved Ozark rate.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<U>Gas
Transportation.</U>One   of   Enogex's   primary   lines  of   business  is  the
transportation  of natural gas,  which  includes both  interstate and intrastate
transportation  along with natural gas gathering.  This business is conducted by
Enogex  and  several  of its  subsidiaries  in  Oklahoma,  Arkansas  and  Texas.
Interruptible   transportation   service  is  offered  to  most  interstate  and
intrastate pipelines and end-users connected to Enogex's systems. Enogex and its
subsidiaries  operate  approximately  9,700  miles of  pipeline  that gather and
transport  gas from the  Arkoma  basin of eastern  Oklahoma  and  Arkansas,  the
Anadarko basin of western Oklahoma and the Permian basin of West Texas.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In   July   1999,
Enogex acquired Transok Holding LLC ("Transok"). Transok was established in 1955
to transport boiler fuel to the gas-powered  electric  generating  facilities of
Public  Service  Company of Oklahoma  ("PSO").  PSO, a subsidiary of Central and
South West  Corporation,  is the second  largest  electric  utility in Oklahoma,
serving the Tulsa market.  Transok was acquired by PSO in 1961 and  maintained a
sole-supplier  relationship with PSO until 1998, when ONG began supplying gas to
three of the PSO generating  stations  pursuant to a competitive bid process put
in place by the OCC.  Notwithstanding the loss of the sole-supplier  status, PSO
remains an  important  customer of  Transok.  Transok  continues  to provide gas
transmission  delivery services to all of PSO's gas-fueled  electric  generation
units in Oklahoma under a firm intrastate  transportation  contract. The current
contract,  which expires  January 1, 2003,  provides for a monthly demand charge
plus a variable  transportation  rate depending on the origins of the gas supply
being  transported.  In addition,  Transok provides straight fee  transportation
services to West Texas Utilities ("WTU"),  an affiliate of PSO, for gas delivery
service  to certain  WTU  generating  stations  in the Texas  Panhandle  under a
contract that expires on December 31, 2004. In 2000, Transok's revenues from the
PSO and WTU contracts were $10.2 million and $2.5 million respectively.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The rates charged
by Enogex and Transok for  transporting  natural gas on behalf of an  interstate
natural  gas  pipeline  company  or a local  distribution  company  served by an
interstate  natural gas pipeline company are subject to the jurisdiction of FERC
under Section 311 of the Natural Gas Policy Act. The statute entitles Enogex and
Transok  to charge a "fair and  equitable"  rate that is  subject  to review and
approval  by the FERC at least  once every  three  years.  This rate  review may
involve an administrative-type  trial and an administrative appellate review. In
addition, Enogex and Transok have agreed to open their systems to all interstate
shippers that are  interested in  transporting  natural gas through the systems.
Enogex  and  Transok  are   required  to  conduct  this   transportation   on  a
non-discriminatory  basis,  although this  transportation is subordinate to that
performed for OG&amp;E and PSO. This decision does not increase  appreciably the
federal  regulatory  burden on Enogex  and  Transok,  but does give  Enogex  and
Transok the opportunity to utilize any unused capacity on an interruptible basis
and thus increase its transportation revenues.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<U>Gas
Processing.</U>  With  the  acquisition  of  Transok,  Enogex  is now one of the
largest  gas  processors  in the  state  of  Oklahoma.  Enogex  now  owns 11 gas
processing plants, with an inlet capacity of over one billion cubic feet per day
("bcfd"), and has ownership interest in two other gas processing plants, with an
inlet capacity of 310 million cubic feet per day ("mmcfd"),  on a net percentage
of ownership basis. The Gas processing  operations are conducted  through Enogex
Products Corporation ("Products") and a subsidiary of Transok. Products has been
active since 1968 in the  processing of natural gas and marketing of natural gas
liquids.  The NuStar Joint  Venture  ("NuStar"),  in which  Products  owns an 80
percent interest,  has been engaged in the processing of natural gas since 1951.
Products' and NuStar's natural gas processing  plant  operations  consist of the
extraction  and  sale of  natural  gas  liquids.  The  products  extracted  from
Transok's natural gas stream include  marketable  ethane,  propane,  butanes and
natural  gasoline mix. The residue gas remaining  after the liquid products have
been extracted consists primarily of ethane and methane.  All Transok processing
plants  are  cryogenic  expander  processing  plants  capable of  recovering  or
rejecting ethane.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;A  portion of the
commercial grade propane processed at Products' Calumet facility and two Transok
plants are sold on the local market.  The other natural gas liquids  produced by
Products and Transok are delivered into pipeline facilities of Koch Hydrocarbon
("Koch") and transported to Conway,  Kansas and Mont Belvieu,  Texas, where they
are sold under contract or on the spot market.  Ethane, which is produced at all
plants except Calumet,  is sold under a contract with Equistar Chemicals LP, Dow
Hydrocarbons  and Resources  Inc. and Koch.  Natural gas liquids from the NuStar
Joint  Venture  are  sold  to the  Huntsman  Chemicals  plant  (formerly  Rexene
Chemicals) in Midland, Texas.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In processing and
marketing  natural gas liquids,  Enogex competes against virtually all other gas
processors producing and selling natural gas liquids. Enogex believes it will be
able to continue to compete  favorably  against such companies.  With respect to
factors  affecting the natural gas liquids industry  generally,  as the price of
natural  gas  liquids  fall  without a  corresponding  decrease  in the price of
natural gas, it may become  uneconomical to extract certain natural gas liquids.
As to factors affecting Enogex specifically, the volume of natural gas processed
at their plants is  dependent  upon the volume of natural gas gathered by Enogex
and other gatherers through their pipeline systems.  Generally, if the volume of
natural gas gathered  increases,  then the volume of liquids extracted by Enogex
should also increase.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<U>Marketing.</U>
Enogex's  natural  gas  marketing  is  conducted  through  OGE Energy  Resources
("Energy  Resources") and Transok.  Energy  Resources  serves both producers and
consumers of natural gas by buying natural gas at pooling points both on and off
the Enogex pipeline system and reselling to interstate  pipelines,  end-users or
downstream  purchasers both within and outside Oklahoma.  The integration of the
Transok and Enogex  pipelines  has  increased  gas  transportation  and provided
Energy Resources with a better platform from which to market natural gas.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Energy  Resources
purchases  and sells gas under  long-term  contracts,  as well as in the  "spot"
market.  In  response to changes  currently  taking  place in the gas  industry,
Energy  Resources  has  been  de-emphasizing  its  short-term  markets,  and  an
increasing  proportion  of its revenues are earned  pursuant to long-term  sales
contracts.  However,  short-term or "spot" sales of natural gas will continue to
play a critical  role in overall  strategy  because  they  provide an  important
source of market  intelligence,  while serving a portfolio  balancing  function.
Price risk on extended  term gas  purchase or sales  contracts  entered  into by
Resources  is hedged  on the NYMEX  futures  exchange  as a matter of  corporate
policy.  Energy  Resources  markets natural gas developed by Enogex  Exploration
Corporation  ("Exploration")  when  volumes  are  sufficiently  concentrated  to
justify Energy Resources marketing these volumes directly instead of through the
property  operator.   Other  services  provided  include  energy  forward  price
evaluations and centralized corporate commodity price risk assessment.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In  its marketing
business,  Energy  Resources  encounters  competition  from  other  natural  gas
transporters and marketers and from other available  alternative energy sources.
The effect of competition from alternative  energy sources is dependent upon the
availability  and cost of competing supply sources.  Energy  Resources  competes
with all major  suppliers of natural gas in the  geographic  markets they serve.
For natural gas,  those  geographic  markets are  primarily  the areas served by
pipelines with which Enogex,  Transok or NOARK are interconnected.  Although the
price of the gas is an  important  factor to a buyer of natural  gas from Energy
Resources, the primary factor is the total cost (including  transportation fees)
that the buyer must pay. Natural gas transported for Energy Resources by Enogex,
Transok or NOARK is billed at the same rates charged for comparable  third-party
transportation.  Energy Resources acts as OG&amp;E's  natural gas purchasing arm
for the natural gas fuel requirements of the OG&amp;E power stations.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Energy  Resources
also conducts wholesale electric power purchase and reselling operations and has
received  market-based rate authority from the FERC. See "Electric  Operations -
Regulation  and Rates."  During 2000,  Energy  Resources had  approximately  1.1
million Mwh of power sales.  Since March 2000,  virtually  all of the  Company's
surplus power sales activity has been performed by Energy Resources.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<U>Exploration
and  Production.</U>  The  exploration  and production  activities are conducted
through  Exploration,  which  was  formed  in 1988  primarily  to  engage in the
development and production of oil and natural gas. Exploration focused its early
drilling  activity in the Antrim  Devonian  shale trend in the state of Michigan
but in recent years has concentrated on drilling opportunities in Oklahoma. As a
part of this refocusing, Exploration sold its interests in Texas and Utah during
2000.  As of December 31,  2000,  Exploration  had  interests in over 350 active
wells and estimated proved reserves of 71,733 MMcfe. The standardized measure of
discounted  future  net cash flow  (with  related  Section  29 tax  credits)  of
Exploration's  proved reserves was $182.5 million at December 31, 2000. In 1998,
Energy Resources  initiated a program of hedging the future gas selling price on
a portion of Exploration's net production through commodity futures contracts to
cushion against unfavorable monthly price swings.</P><BR>


<P ALIGN=CENTER><B>FINANCE AND CONSTRUCTION</B></P><BR>


<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Company
generally  meets its cash needs  through a combination  of internally  generated
funds, short-term borrowings and permanent financing. Cash flows from operations
have enabled the Company to  internally  generate the required  funds to satisfy
construction expenditures.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Management
expects that  internally  generated  funds will be adequate  over the next three
years to meet the Company's anticipated construction  expenditures.  The primary
capital requirements for 2001 through 2003 are estimated as follows:</P>

<PRE>
(dollars in millions)                         2001        2002        2003
----------------------------------------------------------------------------
Electric utility construction
  expenditures including AFUDC............   $118.0      $118.0      $118.0

Non-utility construction expenditures
  and pending acquisitions................     46.0        46.0        46.0

Maturities of long-term debt..............      7.0       115.0        14.3
----------------------------------------------------------------------------
    Total.................................   $171.0      $279.0      $178.3
============================================================================
</PRE>
<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The    three-year
estimate  includes  expenditures  for  construction  of new  facilities  to meet
anticipated demand for service, to replace or expand existing facilities in both
its electric and  non-utility  businesses,  and to some extent,  for  satisfying
maturing  debt.   Approximately  $2.5  million  of  the  Company's  construction
expenditures  budgeted  for  2001  are to  comply  with  environmental  laws and
regulations.  OG&amp;E's  construction  program  was  developed  to  support  an
anticipated  peak demand  growth of one to two percent  annually and to maintain
minimum  capacity reserve margins as stipulated by the Southwest Power Pool. See
"Electric Operations - Rate Structure, Load Growth and Related Matters."</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E  intends
to meet its customers' increased electricity needs during the foreseeable future
primarily by maintaining  the  reliability  and  increasing  the  utilization of
existing capacity,  increasing demand-side management efforts and, if necessary,
purchasing  power from third  parties.  OG&amp;E will continue to evaluate these
strategies  against the  construction  of  additional  peaking  units or another
base-load generating unit. These evaluations will consider,  among other things,
the  amount  of  capital  requirements  and the  relative  cost of fuel  supply,
compared to other alternatives.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  Company will
continue to use short-term  borrowings to meet temporary cash requirements.  The
Company has the  necessary  approvals to incur up to $400 million in  short-term
borrowings  at any one time.  At December 31,  2000,  the Company had in place a
line of credit for up to $300  million,  with $200  million to expire on January
15, 2001,  and the  remaining  $100  million to expire on January 15,  2004.  In
January 2001, the Company's line of credit for $200 million was renewed, with an
expiration date of January 15, 2002.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
financial  results  continue to depend to a large extent upon the rates OG&amp;E
charges customers and the actions of the regulatory bodies that set those rates,
the amount of energy used by OG&amp;E's customers,  the cost and availability of
external financing and the cost of conforming to government regulations.</P><BR>


<P ALIGN=CENTER><B>ENVIRONMENTAL MATTERS</B></P><BR>


<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
management  believes 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 $50.5
million during 2001,  compared to approximately  $47.1 million utilized in 2000.
Approximately $2.5 million of the Company's  construction  expenditures budgeted
for 2001 are to comply  with  environmental  laws and  regulations.  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.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As   required  by
Title  IV of the  Clean  Air Act  Amendments  of  1990  ("CAAA"),  OG&amp;E  has
completed  installation and certification of all required  continuous  emissions
monitors  ("CEMs") at its generating  stations.  OG&amp;E submits emissions data
quarterly  to the  Environmental  Protection  Agency  ("EPA") as required by the
CAAA. Phase II sulfur dioxide ("SO2") emission  requirements  affected  OG&amp;E
beginning  in the year  2000.  OG&amp;E  met the SO2 limits  without  additional
capital  expenditures  through  the  purchase  of  low  sulfur  coal.  In  2000,
OG&amp;E's SO2 emissions were well below the allowable limits.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;With  respect  to
the  nitrogen  oxide  ("NOx")  regulations  of  Title IV of the  CAAA,  OG&amp;E
committed  to  meeting  a 0.45  lbs/mmbtu  NOx  emission  level  in  1997 on all
coal-fired boilers. As a result, OG&amp;E was eligible to exercise its option to
extend the effective date of the lower emission  requirements from the year 2000
until 2008.  OG&amp;E's  average NOx emissions from its  coal-fired  boilers for
2000 was 0.37 lbs/mmbtu.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E      has
submitted all of its required  Title V permit  applications.  As a result of the
Title V Program, OG&amp;E paid approximately $0.4 million in fees in 2000.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other   potential
air regulations have emerged that could impact  OG&amp;E.  On December 14, 2000,
the EPA  announced  that it is  appropriate  and  necessary to regulate  mercury
emissions  from  coal-fired  utility  boilers.  If the EPA  decides to  regulate
mercury  emissions,  limits on the amount of mercury  emitted are expected to be
finalized  by  December  2004  with  OG&amp;E's  compliance  required  by  2008.
Depending  upon  the  final  regulations  implemented,   this  could  result  in
significant capital and operating expenditures.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In  1997, the EPA
finalized revisions to the ambient ozone and particulate standards. However, the
standards  were  challenged  in court and the ozone  standard  was  subsequently
remanded  back to the EPA  for  further  consideration.  The  EPA  appealed  the
decision to the U.S.  Supreme Court and the Supreme Court issued its decision on
February 27, 2001. In its decision,  the Supreme Court  remanded the case to the
District of Columbia Court of Appeals,  in part, to allow additional  challenges
to the  standards.  If the proposed  standard is eventually  upheld,  then it is
likely that Tulsa County will fail to meet the new  standard for ozone.  The EPA
has already  indicated  that in addition to Tulsa County,  Muskogee  County will
also be considered non-attainment because of its impact on Tulsa. If this occurs
NOx reductions at OG&amp;E's Muskogee  Generating Station could be required.  In
addition,  the EPA projects that Muskogee,  Kay, Tulsa and Comanche  Counties in
Oklahoma would fail to meet the standard for particulate  matter.  If reductions
are  required  in  Muskogee,  Kay and  Oklahoma  Counties,  significant  capital
expenditures could be required by OG&amp;E.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  EPA also has
issued regulations  concerning  regional haze. These regulations are intended to
protect  visibility in national parks and wilderness areas throughout the United
States. In Oklahoma,  the Wichita Mountains would be the only area covered under
the  regulation.  Sulfates and nitrate  aerosols  (both emitted from  coal-fired
boilers) can lead to the degradation of visibility.  Under these regulations, it
is possible  that controls on emission  sources  hundreds of miles away from the
affected  area may be  required.  The EPA has begun the  process of  determining
what, if any,  impact  emission  sources in Oklahoma have on national  parks and
wilderness  areas.  If  an  impact  is  determined,   then  significant  capital
expenditures  could  be  required  for  both  Sooner  and  Muskogee   Generating
Stations.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In December 1997,
the United  States was a signatory to the Kyoto  Protocol  for the  reduction of
greenhouse  gases that  contribute to global  warming.  The U.S.  committed to a
seven percent  reduction from the 1990 levels.  While it appears that the Senate
will  not  ratify  the  Kyoto  Protocol,  momentum  is  gaining  in the  federal
government for some type of reduction in the level of carbon dioxide  emissions.
If  legislation  is passed,  it could  have a  tremendous  impact on  OG&amp;E's
operations by requiring  OG&amp;E to  significantly  reduce the use of coal as a
fuel source.'</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E  has and
will continue to seek new pollution prevention opportunities and to evaluate the
effectiveness  of its waste  reduction,  reuse and recycling  efforts.  In 2000,
OG&amp;E obtained refunds of approximately  $365,000 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 reuse of  existing  materials.  Similar  savings  are  anticipated  in future
years.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E      has
received approvals to renew its Oklahoma Pollution Discharge  Elimination System
("OPDES")  permits  for all  facilities  except  one,  which is  awaiting  final
regulatory  action.  All of the  renewed  permits  issued to date offer  greater
operational  flexibility than those in the past. In addition,  OG&amp;E has made
application  for a new OPDES permit to cover gas turbine  generating  units that
were constructed at one of its existing plants.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E
requested that the State agency responsible for the development of Water Quality
Standards remove the agriculture  beneficial use classification  from one of its
cooling water reservoirs. Without removal of this classification, OG&amp;E could
be subjected to costly treatment and/or facility  reconfiguration  requirements.
Both the State and EPA have now approved this request.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E  remains
a party to one action brought by the EPA  concerning  cleanup of a disposal site
for hazardous and toxic waste. See Item 3 "Legal Proceedings."</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  Company  has
and will continue to evaluate the impact of its  operations on the  environment.
As a result,  contamination  on Company  property may be discovered from time to
time.  One site has been  identified as having been  contaminated  by historical
operations.  Remedial  options  based on the  future  use of this site are being
pursued with appropriate  regulatory agencies. The cost of these actions has not
had and is not  anticipated  to have a material  adverse impact on the Company's
financial position or results of operations.</P><BR>


<P ALIGN=CENTER><B>EMPLOYEES</B></P><BR>


<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  Company  and
its subsidiaries had 3,032 employees at December 31, 2000.</P><BR>



<P ALIGN=LEFT><U><B>Item 2. Properties.</B></U></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E owns and
operates an interconnected  electric  production,  transmission and distribution
system,  located  in  Oklahoma  and  western  Arkansas,   which  includes  eight
generating  stations  with an  aggregate  capability  of  5,781  megawatts.  The
following  table sets forth  information  with  respect to  electric  generating
facilities, all of which are located in Oklahoma:</P>

<PRE>
                                                                 Unit                Station
                                            Year              Capability            Capability
Station &amp; Unit             Fuel           Installed           (Megawatts)           (Megawatts)
--------------             ----           ---------           -----------           -----------
Seminole     1             Gas              1971                 517.0
             2             Gas              1973                 505.0
             3             Gas              1975                 496.0                 1,518

Muskogee     3             Gas              1956                 171.0
             4             Coal             1977                 503.0
             5             Coal             1978                 500.0
             6             Coal             1984                 516.0                 1,690

Sooner       1             Coal             1979                 500.0
             2             Coal             1980                 512.0                 1,012

Horseshoe    6             Gas              1958                 171.0
Lake         7             Gas              1963                 234.0
             8             Gas              1969                 402.0
             9             Gas              2000                  45.0
             10            Gas              2000                  45.0                   897

Mustang      1             Gas              1950                  56.0
             2             Gas              1951                  53.0
             3             Gas              1955                 118.0
             4             Gas              1959                 258.0
             5             Gas              1971                  63.0                   548

Conoco       1             Gas              1991                  32.0
             2             Gas              1991                  31.0                    63

Enid         1             Gas              1965                  11.0
             2             Gas              1965                   8.0
             3             Gas              1965                  12.0
             4             Gas              1965                  12.0                    43

Woodward     1             Gas              1963                  10.0                    10
                                                                                    -----------
Total Generating Capability (all stations)                                             5,781
                                                                                    ===========
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;At  December  31,
2000, OG&amp;E's  transmission system included:  (i) 64 substations with a total
capacity of approximately 18 million kVA and approximately 3,996 structure miles
of  lines  in  Oklahoma;  and  (ii) six  substations  with a total  capacity  of
approximately  2.3 million kVA and approximately 241 structure miles of lines in
Arkansas.  OG&amp;E's  distribution system included:  (i) 299 substations with a
total  capacity of  approximately  4.4 million kVA,  22,326  structure  miles of
overhead  lines,  1,739  miles  of  underground   conduit  and  7,076  miles  of
underground  conductors  in  Oklahoma;  and  (ii)  31  substations  with a total
capacity of approximately  731,000 kVA, 1,861 structure miles of overhead lines,
198 miles of  underground  conduit and 411 miles of  underground  conductors  in
Arkansas.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Enogex   and  its
subsidiaries own: (i) approximately  9,700 miles of intrastate  transmission and
gathering  lines in the  states of  Oklahoma  and  Texas;  (ii) 11  natural  gas
processing  plants  with a capacity  to process  over one bcfd,  all  located in
Oklahoma;  (iii) 75 percent  interest in NOARK,  which  consists of 925 miles of
interstate transmission and gathering pipelines, located in eastern Oklahoma and
Arkansas;  (iv) an 18 billion  cubic feet ("bcf") gas storage  field in Oklahoma
with a withdrawal capacity of 450 mmcfd; (v) five bcf of gas storage in Oklahoma
with a withdrawal  capacity of 400 mmcfd; (vi) an 80 percent interest in NuStar,
which  includes  a 66.67  percent  interest  in the 110 mmcfd  capacity  Benedum
processing  plant,  a 100 percent  interest in a smaller 30 mmcfd by-pass plant,
over 200 miles of gathering pipelines and 52 miles of NGL pipeline,  all located
in the Permian  Basin of West Texas;  and (vii) 100 percent of the Belvan Corp.,
which consists of a natural gas  processing  plant with a capacity of process 15
mmcfd, a sulfur recovery plant, and an eight mile NGL pipeline, and 345 miles of
gathering lines in West Texas.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;During  the three
years ended December 31, 2000, the Company's gross property, plant and equipment
additions  approximated $1.4 billion and gross retirements  approximated  $163.2
million.  These  additions  were  provided by  internally  generated  funds from
operating  cash  flows,  permanent  financing  and  short-term  borrowings.  The
additions during this three-year  period amounted to approximately  38.5 percent
of total property, plant and equipment at December 31, 2000.</P>

<P ALIGN=LEFT><U><B>Item 3. Legal Proceedings.</B></U></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;On  January  11,  1993,  OG&amp;E  received a Section  107 (a)
Notice  Letter from the EPA,  Region VI, as  authorized  by the  CERCLA,  42 USC
Section 9607 (a), concerning the Double Eagle Refinery Superfund Site located at
1900 NE First Street in Oklahoma City, Oklahoma.  The EPA has named OG&amp;E and
45 others as PRPs.  Each PRP could be held  jointly  and  severally  liable  for
remediation of this site.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On  February  15,
1996,  OG&amp;E  elected to  participate  in the de minimis  settlement of EPA's
Administrative   Order  on  Consent.   This  would  limit  OG&amp;E's  financial
obligation  and  also  would   eliminate  its  involvement  in  the  design  and
implementation  of the  site  remedy.  A third  party  is  currently  contesting
OG&amp;E's  participation  as a de minimis  party.  Regardless of the outcome of
this issue, OG&amp;E believes that its ultimate liability for this site will not
be material primarily due to the limited volume of waste sent by OG&amp;E to the
site.</P>


<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;As previously reported, on September 18, 1996, Trigen-Oklahoma
City Energy  Corporation  ("Trigen") sued OG&amp;E in the United States District
Court, Western District of Oklahoma, Case No. CIV-96-1595-M.  Trigen alleged six
causes of action:  (i)  monopolization  in violation of Section 2 of the Sherman
Act;  (ii) attempt to  monopolize  in violation of Section 2 of the Sherman Act;
(iii) acts in restraint of trade in  violation  of Oklahoma  law, 79 O.S.  1991,
&sect; 1; (iv) discriminatory  sales in violation of 79 O.S. 1991, &sect; 4; (v)
tortious  interference  with  contract;  and (vi) tortious  interference  with a
prospective economic advantage. On December 21, 1998, the jury awarded Trigen in
excess of $30 million in actual and punitive damages.  On February 19, 1999, the
trial court entered judgment in favor of Trigen as follows: (i) $6.8 million for
various antitrust violations,  (ii) $4 million for tortious interference with an
existing contract, (iii) $7 million for tortious interference with a prospective
economic advantage and (iv) $10 million in punitive damages. The trial judge, in
a companion  order,  acknowledged  that the  portions of the  judgment  could be
duplicative, that the antitrust amounts could be tripled and that parties should
address these issues in their post-trial  motions.  On January 25, 2000, a trial
judge rejected  OG&amp;E's  post-trial motions to reverse the jury verdict or to
grant  OG&amp;E a new trial.  The judge did,  however,  reduce the  original $30
million judgment against OG&amp;E to $20 million.  On February 4, 2000, OG&amp;E
filed a notice  of  appeal.  In  addition,  Trigen  has  filed a motion  seeking
attorneys'  fees and  costs in an amount  over $3  million.  Trigen  will not be
entitled to attorneys' fees or costs unless it prevails on appeal. Oral argument
was heard by the Tenth  Circuit on January 22,  2001. A decision is not expected
for several months. While the outcome of the appeal is uncertain,  legal counsel
and  management  believe  that it is not  probable  that Trigen will  ultimately
succeed in preserving the verdicts or judgment. Accordingly, the Company has not
accrued any loss associated with the damages awarded.  The Company believes that
the ultimate  resolution of this case will not have a material adverse effect on
the Company's consolidated financial position or results of operations.</P>


<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;The  City of Enid, Oklahoma ("Enid") through its City Council,
notified  OG&amp;E of its intent to purchase  OG&amp;E's  electric  distribution
facilities for Enid and to terminate OG&amp;E's franchise to provide electricity
within Enid as of June 26, 1998.  On August 22,  1997,  the City Council of Enid
adopted  Ordinance No. 97-30,  which in essence  granted  OG&amp;E a new 25-year
franchise subject to approval of the electorate of Enid on November 18, 1997. In
October 1997,  eighteen residents of Enid filed a lawsuit against Enid, OG&amp;E
and others in the District Court of Garfield County, State of Oklahoma, Case No.
CJ-97-829-01.  Plaintiffs seek a declaration  holding that (i) the Mayor of Enid
and the City Council  breached  their  fiduciary duty to the public and violated
Article 10, Section 17 of the Oklahoma  Constitution  by allegedly  "gifting" to
OG&amp;E the option to acquire OG&amp;E's  electric system when the City Council
approved the new franchise by Ordinance No. 97-30; (ii) the subsequent  approval
of the new  franchise by the  electorate of the City of Enid at the November 18,
1997, franchise election cannot cure the alleged breach of fiduciary duty or the
alleged constitutional violation; (iii) violations of the Oklahoma Open Meetings
Act occurred and that such violations render the resolution  approving Ordinance
No. 97-30 invalid;  (iv)  OG&amp;E's  support of the Enid Citizens'  Against the
Government Takeover was improper;  (v) OG&amp;E has violated the favored nations
clause of the existing  franchise;  and (vi) the City of Enid and OG&amp;E  have
violated the competitive  bidding  requirements  found at 11 O.S. 35-201,  <I>et
seq.</I>  Plaintiffs seek money damages against the Defendants under 62 O.S. 372
and 373.  Plaintiffs allege that the action of the City Council in approving the
proposed  franchise  allowed  the option to purchase  OG&amp;E's  property to be
transferred to OG&amp;E for inadequate consideration. Plaintiffs demand judgment
for  treble  the  value of the  property  allegedly  wrongfully  transferred  to
OG&amp;E.  On October 28, 1997, another resident filed a similar lawsuit against
OG&amp;E,  Enid and the Garfield  County Election Board in the District Court of
Garfield County,  State of Oklahoma,  Case No. CJ-97-852-01.  However,  Case No.
CJ-97-852-01  was dismissed  without  prejudice in December 1997. On December 8,
1997,  OG&amp;E filed a Motion to Dismiss Case No.  CJ-97-829-01  for failure to
state claims upon which relief may be granted. This motion is currently pending.
While the Company cannot  predict the precise  outcome of this  proceeding,  the
Company  believes at the  present  time that this  lawsuit is without  merit and
intends to vigorously defend this case.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;On  February 19, 1998,  Enogex was sued by Melvin  Scoggin and
Oak Tree  Resources,  LLC, in the District  Court of Oklahoma  County,  State of
Oklahoma,  for alleged  breach of contract,  fraud,  breach of  fiduciary  duty,
misappropriation   and  unjust  enrichment  arising  from   communications  that
allegedly  created  agreements  regarding  oil and gas  exploration  activities.
Plaintiffs'  seek  damages  in excess  of $25  million.  Enogex  filed an answer
denying  Plaintiffs'  allegations and various motions for summary  judgment.  On
October 20, 1999, and October 25, 1999, the trial judge granted Enogex's motions
for  summary  judgment  and  entered  judgment  in favor of Enogex on all claims
raised by the Plaintiffs.  The Plaintiffs  appealed the trial court decision and
the Court of Appeals upheld the trial court's  judgment on all counts.  The time
for  Plaintiffs  to appeal the decision to the Supreme Court of Oklahoma has not
expired as of the date of this  report.  The Company  continues  to believe that
this case is without merit.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;United  States of America ex rel., Jack J.  Grynberg v. Enogex
Inc., Enogex Services Corporation (now, Energy Resources) and OG&amp;E.  (United
States  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. (United States District Court for the Eastern District of Louisiana,
Case No.  97-2089;  United  States  District  Court for the Western  District of
Oklahoma,  Case No.  97-1009M.)  On June 15,  1999,  the Company was served with
Plaintiff's  Complaint.  Plaintiff's  action is a qui tam action under the False
Claims Act.  Jack J.  Grynberg,  as  individual  Relator on behalf of the United
States  Government,  Plaintiff,  alleges:  (i) each of the named Defendants have
improperly  and  intentionally  mismeasured  gas (both  volume and BTU  content)
purchased   from   federal  and  Indian   lands  which  have   resulted  in  the
under-reporting   and   underpayment  of  gas  royalties  owed  to  the  Federal
Government;  (ii) certain  provisions  generally found in gas purchase contracts
are improper;  (iii)  transactions by affiliated  companies are not arms-length;
(iv) excess processing cost deduction; and (v) failure to account for production
separated  out as a result  of gas  processing.  Grynberg  seeks  the  following
damages:  (a) additional  royalties which he claims should have been paid to the
Federal  Government,  some  percentage  of which  Grynberg,  as Relator,  may be
entitled to  recover;  (b) treble  damages;  (c) civil  penalties;  (d) an order
requiring  Defendants to measure the way Grynberg  contends is the better way to
do so; (e)  interest,  costs and  attorneys'  fees.  Plaintiff has filed over 70
other cases naming over 300 other  defendants in various  Federal  Courts across
the country containing nearly identical allegations.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In     qui    tam
actions,  the United States  Government can intervene and take over such actions
from the Relator.  The  Department  of Justice,  on behalf of the United  States
Government,  has  decided  not to  intervene  in this action or any of the other
Grynberg qui tam actions.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On  November  16,
1999,  the  Multidistrict  Litigation  Panel  ("MDL  Panel")  entered  its order
transferring  and  consolidating  for pretrial  purposes  approximately 76 other
similar actions filed in nine other Federal Courts.  The consolidated  cases are
now before the United States District Court for the District of Wyoming.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On  November  17,
1999,  the Company filed a motion to dismiss,  seeking:  (i) a stay of discovery
until after the  dispositive  motions are  resolved;  and (ii)  dismissal of the
complaint on various basis under the Federal Rules of Civil Procedure.  A number
of other defendants adopted the Company's pleadings or filed similar motions. On
December 22, 1999,  the Company  joined a number of other  defendants  in filing
Defendants'  Statement of Points and  Authorities  regarding  discovery  issues.
Grynberg's  responses  to all motions to dismiss were filed on January 14, 2000,
and the Company's reply and those of other defendants were filed on February 14,
2000. A hearing on the motions to dismiss was held on March 17, 2000.  The Court
has not yet ruled on the motions to dismiss.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On    April   10,
2000,  the  MDL  Panel  transferred  another  <I>qui  tam</I>  case  <I>(Quinque
Operating Company, et al. v. Enogex Services Corporation,  Enogex, Inc., Transok
LLC,  Transok,   Inc.,  and  Oklahoma  Gas  &amp;   Electric  Company,  et  al.)
("Quinque")</I>  to Judge  Downes in Wyoming and the MDL Panel  consolidated  it
with this case.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On July 27, 2000,
the  Department  of  Justice  ("DOJ")  filed a  Motion  to  Dismiss  certain  of
Grynberg's  claims on the basis  Grynberg  was not the first to file such <I>qui
tam</I> allegations. The DOJ's Motion to Dismiss was heard on February 22, 2001.
</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   October   6,
2000, the MDL Panel  transferred two additional  <I>qui tam</I> cases <I>(Harold
E. Wright,  et al. v. AGIP Petroleum,  et al.,</I> E.D. Texas,  C.A. No. 9:98-30
and <I>M. Glenn Ousterhaudt,  III, et al. v. Amoco Production,  et al.,</I> E.D.
Texas,  C.A. No. 9:98-101) to Judge Downes in Wyoming,  and the MDL consolidated
them with this case and the <I>Quinque</I>  case. The Company has not been named
as a party in either the  <I>Wright  or  Ousterhaudt</I>  cases;  therefore,  no
information regarding these two cases is being provided at this time.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;While the Company
cannot predict the precise outcome of this  proceeding,  the Company believes at
the present  time that this lawsuit is without  merit and intends to  vigorously
defend this case.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;On  September 24, 1999, the Company was served with an Amended
Class Action Petition filed in United States District Court,  State of Kansas by
Quinque   Operating   Company,   on  behalf  of  itself  and  others,   alleging
approximately 200 defendants, including OG&amp;E, Enogex and two subsidiaries of
Enogex,  including  Transok,  have improperly and intentionally  mismeasured gas
(both  volume and Btu  content)  purchased  from all lands in the United  States
except from federal and Indian lands.  Plaintiffs  claim (i) underpayment by the
Company  and all other  Defendants  of gas  royalties  claimed to be owed to the
Plaintiffs and the punitive class; (ii) breach of contract;  (iii) negligence or
intentional misrepresentation; (iv) civil conspiracy; (v) fraud; and (vi) breach
of fiduciary duty.  Plaintiffs seek the following damages: (a) actual damages in
excess of $75,000; (b) punitive damages; (c) certification of the class; and (d)
injunction to prevent mismeasurement in the future.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   October   5,
1999,  the Company filed its Notice with the MDL Panel advising the MDL Panel of
a possible  tag-along action to the Grynberg <I>qui tam</I> actions discussed in
Item 3, number 4 above.  On March 30,  2000,  the MDL Panel heard oral  argument
regarding  the  transfer of this action as a  tag-along  case;  and on April 10,
2000,  the MDL Panel  transferred  this  case to Judge  Downes  in  Wyoming  and
consolidated it with the Grynberg cases above.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On  September  8,
2000,  Plaintiffs filed a Motion for Expedited  Hearing on Motion to Remand.  On
January 12, 2001, the Court issued its oral order granting Plaintiff's Motion to
Remand.  The Court is currently  reviewing a Motion to Reconsider before sending
the Order to the Stevens  County Clerk,  effectively  remanding the case back to
the Kansas State Court.</P>


<P ALIGN=LEFT><U><B>Item 4. Submission of Matters to a Vote of Security Holders.
</B></U></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;None</P><BR>


<P ALIGN=LEFT><U><B>Executive Officers of the Registrant.</B></U></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     following
persons were Executive Officers of the Registrant as of March 15, 2001:</P>

<PRE>
      Name                  Age                           Title
--------------------        ---              --------------------------------
Steven E. Moore              54              Chairman of the Board, President
                                                 and Chief Executive Officer

Al M. Strecker               57              Executive Vice President and
                                                 Chief Operating Officer

Roger A. Farrell             48              President and Chief Executive
                                                 Officer - Enogex Inc.

James R. Hatfield            43              Senior Vice President and
                                                 Chief Financial Officer

Jack T. Coffman              57              Senior Vice President - Power
                                                 Supply - OG&amp;E

Melvin D. Bowen, Jr.         59              Vice President - Power Delivery -
                                                 OG&amp;E

Michael G. Davis             51              Vice President - Marketing and
                                                 Customer Care

Irma B. Elliott              62              Vice President and
                                                 Corporate Secretary

Steven R. Gerdes             44              Vice President - Shared
                                                 Services

David J. Kurtz               39              Vice President - Business
                                                 Development

Donald R. Rowlett            43              Vice President and Controller

Don L. Young                 60              Controller Corporate Audits

Eric B. Weekes               49              Treasurer
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;No         family
relationship  exists  between any of the Executive  Officers of the  Registrant.
Messrs. Moore, Strecker,  Hatfield, Davis, Gerdes, Kurtz, Rowlett, Young, Weekes
and Ms.  Elliott are also  officers of OG&amp;E.  Each Officer is to hold office
until the Board of  Directors  meeting  following  the next  Annual  Meeting  of
Shareowners, currently scheduled for May 24, 2001.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The      business
experience of each of the Executive Officers of the Registrant for the past five
years is as follows:</P>

<PRE>
        Name                               Business Experience
--------------------           -------------------------------------------------
Steven E. Moore                1996-Present:       Chairman of the Board,
                                                     President and Chief
                                                     Executive Officer


Al M. Strecker                 1998-Present:       Executive Vice President and
                                                     Chief Operating Officer
                               1996-1998:          Senior Vice President


Roger A. Farrell               1998-Present:       President and Chief Executive
                                                     Officer - Enogex Inc.
                               1997-1998:          Executive Vice President -
                                                     Enogex Inc.
                               1996-1997:          Vice President - Business
                                                     Development - Enogex Inc.


James R. Hatfield              2000-Present:       Senior Vice President and
                                                     Chief Financial Officer
                               1999-2000:          Senior Vice President,
                                                     Chief Financial Officer
                                                     and Treasurer
                               1997-1999:          Vice President and Treasurer
                               1996-1997:          Treasurer - OG&amp;E


Jack T. Coffman                1999-Present:       Senior Vice President -
                                                     Power Supply - OG&amp;E
                               1996-1999:          Vice President -
                                                     Power Supply - OG&amp;E


Melvin D. Bowen, Jr.           1996-Present:       Vice President -
                                                     Power Delivery - OG&amp;E


Michael G. Davis               1998-Present:       Vice President - Marketing
                                                     and Customer Care
                               1996-1998:          Vice President -
                                                     Marketing and Customer
                                                     Services - OG&amp;E


Irma B. Elliott                1996-Present:       Vice President and
                                                     Corporate Secretary


Steven R. Gerdes               1998-Present:       Vice President - Shared
                                                     Services
                               1997-1998:          Director - Shared Services
                               1997:               Manager - Enterprise Support
                               1996-1997:          Manager - Purchasing and
                                                     Material Management - OG&amp;E


David J. Kurtz                 1999-Present:       Vice President - Business
                                                     Development
                               1997-1999:          Vice President - Business
                                                     Development - Enogex Inc.
                               1996-1997:          Director - Gas Supply -
                                                     Enogex Inc.


Donald R. Rowlett              1999-Present:       Vice President and Controller
                               1996-1999:          Controller Corporate
                                                     Accounting


Don L. Young                   1996-Present:       Controller Corporate
                                                     Audits


Eric B. Weekes                 2000-Present:       Treasurer
                               1997-2000:          Treasurer - Illinois Power
                                                     and Light
                               1996-1997:          Senior Financial Manager -
                                                     Kraft Foods Inc.
</PRE>

<P ALIGN=CENTER><B>PART II</B></P><BR>

<P ALIGN=LEFT><U><B>Item 5. Market for Registrant&#146;s Common Equity and
Related<BR>Stockholder Matters.</B></U></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
Common Stock is listed for trading on the New York and Pacific  Stock  Exchanges
under the ticker symbol "OGE." Quotes may be obtained in daily  newspapers where
the common stock is listed as "OGE Engy" in the New York Stock Exchange  listing
table. The following table gives  information  with respect to price ranges,  as
reported in <U><I>The  Wall Street  Journal</I></U>  as New York Stock  Exchange
Composite Transactions, and dividends paid for the periods shown.</P>
<PRE>
                                     2000                                         1999

                    ----------------------------------------------------------------------------------
                       Dividend                                    Dividend
                         Paid        High          Low               Paid          High         Low
                    ----------------------------------------------------------------------------------

First Quarter          $0.3325      $20.88        $16.50           $0.3325        $29.06       $22.56

Second Quarter          0.3325       21.25         18.31            0.3325         25.94        21.81

Third Quarter           0.3325       23.25         18.75            0.3325         24.56        21.69

Fourth Quarter          0.3325       24.75         18.94            0.3325         23.19        18.50
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The   number   of
record holders of Common Stock at December 31, 2000, was 36,326.  The book value
of the Company's Common Stock at December 31, 2000, was $13.66.</P><BR>



<P ALIGN=LEFT><U><B>Item 6. Selected Financial Data.</B></U></P><BR>

<P ALIGN=CENTER><B>HISTORICAL DATA</B></P><BR>

<PRE>
                                                  2000            1999            1998            1997            1996
                                              ----------------------------------------------------------------------------
SELECTED FINANCIAL DATA
 (dollars in thousands except
  for per share data)
  Operating revenues..................        $ 3,298,727     $ 2,172,434     $ 1,617,737     $ 1,443,610     $ 1,387,435
  Operating expenses..................          2,948,906       1,834,269       1,278,280       1,175,160       1,107,989
                                              ------------    ------------    ------------    ------------    ------------
  Operating income....................            349,821         338,165         339,457         268,450         279,446
  Other income and (deductions).......              6,383           3,317           5,758           5,047              97
  Interest charges....................            132,664         100,279          70,699          66,495          67,984
                                              ------------    ------------    ------------    ------------    ------------
  Net income..........................            147,035         151,259         165,872         132,550         133,332
  Preferred dividend
    requirements......................                ---             ---             733           2,285           2,302
  Earnings available for
    common............................        $   147,035     $   151,259     $   165,139     $   130,265     $   131,030
                                              ============    ============    ============    ============    ============
  Long-term debt......................        $ 1,648,523     $ 1,140,532     $   935,583     $   841,924     $   829,281
  Total assets........................        $ 4,319,630     $ 3,921,334     $ 2,983,929     $ 2,765,865     $ 2,762,355
  Earnings per average common
    share.............................        $      1.89     $      1.94     $      2.04     $      1.61     $      1.62

CAPITALIZATION RATIOS
  Common equity.......................              39.23%          47.20%          52.72%          52.50%          52.26%
  Cumulative preferred stock..........                ---             ---             ---            2.63%           2.68%
  Long-term debt......................              60.77%          52.80%          47.28%          44.87%          45.06%

INTEREST COVERAGES
  Before federal income taxes
    (including AFUDC).................               2.66X           3.39X           4.84X           4.11X           4.07X
    (excluding AFUDC).................               2.64X           3.38X           4.82X           4.10X           4.06X
  After federal income taxes
    (including AFUDC).................               2.09X           2.50X           3.31X           2.98X           2.94X
    (excluding AFUDC).................               2.07X           2.49X           3.30X           2.97X           2.93X
==========================================================================================================================
</PRE>

<P  ALIGN=LEFT><U><B>Item  7. Management's  Discussion and analysis of Financial
Condition and Results of Operations.</B></U></P>

<P ALIGN=LEFT><B>Management&#146;s Discussion and Analysis</B></P>

<P ALIGN=LEFT><B>OVERVIEW</B></P>

<PRE>
                                                                                                Percent Change
                                                                                               From Prior Year
                                                                                               ----------------
 (thousands except per share amounts)                     2000          1999          1998       2000     1999
---------------------------------------------------------------------------------------------------------------

Operating revenues.............................        $3,298,727    $2,172,434    $1,617,737    51.8     34.3
Earnings available for common stock............        $  147,035    $  151,259    $  165,139    (2.8)    (8.4)
Average shares outstanding.....................            77,864        77,916        80,772    (0.1)    (3.5)
Earnings per average common share..............        $     1.89    $     1.94    $     2.04    (2.6)    (4.9)
Earnings per average common share -
  assuming dilution............................        $     1.89    $     1.94    $     2.04    (2.6)    (4.9)
Dividends paid per share.......................        $     1.33    $     1.33    $     1.33     ---      ---
===============================================================================================================
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE  Energy Corp.
(the  "Company")  serves  as the  parent  holding  company  to its  two  primary
subsidiaries,  Oklahoma Gas and Electric  Company  ("OG&amp;E")  and Enogex Inc.
("Enogex").  This  holding  company  structure  is intended to allow the Company
greater  flexibility  to take  advantage  of  opportunities  in an  increasingly
competitive  business environment and to clearly separate the Company's electric
utility business from its non-utility businesses.  Despite the continuing growth
at Enogex,  the Company's  financial results and condition remain  substantially
dependent at this time on the financial results and condition of OG&amp;E.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     following
discussion  and  analysis  presents  factors  that had a material  effect on the
operations and financial position of the Company and its subsidiaries during the
last  three  years  and  should  be read in  conjunction  with the  Consolidated
Financial  Statements and Notes thereto.  Trends and contingencies of a material
nature are discussed to the extent known and considered relevant.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Company
reported  earnings of $1.89 a share in 2000, a 2.6 percent decrease from $1.94 a
share in 1999.  Record revenues of $3.3 billion were offset by higher  operating
and maintenance expenses and increased interest expense.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Enogex
contributed  $0.25 in  earnings  per  share in 2000,  down  from  $0.28 in 1999.
Revenues  increased at Enogex due to higher  commodity  prices and increased gas
marketing volumes,  as well as greater natural gas transportation and processing
volumes reflecting the full year impact of the Transok  acquisition in mid 1999.
The  higher  revenues  at  Enogex  were  offset by  higher  gas and  electricity
purchased  for  resale,  operation  and  maintenance  (including  a $25  million
increase in under-recovered  pipeline fuel expense) and interest  expenses.  The
holding company incurred increased  interest expenses,  which resulted in a loss
of $0.19 per share in 2000, down from a loss of $0.12 per share in 1999.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  reduction in
earnings in 2000 was  partially  offset by higher  earnings at  OG&amp;E,  which
contributed  $1.83 in  earnings  per share in 2000,  up from $1.78 in 1999.  The
increase in OG&amp;E's  earnings was primarily  attributable  to higher revenues
from kilowatt-hour  sales to OG&amp;E electric customers ("system sales") due to
more  favorable  weather in the last six months of 2000.  Revenue also increased
due to the recovery of higher fuel costs. As described in more detail below, the
increase in revenues was only partially offset by state  regulatory  action that
changed  the  Generation   Efficiency   Performance   Rider  ("GEP  Rider")  and
implemented the Acquisition Premium Credit Rider ("APC Rider").</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The 1999 decrease
in earnings to $1.94 a share from $2.04 a share in 1998 was primarily the result
of lower revenues at OG&amp;E due to milder weather,  lower recoveries under the
GEP Rider and less revenue  from sales to other  utilities  and power  marketers
("off-system   sales").  The  decrease  in  earnings  was  partially  offset  by
significantly higher earnings at Enogex, and benefits resulting from the Company
repurchasing 3 million shares of its common stock in January 1999.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The      dividend
payout  ratio  (expressed  as a  percentage  of  earnings  available  for common
shareholders)  was 70 percent in 2000 as compared to 69 percent in 1999,  within
the Company's  desired dividend payout ratio of 75 percent or below based on the
current business environment. Future dividend action will be dependent primarily
on two factors.  First,  the appropriate  payout ratio will be determined by the
pace and structure of the deregulation of the electric utility business. Second,
the payout rates will continue to be based on current and anticipated  operating
results.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
regulated  utility  business  has been  and  will  continue  to be  affected  by
competitive  changes to the utility industry.  Significant  changes already have
occurred in the wholesale  electric markets at the federal level and significant
changes are  expected at the retail level in the states  served by OG&amp;E.  In
Oklahoma,   legislation   was  passed  in  1997  to  provide   for  the  orderly
restructuring of the electric industry with the goal to provide retail customers
with the ability to choose their  electric  suppliers by July 1, 2002.  In April
1999,  Arkansas became the 18th state to pass a law calling for restructuring of
the electric utility  industry at the retail level.  The law initially  targeted
customer  choice of  electricity  providers by January 1, 2002,  but the law was
amended to delay  customer  choice  until  October 1, 2003.  It now appears that
customer  choice of electric  suppliers  may also be delayed in Oklahoma  beyond
2002.  These  developments at the federal and state levels are described in more
detail below under "Regulation; Competition."</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On  July 1, 1999,
the Company, through Enogex, completed the largest acquisition in its history by
acquiring Tejas Transok  Holding,  L.L.C. and its  subsidiaries  ("Transok"),  a
gatherer,  processor  and  transporter  of natural  gas in  Oklahoma  and Texas.
Transok's  principal  assets  include  approximately  4,900 miles of natural gas
pipelines  in Oklahoma  and Texas with a capacity of  approximately  2.6 billion
cubic feet per day and 18 billion cubic feet of underground natural gas storage.
Transok assets also include nine gas-processing plants. Enogex purchased Transok
for $710.3  million,  which  includes  assumption  of $173  million of long-term
debt.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In December 2000,
the Company  announced that Enogex's  natural gas pipeline  business  signed two
long-term  contracts  with third parties to transport 100 percent of the natural
gas to fuel a new 1,100  megawatt  power  plant  under  construction  in Coweta,
Oklahoma,  near Tulsa in northeastern  Oklahoma, and to transport 100 percent of
the natural gas to fuel a new 800  megawatt  power plant under  construction  in
Jenks,  Oklahoma.  These two new  facilities  will be  connected  to the Transok
pipeline system,  operated by Enogex. The new power plant in Coweta, Oklahoma is
designed to burn up to 185 million cubic feet of natural gas per day. Testing is
scheduled to begin in November 2001, with full commercial  operation expected in
June 2002. The new power plant in Jenks,  Oklahoma is designed to burn up to 150
million  cubic feet of natural gas per day.  Testing is  scheduled  to begin May
2001 and full commercial  operation is expected to begin in January 2002.  These
are the type of growth opportunities  envisioned by the Company when Transok was
acquired in 1999. The Company will continue to pursue these kinds of projects as
deregulation of electricity and natural gas encourage further development of the
energy infrastructure in our region.</P>

<P ALIGN=LEFT><B>Forward-Looking Statements</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Except   for  the
historical  statements  contained herein, the matters discussed in the following
discussion  and  analysis  are  forward-looking  statements  that are subject to
certain risks,  uncertainties and assumptions.  Such forward-looking  statements
are  intended  to be  identified  in this  document  by the words  "anticipate",
"estimate", "objective", "possible", "potential" and similar expressions. Actual
results may vary  materially.  Factors that could cause actual results to differ
materially  include,  but are  not  limited  to:  general  economic  conditions,
including  their  impact on capital  expenditures;  business  conditions  in the
energy  industry;  competitive  factors  including  the extent and timing of the
entry of additional  competition in the markets  served by the Company;  unusual
weather;  state and federal legislative and regulatory decisions and initiatives
that affect cost and investment recovery,  have an impact on rate structures and
affect the speed and degree to which competition  enters the Company's  markets;
and the other risk factors  listed in the reports  filed by the Company with the
Securities and Exchange Commission.</P>

<P ALIGN=LEFT><B>Results of Operations</B></P>

<P ALIGN=LEFT><B>REVENUES</B></P>

<PRE>
                                                                                               Percent Change
                                                                                               From Prior Year
                                                                                              -----------------
 (thousands)                                      2000            1999             1998         2000      1999
---------------------------------------------------------------------------------------------------------------

Sales of electricity to OG&amp;E customers....    $ 1,440,637     $ 1,258,950      $ 1,274,643      14.4      (1.2)
Off-system sales..........................         12,948          27,894           37,435     (53.6)    (25.5)
Enogex....................................      1,845,142         885,512          304,694     108.4     190.6
Miscellaneous.............................            ---              78              965    (100.0)    (91.9)
-----------------------------------------------------------------------------------------------------
     Total operating revenues.............    $ 3,298,727     $ 2,172,434      $ 1,617,737      51.8      34.3
===============================================================================================================
System megawatt-hour sales................     25,001,686      23,468,130       23,642,599       6.5      (0.7)
Off-system megawatt-hour sales............        256,358         374,027          727,601     (31.5)    (48.6)
-----------------------------------------------------------------------------------------------------
     Total megawatt-hour sales............     25,258,044      23,842,157       24,370,200       5.9      (2.2)
===============================================================================================================
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In          2000,
approximately 56 percent of the Company's  revenues consisted of the non-utility
operations  of Enogex,  while the  remaining  44 percent  were  provided  by the
regulated sales of electricity by OG&amp;E as a public utility. Enogex's primary
operations consist of gathering and processing natural gas, transporting natural
gas through its pipelines in Oklahoma,  Arkansas and Texas for various customers
(including OG&amp;E), marketing electricity, natural gas and natural gas liquids
and  investing in the drilling for and  production of natural gas and crude oil.
While the marketing  activities of Enogex  represented  $1.3 billion of Enogex's
revenues in 2000,  this activity had relatively  low operating  margins and less
impact on earnings than other portions of Enogex's  business.  Revenues from the
sales  of  electricity  are  somewhat  seasonal,  with a  large  portion  of the
Company's annual electric  revenues  occurring during the summer months when the
electricity  needs  of  its  customers  increase.   Actions  of  the  regulatory
commissions  that set  OG&amp;E's  electric  rates will  continue  to affect the
Company's financial results.  The commissions also have the authority to examine
the  appropriateness  of  OG&amp;E's  recovery from its customers of fuel costs,
which include the transportation fees that OG&amp;E pays Enogex for transporting
natural gas to OG&amp;E's  generating  units. See "Regulation;  Competition" and
Note 11 of Notes to  Consolidated  Financial  Statements for a discussion of the
impact of Oklahoma  Corporation  Commission  ("OCC")  actions  relating to these
transportation fees.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Operating
revenues   increased  $1.1  billion  or  51.8  percent   during  2000,   largely
attributable to  significantly  increased  Enogex  revenues.  In 2000,  Enogex's
revenues  increased $959.6 million or 108.4 percent largely due to the inclusion
of a full year of revenues from  Transok's  operations  and to higher  commodity
prices and greater natural gas marketing, transportation and processing volumes.
The  integration  of  the  Transok  and  Enogex   pipelines  has  increased  gas
transportation revenue and provided Enogex's energy marketing unit with a better
platform from which to market natural gas.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E revenues
increased $166.7 million or 13 percent primarily  attributable to warmer weather
in the third  quarter  and colder  weather in the fourth  quarter in  OG&amp;E's
electric  service  area and the  recovery of higher fuel  costs.  The  favorable
weather was primarily  responsible  for a 14.4 percent  increase in revenue from
system sales. The increased  revenue from system sales was partially offset by a
53.6 percent  decrease in revenue from off-system  sales. The decline in revenue
from  off-system  sales  resulted  from a reduction  in both volumes and prices.
OG&amp;E  revenues  were also  adversely  affected  by the actions of the OCC in
lowering  recoveries by $10.9 million under the GEP Rider and  implementing  the
APC Rider, which reduced revenues by $10.2 million.  OG&amp;E's revenues in 2000
also were affected by a $2.3 million annual  reduction of its rates in Arkansas,
which  became  effective in August  1999.  See Note 11 of Notes to  Consolidated
Financial Statements for a more detailed discussion of these matters.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;During      1999,
revenues increased $554.7 million or 34.3 percent due to a significant  increase
in revenue from Enogex. In 1999,  Enogex's revenues  increased $580.8 million or
190.6  percent,  primarily  due to a  significant  increase in sales volumes and
rising prices in natural gas and natural gas liquids, the acquisition of Transok
in July  1999  ($274.9  million)  and  increased  power-marketing  sales  ($18.5
million).  The increased revenues from Enogex were partially offset by decreased
revenues  at  OG&amp;E.  Revenues  at OG&amp;E  decreased  $25.2  million or 1.9
percent  primarily due to a decrease in system sales and off-system  sales, both
of which  were  higher in 1998  because of the record  heat  experienced  in the
summer of 1998.  Lower  recoveries under the GEP Rider also contributed to lower
revenues at OG&amp;E.</P>

<P ALIGN=LEFT><B>EXPENSES AND OTHER ITEMS</B></P>

<PRE>
                                                                                                   Percent Change
                                                                                                  From Prior Year
                                                                                                  ----------------
 (dollars in thousands)                                   2000          1999          1998         2000     1999
------------------------------------------------------------------------------------------------------------------

Fuel ...............................................   $  451,613    $  309,327    $  315,194       46.0     (1.9)
Purchased power.....................................      263,328       249,203       240,542        5.7      3.6
Gas and electricity purchased for resale (Enogex)...    1,458,085       672,281       216,432      116.9    210.6
Other operation and maintenance.....................      536,751       382,235       305,106       40.4     25.3
Depreciation and amortization.......................      176,144       165,041       149,818        6.7     10.2
Taxes other than income.............................       62,985        56,182        51,188       12.1      9.8
------------------------------------------------------------------------------------------------------------------
     Total operating expenses.......................   $2,948,906    $1,834,269    $1,278,280       60.8     43.5
------------------------------------------------------------------------------------------------------------------
     Total other income (expenses)..................   $ (126,281)   $  (96,962)   $  (64,941)      30.2     49.3
------------------------------------------------------------------------------------------------------------------
     Provision for income taxes.....................   $   76,505    $   89,944    $  108,644      (14.9)   (17.2)
==================================================================================================================
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Total   operating
expenses  increased  $1.1  billion  or 60.8  percent in 2000,  primarily  due to
increased sales volumes,  rising commodity  prices,  and the full year impact of
the Transok acquisition in July 1999.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Enogex's  gas and
electricity  purchased for resale  pursuant to its  energy-marketing  operations
increased  $785.8 million or 116.9 percent in 2000 as compared to $455.8 million
or 210.6  percent  for 1999.  The 2000  increase  was due to natural  gas resale
activity  associated  with  Transok's  operations  ($243.6  million),  increased
natural gas prices and  increased  volumes in the  marketing of natural gas. The
1999 increase was due to a significant increase in sales volumes of natural gas,
the Transok acquisition in mid 1999, and increased power marketing sales.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other   operation
and  maintenance  increased  $154.5  million or 40.4  percent in 2000  primarily
because of the July 1999 Transok acquisition ($126.0 million), increased natural
gas purchases for operations  ($14.6  million),  higher  employee  benefit costs
($13.1 million) and higher labor costs ($6.6 million).  The increase in expenses
included $25 million of under-recovered pipeline system fuel expenses at Enogex.
Enogex  has,  among  other  actions,  filed for fuel rate  adjustments  with the
Federal Energy Regulatory Commission ("FERC") to recoup certain prior fuel costs
and to more  accurately  recover  fuel  costs  in the  future.  In  1999,  other
operation  and  maintenance  expenses  increased  $77.1  million or 25.3 percent
primarily  because of expansion  activities at Enogex ($66.1 million) and higher
bad debt expense at OG&amp;E  ($5.2  million).  These  increases  were partially
offset by reduced general corporate expenses ($2.7 million).</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's
electric generating capability is fairly evenly divided between coal and natural
gas and  provides  for  flexibility  to use  either  fuel to the  best  economic
advantage for OG&amp;E and its customers.  Despite this flexibility  (OG&amp;E's
fuel mix was 74 percent low-cost coal and 26 percent natural gas in 2000),  fuel
costs increased $142.3 million or 46.0 percent in 2000,  primarily due to a 29.9
percent  increase  in  the  average  cost  of  fuel  burned  for  generation  of
electricity and a 7.1 percent increase in total energy  generated.  During 1999,
fuel costs  decreased $5.9 million or 1.9 percent due to a 3.4 percent  decrease
in total generation,  which offset a 1.9 percent increase in the average cost of
fuel burned.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Variances  in the
actual cost of fuel used in electric  generation  and  certain  purchased  power
costs,  as compared to that component in  cost-of-service  for  ratemaking,  are
passed  through  to  OG&amp;E's   electric   customers  through  automatic  fuel
adjustment  clauses.  The  automatic  fuel  adjustment  clauses  are  subject to
periodic review by the OCC, the Arkansas Public Service Commission  ("APSC") and
the  FERC.  The OCC,  the  APSC  and the  FERC  have  authority  to  review  the
appropriateness  of gas  transportation  charges  or other  fees  OG&amp;E  pays
Enogex,  which OG&amp;E seeks to recover through the fuel  adjustment  clause or
other tariffs. See Note 11 of Notes to Consolidated Financial Statements.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's
purchased  power costs  increased $14.1 million or 5.7 percent in 2000 primarily
due to a 9.5 percent  increase in the cost of  purchased  energy per kwh,  which
offsets  a 4.3  percent  reduction  in  total  energy  purchased.  During  1999,
purchased power costs increased $8.7 million or 3.6 percent due in large part to
emergency  purchases in the aftermath of  tornadoes,  on May 3, 1999 and June 1,
1999,  which inflicted  heavy damage to the OG&amp;E power supply,  transmission
and delivery  systems.  In 1999, the cost of purchased  energy per kwh increased
8.7 percent.  As required by the Public Utility Regulatory Policy Act ("PURPA"),
OG&amp;E is currently purchasing power from qualified  cogeneration  facilities.
See Note 10 of Notes to Consolidated Financial Statements.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Depreciation  and
amortization  expenses increased $11.1 million or 6.7 percent, and $15.2 million
or 10.2 percent in 2000 and 1999,  respectively,  reflecting increased levels of
depreciable plant, primarily property of Transok.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Interest  expense
increased  $32.4  million or 32.3  percent in 2000  primarily  due to  increased
long-term  debt at  Enogex  as a result of the  Transok  acquisition  and due to
interest  costs on the trust  preferred  securities  issued in October 1999. The
proceeds from the increased  long-term debt and trust preferred  securities were
used to repay  short-term debt incurred to finance the Transok  acquisition.  In
1999,  interest  expense  increased  $29.6 million or 41.8 percent due to higher
interest charges at Enogex and costs  associated with increased  short-term debt
incurred to finance the Transok acquisition.</P>

<P ALIGN=LEFT><B>Liquidity and Capital Resources</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       primary
capital  requirements  for 2000 and as  estimated  for 2001  through 2003 are as
follows:</P>

<PRE>
(dollars in millions)                       2000      2001      2002      2003
================================================================================
Electric utility construction
  expenditures including AFUDC...........  $128.4    $118.0    $118.0    $118.0
Non-utility construction expenditures
  and acquisitions.......................    51.1      46.0      46.0      46.0
Maturities of long-term debt.............   169.0       7.0     115.0      14.3
--------------------------------------------------------------------------------
    Total................................  $348.5    $171.0    $279.0    $178.3
================================================================================
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
primary needs for capital are related to  construction of new facilities to meet
anticipated demand for OG&amp;E's utility service, to replace or expand existing
facilities  in  OG&amp;E's  electric  utility  business,  to  replace  or expand
existing  facilities in its non-utility  businesses,  to acquire new non-utility
facilities or businesses  and, to some extent,  to satisfy  maturing  debt.  The
Company  generally  meets its cash needs  through a  combination  of  internally
generated funds, short-term borrowings and permanent financing.</P>

<P ALIGN=LEFT><B>2000 CAPITAL REQUIREMENTS AND FINANCING ACTIVITIES</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Capital
requirements were $348.5 million in 2000. Approximately $4.4 million of the 2000
capital  requirements  were  to  comply  with  environmental  regulations.  This
compares  to  capital  requirements  of $729.9  million  in 1999,  of which $2.0
million was to comply with environmental regulations. During 2000, the Company's
sources of capital were  internally  generated  funds from operating cash flows,
permanent  financing  and  short-term  borrowings.  The  increases  in  accounts
receivable and accounts payable,  in 2000, are reflective of increased levels of
activity by the Enogex  marketing  unit and also  reflective of the  significant
increases in the cost of natural gas at both OG&amp;E and Enogex.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Short-term
borrowings  were  used  during  2000 to meet  temporary  cash  requirements.  At
December 31, 2000, the Company had outstanding  short-term  borrowings of $284.5
million.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   October  15,
2000, a $110 million  series of OG&amp;E's  6.25 percent  Senior Notes  matured.
OG&amp;E temporarily funded this transaction through short-term  borrowings from
the Company.  On October 23, 2000, OG&amp;E issued $110 million of 7.125 percent
Senior Notes,  Series due October 15, 2005.  Net proceeds from this  transaction
were used to repay the temporary short-term borrowings from the Company.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E acquired
two gas turbine  generators  for use at its Horseshoe Lake  Generating  Station.
These  two  generators  began  operation  on June 14 and  July  16,  2000.  Each
generator  can  produce  approximately  45  megawatts  of  additional  peak-load
generating  capacity.  The total  cost of this  project  was  approximately  $45
million.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On July 21, 2000,
OG&amp;E  reactivated  two of its  generators,  which had been idle for  several
years, at its Mustang Generating Station.  These two generators together produce
approximately 109 megawatts of additional  peak-load  generating  capacity.  The
total cost of this reactivation project was approximately $5 million.  Together,
these  four  generators  at  Horseshoe  Lake and  Mustang  increased  OG&amp;E's
electric generating capacity by approximately 4 percent.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As      discussed
previously,  on July 1, 1999,  Enogex  completed its  acquisition of Transok for
$710.3 million, which included assumption of $173 million of long-term debt. The
purchase of Transok was  temporarily  funded  through a $560  million  revolving
credit  agreement  with a  consortium  of banks with Bank One,  N.A.  serving as
agent. On October 21, 1999, the financing trust subsidiary of the Company issued
$200 million of 8.375 percent trust  preferred  securities  which mature October
15, 2039,  and all of the proceeds  were used to repay a portion of  outstanding
borrowings under the revolving  credit agreement  implemented in connection with
the Transok acquisition.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   January  14,
2000,  Enogex sold $400  million of 8.125  percent  senior  unsecured  notes due
January 15, 2010.  Enogex  entered into a series of one year  interest rate swap
agreements to manage  interest  costs  associated  with this $400 million issue.
During 2000, the effect of these swap agreements  reduced the overall  effective
interest  rate from 8.125  percent to 6.6875  percent.  The interest  rate swaps
expired in January 2001.  Enogex used the proceeds from the issuance of this new
debt to repay the Company for the temporary  short-term debt associated with the
Transok acquisition and for general corporate purposes.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Enogex  used cash
flow from operations to retire $57 million of long-term debt that matured in the
third quarter of 2000.  This debt consisted of $23 million  principal  amount of
6.77 percent  medium-term  notes due August 7, 2000, $4 million principal amount
of 6.76  percent  medium-term  notes due August 7, 2000,  $20 million  principal
amount of 6.68 percent  medium-term  notes due August 31, 2000,  and $10 million
principal amount of 6.70 percent medium-term notes due September 1, 2000. Enogex
is expected to continue  reducing its  outstanding  long-term  debt during 2001.
Enogex retired $5 million of long-term debt in January 2001.</P>

<P ALIGN=LEFT><B>FUTURE CAPITAL REQUIREMENTS</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
construction  program for the next  several  years does not  include  additional
base-load generating units.  Rather, to meet the increased  electricity needs of
OG&amp;E's  electric utility customers during the foreseeable  future,  OG&amp;E
will  concentrate on maintaining  the reliability and increasing the utilization
of  existing  capacity,   increasing  demand-side  management  efforts  and,  if
necessary,  purchasing  power from third  parties.  OG&amp;E  will  continue  to
evaluate these strategies  against the construction of additional  peaking units
or another  base-load  generating unit. These  evaluations will consider,  among
other things,  the amount of capital  requirements and the relative cost of fuel
supply,  compared  to other  alternatives.  Approximately  $2.5  million  of the
Company's  construction  expenditures  budgeted  for  2001  are to  comply  with
environmental laws and regulations.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  Company will
continue to pursue a convergence  strategy for its  electricity  and natural gas
businesses.  This strategy  seeks to maximize the value of the  Company's  power
plants  and  gas  pipelines  by   coordinating,   consistent   with   regulatory
requirements,    their   activities   through   its   marketing,   trading   and
energy-services unit.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As  discussed  in
Note 8 of Notes to Consolidated Financial Statements,  the Company recently made
several  changes to its pension  plan,  including the addition of a cash balance
benefit feature. The cash balance plan may provide lower post-employment pension
benefits  to  employees,  which  could  result  in less  pension  expense  being
recorded.  Over the near term, the Company's cash  requirements for the plan are
not expected to be materially different than the requirements  existing prior to
the plan changes.  However,  as the population of employees included in the cash
balance  plan  feature  increases,   the  Company's  cash  requirements  may  be
materially  different than the  requirements  under the Company's  prior pension
plan.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Future  financing
requirements may be dependent, to varying degrees, upon numerous factors such as
general economic  conditions,  abnormal  weather,  load growth,  acquisitions of
other businesses,  inflation, changes in environmental laws or regulations, rate
increases or decreases  allowed by  regulatory  agencies,  new  legislation  and
market entry of competing electric power generators.</P>

<P ALIGN=LEFT><B>FUTURE SOURCES OF FINANCING</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Management
expects that  internally  generated  funds will be adequate  over the next three
years to meet anticipated construction expenditures.  Short-term borrowings will
continue to be used to meet  temporary  cash  requirements.  The Company has the
necessary approvals to incur up to $400 million in short-term  borrowings at any
one time. At December 31, 2000, the Company had in place a line of credit for up
to $300  million,  with $200  million to expire on  January  15,  2001,  and the
remaining  $100  million to expire on January 15,  2004.  In January  2001,  the
Company's line of credit for $200 million was renewed,  with an expiration  date
of January 15, 2002.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Company
continues to evaluate  opportunities to enhance  shareowner  returns and achieve
long-term financial objectives through  acquisitions of non-utility  businesses.
Permanent financing could be required for such acquisitions.</P>

<P ALIGN=LEFT><B>ELECTRIC COMPETITION; REGULATION</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As     previously
reported,  Oklahoma enacted in April 1997 the Electric Restructuring Act of 1997
(the  "Act"),  which is designed to provide  for choice by retail  customers  of
their  electric  supplier by July 1, 2002.  Various  amendments  to the Act were
enacted  in 1998  and  1999.  Additional  implementing  legislation  needs to be
adopted by the Oklahoma  Legislature to address many specific issues  associated
with the Act and with  deregulation.  If implemented  as proposed,  the Act will
significantly affect OG&amp;E's future operations.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The        stated
purpose of the Act is generally to restructure the electric  utility industry to
provide  for more  competition  and, in  particular,  to provide for the orderly
restructuring  of the  electric  utility  industry in Oklahoma in order to allow
customers to choose their electricity suppliers while maintaining the safety and
reliability  of the  electric  system in the state.  The Act  directed the Joint
Electric Utility Task Force,  composed of seven members from the Oklahoma Senate
and seven  members from the Oklahoma  House of  Representatives,  to undertake a
study of all relevant  issues  relating to  restructuring  the electric  utility
industry in Oklahoma and to develop a proposed  electric  utility  framework for
Oklahoma. The study was completed in 1999.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Neither       the
Oklahoma Tax  Commission  nor the OCC is  authorized  under the Act to issue any
rules on such matters  without the approval of the Oklahoma  Legislature.  Other
provisions of the Act, (i) prohibit  customer  switching  prior to July 1, 2002,
except  by mutual  consent,  (ii)  prohibit  municipalities  that do not  become
subject to the Act, from selling power outside their  municipal  limits,  except
from  lines  owned on April 25,  1997,  (iii)  require a uniform  tax  policy be
established  by  July  1,  2002  and  (iv)  require  out-of-state  suppliers  of
electricity  and  their  affiliates  who make  retail  sales of  electricity  in
Oklahoma through the use of transmission and distribution facilities of in-state
suppliers  to  provide  equal  access  to their  transmission  and  distribution
facilities outside of Oklahoma.  The Act was modified during the 1999 session of
the Oklahoma Legislature to clarify certain ambiguities by defining key terms in
the Act.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As      discussed
above, additional  implementing  legislation needs to be adopted by the Oklahoma
Legislature  to address many specific  issues  associated  with the Act and with
deregulation. In May 2000, a bill addressing the specific issues of deregulation
was passed in the  Oklahoma  State  Senate and then was defeated in the Oklahoma
House of Representatives.  The Company cannot predict what, if any,  legislation
will be adopted at the next  legislative  session.  The Company will participate
actively in the  legislative  process and expects the  scheduled  start date for
customer choice of July 1, 2002, to be postponed.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In   April  1999,
Arkansas became the 18th state to pass a law ("the  Restructuring  Law") calling
for  restructuring  of the electric  utility  industry at the retail level.  The
Arkansas  Restructuring Law, like the Oklahoma law, would  significantly  affect
OG&amp;E's future operations. OG&amp;E's electric service area includes parts of
western Arkansas,  including Fort Smith, the second-largest  metropolitan market
in the state.  The  Restructuring  Law  initially  targeted  customer  choice of
electricity  providers by January 1, 2002. In February 2001, the law was amended
to delay the start date of  customer  choice of electric  providers  in Arkansas
until  October  1,  2003,  with the APSC  having  discretion  to  further  delay
implementation  to October 1, 2005.  The  Restructuring  Law also  provides that
utilities  owning or controlling  transmission  assets must transfer  control of
such  transmission  assets  to  an  independent  system  operator,   independent
transmission  company or regional  transmission  group, if any such organization
has been approved by the FERC. Other provisions of the  Restructuring Law permit
municipal  electric  systems to opt in or out, permit recovery of stranded costs
and  transition  costs and require  filing of  unbundled  rates for  generation,
transmission,  distribution  and customer  service.  OG&amp;E filed  preliminary
business  separation plans with the APSC on August 8, 2000. The APSC established
a  timetable  to  establish  rules   implementing  the  Arkansas   restructuring
statutes.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  OCC also has
adopted  rules that are  designed to make the gas  utility  business in Oklahoma
more competitive. These rules do not impact the electric industry. The rules are
expected  to offer  increased  opportunities  to Enogex's  pipeline  and related
businesses.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The   efforts  to
increase  competition  in the electric  industry at the retail level in Oklahoma
and Arkansas have been  paralleled  and even surpassed by efforts at the federal
level to increase  competition  in the wholesale  markets for  electricity.  The
National Energy Policy Act of 1992 ("Energy Act"), among other things,  promoted
the  development of independent  power  producers  ("IPPs").  The Energy Act was
followed  by FERC  Order  888  and  Order  889,  which  facilitated  third-party
utilization of the transmission grid for sales of wholesale power.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  Energy  Act,
Orders 888 and 889, and other FERC policies and initiatives  have  significantly
increased  competition  in the  wholesale  power  market.  Utilities,  including
OG&amp;E,  have increased their own in-house wholesale marketing efforts and the
number of  entities  with whom they  trade.  Moreover,  power  marketers  are an
increasingly  important  presence  in the  industry.  These  entities  typically
arbitrage  wholesale price  differentials  by buying power produced by others in
one market and selling it in another.  IPPs also are becoming a more significant
sector  of the  electric  utility  industry.  In  both  Oklahoma  and  Arkansas,
significant additions of new power plants have been announced,  almost all of it
from IPPs.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Notwithstanding
these  developments  in  the  wholesale  power  market,   FERC  recognized  that
impediments  remained to the achievement of fully competitive  wholesale markets
including:  (i) engineering and economic  inefficiencies inherent in the current
operation  and  expansion  of  the   transmission   grid  and  (ii)   continuing
opportunities  for  transmission   owners  (primarily   electric  utilities)  to
discriminate in the operation of their transmission facilities in favor of their
own or  affiliated  power  marketing  activities.  Whereas FERC in the past only
encouraged  utilities  to join and place their  transmission  systems  under the
operational control of independent system operators ("ISOs"), FERC, issued Order
2000 on December 20, 1999, its final rule on regional transmission organizations
("RTOs").  Order 2000 is  intended  to have the effect of turning  the  nation's
transmission facilities into independently operated "common carriers" that offer
comparable service to all would-be-users. Although adopting a voluntary approach
towards RTO  formation,  FERC stressed that Order 2000 does not preclude it from
requiring  RTO  participation.  Order  2000  sets  out  a  timetable  for  every
jurisdictional utility (including OG&amp;E) to either join in an RTO filing, or,
alternatively,  to submit a filing by October 15, 2000 describing its efforts to
join an RTO,  the  reasons  for not  participating  in an RTO  proposal  and any
obstacles   to   participation,   and  its  plans  for   further   work   toward
participation.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E   is   a
member  of  the  Southwest   Power  Pool  ("SPP"),   the  regional   reliability
organization for Oklahoma,  Arkansas,  Kansas,  Louisiana,  Missouri and part of
Texas.  OG&amp;E  participated  with  the  SPP in the  development  of  regional
transmission tariffs and executed an Agency Agreement with the SPP to facilitate
interstate  transmission operations within this region. In October 2000, the SPP
filed its application  with the FERC to become an RTO.  OG&amp;E intends to meet
its obligations  under Order 2000 and under the restructuring law in Arkansas by
joining the RTO being formed by the SPP. The transfer of operational  control of
OG&amp;E's  transmission  system  to a  FERC-approved  RTO  is not  expected  to
significantly  impact  OG&amp;E's  financial  results.  Yet,  it is  expected to
increase the markets in which  OG&amp;E can sell power at wholesale  and, at the
same time, to increase  competition  in such  wholesale  markets.  As a low-cost
producer  of  electricity  with two of the most  efficient  power  plants in the
country, OG&amp;E expects to remain a competitive supplier of electricity.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As      discussed
previously,   legislation  was  enacted  in  Oklahoma  and  Arkansas  that  will
restructure the electric utility industry in those states, assuming that all the
conditions  in the  legislation  are  met.  This  legislation  would  deregulate
OG&amp;E's  electric  generation  assets and the  continued  use of Statement of
Financial  Accounting  Standards ("SFAS") No. 71; "Accounting for the Effects of
Certain Types of Regulation" with respect to the related  regulatory  assets may
no  longer  be  appropriate.   This  may  result  in  either  full  recovery  of
generation-related  regulatory assets (net of related regulatory liabilities) or
a non-cash,  pre-tax write-off as an extraordinary  charge of up to $29 million,
depending on the  transition  mechanisms  developed by the  legislature  for the
recovery of all or a portion of these net regulatory assets.</P>

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

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   January  12,
2000, the OCC Staff (the "Staff") filed three  applications  to address  various
aspects  of  OG&amp;E's  electric  rates.  See Note 11 of Notes to  Consolidated
Financial Statements for a discussion of these matters.</P>

<P ALIGN=LEFT><B>MARKET RISK</B></P>

<P ALIGN=LEFT><B>RISK MANAGEMENT</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The          risk
management  process  established  by the  Company is  designed  to measure  both
quantitative and qualitative  risks in its businesses.  A senior risk management
committee has been  established  to review these risks on a regular  basis.  The
Company is exposed to market risk, including changes in certain commodity prices
and interest rates.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;To   manage   the
volatility  relating  to  these  exposures,  the  Company  enters  into  various
derivative transactions pursuant to the Company's policies on hedging practices.
Derivative  positions  are monitored  using  techniques  such as  mark-to-market
valuation, value-at-risk and sensitivity analysis.</P>

<P ALIGN=LEFT><B>INTEREST RATE RISK</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
exposure  to changes in interest  rates  relates  primarily  to  long-term  debt
obligations and commercial paper. The Company manages its interest rate exposure
by  limiting  its   variable-rate   debt  to  a  certain   percentage  of  total
capitalization  and by  monitoring  the  effects of market  changes in  interest
rates.  The Company may utilize interest rate derivatives to alter interest rate
exposure in an attempt to reduce  interest rate expense related to existing debt
issues.  Interest  rate  derivatives  are used  solely to modify  interest  rate
exposure and not to modify the overall leverage of the debt portfolio.  The fair
value  of  long-term  debt is  estimated  based  on  quoted  market  prices  and
management's  estimate  of current  rates  available  for  similar  issues.  The
following  table  itemizes  the  Company's  long-term  debt  maturities  and the
weighted-average interest rates by maturity date.</P>

<PRE>
=========================================================================================================================
                                                                                                                 2000
                                                                                                               Year-end
(dollars in millions)          2001       2002       2003       2004       2005      Thereafter     Total     Fair Value
-------------------------------------------------------------------------------------------------------------------------
Fixed rate debt:
  Principal amount.........   $  7.0     $115.0     $ 14.3     $ 57.8     $152.9     $ 1,170.9    $1,517.9    $1,550.0
  Weighted-average
    interest rate..........     7.15%      7.34%      7.70%      7.20%      7.09%         7.57%       7.34%        ---
Variable-rate debt:
  Principal amount.........      ---        ---        ---        ---        ---     $   135.4    $  135.4    $  135.4
  Weighted-average
    interest rate..........      ---        ---        ---        ---        ---          4.25%       4.25%        ---
=========================================================================================================================
</PRE>

<P ALIGN=LEFT><B>COMMODITY PRICE EXPOSURE</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  market  risk
inherent in the Company&#146;s  market risk sensitive  instruments and positions
are  the  potential   loss  in  value  arising  from  adverse   changes  in  the
Company&#146;s commodity prices.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The   prices   of
natural gas,  natural gas liquids and  electricity  are subject to  fluctuations
resulting  from  changes in supply and demand.  To  partially  reduce price risk
caused  by these  market  fluctuations,  the  Company  may  hedge  (through  the
utilization  of  derivatives)  a portion of the  Company's  supply  and  related
purchase and sale contracts, as well as any anticipated  transactions (purchases
and  sales).  See  "Price  Risk  Management  Activities"  in Note 1 of  Notes to
Consolidated  Financial  Statements.  Because the  commodities  covered by these
derivatives are  substantially  the same  commodities  that the Company buys and
sells in the physical  market,  no special  studies  other than  monitoring  the
degree of  correlation  between  the  derivative  and cash  markets  are  deemed
necessary.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;A     sensitivity
analysis has been prepared to estimate the price  exposure to the market risk of
the  Company's  natural  gas,  natural  gas liquids  and  electricity  commodity
positions.  The Company's daily net commodity  position  consists of natural gas
inventories,   purchased  electric   capacity,   commodity  purchase  and  sales
contracts, and derivative financial and commodity instruments. The fair value of
such position is a summation of the fair values calculated for each commodity by
valuing each net position at quoted market  prices.  Market risk is estimated as
the  potential  loss in fair  value  resulting  from a  hypothetical  10 percent
adverse  change in such  prices  over the next 12  months.  The  results of this
analysis,  which may differ  from  actual  results,  are as  follows  for fiscal
2001:</P>

<PRE>
(dollars in thousands)                 Wholesale            Non-Trading
========================================================================

Commodity market risk, net.......      $   3,138            $    6,249
========================================================================
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In June 1998, the
Financial  Accounting  Standards  Board ("FASB")  issued  Statement of Financial
Accounting  Standards ("SFAS") No. 133,  "Accounting for Derivative  Instruments
and for Hedging Activities",  with an effective date for periods beginning after
June 15,  1999.  In July 1999,  the FASB issued SFAS No.  137,  "Accounting  for
Derivative  Instruments and Hedging  Activities - Deferral of the Effective Date
of FASB  Statement No. 133".  As a result of SFAS No. 137,  adoption of SFAS No.
133 is now required for financial  statements for periods  beginning  after June
15, 2000. In June 2000,  the FASB issued SFAS No. 138,  "Accounting  for Certain
Derivative  Instruments  and  Certain  Hedging  Activities",  which  amends  the
accounting  and  reporting  standards  of SFAS No.  133 for  certain  derivative
instruments and hedging activities. SFAS No. 133 sweeps in a broad population of
transactions  and changes the  previous  accounting  definition  of a derivative
instrument.  Under SFAS No. 133, every derivative  instrument is recorded in the
balance sheet as either an asset or liability  measured at its fair value.  SFAS
No. 133  requires  that  changes in the  derivative's  fair value be  recognized
currently in earnings unless specific hedge accounting  criteria are met. During
2000, the Company  established an SFAS No. 133 implementation team that reviewed
contracts  throughout the Company  identifying  both  freestanding  and embedded
derivatives  which met the  criteria set forth in SFAS No. 133 and SFAS No. 138.
The Company adopted the new standards  effective  January 1, 2001. On January 1,
2001, the Company  redesignated all of its hedging  relationships and recognized
all derivatives at their fair value in accordance with SFAS No. 133 and SFAS No.
138. As a result of adopting these  standards the Company  recorded a cumulative
effect   transition   adjustment   debit  to  Other   Comprehensive   Income  of
approximately $26.9 million.</P>

<P ALIGN=LEFT><B>CONTINGENCIES</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Company
through  its  subsidiaries  is  defending  various  claims  and  legal  actions,
including  environmental  actions,  which  are  common  to its  operations.  The
Company's  subsidiaries,  primarily OG&amp;E,  also could be impacted by various
proposed environmental  regulations that if adopted, could result in significant
increases  in  capital  expenditures  and  operating  expenses.  For  a  further
discussion of these matters,  including a lawsuit involving Trigen-Oklahoma City
Energy Corporation,  see Note 10 of Notes to Consolidated  Financial Statements.
As to  environmental  matters,  OG&amp;E has been  designated as a  "potentially
responsible  party"  ("PRP")  with  respect  to a waste  disposal  site to which
OG&amp;E  sent  materials.  While it is not  possible to  determine  the precise
outcome of this  matter,  in the  opinion  of  management,  OG&amp;E's  ultimate
liability for this site will not be material.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Besides       the
various existing contingencies herein described,  and those described in Note 10
of Notes to Consolidated Financial Statements, the Company's ability to fund its
future  operational  needs and to finance its construction  program is dependent
upon  numerous  other  factors  beyond its  control,  such as  general  economic
conditions,  abnormal weather, load growth, inflation, new environmental laws or
regulations, and the cost and availability of external financing.</P>

<P ALIGN=LEFT><B>2001 OUTLOOK</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Company
expects  that  earnings  in 2001 will be at $2.00 to $2.10 per  share.  Earnings
growth is expected primarily from improved performance at Enogex.</P><BR>



<P ALIGN=LEFT><FONT SIZE=2><B><U>Item 8.  Financial Statements and Supplementary
 Data.</U></B></FONT></P>

<P ALIGN=CENTER><B>CONSOLIDATED BALANCE SHEETS</B></P>


<PRE>


December 31 (dollars in thousands)                                    2000           1999           1998
============================================================================================================
ASSETS

CURRENT ASSETS:
  Cash and cash equivalents....................................    $      454     $    7,271     $      378
  Accounts receivable - customers, less reserve of $4,135,
    $5,270 and $3,342, respectively............................       446,185        263,708        141,235
  Accrued unbilled revenues....................................        49,000         40,200         22,500
  Accounts receivable - other..................................        24,713         10,462         12,902
  Fuel inventories.............................................       200,316        117,185         57,288
  Materials and supplies, at average cost......................        41,517         39,194         29,734
  Prepayments and other........................................        45,715         12,328         30,753
  Price risk management........................................        45,727          4,583            798
  Accumulated deferred tax assets..............................        10,669          8,729          7,811
------------------------------------------------------------------------------------------------------------
    Total current assets.......................................       864,296        503,660        303,399
------------------------------------------------------------------------------------------------------------
OTHER PROPERTY AND INVESTMENTS, at cost........................        36,980         31,012         31,682
------------------------------------------------------------------------------------------------------------
PROPERTY, PLANT AND EQUIPMENT:
  In service...................................................     5,323,541      5,209,783      4,391,232
  Construction work in progress................................        47,016         56,553         50,039
------------------------------------------------------------------------------------------------------------
    Total property, plant and equipment........................     5,370,557      5,266,336      4,441,271
      Less accumulated depreciation............................     2,151,093      2,024,349      1,914,721
------------------------------------------------------------------------------------------------------------
  Net property, plant and equipment............................     3,219,464      3,241,987      2,526,550
------------------------------------------------------------------------------------------------------------

DEFERRED CHARGES:
  Advance payments for gas.....................................        12,500         11,800         15,000
  Income taxes recoverable through future rates................        38,654         39,692         40,731
  Other........................................................       147,736         93,183         66,567
------------------------------------------------------------------------------------------------------------
    Total deferred charges.....................................       198,890        144,675        122,298
------------------------------------------------------------------------------------------------------------

TOTAL ASSETS...................................................    $4,319,630     $3,921,334     $2,983,929
============================================================================================================





The accompanying Notes to Consolidated Financial Statements are an integral part hereof.








                                     CONSOLIDATED BALANCE SHEETS (Continued)


December 31 (dollars in thousands)                                    2000           1999           1998
============================================================================================================
LIABILITIES AND STOCKHOLDERS' EQUITY

CURRENT LIABILITIES:
  Short-term debt..............................................    $  284,500     $  589,100     $  119,100
  Accounts payable.............................................       330,445        161,183         96,936
  Dividends payable............................................        25,890         25,889         26,865
  Customers' deposits..........................................        22,647         22,138         23,985
  Accrued taxes................................................        33,067         41,215         30,500
  Accrued interest.............................................        40,699         28,191         21,081
  Long-term debt due within one year...........................         2,000        169,000          2,000
  Price risk management........................................        33,709          1,297          4,645
  Other........................................................        36,975         38,848         30,721
------------------------------------------------------------------------------------------------------------
    Total current liabilities..................................       809,932      1,076,861        355,833
------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT.................................................     1,648,523      1,140,532        935,583
------------------------------------------------------------------------------------------------------------

DEFERRED CREDITS AND OTHER LIABILITIES:
  Accrued pension and benefit obligation.......................        14,256         16,686         17,952
  Accumulated deferred income taxes............................       618,360        566,137        531,940
  Accumulated deferred investment tax credits..................        57,429         62,578         67,728
  Other........................................................       106,822         39,161         31,511
------------------------------------------------------------------------------------------------------------
    Total deferred credits and other liabilities...............       796,867        684,562        649,131
------------------------------------------------------------------------------------------------------------

STOCKHOLDERS' EQUITY:
  Common stockholders' equity..................................       443,298        441,847        513,614
  Retained earnings............................................       621,010        577,532        529,768
------------------------------------------------------------------------------------------------------------
    Total stockholder's equity.................................     1,064,308      1,019,379      1,043,382
------------------------------------------------------------------------------------------------------------

TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY.....................    $4,319,630     $3,921,334     $2,983,929
============================================================================================================





The accompanying Notes to Consolidated Financial Statements are an integral part hereof.








                                         CONSOLIDATED STATEMENTS OF CAPITALIZATION


December 31 (dollars in thousands)                                           2000           1999           1998
==================================================================================================================
COMMON STOCK AND RETAINED EARNINGS:
  Common stock, par value $0.01 per share,
    authorized 125,000,000 shares; and
    outstanding 77,921,997, 77,863,370,
    and 80,797,539 shares, respectively..............................    $      779     $      779     $      808
  Premium on capital stock...........................................       442,519        441,068        512,806
  Retained earnings..................................................       621,010        577,532        529,768
------------------------------------------------------------------------------------------------------------------
      Total common stock and retained earnings.......................     1,064,308      1,019,379      1,043,382
------------------------------------------------------------------------------------------------------------------
LONG-TERM DEBT:
    SERIES    DATE DUE
    6.250%    Senior Notes, Series Due October 15, 2000..............           ---        110,000        110,000
    7.125%    Senior Notes, Series Due October 15, 2005..............       110,000            ---            ---
    6.500%    Senior Notes, Series Due July 15, 2017.................       125,000        125,000        125,000
    7.300%    Senior Notes, Series Due October 15, 2025..............       110,000        110,000        110,000
    6.650%    Senior Notes, Series Due July 15, 2027.................       125,000        125,000        125,000
    6.500%    Senior Notes, Series Due April 15, 2028................       100,000        100,000        100,000
  Other bonds-
    Var. %    Garfield Industrial Authority, January 1, 2025.........        47,000         47,000         47,000
    Var. %    Muskogee Industrial Authority, January 1, 2025.........        32,400         32,400         32,400
    Var. %    Muskogee Industrial Authority, June 1, 2027............        56,000         56,000         56,000
  Unamortized premium and discount, net..............................        (2,818)        (2,354)        (2,488)
  Enogex Inc. notes (Note 6).........................................       574,941        233,486        234,671
  Transok Holding LLC (Note 6).......................................       173,000        173,000            ---
  Trust Originated Preferred Securities (Note 5).....................       200,000        200,000            ---
------------------------------------------------------------------------------------------------------------------
      Total long-term debt...........................................     1,650,523      1,309,532        937,583
        Less long-term debt due within one year......................         2,000        169,000          2,000
------------------------------------------------------------------------------------------------------------------
      Total long-term debt (excluding long-term
        debt due within one year)....................................     1,648,523      1,140,532        935,583
------------------------------------------------------------------------------------------------------------------
Total Capitalization.................................................    $2,712,831     $2,159,911     $1,978,965
==================================================================================================================






The accompanying Notes to Consolidated Financial Statements are an integral part hereof.








                                              CONSOLIDATED STATEMENTS OF INCOME


Year ended December 31 (dollars in thousands except per share data)       2000           1999           1998
================================================================================================================
OPERATING REVENUES.................................................    $3,298,727     $2,172,434     $1,617,737
----------------------------------------------------------------------------------------------------------------
OPERATING EXPENSES:
  Fuel.............................................................       451,613        309,327        315,194
  Purchased power..................................................       263,328        249,203        240,542
  Gas and electricity purchased for resale.........................     1,458,085        672,281        216,432
  Other operation and maintenance..................................       536,751        382,235        305,106
  Depreciation and amortization....................................       176,144        165,041        149,818
  Taxes other than income..........................................        62,985         56,182         51,188
----------------------------------------------------------------------------------------------------------------
    Total operating expenses.......................................     2,948,906      1,834,269      1,278,280
----------------------------------------------------------------------------------------------------------------
OPERATING INCOME...................................................       349,821        338,165        339,457
----------------------------------------------------------------------------------------------------------------
OTHER INCOME, NET..................................................         2,595            480          2,197
----------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INTEREST AND TAXES.................................       352,416        338,645        341,654

INTEREST INCOME (EXPENSES):
  Interest income..................................................         3,788          2,837          3,561
  Interest on long-term debt.......................................      (101,452)       (60,727)       (60,856)
  Interest on trust preferred securities...........................       (17,268)        (3,358)           ---
  Other interest charges...........................................       (13,944)       (36,194)        (9,843)
----------------------------------------------------------------------------------------------------------------
    Net interest income (expenses).................................      (128,876)       (97,442)       (67,138)
----------------------------------------------------------------------------------------------------------------
EARNINGS BEFORE INCOME TAXES.......................................       223,540        241,203        274,516
INCOME TAX EXPENSE.................................................        76,505         89,944        108,644
----------------------------------------------------------------------------------------------------------------
NET INCOME.........................................................       147,035        151,259        165,872
PREFERRED DIVIDEND REQUIREMENTS....................................           ---            ---            733
----------------------------------------------------------------------------------------------------------------
EARNINGS AVAILABLE FOR COMMON STOCK................................    $  147,035     $  151,259     $  165,139
================================================================================================================
AVERAGE COMMON SHARES OUTSTANDING (thousands)......................        77,864         77,916         80,772
EARNINGS PER AVERAGE COMMON SHARE..................................    $     1.89           1.94     $     2.04
AVERAGE COMMON SHARES OUTSTANDING ASSUMING DILUTION (thousands)....        77,688         77,831         80,787
EARNINGS PER AVERAGE COMMON SHARE ASSUMING DILUTION................    $     1.89           1.94     $     2.04
================================================================================================================





The accompanying Notes to Consolidated Financial Statements are an integral part hereof.








                                   CONSOLIDATED STATEMENTS OF RETAINED EARNINGS


Year ended December 31 (dollars in thousands)                         2000           1999           1998
============================================================================================================
BALANCE AT BEGINNING OF PERIOD.................................    $  577,532     $  529,768     $  472,063
ADD - net income...............................................       147,035        151,259        165,872
------------------------------------------------------------------------------------------------------------
  Total........................................................       724,567        681,027        637,935
------------------------------------------------------------------------------------------------------------

DEDUCT:
  Cash dividends declared on preferred stock...................           ---            ---            733
  Cash dividends declared on common stock......................       103,557        103,495        107,434
------------------------------------------------------------------------------------------------------------
    Total......................................................       103,557        103,495        108,167
------------------------------------------------------------------------------------------------------------
BALANCE AT END OF PERIOD.......................................    $  621,010     $  577,532     $  529,768
============================================================================================================






The accompanying Notes to Consolidated Financial Statements are an integral part hereof.








                                       CONSOLIDATED STATEMENTS OF CASH FLOWS


Year ended December 31 (dollars in thousands)                         2000           1999           1998
============================================================================================================
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net Income...................................................    $  147,035     $  151,259     $  165,872
  Adjustments to Reconcile Net Income to Net Cash Provided
   from Operating Activities:
    Depreciation and amortization..............................       176,144        165,041        149,818
    Deferred income taxes and investment tax credits, net......        46,999         31,093         23,922
    Gain on sale of assets.....................................        (4,820)           ---            ---
    Change in Certain Current Assets and Liabilities:
      Accounts receivable - customers..........................      (182,477)       (69,875)       (23,875)
      Accrued unbilled revenues................................        (8,800)       (17,700)        14,400
      Fuel, materials and supplies inventories.................       (85,454)       (25,049)        (9,223)
      Other current assets.....................................       (90,724)        16,274        (26,513)
      Accounts payable.........................................       169,262          9,668         19,203
      Accrued taxes............................................        (8,148)        10,715          8,823
      Accrued interest.........................................        12,508          7,110          1,040
      Other current liabilities................................        31,048        (48,451)        (3,577)
  Other operating activities...................................         8,796         (5,832)       (28,103)
------------------------------------------------------------------------------------------------------------
        Net cash provided from operating activities............       211,369        224,253        292,269
------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Capital expenditures.........................................      (179,471)      (181,163)      (235,231)
  Proceeds from sale of assets.................................        23,573            ---            ---
  Acquisition of Transok.......................................           ---       (531,767)           ---
  Other investing activities...................................           637          2,832         (8,084)
------------------------------------------------------------------------------------------------------------
        Net cash used in investing activities..................      (155,261)      (710,098)      (243,315)
------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Retirement of long-term debt.................................      (168,545)        (2,000)      (113,500)
  Proceeds from long-term debt.................................       510,000            ---        100,000
  Increase (decrease) in short-term debt, net..................      (304,600)       470,000        118,100
  Issuance (retirement) of common stock........................             1            (30)           ---
  Premium on issuance (retirement) of common stock.............         1,450        (71,737)           ---
  Issuance of trust originated preferred securities............           ---        200,000            ---
  Redemption of preferred stock................................           ---            ---        (49,266)
  Contribution from minority interest..........................         2,590            ---            ---
  Payment of obligation under capital lease....................          (264)           ---            ---
  Cash dividends declared on preferred stock...................           ---            ---           (733)
  Cash dividends declared on common stock......................      (103,557)      (103,495)      (107,434)
------------------------------------------------------------------------------------------------------------
        Net cash (used in) provided from financing activities..       (62,925)       492,738        (52,833)
------------------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS...........        (6,817)         6,893         (3,879)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD...............         7,271            378          4,257
CASH AND CASH EQUIVALENTS AT END OF PERIOD.....................    $      454     $    7,271     $      378
============================================================================================================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
  Cash Paid During the Period for:
    Interest (net of amount capitalized).......................    $  105,288     $   76,047     $   59,792
    Income taxes...............................................    $   48,680     $   52,428     $   77,150
------------------------------------------------------------------------------------------------------------
NON-CASH INVESTING AND FINANCING ACTIVITIES
  Capital lease financing......................................    $      ---     $      ---     $    9,818
  Debt assmed in acquisition...................................    $      ---     $  173,000     $   80,000
  Other investing and financing activities.....................    $    2,400     $    3,182     $   (3,000)
  Current liabilities assumed in acquisition of Transok........    $      ---     $   98,917     $      ---
============================================================================================================




The accompanying Notes to Consolidated Financial Statements are an integral part hereof.

</PRE>


<P ALIGN=LEFT><B>Notes To Consolidated Financial Statements</B></P>

<P><B>1.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Summary of Significant Accounting Policies
</B></P><BR>


<P ALIGN=LEFT><B>ORGANIZATION</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE  Energy Corp.
(the  "Company")  is the parent  company of Oklahoma  Gas and  Electric  Company
("OG&amp;E"),  Enogex Inc. and  subsidiaries  ("Enogex")  and OGE Energy Capital
Trust I. All  significant  intercompany  transactions  have been  eliminated  in
consolidation.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Company
distributes  operating  costs  to  its  affiliates  based  on  several  factors.
Operating  costs directly  related to specific  affiliates are assigned to those
affiliates.  Where more than one affiliate  benefits from certain  expenditures,
the costs are shared between those affiliates receiving the benefits.  Operating
costs  incurred  for the  benefit  of all  affiliates  are  allocated  among the
affiliates, based primarily upon head-count, occupancy, usage or the "Distragas"
method.  The  Distragas  method  is a  three-factor  formula  that uses an equal
weighting of payroll,  operating  income and assets.  The Company  believes this
method provides a reasonable basis for allocating common expenses.</P>

<P ALIGN=LEFT><B>ACCOUNTING RECORDS</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The    accounting
records of OG&amp;E are  maintained  in  accordance  with the Uniform  System of
Accounts  prescribed by the Federal Energy  Regulatory  Commission  ("FERC") and
adopted by the Oklahoma  Corporation  Commission ("OCC") and the Arkansas Public
Service Commission ("APSC"). Additionally,  OG&amp;E, 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  costs that would  otherwise be charged to expense can be
deferred as regulatory  assets,  based on expected  recovery  from  customers in
future rates. Likewise,  certain credits that would otherwise reduce expense are
deferred as regulatory  liabilities  based on 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.  At December 31, 2000, regulatory assets and
regulatory  liabilities  are being  amortized  and reflected in rates charged to
customers over periods up to 20 years.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The components of
other deferred charges and credits, and regulatory assets and liabilities on the
Consolidated Balance Sheets included the following, as of December 31:</P>

<P ALIGN=LEFT><B>Other Deferred Charges and Credits</B></P>

<PRE>
(dollars in thousands)                                    2000         1999         1998
==========================================================================================
Electric Utility Deferred Charges:
  Generating stations..............................    $     420    $   4,654    $     ---
  Unamortized debt expense.........................        5,565        5,196        8,566
  Unamortized loss on reacquired debt..............       25,644       27,281       29,072
  Miscellaneous....................................        4,471        4,116        2,217
---------------------------------------------------    ----------   ----------   ----------
    Total electric utility deferred charges........       36,100       41,247       39,855
---------------------------------------------------    ----------   ----------   ----------

Non-Electric Utility Deferred Charges:
  Enogex gas sales contracts.......................        8,832       10,891       12,389
  Enogex pipeline over-deliveries..................       68,510       14,263        3,926
  Unamortized debt expense.........................       13,141       10,008        2,954
  Enogex minority interest asset...................        4,838        6,845          ---
  Miscellaneous....................................       16,315        9,929        7,443
---------------------------------------------------    ----------   ----------   ----------
    Total non-electric utility deferred charges....      111,636       51,936       26,712
---------------------------------------------------    ----------   ----------   ----------
Total Deferred Charges.............................      147,736       93,183       66,567
---------------------------------------------------    ----------   ----------   ----------

Electric Utility Deferred Credits:
  Take or pay gas litigation.......................      12,.500       11,800       15,000
  Miscellaneous....................................          ---          133        4,768
---------------------------------------------------    ----------   ----------   ----------
    Total electric utility deferred credits........       12,500       11,933       19,768
---------------------------------------------------    ----------   ----------   ----------

Non-Electric Utility Deferred Credits:
  Enogex pipeline under-deliveries.................       68,182        5,072        2,054
  Miscellaneous....................................       26,140       22,156        9,689
---------------------------------------------------    ----------   ----------   ----------
    Total non-electric utility deferred credits....       94,322       27,228       11,743
---------------------------------------------------    ----------   ----------   ----------
Total Deferred Credits.............................    $ 106,822    $  39,161    $  31,511
===========================================================================================
</PRE>

<P ALIGN=LEFT><B>Regulatory Assets and Liabilities</B></P>

<PRE>
(dollars in thousands)                                    2000         1999        1998
==========================================================================================
Regulatory Assets:
  Income taxes recoverable from customers.........     $ 83,617     $ 93,888     $104,160
  Unamortized loss on reacquired debt.............       25,644       27,281       29,072
  Miscellaneous...................................        4,471        4,116        2,217
--------------------------------------------------     ---------    ---------    ---------
    Total Regulatory Assets.......................      113,732      125,285      135,449

Regulatory Liabilities:
  Income taxes refundable to customers............      (44,963)     (54,196)     (63,429)
--------------------------------------------------     ---------    ---------    ---------
Net Regulatory Assets.............................     $ 68,769     $ 71,089     $ 72,020
==========================================================================================
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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.</P>

<P ALIGN=LEFT><B>ACCOUNTING PRONOUNCEMENTS</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In June 1998, the
FASB issued SFAS No. 133, "Accounting for Derivative Instruments and for Hedging
Activities",  with an effective date for periods  beginning after June 15, 1999.
In July  1999,  the  FASB  issued  SFAS  No.  137,  "Accounting  for  Derivative
Instruments  and Hedging  Activities  - Deferral of the  Effective  Date of FASB
Statement No. 133". As a result of SFAS No. 137, adoption of SFAS No. 133 is now
required for financial  statements for periods beginning after June 15, 2000. In
June 2000,  the FASB  issued SFAS No. 138,  "Accounting  for Certain  Derivative
Instruments  and Certain  Hedging  Activities",  which amends the accounting and
reporting  standards  of SFAS No. 133 for  certain  derivative  instruments  and
hedging  activities.  SFAS No. 133 sweeps in a broad  population of transactions
and changes the previous accounting definition of a derivative instrument. Under
SFAS No. 133,  every  derivative  instrument is recorded in the balance sheet as
either an asset or liability  measured at its fair value.  SFAS No. 133 requires
that changes in the derivative's fair value be recognized  currently in earnings
unless  specific  hedge  accounting  criteria are met.  During 2000, the Company
established  an  SFAS  No.  133  implementation  team  that  reviewed  contracts
throughout the Company  identifying both  freestanding and embedded  derivatives
which met the  criteria  set forth in SFAS No. 133 and SFAS No. 138. The Company
adopted the new standards  effective  January 1, 2001.  On January 1, 2001,  the
Company  redesignated  all of  its  hedging  relationships  and  recognized  all
derivatives  at their  fair value in  accordance  with SFAS No. 133 and SFAS No.
138. As a result of adopting these  standards the Company  recorded a cumulative
effect   transition   adjustment   debit  to  Other   Comprehensive   Income  of
approximately $26.9 million.</P>

<P ALIGN=LEFT><B>PRICE RISK MANAGEMENT ACTIVITIES</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In   the   normal
course of  business,  Enogex  and its  subsidiaries  utilize  energy  derivative
contracts  to hedge  the  price  and basis  risk  associated  with  specifically
identified purchase or sales contracts,  natural gas inventories,  production of
gas  reserves or  operational  needs.  The Company  accounts  for changes in the
market value of qualifying hedging instruments as deferred gains or losses until
the production month of the hedged  transaction,  at which time the gain or loss
on the hedging instrument and hedged transaction is recognized in the results of
operations.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Additionally,
Enogex through its energy trading subsidiary will utilize  derivative  contracts
in its energy  trading  activities.  Derivatives  utilized in the energy trading
activities  are marked to market with the  corresponding  market gains or losses
recognized in the results of operations as the market value changes.</P>

<P ALIGN=LEFT><B>USE OF ESTIMATES</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In  preparing the
consolidated 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  liabilities  at the date of the financial
statements  and the  reported  amounts  of  revenues  and  expenses  during  the
reporting period. Actual results could differ from those estimates.</P>

<P ALIGN=LEFT><B>PROPERTY, PLANT AND EQUIPMENT</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;All     property,
plant and equipment are recorded at cost.  Electric utility plant is recorded at
its original cost. Newly  constructed  plant is added to plant balances at costs
which  include  contracted  services,  direct  labor,  materials,  overhead  and
allowance  for funds used  during  construction.  Replacement  of major units of
property are  capitalized  as plant.  The  replaced  plant is removed from plant
balances and the cost of such  property  together  with the cost of removal less
salvage is charged to accumulated depreciation.  Repair and replacement of minor
items of property are included in the Consolidated Statements of Income as other
operation and maintenance expense.</P>

<P ALIGN=LEFT><B>DEPRECIATION</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The provision for
depreciation,  which was  approximately  3.1 percent of the average  depreciable
utility  plant for 2000,  and 3.2  percent  for 1999 and 1998,  is provided on a
straight-line   method  over  the  estimated   service  life  of  the  property.
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.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Enogex's      gas
pipeline,   gathering  systems,   compressors  and  gas  processing  plants  are
depreciated on a straight-line  method over periods ranging from 17 to 83 years.
Development   and   production    properties   are    depreciated    using   the
units-of-production method.</P>

<P ALIGN=LEFT><B>ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Allowance     for
funds  used  during  construction  ("AFUDC")  is  calculated  according  to FERC
pronouncements  for the imputed  cost of equity and  borrowed  funds.  AFUDC,  a
non-cash item, is reflected as a credit on the Consolidated Statements of Income
and a charge to construction work in progress.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;AFUDC      rates,
compounded  semi-annually,  were 6.68, 5.36 and 5.75 percent for the years 2000,
1999 and 1998, respectively.</P>

<P ALIGN=LEFT><B>FAIR VALUE OF FINANCIAL INSTRUMENTS</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The      carrying
value of the  financial  instruments  on the  Consolidated  Balance  Sheets  not
otherwise discussed in these notes approximates fair value.</P>

<P ALIGN=LEFT><B>CASH AND CASH EQUIVALENTS</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;For  purposes  of
these  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
market.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
cash management program utilizes controlled  disbursement banking  arrangements.
Outstanding  checks in excess of cash  balances  totaled  $25.0  million,  $11.7
million and $27.8 million at December 31, 2000, 1999 and 1998, respectively, and
are  classified as accounts  payable in the  accompanying  Consolidated  Balance
Sheets.  Sufficient funds were available to fund these  outstanding  checks when
they were presented for payment.</P>

<P ALIGN=LEFT><B>HEAT PUMP LOANS</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E   has  a
heat pump loan  program,  whereby,  qualifying  customers may obtain a loan from
OG&amp;E to purchase a heat pump. Customer loans are available from a minimum of
$1,500 to a maximum of $13,000 with a term of 6 months to 72 months. The finance
rate  is  based  upon   short-term  loan  rates  and  is  reviewed  and  updated
periodically.  The interest rates were 10.99,  8.99 and 8.25 percent at December
31, 2000, 1999 and 1998, respectively.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       current
portion of these loans  totaled $1.5  million,  $0.6 million and $1.0 million at
December 31, 2000, 1999 and 1998,  respectively,  and are classified as accounts
receivable - customers in the  accompanying  Consolidated  Balance  Sheets.  The
noncurrent  portion of these loans totaled $5.9  million,  $2.3 million and $4.0
million at December 31, 2000, 1999 and 1998, respectively, and are classified as
other property and investments in the accompanying  Consolidated Balance Sheets.
OG&amp;E  sold  approximately  $12.7  million and $25.0 million of its heat pump
loans in 1999 and 1998, respectively.</P>

<P ALIGN=LEFT><B>REVENUE RECOGNITION</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E
customers  are  billed  monthly on a cycle  basis.  OG&amp;E  accrues  estimated
revenues  for  services  provided  but not yet billed,  as the cost of providing
service is recognized as incurred.  Enogex accrues  revenues as the products and
services are delivered.</P>

<P ALIGN=LEFT><B>AUTOMATIC FUEL ADJUSTMENT CLAUSES</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Variances  in the
actual cost of fuel used in electric  generation  and  certain  purchased  power
costs,  as compared to that component in  cost-of-service  for  ratemaking,  are
charged to substantially all of OG&amp;E's  electric customers through automatic
fuel  adjustment  clauses,  which are subject to periodic review by the OCC, the
APSC and the FERC.  In March 2000,  the OCC  approved  the  Acquisition  Premium
Credit Rider ("APC Rider") for $10.7 million annually. The purpose of this rider
is to  credit  the  Oklahoma  retail  customers  for the  completion  of the OCC
authorized  recovery of the premium paid by OG&amp;E when it acquired  Enogex in
1986. The APC Rider is applicable to each Oklahoma retail rate schedule to which
OG&amp;E's fuel cost adjustment clause applies.</P>

<P ALIGN=LEFT><B>FUEL INVENTORIES</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Fuel  inventories
for the generation of electricity  consists of coal,  natural gas and oil. These
inventories are accounted for under the last-in, first-out ("LIFO") cost method.
The estimated  replacement  cost of fuel  inventories was higher than the stated
LIFO cost by approximately $11.6 million for 2000 and lower than the stated LIFO
cost by approximately  $0.9 million for 1999 and $4.4 million for 1998, based on
the average cost of fuel  purchased late in the  respective  years.  Natural gas
products  inventories  used in Enogex's energy trading  activities and accounted
for under the FASB Emerging  Issues Task Force Issue No. 98-10,  "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," are valued
at market.</P>

<P ALIGN=LEFT><B>ACCRUED VACATION</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Company
accrues  vacation pay by establishing a liability for vacation earned during the
current year,  but not payable until the following  year.  The accrued  vacation
totaled  $14.4  million,  $14.4  million and $13.4 million at December 31, 2000,
1999 and 1998,  respectively,  and is classified as other current liabilities in
the accompanying Consolidated Balance Sheets.</P>

<P ALIGN=LEFT><B>ENVIRONMENTAL COSTS</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Accruals      for
environmental costs are recognized when it is probable that a liability has been
incurred and the amount of the  liability can be  reasonably  estimated.  When a
single  estimate  of the  liability  cannot  be  determined,  the low end of the
estimated  range is  recorded.  Costs are  charged to expense or  deferred  as a
regulatory  asset based on expected  recovery from customers in future rates, if
they relate to the  remediation  of conditions  caused by past  operations or if
they  are  not  expected  to  mitigate  or  prevent  contamination  from  future
operations.  Where environmental  expenditures relate 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 OG&amp;E has been
designated as one of several potentially responsible parties, the amount accrued
represents OG&amp;E's estimated share of the cost.</P>

<P ALIGN=LEFT><B>RECLASSIFICATIONS</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Certain   amounts
have been  reclassified on the consolidated  financial  statements to conform to
the 2000 presentation.</P>

<P ALIGN=LEFT><B>2.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Income Taxes</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The items
comprising tax expense are as follows:</P>

<PRE>
Year ended December 31 (dollars in thousands)                                    2000            1999            1998
=======================================================================================================================
Provision For Current Income Taxes:
     Federal..........................................................       $  23,311       $  50,090       $  72,084
     State............................................................           6,824           8,617          12,638
----------------------------------------------------------------------       ----------      ----------      ----------
         Total Provision For Current Income Taxes.....................          30,135          58,707          84,722
----------------------------------------------------------------------       ----------      ----------      ----------

Provisions (Benefit) For Deferred Income Taxes, net:
     Federal
         Depreciation.................................................          51,398          29,392           1,490
         Repair allowance.............................................           1,711           1,978           1,200
         Removal costs                                                           2,710           3,461            (220)
         Salvage......................................................          (1,718)         (3,131)            ---
         Software development costs...................................          (3,162)          2,906             ---
         Casualty losses..............................................          (5,439)          5,167             ---
         Contributions in aid of construction.........................          (2,689)         (1,249)           (442)
         Company restructuring........................................              46             100              22
         Pension expense..............................................           1,325          (2,626)         14,806
         Bond redemption-unamortized costs............................          (1,064)            249           8,458
         Partnerships.................................................           4,682           4,270           1,400
         Other........................................................          (2,685)         (6,134)           (938)
     State............................................................           7,032           1,858           3,296
----------------------------------------------------------------------       ----------      ----------      ----------
         Total Provision  (Benefit) For Deferred Income Taxes, net....          52,147          36,241          29,072
----------------------------------------------------------------------       ----------      ----------      ----------
Deferred Investment Tax Credits, net..................................          (5,150)         (5,150)         (5,150)
Income Taxes Relating to Other Income and Deductions..................            (627)            146             ---
----------------------------------------------------------------------       ----------      ----------      ----------
         Total Income Tax Expense.....................................       $  76,505       $  89,944       $ 108,644
----------------------------------------------------------------------       ----------      ----------      ----------
Pretax Income                                                                $ 223,540       $ 241,203       $ 274,516
======================================================================       ==========      ==========      ==========


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

 Year ended December 31                                                          2000            1999           1998
======================================================================================================================
Statutory federal tax rate............................................           35.0%           35.0%           35.0%
State income taxes, net of federal income tax benefit.................            4.0             2.8             3.8
Tax credits, net......................................................           (3.4)           (3.4)           (3.0)
Other, net............................................................           (1.4)            2.9             3.8
----------------------------------------------------------------------       ----------      ----------      ----------
     Effective income tax rate as reported............................           34.2%           37.3%           39.6%
======================================================================       ==========      ==========      ==========
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The Company files
consolidated  income tax  returns.  Income  taxes are  allocated to each company
based on its separate taxable income or loss.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Investment    tax
credits on electric  utility property have been deferred and are being amortized
to income over the life of the related property.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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
("temporary  differences")  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.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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 OG&amp;E.  The
components of Accumulated  Deferred  Income Taxes at December 31, 2000, 1999 and
1998 are as follows:</P>



<PRE>
 (dollars in thousands)                                                     2000           1999           1998
================================================================================================================
Current Deferred Tax Assets:
     Accrued vacation .............................................     $   5,184      $   5,497      $   5,088
     Uncollectible accounts........................................         4,089          1,776          1,242
     Capitalization of indirect costs..............................           318            249            172
     RAR interest .................................................           774            774            774
     Provision for Worker's Compensation claims....................           272            348            462
     Other.........................................................            32             85             73
-------------------------------------------------------------------     ----------     ----------     ----------
         Current Deferred Tax Assets...............................     $  10,669      $   8,729      $   7,811
================================================================================================================

Deferred Tax Liabilities:
     Accelerated depreciation and other property-related
         differences...............................................     $ 587,038      $ 532,814      $ 491,943
     Allowance for funds used during construction..................        34,093         37,152         38,575
     Income taxes recoverable through future rates.................        32,365         36,335         40,310
     Bond redemption-unamortized costs.............................         8,964          9,640          9,353
-------------------------------------------------------------------     ----------     ----------     ----------
         Total.....................................................       662,460        615,941        580,181
-------------------------------------------------------------------     ----------     ----------     ----------

Deferred Tax Assets:
     Deferred investment tax credits...............................       (18,388)       (20,130)       (21,875)
     Income taxes refundable through future rates..................       (17,404)       (20,974)       (24,547)
     Postemployment medical and life insurance benefits............        (1,792)        (1,795)        (3,100)
     Company pension plan..........................................        (4,078)        (5,206)          (682)
     Other.........................................................        (2,438)        (1,699)         1,963
-------------------------------------------------------------------     ----------     ----------     ----------
         Total.....................................................       (44,100)       (49,804)       (48,241)
-------------------------------------------------------------------     ----------     ----------     ----------
Accumulated Deferred Income Tax Liabilities........................     $ 618,360      $ 566,137      $ 531,940
================================================================================================================
</PRE>

<P ALIGN=LEFT><B>3.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Common Stock and Retained
Earnings</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In  May 1998, the
Company's  Board of Directors  approved a two-for-one  stock split of its common
stock,  par value  $0.01 per share (the  "Common  Stock"),  by  declaring  a 100
percent stock dividend  payable June 15, 1998.  Accordingly,  each shareowner of
record of the Common  Stock  received one  additional  share of Common Stock for
each share of Common Stock held on June 1, 1998.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   January  15,
1999,  the Company  repurchased  3 million  shares of its Common  Stock under an
Advanced Share  Repurchase  agreement with CIBC  Oppenheimer  Corp. The purchase
price was $80.4 million or $26.8125 per share,  the closing price on January 15,
1999. Under the terms of this Advanced Share Repurchase  Agreement,  the Company
agreed to bear the risk of  increases  and the benefit of decreases on the price
on the Common Stock until CIBC Oppenheimer Corp.  replaced,  through open market
purchases or privately negotiated transactions,  the shares sold to the Company.
Also,  there were 58,627,  65,831 and 25,705 shares of new stock issued pursuant
to the Stock Incentive Plan during 2000, 1999 and 1998,  respectively.  The $1.5
million  increase  in 2000 in  premium  on  capital  stock as  presented  on the
Consolidated  Statements of  Capitalization,  represents  the issuance of common
stock pursuant to the Stock Incentive  Plan. The $71.7 million  decrease in 1999
in premium on capital stock represents the repurchase of common stock, which was
only  partially  offset by the  issuance of common  stock  pursuant to the Stock
Incentive Plan.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;There were
6,324,118  shares of unissued common stock reserved for the various employee and
Company  stock plans at  December  31,  2000.  With the  exception  of the Stock
Incentive  Plan,  the common stock  requirements,  pursuant to those plans,  are
currently being satisfied with stock purchased on the open market.</P>

<P ALIGN=LEFT><B>SHAREOWNERS RIGHTS PLAN</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In December 1990,
OG&amp;E  adopted a  Shareowners  Rights Plan  designed to protect  shareowners'
interests  in the event  that  OG&amp;E  was ever  confronted  with an unfair or
inadequate acquisition proposal. In connection with the corporate restructuring,
the Company adopted a substantially  identical Shareowners Rights Plan in August
1995. Pursuant to the plan, the Company declared a dividend  distribution of one
"right"  for each share of Company  common  stock.  As a result of the June 1998
two-for-one  stock split, each share of common stock is now entitled to one-half
of a right.  Each right  entitles  the holder to  purchase  from the Company one
one-hundredth  of a share of new  preferred  stock of the Company  under certain
circumstances.  The rights may be exercised if a person or group  announces  its
intention  to  acquire,  or does  acquire,  20 percent or more of the  Company's
common  stock.  Under certain  circumstances,  the holders of the rights will be
entitled  to  purchase  either  shares of common  stock of the Company or common
stock of the acquirer at a reduced  percentage of market value. In October 2000,
the  Shareowners  Rights Plan was amended and restated to extend the  expiration
date to December 11, 2010 and to change the exercise price of the rights.</P>

<P ALIGN=LEFT><B>4.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; Stock Incentive Plan</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   January  21,
1998, the Company adopted a Stock Incentive  Plan.  Under this plan,  restricted
stock,  stock options,  stock  appreciation  rights and performance units may be
granted  to  officers,  directors  and  other key  employees.  The  Company  has
authorized the issuance of up to 4,000,000 shares under the plan.</P>


<P ALIGN=LEFT><B>RESTRICTED STOCK</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The Company had a
Restricted Stock Plan whereby certain employees  periodically received shares of
the Company's  common stock at the  discretion  of the Board of  Directors.  The
Stock Incentive Plan replaced the Restricted Stock Plan. The Company distributed
58,627,  65,831 and 38,900  shares of common stock  during 2000,  1999 and 1998,
respectively.  The Company also reacquired 13,195 shares in 1998. The restricted
stock distributed vests at the end of three years.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Changes in common
stock were:</P>

<PRE>
(dollars in thousands)                                              2000         1999        1998
---------------------------------------------------------------------------------------------------
Shares outstanding January 1...................................    77,863       80,798      80,772
Repurchased shares.............................................       ---       (3,000)        ---
Issued/reacquired under the Stock Incentive and Restricted
  Stock Plan, net.............................................         59           65          26
---------------------------------------------------------------------------------------------------
Shares outstanding December 31.................................    77,922       77,863      80,798
===================================================================================================
</PRE>

<P ALIGN=LEFT><B>STOCK OPTIONS</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In  January 2000,
the Company awarded  approximately 364,200 stock options, with an exercise price
of $18.25.  During 2000,  36,068 stock  options were  forfeited  and 8,332 stock
options  expired.  In January 1999, the Company  awarded  approximately  442,800
stock options, with an exercise price of $28.75. In January 1998,  approximately
427,600 stock options were awarded with an exercise  price of $25.9375.  Options
granted under the Stock  Incentive  Plan vest in one-third  annual  installments
beginning  one year  from the date of grant  and have a  contractual  life of 10
years. At December 31, 2000, 1,190,200 stock options were outstanding.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;During  1996, the
Company  adopted SFAS No. 123 and pursuant to its provision  elected to continue
using the intrinsic value method of accounting for stock-based awards granted to
employees in accordance with Accounting Principles Board ("APB") Opinion No. 25,
"Accounting  for Stock Issued to  Employees".  Accordingly,  the Company has not
recognized  compensation expense for its stock-based awards to employees.  Using
the Black-Scholes pricing model, the estimated fair value of each option granted
was $3.34 in 2000.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     following
table shows  assumptions  used to estimate the fair value of options  granted in
2000:</P>

<PRE>
         Expected life of options....................................  7 years
         Risk-free interest rate.....................................    5.08%
         Expected volatility.........................................   22.16%
         Expected dividend yield.....................................    5.71%
</PRE>
<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     following
table  reflects pro forma  earnings  available  for common stock had the Company
elected to adopt the fair value approach to SFAS No. 123:</P>


<PRE>
(dollars in thousands)                                      2000          1999          1998
-----------------------------------------------------------------------------------------------
   Earnings available for
     common stock:               As Reported........      $147,035      $151,259      $165,139
                                 Pro Forma..........       146,438       150,864       164,933
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In 2000, reported
earnings  per share was $1.89,  while the pro forma  earnings  per share had the
Company elected to adopt the fair value approach to SFAS 123 was $1.88. Reported
and pro forma earnings per share amounts are equivalent for 1998 and 1999.</P>

<P ALIGN=LEFT><B>5.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Trust  Preferred Securities of
Subsidiary</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   October  21,
1999,  the OGE Energy  Capital  Trust I, a wholly-owned  financing  trust of the
Company,  issued $200 million  principal amount of 8.375 percent trust preferred
securities  that mature in 2039.  The proceeds of this debt were used to repay a
portion  of  outstanding   short-term  borrowings  under  the  revolving  credit
agreement implemented in connection with the Transok acquisition.  Distributions
paid by the financing  trust on the preferred  securities  are financed  through
payments on debt  securities  issued by the  Company  and held by the  financing
trust,  which are  eliminated  in the  Company's  consolidation.  The  preferred
securities are redeemable at $25 per share beginning in 2004.  Distributions and
redemption  payments  are  guaranteed  by the  Company.  Distributions  paid  to
preferred  security holders are recorded as interest expense in the Consolidated
Statements of Income.</P>

<P ALIGN=LEFT><B>6.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Long-Term Debt</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   October  15,
2000, a $110 million series of OG&amp;E's 6.25 percent Senior Notes matured. The
Company temporarily funded this debt through short-term  borrowings.  On October
23, 2000, OG&amp;E issued $110 million of 7.125 percent Senior Notes, Series due
October 15, 2005.  Net  proceeds  from this  transaction  were used to repay the
temporary short-term borrowings from the Company.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Enogex    retired
$57 million of long-term  debt that matured in the third  quarter of 2000.  This
debt consisted of $23 million principal amount of 6.77 percent medium-term notes
due August 7, 2000,  $4 million  principal  amount of 6.76  percent  medium-term
notes  due  August  7,  2000,  $20  million  principal  amount  of 6.68  percent
medium-term  notes due August 31, 2000 and $10 million  principal amount of 6.70
percent medium-term notes due September 1, 2000.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On  July 1, 1999,
Enogex  completed its acquisition of Transok for  approximately  $710.3 million,
which  included  assumption  of $173  million of  long-term  debt.  To repay the
remaining  balance of the temporary  short-term debt associated with the Transok
acquisition,  Enogex,  on January 14, 2000, sold $400 million of unsecured 8.125
percent  Senior Notes due January 15, 2010.  Enogex entered into a series of one
year interest rate swap agreements to manage interest costs associated with this
$400  million  issue.  The effect of these swap  agreements  reduced the overall
effective  interest rate from 8.125 percent to 6.6875  percent  during 2000. The
interest rate swaps  expired in January  2001.  The balance of the proceeds from
this new debt was used for  general  corporate  purposes.  The  following  table
itemizes   the  Enogex   long-term   debt   assumed  as  part  of  the   Transok
acquisition:</P>


<PRE>
(dollars in thousands)
----------------------------------------------------------------------
Series Due 2002 -- 7.32% - 8.13%.........................   $  50,000
Series Due 2003 -- 6.60% - 8.28%.........................      12,300
Series Due 2004 -- 6.71% - 8.34%.........................      25,750
Series Due 2005 -- 6.81% - 7.71%.........................      40,950
Series Due 2007 -- 8.28%.................................       3,000
Series Due 2008 -- 7.07%.................................       1,000
Series Due 2012 -- 8.35% - 8.90%.........................      10,000
Series Due 2017 -- 8.96%.................................      15,000
Series Due 2023 -- 7.75%.................................      15,000
---------------------------------------------------------   ----------
     Total...............................................   $ 173,000
=========================================================   ==========
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   January  10,
2001,  Enogex retired $5 million  principal  amount of 7.75 percent  medium-term
notes due April 24,  2023.  This debt had been  assumed  as part of the  Transok
acquisition.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As   of  December
31, 2000, other Enogex long-term debt consisted of $400 million principal amount
of 8.125 percent Senior Notes due January 15, 2010, $75 million principal amount
of 7.15 percent  Senior Notes  subject to  semiannual  principal  payments of $1
million each and due June 1, 2018, $6.9 million principal amount of 7.00 percent
Notes due July 1, 2020 and $93 million of medium-term  notes at a composite rate
of 6.96  percent.  The  following  table  itemizes  the other  Enogex  long-term
debt:</P>

<PRE>
December 31 (dollars in thousands)                        2000          1999         1998
--------------------------------------------------------------------------------------------
Series Due August 7, 2000 -- 6.76% - 6.77%.......      $     ---     $  27,000    $  27,000
Series Due August 31, 2000 -- 6.68%..............            ---        20,000       20,000
Series Due September 1, 2000 - 6.70%.............            ---        10,000       10,000
Series Due August 7, 2002 -- 7.02% - 7.05%.......         63,000        63,000       63,000
Series Due July 23, 2004 -- 6.79%................         30,000        30,000       30,000
Series Due January 15, 2010 -- 8.125%............        400,000           ---          ---
Series Due June 1, 2018 -- 7.15%.................         75,000        77,000       79,000
Series Due July 1, 2020 -- 7.00%.................          6,941         6,486        5,671
-------------------------------------------------      ----------    ----------   ----------
  Total..........................................      $ 574,941     $ 233,486    $ 234,671
=================================================      ==========    ==========   ==========
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Maturities of the
Company's  long-term  debt  during the next five years  consist of $2 million in
2001;  $115 million in 2002;  $14.3 million in 2003;  $57.8 million in 2004, and
$152.9 million in 2005.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  Company  has
previously incurred costs related to debt refinancings. Unamortized debt expense
and unamortized loss on reacquired debt, and unamortized premium and discount on
long-term debt are being  amortized over the life of the respective debt and are
classified as deferred charges - other and long-term debt, respectively,  in the
accompanying Consolidated Balance Sheets.</P>

<P ALIGN=LEFT><B>7.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Short-Term Debt</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Company
borrows on a short-term basis, as necessary, by the issuance of commercial paper
and by  obtaining  short-term  bank loans.  The  maximum and average  amounts of
short-term  borrowings during 2000 (excluding the temporary short-term financing
for  the  Transok   acquisition)   were  $284.5  million  and  $182.4   million,
respectively, at a weighted average interest rate of 6.68%. The weighted average
interest rates for 1999 and 1998 were 5.36% and 5.75%, respectively.  Short-term
debt in the amount of $284.5  million was  outstanding at December 31, 2000. The
Company has the  necessary  regulatory  approvals to incur up to $400 million in
short-term  borrowings at any one time. At December 31, 2000, the Company had in
place a line of credit  for up to $300  million,  $200  million  of which was to
expire on January 15,  2001,  and the  remaining  $100  million was to expire on
January 15, 2004. In January 2001,  the Company's  line of credit for up to $200
million was renewed, with an expiration date of January 15, 2002.</P>

<P ALIGN=LEFT><B>8.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Pension and Postretirement
Benefit Plans</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;All eligible
employees  of the  Company  are covered by a  non-contributory  defined  benefit
pension  plan.  In early 2000,  the Board  approved  significant  changes to the
pension plan. Under the existing plan, benefits were based primarily on years of
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 that an employee  retired and  additional
significant  reductions  for  retirement  prior to age 55.  The  changes  to the
existing pension plan included: (i) elimination of the significant reduction for
employees  electing to retire before age 55, (ii) the addition of an alternative
method of computing the reduction in benefits for an employee  retiring prior to
age 62,  which  alternative  method is based on years of service and age with an
employee  whose  age and  years of  service  total or  exceed  80 at the time of
retirement  receiving no reduction in the benefits  payable under the plan,  and
(iii) the ability of an employee at time of retirement to receive, in lieu of an
annuity, a lump sum payment equal to the present value of the annuity. Also, for
employees  hired after January 31, 2000, the pension plan will be a cash balance
plan, under which the Company annually will contribute to the employee's account
an amount equal to 5 percent of the employee's annual  compensation plus accrued
interest. Employees hired prior to February 1, 2000, will receive the greater of
the cash balance  benefit or the benefit based on final average  compensation as
described above.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;It     is     the
Company's  policy to fund the plan on a current basis to comply with the minimum
required  contributions  under  existing  tax  regulations.   The  Company  made
contributions of $16.2 million during 2000 to increase the Plan's 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.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The plan's assets
consist  primarily  of U.S.  Government  securities,  listed  common  stock  and
corporate debt.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In   addition  to
providing  pension  benefits,  the  Company  provides  certain  medical and life
insurance benefits for retired members  ("postretirement  benefits").  Under the
existing plan,  employees retiring from the Company on or after attaining age 55
who have met  certain  length of service  requirements  were  entitled  to these
benefits.  Pursuant to  amendments  made to the medical plan in 2000,  employees
hired prior to February 1, 2000,  whose age and years of service total or exceed
80 or have  attained  age 55 with 10 years of service at the time of  retirement
are entitled to these benefits.  Employees hired after January 31, 2000, are not
entitled to the  medical  benefits.  The  benefits  are subject to  deductibles,
co-payment  provisions and other  limitations.  OG&amp;E  charges to expense the
SFAS  No.  106  costs  and   includes  an  annual   amount  as  a  component  of
cost-of-service in future ratemaking proceedings.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;A  reconciliation
of the funded  status of the plans and the  amounts  included  in the  Company's
Consolidated Balance Sheets follows:</P>

<PRE>
Projected Benefit Obligations:

===============================================================================================================================
                                                                                                     Postretirement
                                                     Pension Plan                                    Benefit Plans
-------------------------------------------------------------------------------------------------------------------------------
 (dollars in thousands)                    2000          1999          1998                 2000          1999           1998
-------------------------------------------------------------------------------------------------------------------------------
Beginning obligations..............    $(299,996)    $(342,433)    $(320,842)           $ (83,428)    $ (89,094)     $ (94,199)
Service cost.......................      (10,559)       (8,241)       (8,272)              (2,084)       (2,695)        (2,030)
Interest cost......................      (27,516)      (21,363)      (21,766)              (7,200)       (6,003)        (5,748)
Participant contributions..........          ---           ---           ---               (1,093)       (1,143)        (1,077)
Plan changes.......................      (20,528)          ---        (3,561)             (17,373)       (1,500)           ---
Actuarial gains (losses)...........      (77,862)       53,535        (8,568)                (379)        7,950          6,029
Benefits paid......................       40,460        17,695        20,345                9,170         9,057          7,931
Expenses ..........................          766           811           231                  ---           ---            ---
-------------------------------------------------------------------------------------------------------------------------------
Ending obligations.................    $(395,235)    $(299,996)    $(342,433)           $(102,387)    $ (83,428)     $ (89,094)
===============================================================================================================================

Fair Value of Plans' Assets:

===============================================================================================================================
                                                                                                     Postretirement
                                                     Pension Plan                                    Benefit Plans
-------------------------------------------------------------------------------------------------------------------------------
 (dollars in thousands)                    2000          1999          1998                 2000          1999           1998
-------------------------------------------------------------------------------------------------------------------------------
Beginning fair value...............    $ 311,937     $ 304,169     $ 242,254            $  55,509     $  52,264      $  45,619
Actual return on plans' assets.....        9,597        22,517        30,865                   42         3,245          5,133
Employer contributions.............       16,190         3,757        51,626                6,184         6,307          5,474
Participants' contributions........          ---           ---           ---                  943           980            915
Benefits paid......................      (40,460)      (17,695)      (20,345)              (7,127)       (7,287)        (6,388)
Expenses...........................         (764)         (811)         (231)                 ---           ---            ---
Other..............................          ---           ---           ---                  ---           ---          1,511
-------------------------------------------------------------------------------------------------------------------------------
Ending fair value..................    $ 296,500     $ 311,937     $ 304,169            $  55,551     $  55,509      $  52,264
===============================================================================================================================
</PRE>

<PRE>
Funded Status of Plans:

===============================================================================================================================
                                                                                                     Postretirement
                                                     Pension Plan                                    Benefit Plans
-------------------------------------------------------------------------------------------------------------------------------
 (dollars in thousands)                    2000          1999          1998                 2000          1999           1998
-------------------------------------------------------------------------------------------------------------------------------
Funded status of the plans.........    $ (98,735)    $  11,941     $ (38,264)           $ (46,836)    $ (27,919)     $ (36,831)
Unrecognized net (gain) loss.......       47,435       (47,326)        1,435              (17,428)      (24,337)       (18,713)
Unrecognized prior service
   cost............................       53,197        37,289        40,448               17,333         1,396            ---
Unrecognized transition
   obligation......................       (1,265)       (2,527)       (3,790)              32,988        35,738         38,487
-------------------------------------------------------------------------------------------------------------------------------
Net balance sheet asset
   (liability).....................    $     632     $    (623)    $    (171)           $ (13,943)    $ (15,122)     $ (17,057)
===============================================================================================================================

Net Periodic Benefit Cost:

===============================================================================================================================
                                                                                                     Postretirement
                                                     Pension Plan                                    Benefit Plans
-------------------------------------------------------------------------------------------------------------------------------
 (dollars in thousands)                    2000          1999          1998                 2000          1999           1998
-------------------------------------------------------------------------------------------------------------------------------
Service cost.......................    $  10,559     $   8,241     $   8,272            $   2,084     $   2,695      $   2,030
Interest cost......................       27,516        21,363        21,766                7,200         6,003          5,748
Return on plan assets..............      (24,160)      (27,374)      (21,443)              (4,985)       (3,963)        (4,309)
Amortization of transition
   obligation......................       (1,263)       (1,263)       (1,263)               2,749         2,749          2,749
Amortization of net gain...........          (91)          ---           ---               (1,727)       (1,244)        (2,105)
Net amount capitalized or
   deferred........................       (2,245)         (880)          ---                  ---        (1,087)          (613)
Net amortization and deferral......          ---           (29)          ---                  ---           ---            ---
Amortization of unrecognized
   prior service cost..............        4,619         3,159         3,159                1,436           104            ---
-------------------------------------------------------------------------------------------------------------------------------
Net periodic benefit costs.........    $  14,935     $   3,217     $  10,491            $   6,757     $   5,257      $   3,500
===============================================================================================================================
</PRE>

<PRE>
Rate Assumptions:

===============================================================================================================================
                                                                                                     Postretirement
                                                     Pension Plan                                    Benefit Plans
-------------------------------------------------------------------------------------------------------------------------------
                                           2000          1999          1998                 2000          1999           1998
-------------------------------------------------------------------------------------------------------------------------------

Discount rate......................        8.00%         8.00%         6.75%                8.00%         8.00%          6.75%

Rate of return on plans' assets....        9.00%         9.00%         9.00%                9.00%         9.00%          9.00%

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                7.00%         7.00%          8.25%

   Ultimate trend rate.............          N/A           N/A           N/A                4.50%         4.50%          4.50%

   Ultimate trend year.............          N/A           N/A           N/A                2007          2007           2007
===============================================================================================================================
N/A - not applicable
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Assumed    health
care cost trend rates have a significant  effect on the amounts reported for the
postretirement medical benefit plans.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  effects of a
one-percentage  point  increase on the  aggregate  of the  service and  interest
components  of the net periodic  postretirement  health care  benefits  would be
approximately $1.1 million,  $1.0 million and $0.9 million at December 31, 2000,
1999 and 1998,  respectively.  The effects of a one-percentage point decrease on
the  aggregate  of the  service  and  interest  components  of the net  periodic
postretirement  health care benefits  would be decreases of  approximately  $0.9
million,  $0.9 million and $0.7  million at December  31,  2000,  1999 and 1998,
respectively.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  effects of a
one-percentage  point  increase on the aggregate of  accumulated  postretirement
benefit  obligation  for  health  care  benefits  would be  approximately  $11.3
million,  $7.1 million and $8.2  million at December  31,  2000,  1999 and 1998,
respectively. The effects of a one-percentage point decrease on the aggregate of
accumulated  postretirement benefit obligation for health care benefits would be
decreases  of  approximately  $9.4  million,  $6.0  million and $6.9  million at
December 31, 2000, 1999 and 1998, respectively.</P>

<P ALIGN=LEFT><B>9.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Report of Business Segments
</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     Company's
electric utility operations are conducted through OG&amp;E,  an operating public
utility  engaged  in the  generation,  transmission,  distribution  and  sale of
electric  energy.  The non-utility  operations are primarily  conducted  through
Enogex.  Enogex is engaged in  transporting  natural gas through its intra-state
pipeline to various  customers  (including  OG&amp;E),  gathering and processing
natural  gas,  marketing  electricity,  natural  gas and natural gas liquids and
investing  in the  development  for and  production  of  natural  gas and  crude
oil.</P>


<PRE>
 (dollars in thousands)                        2000            1999           1998
======================================================================================

Operating Information:
  Operating Revenues
    Electric utility.....................   $1,453,585      $1,286,844     $1,312,078
    Non-utility..........................    2,111,600       1,086,105        506,471
    Intersegment revenues (A)............     (266,458)       (200,515)      (200,812)
-----------------------------------------   -----------     -----------    -----------
      Total..............................   $3,298,727      $2,172,434     $1,617,737
=========================================   ===========     ===========    ===========
  Pre-tax Operating Income
    Electric utility.....................   $  271,138      $  269,564     $  315,798
    Non-utility..........................       78,683          68,601         23,659
-----------------------------------------   -----------     -----------    -----------
      Total..............................   $  349,821      $  338,165     $  339,457
=========================================   ===========     ===========    ===========
  Income Tax Expense (Benefit)
    Electric utility.....................   $   80,342      $   84,965     $  105,574
    Non-utility..........................       (3,837)          4,979          3,070
-----------------------------------------   -----------     -----------    -----------
      Total..............................   $   76,505      $   89,944     $  108,644
=========================================   ===========     ===========    ===========
  Interest Income
    Electric utility.....................   $    1,121      $    1,710     $    2,314
    Non-utility..........................       24,907           9,928          7,046
    Intersegment (B).....................      (22,240)         (8,801)        (5,799)
-----------------------------------------   -----------     -----------    -----------
      Total..............................   $    3,788      $    2,837     $    3,561
=========================================   ===========     ===========    ===========
  Interest Expense
    Electric utility.....................   $   49,009      $   46,658     $   49,941
    Non-utility..........................      108,124          63,142         27,628
    Intersegment (B).....................      (22,240)         (8,801)        (5,799)
-----------------------------------------   -----------     -----------    -----------
      Total..............................   $  134,893      $  100,999     $   71,770
=========================================   ===========     ===========    ===========
  Net Income
    Electric utility.....................   $  142,392      $  139,041     $  160,338
    Non-utility..........................        4,643          12,218          5,534
-----------------------------------------   -----------     -----------    -----------
      Total..............................   $  147,035      $  151,259     $  165,872
=========================================   ===========     ===========    ===========

Investment Information:
  Identifiable Assets as of December 31
    Electric utility.....................   $2,437,449      $2,320,660     $2,320,097
    Non-utility..........................    1,882,181       1,600,674        663,832
-----------------------------------------   -----------     -----------    -----------
      Total..............................   $4,319,630      $3,921,334     $2,983,929
=========================================   ===========     ===========    ===========

Other Information:
  Depreciation and amortization
    Electric utility.....................   $  117,257      $  119,059     $  116,213
    Non-utility..........................       58,887          45,982         33,605
-----------------------------------------   -----------     -----------    -----------
      Total..............................   $  176,144      $  165,041     $  149,818
=========================================   ===========     ===========    ===========
  Construction Expenditures
    Electric utility.....................   $  128,410      $  101,263     $   96,678
    Non-utility..........................       51,061          79,900        138,553
-----------------------------------------   -----------     -----------    -----------
      Total..............................   $  179,471      $  181,163     $  235,231
=========================================   ===========     ===========    ===========
(A)  Intersegment  revenues  are  recorded  at  prices  comparable  to  those of
       unaffiliated customers and are affected by regulatory considerations.
(B)  Intersegment interest is calculated based upon short-term loan rates and is
       reviewed and updated periodically.
</PRE>

<P ALIGN=LEFT><B>10.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Commitments and Contingencies
</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E      has
entered into purchase  commitments in connection  with  OG&amp;E's  construction
program and the purchase of necessary  fuel supplies of coal and natural gas for
OG&amp;E's  generating units. The Company's  construction  expenditures for 2001
are estimated at $164 million.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E acquires
some of its natural gas for boiler fuel under a wellhead  contract that contains
provisions  allowing the owner to require prepayments for gas if certain minimum
quantities  are not taken.  At December  31,  2000,  1999 and 1998,  outstanding
prepayments for gas, including the amounts  classified as current assets,  under
this and other prior similar contracts were approximately  $15.0 million,  $14.9
million and $15.2 million, respectively.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;At  December  31,
2000, OG&amp;E held  non-cancelable  operating leases covering 1,481 coal hopper
railcars.  Rental  payments  are charged to fuel expense and  recovered  through
OG&amp;E's  tariffs  and  automatic  fuel  adjustment  clauses.  The leases have
purchase  and renewal  options.  Future  minimum  lease  payments  due under the
railcar leases,  assuming the leases are renewed under the renewal option are as
follows:</P>
<PRE>

                 (dollars in thousands)
        ================================================================================
         2001....................     $5,541       2004....................    $  5,203
         2002....................      5,429       2005....................       5,091
         2003....................      5,316       2006 and beyond.........      44,710
              Total Minimum Lease Payments.................................    $ 71,290
        ================================================================================
</PRE>
<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Rental   payments
under operating leases were  approximately $5.4 million in 2000, $4.9 million in
1999 and $5.3 million in 1998. OG&amp;E is currently in the process of replacing
these  leases.  Management  does not  anticipate  the terms of the new leases to
differ significantly from the existing leases.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E       is
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.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E      had
entered into an agreement with Central Oklahoma Oil and Gas Corp.  ("COOG"),  an
unrelated third party, to develop a natural gas storage  facility.  Operation of
the gas storage  facility proved  beneficial by allowing  OG&amp;E to lower fuel
costs by base loading coal generation,  a less costly fuel supply.  During 1996,
OG&amp;E  completed  negotiations  and  contracted  with  COOG  for gas  storage
service.  Pursuant to the contract, COOG reimbursed OG&amp;E for all outstanding
cash advances and interest  amounting to approximately  $46.8 million.  OG&amp;E
also entered into a bridge  financing  agreement as guarantor  for COOG. In July
1997, COOG obtained permanent financing and issued a note in the amount of $49.5
million.  The proceeds  from the permanent  financing  were applied to repay the
outstanding bridge financing.  In connection with the permanent  financing,  the
Company entered into a note purchase  agreement,  where it has agreed,  upon the
occurrence of a monetary default by COOG on its permanent financing, to purchase
COOG's note at a price equal to the unpaid principal and interest under the COOG
note.  In July 1998,  Enogex also agreed to lease  underground  gas storage from
COOG. As part of this lease transaction,  the Company agreed to make up to a $12
million  secured loan to an affiliate of COOG.  As part of this  agreement,  the
Company has an $8 million loan outstanding  repayable in 2003 and secured by the
assets  and  stock of COOG.  This  loan is  classified  as  other  property  and
investments in the accompanying Consolidated Balance Sheets.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E      has
entered into  agreements  with four qualifying  cogeneration  facilities  having
initial terms of 3 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 FERC require  OG&amp;E to
purchase  power   generated  in  a   manufacturing   process  from  a  qualified
cogeneration facility ("QF"). The rate for such power to be paid by OG&amp;E was
approved by the OCC. The rate  generally  consists of two  components:  one is a
rate for actual  electricity  purchased from the QF by OG&amp;E;  the other is a
capacity  charge,  which  OG&amp;E  must  pay  the QF for  having  the  capacity
available.  However,  if no electrical power is made available to OG&amp;E for a
period  of time  (generally  three  months),  OG&amp;E's  obligation  to pay the
capacity  charge  is  suspended.  The total  cost of  cogeneration  payments  is
recoverable in rates from customers.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;During 2000, 1999
and 1998,  OG&amp;E made total payments to cogenerators of approximately  $227.6
million,  $229.3 million and $226.5  million,  of which $189.6  million,  $188.8
million and $185.5 million,  respectively,  represented  capacity payments.  All
payments  for  purchased  power,  including  cogeneration,  are  included in the
Consolidated  Statements  of Income  as  purchased  power.  The  future  minimum
capacity payments under the contracts for the next five years are approximately:
2001 - $191  million,  2002 - $192  million,  2003 - $163  million,  2004 - $151
million and 2005 - $88 million.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Approximately
$2.5 million of the Company's construction expenditures budgeted for 2001 are to
comply with environmental laws and regulations.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The
Company&#146;s  management  believes all of its  operations  are in  substantial
compliance with present federal, state and local environmental  standards. It is
estimated that the  Company&#146;s  total  expenditures for capital,  operating,
maintenance and other costs to preserve and enhance  environmental  quality will
be  approximately  $50.5 million during 2001,  compared to  approximately  $47.1
million in 2000. 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
</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Beginning      in
2000, OG&amp;E became subject to more stringent sulfur dioxide emissions.  These
lower  limits had no  significant  financial  impact due to  OG&amp;E's  earlier
decision to burn low sulfur coal. In 2000,  OG&amp;E's  sulfur dioxide emissions
were well below the allowable limits. With respect to nitrogen oxides,  OG&amp;E
continues to meet the current emission standard.  However, further reductions in
nitrogen  oxides  could be required if, among other  things,  a study  currently
being  conducted by the state of Oklahoma  determines  that such nitrogen oxides
are  contributing  to regional  haze, the United States Supreme Court decides to
uphold new ozone standards or if OG&amp;E fails to meet the new fine particulate
standards. Any of these scenarios would require significant capital expenditures
and increased operating and maintenance costs.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In    1997,   the
United States was a signatory to the Kyoto Protocol on global warming. While the
Protocol  is not  likely  to be  ratified  by the  U.S.  Senate,  some  form  of
legislation  limiting  carbon  dioxide  emissions may occur.  If  legislation is
passed,  it could  have a  tremendous  impact  on the  Company's  operations  by
requiring  the  Company  to  significantly  reduce  the  use of  coal  as a fuel
source.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The      Oklahoma
Department of Environmental Quality's Clean Air Act Amendment Title V permitting
program was approved by the  Environmental  Protection  Agency  ("EPA") in March
1996. By March of 1997, OG&amp;E had submitted all required permit applications.
As of December 31, 2000, OG&amp;E had received Title V permits for all but three
of its generating stations. Since OG&amp;E submitted all its permit applications
on time it is  considered  in  compliance  with the Title V permit  program even
though all permits have not been issued. Air permit fees for generating stations
were  approximately  $0.4 million in 2000 and are estimated to be about the same
in 2001.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On  December  14,
2000,  the EPA  announced  its  decision  to  regulate  mercury  emissions  from
coal-fired utility boilers. Limits on the amount of mercury emitted are expected
to be finalized by December 2004, although full compliance by the Company is not
expected  to be  required  until  2008.  Depending  upon the  final  regulations
implemented,   this  could   result  in   significant   capital  and   operating
expenditures.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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's original rules on
this issue were  set-aside in 1977 by the Fourth  Circuit U.S. Court of Appeals.
In 1993,  EPA  announced  its plan to develop new rules in part due to a lawsuit
filed by the  Hudson  Riverkeeper.  To  settle  the  lawsuit,  the EPA  signed a
court-approved  consent decree to develop  316(b)  regulations on an agreed upon
schedule.  Proposed  rules,  for existing  utility  sources,  are expected to be
published  in February  2002 and final rules are expected to be  promulgated  in
August  2003.  Based on the content of the final  rules,  capital and  operating
expenses may increase at most of  OG&amp;E's  generating  facilities.  Increased
capital  costs may be  necessary to retrofit  and/or  redesign  existing  intake
structures to comply with any new 316(b) regulations.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E   is   a
party to an action  brought by the EPA  concerning  cleanup of a disposal  site.
OG&amp;E was not the owner or operator of this site, rather OG&amp;E, along with
many others, shipped materials to the owner or operator of the site who disposed
of the materials. OG&amp;E's total waste disposed at this site is minimal and on
February 15, 1996,  OG&amp;E elected to participate in the de minimis settlement
offered  by the  EPA.  One of  the  other  potentially  responsible  parties  is
currently contesting OG&amp;E's  participation as a de minimis party. Regardless
of the outcome of this issue,  OG&amp;E believes its ultimate liability for this
site is minimal.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Trigen-Oklahoma
City Energy Corp.  ("Trigen") sued OG&amp;E in the United States District Court,
Western  District of Oklahoma,  alleging  numerous  causes of action,  including
monopolization  of cooling services in violation of the Sherman Act. On December
21,  1998,  the jury  awarded  Trigen  in excess of $30  million  in actual  and
punitive  damages.  On February 19, 1999,  the trial court  entered  judgment in
favor of Trigen as follows:  (i) $6.8 million for various antitrust  violations,
(ii) $4 million for tortious  interference with an existing  contract,  (iii) $7
million for tortious interference with a prospective economic advantage and (iv)
$10  million  in  punitive  damages.  The trial  judge,  in a  companion  order,
acknowledged  that  portions  of the  judgment  could be  duplicative,  that the
antitrust  amounts could be tripled and that parties should address these issues
in their  post-trial  motions.  On January  25,  2000,  a trial  judge  rejected
OG&amp;E's post-trial motions to reverse the jury verdict or to grant OG&amp;E a
new trial.  The judge did,  however  reduce the  original  $30 million  judgment
against OG&amp;E to $20 million.  OG&amp;E appealed the trial court's ruling and
oral arguments were heard by the Tenth Circuit Court of Appeals in January 2001.
A decision is not expected for several  months.  While the outcome of the appeal
is  uncertain,  legal  counsel and  management  believe it is not probable  that
Trigen will  ultimately  succeed in preserving  the verdicts.  Accordingly,  the
Company has not  accrued  any loss  associated  with the  damages  awarded.  The
Company  believes  that the  ultimate  resolution  of this  case will not have a
material  adverse  effect on the Company's  consolidated  financial  position or
results of operations.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In   the   normal
course of business,  other  lawsuits,  claims,  environmental  actions and other
governmental  proceedings  arise  against  the  Company  and  its  subsidiaries.
Management,  after  consultation  with legal counsel,  does not anticipate  that
liabilities  arising out of other currently  pending or threatened  lawsuits and
claims  will  have a  material  adverse  effect  on the  Company's  consolidated
financial position or results of operations.</P>

<P ALIGN=LEFT><B>11.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Rate Matters and Regulation
</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   January  12,
2000, the OCC Staff (the "Staff") filed three  applications  to address  various
aspects of  OG&amp;E's  electric  rates.  The first  application  related to the
completion on March 1, 2000, of the recovery of the amortization premium paid by
OG&amp;E when it acquired Enogex in 1986 and the resulting removal,  pursuant to
the APC Rider,  of $12.8 million  ($10.7  million in the Oklahoma  Jurisdiction)
from the amount being recovered by OG&amp;E from its customers through currently
authorized electric rates.  OG&amp;E consented to this action and in March 2000,
the OCC approved the APC Rider for $10.7 million annually.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The        second
application  related to a review of the GEP Rider,  which,  as part of the OCC's
order issued in 1997 in connection with OG&amp;E's last general rate review (the
"1997  Order"),  was  scheduled  for review in March  2000.  OG&amp;E  collected
approximately  $9.9 million pursuant to the GEP Rider during 2000. The GEP Rider
initially was designed so that when  OG&amp;E's  average annual cost of fuel per
kwh was less than 96.261 percent of the average non-nuclear fuel cost per kwh of
certain other  investor-owned  utilities in the region,  OG&amp;E was allowed to
collect,  through  the GEP Rider,  one-third  of the amount by which  OG&amp;E's
average annual cost of fuel was below 96.261 percent of the average of the other
specified  utilities.  If OG&amp;E's  fuel cost exceeded  103.739 percent of the
stated average,  OG&amp;E was not allowed to recover one-third of the fuel costs
above that average from Oklahoma customers.  In April 2000 testimony,  the Staff
stated that they continued to support  incentive  programs that reward  superior
performance,  but in their view the  existing GEP Rider was not  functioning  as
they had originally envisioned it.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In June 2000, the
OCC approved the  collection of $6.6 million  through the GEP Rider for the time
period  July 1, 2000  through  June 30, 2001 and  approved  the  following  four
modifications  to the GEP  Rider:  (i)  changing  OG&amp;E&#146;s  peer group to
include  utilities with a higher  coal-to-gas  generation mix; (ii) reducing the
amount of fuel costs that can be recovered if  OG&amp;E&#146;s  costs exceed the
new peer group by  changing  the  percentage  above which  OG&amp;E  will not be
allowed to recover  one-third  of the fuel costs from  Oklahoma  customers  from
103.739 percent to 101.0 percent;  (iii) reducing  OG&amp;E&#146;s share of cost
savings as  compared  to its new peer group from 33 percent to 30  percent;  and
(iv)  limiting  to $10.0  million  the amount of any awards  paid to OG&amp;E or
penalties  charged to OG&amp;E.  The GEP Rider is to be revised effective July 1
of each year to reflect changes in the relative annual cost of fuel reported for
the preceding calendar year.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The         final
application,  relating to fuel cost recoveries, was used by the Staff to address
the competitive bid process of OG&amp;E's gas transportation  needs. In the 1997
Order,  the OCC approved a  stipulation  wherein  OG&amp;E  agreed to initiate a
competitive  bidding  process for gas  transportation  service to its  gas-fired
plants,  with the competitive  services commencing no later than April 30, 2000.
The order also set annual compensation for the transportation  services provided
by Enogex to OG&amp;E at $41.3  million  annually  until March 1, 2000, at which
time the rate would drop to $28.5 million  (reflecting removal of the APC Rider,
upon the completion of the recovery from customers of the  amortization  premium
paid by OG&amp;E when it acquired Enogex in 1986) and remain at that level until
competitively-bid  gas  transportation  began. Final firm bids were submitted by
Enogex and other  pipelines on April 15, 1999. In July 1999,  OG&amp;E  filed an
application with the OCC requesting  approval of a  performance-based  rate plan
for its Oklahoma  retail  customers  from April 2000 until the  introduction  of
customer  choice for electric  power in July 2002. As part of this  application,
OG&amp;E stated that Enogex had submitted the only viable bid ($33.4 million per
year) for gas  transportation to OG&amp;E's six gas-fired power plants that were
the  subject of the  competitive  bid.  As part of its  application  to the OCC,
OG&amp;E  offered to discount  Enogex's bid from $33.4 million annually to $25.2
million annually.  OG&amp;E executed a gas  transportation  contract with Enogex
under which Enogex  continues to serve the needs of OG&amp;E's power plants at a
price to be paid by  OG&amp;E  of $33.4  million  annually  and,  if  OG&amp;E's
proposal had been approved by the OCC,  OG&amp;E  would have recovered a portion
of such amount ($25.2 million) from its customers.  OG&amp;E negotiated with the
Staff, the Office of the Oklahoma Attorney General and a coalition of industrial
customers  in an effort to settle  all issues  (including  the  competitive  bid
process) associated with its application for a performance-based rate plan. When
these negotiations failed,  OG&amp;E withdrew its application,  which withdrawal
was approved by the OCC in December 1999.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In   July   2000,
OG&amp;E  entered into a stipulation  (the  "Stipulation")  with the Staff,  the
Office of the Attorney General and a coalition of industrial customers regarding
the  competitive  bid process of  OG&amp;E's  gas  transportation  service.  The
Stipulation  (which,  with one  exception,  was  signed  by all  parties  to the
proceeding)  would permit  OG&amp;E to recover  $25.2  million  annually for gas
transportation services to be provided by Enogex pursuant to the competitive bid
process.  The  Stipulation was presented for approval to an  Administrative  Law
Judge ("ALJ") in September 2000, and the ALJ recommended its approval.  However,
at a  hearing  on  September  28,  2000,  the OCC  chose to delay  the  decision
concerning the Stipulation and two of the three commissioners  expressed concern
over the  competitive  bid process.  OG&amp;E cannot predict what further action
the OCC may  take.  OG&amp;E  believes  that the  competitive  bid  process  was
appropriate and is currently collecting $28.5 million on an annual basis through
its base rates and APC Rider for gas transportation services from Enogex for the
power plant requirements covered by the competitive bid.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On  February  13,
1998, the APSC staff filed a motion for a show cause order to review  OG&amp;E's
electric  rates in the State of Arkansas.  The Staff  recommended a $3.1 million
annual rate reduction  (based on a test year ended December 31, 1996). The Staff
and OG&amp;E  reached a settlement  for a $2.3  million  annual rate  reduction,
which was approved by the APSC in August 1999.</P>

<P ALIGN=LEFT><B>12.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Disclosures about Fair Value
of Financial Instruments </B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The fair value of
Long-Term  Debt and  Preferred  Securities  is estimated  based on quoted market
prices and management's  estimate of current rates available for similar issues.
The fair value of the Enogex Notes is based on management's  estimate of current
rates available for similar issues with the same remaining maturities.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Indicated   below
are the carrying  amounts and estimated  fair values of the Company's  financial
instruments as of December 31:</P>

<PRE>
                                                             2000                      1999                     1998
                                                     --------------------     --------------------    ---------------------
                                                     Carrying      Fair       Carrying      Fair      Carrying      Fair
(dollars in thousands)                                Amount       Value       Amount       Value      Amount       Value
===========================================================================================================================
Long-Term Debt and Preferred Securities:
     Senior Notes............................        $567,182    $552,256     $457,646    $422,181    $567,512    $593,313
     Industrial Authority Bonds..............         135,400     135,400      135,400     135,400     135,400     135,400
     Enogex Inc. Notes.......................         745,941     797,766      347,486     410,578     232,671     251,505
     Trust Originated Preferred Securities...         200,000     200,000      200,000     200,000         ---         ---
===========================================================================================================================
</PRE>

<P ALIGN=LEFT><B>13.&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Subsequent Events</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In  January 2001,
the Company  renewed its  agreement for a line of credit for up to $300 million,
$200  million of which is to expire on January  15,  2002,  and $100  million of
which is to expire on January 15, 2004.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On   January  10,
2001,  Enogex retired $5 million  principal  amount of 7.75 percent  medium-term
notes  due  April  24,  2023.  This  debt  was  assumed  as part of the  Transok
acquisition.</P><BR><BR>



<P ALIGN=LEFT><U>Report of Independent Public Accountants</U></P>


<P ALIGN=CENTER>ARTHUR ANDERSEN</P>

<P ALIGN=LEFT><B>To the Shareowners of<BR>
OGE Energy Corp.:</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;We  have  audited
the accompanying consolidated balance sheets and statements of capitalization of
OGE Energy Corp. (an Oklahoma  corporation)  and its subsidiaries as of December
31, 2000,  1999 and 1998,  and the related  consolidated  statements  of income,
retained  earnings  and cash flows for the years  then  ended.  These  financial
statements   are  the   responsibility   of  the   Company's   management.   Our
responsibility  is to express an opinion on these financial  statements based on
our audits.</P>

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

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In  our  opinion,
the  financial  statements  referred to above  present  fairly,  in all material
respects,  the financial position of OGE Energy Corp. and its subsidiaries as of
December 31, 2000, 1999 and 1998, and the results of their  operations and their
cash flows for the years then ended in  conformity  with  accounting  principles
generally accepted in the United States.</P><BR><BR><BR>




<P ALIGN=CENTER>&nbsp;&nbsp;&nbsp;&nbsp;/s/ Arthur Andersen LLP<BR>
Arthur Andersen LLP</P><BR>

<P ALIGN=LEFT>Oklahoma City, Oklahoma,<BR>
January 18, 2001</P><BR><BR><BR>



<P ALIGN=LEFT><U>Report of Management</U></P><BR>



<P ALIGN=LEFT><B>To Our Shareowners:</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The management of
OGE Energy Corp. is responsible for the  preparation,  integrity and objectivity
of the consolidated financial statements of the Company and its subsidiaries and
other information included in this report. The consolidated financial statements
have been prepared in conformity with accounting  principles  generally accepted
in the United States.  As appropriate,  the statements  include amounts based on
informed estimates and judgments of management.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The management of
the Company has established and maintains a system of internal  control designed
to provide  reasonable  assurance,  on a cost-effective  basis,  that assets are
safeguarded,   transactions   are  executed  in  accordance  with   management's
authorization  and  financial  records are reliable for  preparing  consolidated
financial  statements.  Management  believes that the system of control provides
reasonable assurance that errors or irregularities that could be material to the
consolidated  financial  statements are prevented or would be detected  within a
timely period.  Key elements of this system include the effective  communication
of  established  written  policies  and  procedures,  selection  and training of
qualified personnel and organizational  arrangements that provide an appropriate
division of  responsibility.  This system of control is  augmented by an ongoing
internal  audit  program  designed to evaluate its  adequacy and  effectiveness.
Management   considers  the   recommendations   of  the  internal  auditors  and
independent  certified  public  accountants  concerning the Company's  system of
internal  control and takes timely and  appropriate  actions to alleviate  their
concerns. Management believes that as of December 31, 2000, the Company's system
of  internal  control  was  adequate  to  accomplish  the  objectives  discussed
herein.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The    Board   of
Directors  of  the  Company  addresses  its  oversight  responsibility  for  the
consolidated financial statements through its Audit Committee, which is composed
of directors who are not  employees of the Company.  The Audit  Committee  meets
regularly  with the  Company's  management,  internal  auditors and  independent
certified public accountants to review matters relating to financial  reporting,
auditing and internal control. To ensure auditor independence, both the internal
auditors and independent  certified public accountants have full and free access
to the Audit Committee.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The   independent
certified public  accounting firm of Arthur Andersen LLP is engaged to audit, in
accordance with auditing standards  generally accepted in the United States, the
consolidated  financial  statements of the Company and its  subsidiaries  and to
issue their report thereon.</P><BR><BR>


<PRE>
    /s/ Steven E. Moore                                            /s/ Al M. Strecker
    ----------------------------------------------------           -------------------------------------------------
    Steven E. Moore, Chairman of the Board,                        Al M. Strecker, Executive Vice President
      President and Chief Executive Officer                          and Chief Operating Officer



    /s/ James R. Hatfield                                          /s/ Donald R. Rowlett
    ----------------------------------------------------           -------------------------------------------------
    James R. Hatfield, Sr. Vice President and                      Donald R. Rowlett, Vice President
      Chief Financial Officer                                        and Controller
</PRE><BR><BR><BR>

<P ALIGN=LEFT><U><B>Supplementary Data</B></U></P>

<P ALIGN=LEFT><U>Interim Consolidated Financial Information (Unaudited)</U></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;In the opinion of
the Company,  the  following  quarterly  information  includes all  adjustments,
consisting of normal  recurring  adjustments,  necessary for a fair statement of
the results of operations for such periods:</P>

<PRE>
Quarter ended (dollars in thousands except                      Dec 31         Sep 30         Jun 30        Mar 31
per share data)
--------------------------------------------------------------------------------------------------------------------

Operating revenues.............................    2000      $  982,276     $1,007,966     $  726,904    $  581,581
                                                   1999         575,978        767,390        450,861       378,205
                                                   1998         361,750        555,999        412,621       287,367
--------------------------------------------------------------------------------------------------------------------

Operating income...............................    2000      $   40,819     $  205,060     $   71,746    $   32,196
                                                   1999          50,570        180,373         73,147        34,075
                                                   1998          31,803        202,943         92,789        11,922
--------------------------------------------------------------------------------------------------------------------

Net income (loss)..............................    2000      $    7,208     $  107,307     $   31,744    $      776
                                                   1999          12,179         90,204         37,744        11,132
                                                   1998          10,230        108,117         47,865          (340)
--------------------------------------------------------------------------------------------------------------------

Earnings (loss) available for common stock.....    2000      $    7,208     $  107,307     $   31,744    $      776
                                                   1999          12,179         90,204         37,744        11,132
                                                   1998          10,230        108,117         47,865        (1,073)
--------------------------------------------------------------------------------------------------------------------

Earnings (loss) per average common share.......    2000      $     0.09     $     1.38     $     0.41    $     0.01
                                                   1999            0.15           1.16           0.49          0.14
                                                   1998            0.13           1.33           0.59         (0.01)
--------------------------------------------------------------------------------------------------------------------
</PRE>

<P ALIGN=LEFT><B><U>Item 9.  Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure.</U></B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Not Applicable.

<P ALIGN=CENTER><B>PART III</B></P>

<P ALIGN=LEFT><B><U>Item 10. Directors and Executive Officers of
the Registrant.</U></B></P>

<P ALIGN=LEFT><B><U>Item 11. Executive Compensation.</U></B></P>

<P ALIGN=LEFT><B><U>Item 12. Security Ownership of Certain
Beneficial</U></B><BR>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<B><U>Owners and Management.</U></B></P>

<P ALIGN=LEFT><B><U>Item 13. Certain Relationships and Related
Transactions.</U></B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Items  10, 11, 12
and 13 are omitted  pursuant to General  Instruction  G of Form 10-K,  since the
Company filed copies of a definitive  proxy  statement  with the  Securities and
Exchange  Commission  on or about  March  30,  2001.  Such  proxy  statement  is
incorporated herein by reference. In accordance with Instruction G of Form 10-K,
the  information  required by Item 10 relating to  Executive  Officers  has been
included in Part I, Item 4, of this Form 10-K.</P>

<P ALIGN=CENTER><B>PART IV</B></P>

<P ALIGN=LEFT><B><U>Item 14. Exhibits, Financial Statement
Schedules and</U></B><BR>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<B><U>Reports on Form 8-K.</U></B></P>

<P ALIGN=LEFT><B><U>(a) 1. Financial Statements</U></B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The     following
consolidated  financial  statements and supplementary  data are included in Part
II, Item 8 of this Report:</P>
<UL>
<LI>Consolidated Balance Sheets at December 31, 2000, 1999 and 1998<BR><BR>

<LI>Consolidated  Statements  of Income for the years ended  December  31, 2000,
1999 and 1998<BR><BR>

<LI>Consolidated  Statements of Retained  Earnings for the years ended  December
31, 2000, 1999 and 1998<BR><BR>

<LI>Consolidated  Statements of  Capitalization  at December 31, 2000,  1999 and
1998<BR><BR>

<LI>Consolidated Statements of Cash Flows for the years ended December 31, 2000,
1999 and 1998<BR><BR>

<LI>Notes to Consolidated Financial Statements<BR><BR>

<LI>Report of Independent Public Accountants<BR><BR>

<LI>Report of Management
</UL><BR><BR>



<P ALIGN=LEFT><U><B>Supplementary Data</B></U></P>
<UL>
<LI>Interim Consolidated Financial Information
</UL><BR><BR>

<P ALIGN=LEFT><B><U>2. Financial Statement Schedule (included in
Part IV)</U></B>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;<B><U>Page</U></B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Schedule II - Valuation and Qualifying Accounts
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;81</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Report of Independent Public Accountants
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;82</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;All  other schedules have been omitted since the
required  information  is not  applicable  or is not  material,  or because  the
information required is included in the respective financial statements or notes
thereto.</P>

<P ALIGN=LEFT><B><U>3.  Exhibits</U></B></P>

<P  ALIGN=LEFT><B><U>Exhibit  No.</U></B>&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
<B><U>Description</U></B></P>

<P ALIGN=LEFT>2.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Purchase Agreement, dated as of
May 14, 1999, by and between<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Tejas Gas, LLC and Enogex Inc. (Filed as Exhibit 2.01<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;to OGE Energy's Form 10-Q for the quarter ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;June 30, 1999 (File No. 1-12579) and incorporated by<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;reference herein)<P>

<P ALIGN=LEFT>3.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Copy of Restated Certificate of
Incorporation.  (Filed as Exhibit<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.01 to OGE Energy's Form 10-K for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1996 (File No. 1-12579) and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporated by reference herein)</P>

<P ALIGN=LEFT>3.02&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;By-laws.  (Filed as Exhibit 3.02
to OGE Energy's Form 10-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;for the year ended December 31, 1996 (File No.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1-12579) and incorporated by reference herein)</P>

<P ALIGN=LEFT>4.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Copy of Trust Indenture dated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;October 1, 1995, from OG&amp;E to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Boatmen's First National Bank of Oklahoma, Trustee.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 4.29 to Registration Statement No. 33-61821<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;and incorporated by reference herein)</P>

<P ALIGN=LEFT>4.02&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Copy of Supplemental Trust Indenture No. 1 dated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;October 16, 1995, being a supplemental instrument<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;to Exhibit 4.01 hereto.  (Filed as Exhibit 4.01 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's Form 8-K Report dated October 23, 1995<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(File No. 1-1097) and incorporated by reference herein)</P>

<P ALIGN=LEFT>4.03&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Supplemental Indenture No. 2, dated as of July 1, 1997,<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;being a supplemental instrument to Exhibit<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.01 hereto.  (Filed as Exhibit 4.01 to OG&amp;E's Form 8-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;filed on July 17, 1997, (File No. 1-1097) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>4.04&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Supplemental Indenture No. 3, dated as of April 1, 1998,<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;being a supplemental instrument to Exhibit 4.01 hereto.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 4.01 to OG&amp;E's Form 8-K filed on<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;April 16, 1998 (File No. 1-1097) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>4.05&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Supplemental Indenture No. 4, dated as of October 15, 2000,<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;being a supplement instrument to Exhibit 4.01 hereto.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 4.02 to OG&amp;E's Form 8-K filed on<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;October 20, 2000 (File No. 1-1097) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>10.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Coal Supply Agreement dated March 1, 1973, between<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E and Atlantic Richfield Company.  (Filed as<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Exhibit 5.19 to Registration Statement No. 2-59887<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.02&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendment dated April 1, 1976, to Coal Supply<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Agreement dated March 1, 1973, between OG&amp;E<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;and Atlantic Richfield Company, together with<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;related correspondence.  (Filed as Exhibit 5.21 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Registration Statement No. 2-59887 and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporated by reference herein)</P>

<P ALIGN=LEFT>10.03&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Second Amendment dated March 1, 1978, to Coal Supply<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Agreement dated March 1, 1973, between OG&amp;E and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Atlantic Richfield Company.  (Filed as Exhibit 5.28<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;to Registration Statement No. 2-62208 and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>10.04&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendment dated June 27, 1990, between OG&amp;E and Thunder<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Basin Coal Company, to Coal Supply Agreement<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;dated March 1, 1973, between OG&amp;E and Atlantic<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Richfield Company.  (Filed as Exhibit 10.04 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's Form 10-K Report for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1994 (File No. 1-1097) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein) [Confidential Treatment has been<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;requested for certain portions of this exhibit.]</P>

<P ALIGN=LEFT>10.05&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Form of Change of Control Agreement for Officers of the<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company and OG&amp;E.  (Filed as Exhibit 10.07 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE Energy's Form 10-K for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1996 (File No. 1-12579) and</P>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporated by reference herein)<BR>

<P ALIGN=LEFT>10.06&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Directors' Deferred Compensation Plan. (Filed as Exhibit 10.06 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE Energy's Form 10-K for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1999 (File No. 1-12579) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>10.07&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company's Stock Incentive Plan.  (Filed as Exhibit 10.07 to OGE<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Energy's Form 10-K for the year ended December 31, 1998<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(File No. 1-12579) and incorporated by reference herein)<P>

<P ALIGN=LEFT>10.08&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's Restoration of Retirement Income Plan, as amended.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 10.12 to Energy Corp.'s Form 10-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;for the year ended December 31, 1996 (File No.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1-12579) and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.09&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's Supplemental Executive Retirement Plan, as amended.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 10.15 to OGE Energy's Form 10-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;for the year ended December 31, 1996 (File No.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1-12579) and incorporated by reference herein)<BR>

<P ALIGN=LEFT>10.10&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company's Annual Incentive Compensation Plan.  (Filed as<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Exhibit 10.12 to OGE Energy's Form 10-K for the<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;year ended December 31, 1998 (File No. 1-12579)<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.11&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company's Deferred Compensation Plan.  (Filed as Exhibit 4<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;to the Company's Form S-8 Registration Statement<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;No. 333-92433 and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.12&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Copy of Amended and Restated Rights Agreement, dated as of<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;October 10, 2000 between OGE Energy Corp. and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Chase Mellon Shareholder Services, LLC, as Rights<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Agent (Filed as Exhibit 4.1 to OGE Energy's Form 8-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;filed on November 1, 2000 (File No. 1-12579) and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporated by reference herein)</P>

<P ALIGN=LEFT>10.13&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendment No. 3 to OG&amp;E's Restoration
of Retirement Income Plan.</P>

<P ALIGN=LEFT>10.14&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendment No. 4 to OGE Energy's
Restoration of Retirement Income Plan.</P>

<P ALIGN=LEFT>21.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Subsidiaries of the Registrant.</P>

<P ALIGN=LEFT>23.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Consent of Arthur Andersen LLP.</P>

<P ALIGN=LEFT>24.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Power of Attorney.</P>

<P ALIGN=LEFT>99.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Cautionary Statement for Purposes of the "Safe Harbor"<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Provisions of the Private Securities Litigation<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Reform Act of 1995.</P><BR><BR><BR>



<P ALIGN=LEFT>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;<U>Executive Compensation Plans and Arrangements
</U></P>

<P ALIGN=LEFT>10.05&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Form of Change of Control Agreement for Officers of the<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company and OG&amp;E.  (Filed as Exhibit 10.07 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE Energy's Form 10-K for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1996 (File No. 1-12579) and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporated by reference herein)</P>

<P ALIGN=LEFT>10.06&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Directors' Deferred Compensation Plan. (Filed as Exhibit 10.06 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE Energy's Form 10-K for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1999 (File No. 1-12579) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>10.07&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company's Stock Incentive Plan.  (Filed as Exhibit 10.07 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE Energy's Form 10-K for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1998 (File No. 1-12579) and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporated by reference herein)</P>

<P ALIGN=LEFT>10.08&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's Restoration of Retirement Income Plan, as amended.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 10.12 to OGE Energy's Form 10-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;for the year ended December 31, 1996 (File No.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1-12579) and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.09&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's Supplemental Executive Retirement Plan, as amended.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 10.15 to OGE Energy's Form 10-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;for the year ended December 31, 1996 (File No.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1-12579) and incorporated by reference herein)<BR>

<P ALIGN=LEFT>10.10&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company's Annual Incentive Compensation Plan.  (Filed as<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Exhibit 10.12 to OGE Energy's Form 10-K for the<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;year ended December 31, 1998 (File No. 1-12579)<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.11&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company's Deferred Compensation Plan.  (Filed as Exhibit 4<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;to the Company's Form S-8 Registration Statement<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;No. 333-92423 and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.13&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendment No. 3 to OG&amp;E's Restoration of Retirement Income Plan.</P>

<P ALIGN=LEFT>10.14&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendment No. 4 to OGE Energy's Restoration of Retirement Income Plan.</P>

<P ALIGN=LEFT><B><U>(b)  Reports on Form 8-K</U></B></P>

<P ALIGN=LEFT>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Item 5. Other Events, dated October 20, 2000.</P><BR><BR><BR>



<P ALIGN=CENTER><B>OGE ENERGY CORP.</B><P>

<P ALIGN=CENTER><B>SCHEDULE II - Valuation and Qualifying Accounts</B></P>


<PRE>
               Column A                   Column B                  Column C                   Column D        Column E
                                           Balance         Charged to      Charged to                           Balance
                                          Beginning        Costs and          Other                             End of
Description                                of Year          Expenses        Accounts          Deductions         Year
-----------                               ---------        --------------------------         ----------       ---------



  2000                                                                    (Thousands)



Reserve for Uncollectible Accounts        $ 5,270          $7,262              -              $ 8,397          $ 4,135



  1999



Reserve for Uncollectible Accounts        $ 3,342          $ 9,560             -              $ 7,632          $ 5,270



  1998



Reserve for Uncollectible Accounts        $ 4,507          $11,507             -              $12,672          $ 3,342
</PRE><BR><BR><BR>



<P ALIGN=CENTER><B>REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS</B></P><BR>


<P ALIGN=LEFT>To OGE Energy Corp.:</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;We  have  audited
in accordance with auditing  standards  generally accepted in the United States,
the  consolidated   financial  statements  of  OGE  Energy  Corp.  (an  Oklahoma
Corporation),  and its subsidiaries  included in this Form 10-K, and have issued
our report  thereon dated January 18, 2001. Our audits were made for the purpose
of forming an opinion on those  statements taken as a whole. The schedule listed
on Page 77 Item 14 (a) 2. is the responsibility of the Company's  management and
is  presented  for  purposes  of  complying  with the  Securities  and  Exchange
Commission's  rules  and is not part of the  basic  financial  statements.  This
schedule has been subjected to the auditing  procedures applied in the audits of
the  basic  financial  statements  and,  in our  opinion,  fairly  states in all
material  respects  the  financial  data  required  to be set forth  therein  in
relation to the basic financial statements taken as a whole.</P><BR><BR><BR>


<P ALIGN=CENTER>&nbsp;&nbsp;&nbsp;&nbsp;/s/ Arthur Andersen LLP<BR>
Arthur Andersen LLP</P><BR>

<P ALIGN=LEFT>Oklahoma City, Oklahoma,<BR>
January 18, 2001</P><BR><BR><BR>



<P ALIGN=CENTER>SIGNATURES</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Pursuant  to  the
requirements of the Securities Exchange Act of 1934, as amended,  the Registrant
has duly  caused  this  Report to be signed  on its  behalf by the  undersigned,
thereunto duly  authorized,  in the City of Oklahoma City, and State of Oklahoma
on the 26th day of March, 2001.</P>

<P ALIGN=CENTER>OGE ENERGY CORP.<BR>
(REGISTRANT)</P>

<P ALIGN=CENTER>/s/ Steven E. Moore<BR>
By Steven E. Moore<BR>
Chairman of the Board, President<BR>
and Chief Executive Officer</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Pursuant  to  the
requirements of the Securities Exchange Act of 1934, as amended, this Report has
been signed below by the following  persons in the  capacities  and on the dates
indicated.</P>

<PRE>
        Signature                           Title                           Date
-------------------------         --------------------------------     --------------
/ s / Steven E. Moore
Steven E. Moore                   Principal Executive
                                    Officer and Director;              March 26, 2001

/ s / James R. Hatfield
James R. Hatfield                 Principal Financial Officer; and     March 26, 2001

/ s / Donald R. Rowlett
Donald R. Rowlett                 Principal Accounting Officer.        March 26, 2001


         Herbert H. Champlin             Director;

         Luke R. Corbett                 Director;

         William E. Durrett              Director;

         Martha W. Griffin               Director;

         Hugh L. Hembree, III            Director;

         Robert Kelley                   Director;

         Bill Swisher                    Director;

         Ronald H. White, M.D.           Director; and

         J. D. Williams                  Director.

/ s /  Steven E. Moore
By Steven E. Moore (attorney-in-fact)                                 March 26, 2001
</PRE><BR><BR><BR>

<P ALIGN=CENTER><U><B>Exhibit Index</B></U></P>

<P  ALIGN=LEFT><B><U>Exhibit  No.</U></B>&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
<B><U>Description</U></B></P>

<P ALIGN=LEFT>2.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Purchase Agreement, dated as of
May 14, 1999, by and between<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Tejas Gas, LLC and Enogex Inc. (Filed as Exhibit 2.01<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;to OGE Energy's Form 10-Q for the quarter ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;June 30, 1999 (File No. 1-12579) and incorporated by<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;reference herein)<P>

<P ALIGN=LEFT>3.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Copy of Restated Certificate of
Incorporation.  (Filed as Exhibit<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.01 to OGE Energy's Form 10-K for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1996 (File No. 1-12579) and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporated by reference herein)</P>

<P ALIGN=LEFT>3.02&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;By-laws.  (Filed as Exhibit 3.02
to OGE Energy's Form 10-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;for the year ended December 31, 1996 (File No.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1-12579) and incorporated by reference herein)</P>

<P ALIGN=LEFT>4.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Copy of Trust Indenture dated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;October 1, 1995, from OG&amp;E to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Boatmen's First National Bank of Oklahoma, Trustee.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 4.29 to Registration Statement No. 33-61821<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;and incorporated by reference herein)</P>

<P ALIGN=LEFT>4.02&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Copy of Supplemental Trust Indenture No. 1 dated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;October 16, 1995, being a supplemental instrument<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;to Exhibit 4.01 hereto.  (Filed as Exhibit 4.01 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's Form 8-K Report dated October 23, 1995<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(File No. 1-1097) and incorporated by reference herein)</P>

<P ALIGN=LEFT>4.03&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Supplemental Indenture No. 2, dated as of July 1, 1997,<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;being a supplemental instrument to Exhibit<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.01 hereto.  (Filed as Exhibit 4.01 to OG&amp;E's Form 8-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;filed on July 17, 1997, (File No. 1-1097) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>4.04&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Supplemental Indenture No. 3, dated as of April 1, 1998,<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;being a supplemental instrument to Exhibit 4.01 hereto.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 4.01 to OG&amp;E's Form 8-K filed on<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;April 16, 1998 (File No. 1-1097) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>4.05&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Supplemental Indenture No. 4, dated as of October 15, 2000,<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;being a supplement instrument to Exhibit 4.01 hereto.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 4.02 to OG&amp;E's Form 8-K filed on<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;October 20, 2000 (File No. 1-1097) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>10.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Coal Supply Agreement dated March 1, 1973, between<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E and Atlantic Richfield Company.  (Filed as<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Exhibit 5.19 to Registration Statement No. 2-59887<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.02&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendment dated April 1, 1976, to Coal Supply<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Agreement dated March 1, 1973, between OG&amp;E<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;and Atlantic Richfield Company, together with<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;related correspondence.  (Filed as Exhibit 5.21 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Registration Statement No. 2-59887 and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporated by reference herein)</P>

<P ALIGN=LEFT>10.03&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Second Amendment dated March 1, 1978, to Coal Supply<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Agreement dated March 1, 1973, between OG&amp;E and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Atlantic Richfield Company.  (Filed as Exhibit 5.28<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;to Registration Statement No. 2-62208 and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>10.04&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendment dated June 27, 1990, between OG&amp;E and Thunder<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Basin Coal Company, to Coal Supply Agreement<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;dated March 1, 1973, between OG&amp;E and Atlantic<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Richfield Company.  (Filed as Exhibit 10.04 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's Form 10-K Report for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1994 (File No. 1-1097) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein) [Confidential Treatment has been<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;requested for certain portions of this exhibit.]</P>

<P ALIGN=LEFT>10.05&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Form of Change of Control Agreement for Officers of the<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company and OG&amp;E.  (Filed as Exhibit 10.07 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE Energy's Form 10-K for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1996 (File No. 1-12579) and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporated by reference herein)</P>

<P ALIGN=LEFT>10.06&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Directors' Deferred Compensation Plan. (Filed as Exhibit 10.06 to<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE Energy's Form 10-K for the year ended<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;December 31, 1999 (File No. 1-12579) and incorporated<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;by reference herein)</P>

<P ALIGN=LEFT>10.07&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company's Stock Incentive Plan.  (Filed as Exhibit 10.07 to OGE<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Energy's Form 10-K for the year ended December 31, 1998<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(File No. 1-12579) and incorporated by reference herein)<P>

<P ALIGN=LEFT>10.08&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's Restoration of Retirement Income Plan, as amended.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 10.12 to OGE Energy's Form 10-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;for the year ended December 31, 1996 (File No.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1-12579) and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.09&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OG&amp;E's Supplemental Executive Retirement Plan, as amended.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(Filed as Exhibit 10.15 to OGE Energy's Form 10-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;for the year ended December 31, 1996 (File No.<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1-12579) and incorporated by reference herein)<BR>

<P ALIGN=LEFT>10.10&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company's Annual Incentive Compensation Plan.  (Filed as<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Exhibit 10.12 to OGE Energy's Form 10-K for the<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;year ended December 31, 1998 (File No. 1-12579)<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.11&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Company's Deferred Compensation Plan.  (Filed as Exhibit 4<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;to the Company's Form S-8 Registration Statement<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;No. 333-92423 and incorporated by reference herein)</P>

<P ALIGN=LEFT>10.12&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Copy of Amended and Restated Rights Agreement, dated as of<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;October 10, 2000 between OGE Energy Corp. and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Chase Mellon Shareholder Services, LLC, as Rights<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Agent (Filed as Exhibit 4.1 to OGE Energy's Form 8-K<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;filed on November 1, 2000 (File No. 1-12579) and<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;incorporated by reference herein)</P>

<P ALIGN=LEFT>10.13&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendment No. 3 to OG&amp;E's Restoration
of Retirement Income Plan.</P>

<P ALIGN=LEFT>10.14&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Amendment No. 4 to OGE Energy's
Restoration of Retirement Income Plan.</P>

<P ALIGN=LEFT>21.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Subsidiaries of the Registrant.</P>

<P ALIGN=LEFT>23.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Consent of Arthur Andersen LLP.</P>

<P ALIGN=LEFT>24.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Power of Attorney.</P>

<P ALIGN=LEFT>99.01&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Cautionary Statement for Purposes of the "Safe Harbor"<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Provisions of the Private Securities Litigation<BR>
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Reform Act of 1995.</P><BR><BR><BR>

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<DOCUMENT>
<TYPE>EX-10.13
<SEQUENCE>2
<FILENAME>0002.htm
<DESCRIPTION>AMENDMENT NO. 3 TO OG&E RET INCOME PLAN
<TEXT>


<HTML>
<HEAD>
<TITLE>AMENDMENT NO. 3 TO OKLAHOMA GAS AND ELECTRIC COMPANY RET INC PLAN</TITLE>
</HEAD>

<BODY>


<P ALIGN=RIGHT><B>Exhibit 10.13</B></P>


<P ALIGN=CENTER><B>AMENDMENT NO. 3<BR>
TO THE<BR>
OKLAHOMA GAS AND ELECTRIC COMPANY<BR>
RESTORATION OF RETIREMENT INCOME PLAN<BR>
(As Amended and Restated Effective January 1, 1994)</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Oklahoma      Gas
Electric  Company,  an Oklahoma  corporation,  in accordance  with the authority
contained in Section 9 of the Oklahoma Gas and Electric  Company  Restoration of
Retirement  Income Plan (the "Plan"),  hereby  amends the Plan,  effective as of
January 1, 1998, as follows:</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  second paragraph of Section
5 of the Plan is deleted and replaced with the following paragraph:</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&#147;Inmaking
this  computation,  it is intended that the recipient  should  receive an amount
from this Plan which, if expressed as an actuarial  equivalent  lump-sum amount,
would enable him to purchase an individual  annuity that would produce a monthly
benefit,  after payment of applicable  Federal,  State and local income taxes on
such lump-sum  amount at the maximum rates in effect in the year of commencement
of Plan  benefits,  equal to the monthly  benefit,  after payment of such income
taxes,  that the recipient  would have received  under the  Retirement  Plan had
Sections  401(a)(17) and 415 of the Code not been applicable  thereto,  less the
benefits which are payable under the Retirement Plan.&#148;</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The first paragraph of Section 6
of the Plan is deleted and replaced with the following paragraph:</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&#147;Payment  of
benefits  under this Plan shall be made only when,  and if, the  participant  is
entitled to benefits under the Retirement  Plan. Such payments shall commence on
the  participant&#146;s  actual  retirement  date or  within a  reasonable  time
thereafter,  and such payments shall be made, on an actuarial  equivalent basis,
in  monthly  or  annual  installments  over a  specified  number  of years to be
determined by the Retirement Committee in its discretion.  If a participant dies
before the expiration of the specified payment period, his or her beneficiary or
beneficiaries  shall be paid a lump-sum amount equal to the present value of the
remaining   installment   payments,   determined  on  an  actuarial   equivalent
basis.&#148;</P><BR><BR><BR>

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</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-10.14
<SEQUENCE>3
<FILENAME>0003.htm
<DESCRIPTION>AMEND NO. 4 TO THE OGE ENERGY CORP. RET INC PLAN
<TEXT>


<HTML>
<HEAD>
<TITLE>AMENDMENT NO. 4 TO OGE ENERGY CORP. RET INC PLAN</TITLE>
</HEAD>

<BODY>


<P ALIGN=RIGHT><B>Exhibit 10.14</B></P>


<P ALIGN=CENTER><B>AMENDMENT NO. 4<BR>
TO THE<BR>
OKLAHOMA GAS AND ELECTRIC COMPANY<BR>
RESTORATION OF RETIREMENT INCOME PLAN<BR>
(As Amended and Restated Effective January 1, 1994)</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;OGE Energy Corp.,
an Oklahoma  corporation  (the  "Company"),  in  accordance  with the  authority
reserved to the Company under Section 9 of the OGE Energy Corp.  Restoration  of
Retirement  Income Plan (the "Plan"),  hereby  amends the Plan,  effective as of
January 1, 2000, in the following particulars:</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;By  deleting the first paragraph
of Section 2 of the Plan and substituting the following new paragraph therefore:
</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&#147;&#147;
Compensation&#148;    shall   mean,   during   an   applicable    period,    the
participant&#146;s  Compensation under the Retirement Plan, except that (i) such
Compensation shall not be limited by Code Section 401(a)(17) as in effect during
such applicable period,  (ii) such Compensation  shall include amounts,  if any,
deferred by the  participant  for the  calendar  year in question  under the OGE
Energy  Corp.  Deferred  Compensation  Plan  (the  &#147;Deferred   Compensation
Plan&#148;),  and (iii)  Compensation  under  this Plan  shall  include  bonuses
payable  pursuant to the OGE Energy Corp.  Annual  Incentive  Plan. Such bonuses
shall be included as Compensation  for purposes of the Plan in the year in which
the services to which the bonuses relate are preformed, notwithstanding the fact
that the bonuses are not actually  declared and paid to  participants  until the
following year.&#148;
</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;By  deleting  Section  4 of  the
Plan and substituting the following therefore:</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;<U>Eligibility</U></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Participants   in
the  Retirement  Plan  whose  pension  or  pension-related  benefits  under  the
Retirement  Plan are  limited  by (i) the  provisions  thereof  relating  to the
maximum  benefit   limitations  of  Section  415  of  the  Code  (the  &#147;415
Limit&#148;),  (ii) the  limitation  on includible  Compensation  under the Code
401(a)(17),  as in effect on and after January 1, 1989,  and as adjusted  and/or
amended from time to time (the &#147;401(a)(17) Limit&#148;), or (iii) by reason
of deferrals under the Deferred Compensation Plan shall be eligible for benefits
under this Plan. In no event shall a participant who is not entitled to benefits
under the Retirement Plan be eligible for a benefit under this Plan.&#148;</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;By deleting the second paragraph
of subsection 5(b) of the Plan and substituting the following therefore:</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&#147;In   making
this  computation,  it is intended that the recipient  should  receive an amount
from this Plan which, if expressed as an actuarial  equivalent  lump-sum amount,
would enable him to purchase an individual  annuity that would produce a monthly
benefit,  after payment of applicable  Federal,  State and local income taxes on
such lump-sum  amount at the maximum rates in effect in the year of commencement
of Plan  benefits,  equal to the monthly  benefit,  after payment of such income
taxes,  that the recipient  would have received  under the  Retirement  Plan had
Sections 401 (a)(17) and 415 of the Code not been applicable  thereto and if the
participant&#146;s  deferrals under the Deferred  Compensation Plan were treated
as compensation  under the Retirement  Plan, less the benefits which are payable
under the Retirement Plan.&#148;</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.&nbsp;&nbsp;
&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;By  deleting the first  sentence
of the third  paragraph  of  subsection  5(b) of the Plan and  substituting  the
following therefore:</P>


<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&#147;Benefits
payable under this Plan shall be computed in  accordance  with the foregoing and
with the objective  that such  recipient  should receive under this Plan and the
Retirement  Plan  that  total  amount  which  would  have been  payable  to that
recipient  solely under the Retirement Plan had the 415 and the 401(a)(17) Limit
not been  applicable  thereto  and the  participant&#146;s  deferrals  under the
Deferred  Compensation  Plan were treated as  compensation  under the Retirement
Plan.&#148;</P><BR><BR><BR>

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</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-21.01
<SEQUENCE>4
<FILENAME>0004.htm
<DESCRIPTION>OGE ENERGY CORP. SUBSIDIARIES OF THE REGISTRANT
<TEXT>


<HTML>
<HEAD>
<TITLE>OGE ENERGY CORP. SUBSIDIARIES OF THE REGISTRANT</TITLE>
</HEAD>

<BODY>


<P ALIGN=RIGHT><B>Exhibit 21.01</B></P><BR>

<P ALIGN=CENTER><B>OGE Energy Corp.<BR>
Subsidiaries of the Registrant</B></P><BR><BR><BR>

<PRE>
                                            Jurisdiction of           Percentage of
Name of Subsidiary                           Incorporation              Ownership
------------------                          ---------------           -------------

Oklahoma Gas and Electric Company              Oklahoma                   100.0
Enogex Inc.                                    Oklahoma                   100.0
Transok Holding LLC                            Delaware                   100.0
OGE Energy Capital Trust I                     Oklahoma                   100.0
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The  above listed
subsidiaries have been consolidated in the Registrant's financial statements.
</P><BR><BR><BR>


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</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-23.01
<SEQUENCE>5
<FILENAME>0005.htm
<DESCRIPTION>CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
<TEXT>


<HTML>
<HEAD>
<TITLE>CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS</TITLE>
</HEAD>

<BODY>


<P ALIGN=RIGHT><B>Exhibit 23.01</B></P><BR>

<P ALIGN=CENTER><B>CONSENT OF
INDEPENDENT PUBLIC ACCOUNTANTS</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As    independent
public accountants,  we hereby consent to the incorporation of our reports dated
January 18, 2001  included in the OGE Energy Corp.  Form 10-K for the year ended
December 31, 2000, into the previously filed Post-Effective Amendment No. 1-B to
Registration  Statement  No.  33-61699,  Post-Effective  Amendment  No.  2-B  to
Registration  Statement  No.  33-61699,  Form  S-8  Registration  Statement  No.
333-71327 and Form S-8 Registration Statement No. 333-92423.</P>



<P ALIGN=CENTER>&nbsp;&nbsp;&nbsp;&nbsp;/s/ Arthur Andersen LLP<BR>
Arthur Andersen LLP</P><BR>

<P ALIGN=LEFT>Oklahoma City, Oklahoma,<BR>
March 23, 2001</P><BR><BR><BR>



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</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-24.01
<SEQUENCE>6
<FILENAME>0006.htm
<DESCRIPTION>POWER OF ATTORNEY
<TEXT>


<HTML>
<HEAD>
<TITLE>POWER OF ATTORNEY</TITLE>
</HEAD>

<BODY>

<P ALIGN=RIGHT><FONT SIZE=2><B>Exhibit 24.01</B></FONT></P>

<P ALIGN=CENTER><B>POWER OF ATTORNEY</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;WHEREAS,      OGE
ENERGY CORP., an Oklahoma corporation (herein referred to as the "Company"),  is
about to file with the Securities and Exchange Commission,  under the provisions
of the  Securities  Exchange Act of 1934, as amended,  its annual report on Form
10-K for the year ended December 31, 2000; and</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;WHEREAS,  each of
the  undersigned  holds the office or offices in the  Company  herein-below  set
opposite his or her name, respectively;</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NOW,   THEREFORE,
each of the undersigned  hereby  constitutes and appoints STEVEN E. MOORE, JAMES
R. HATFIELD and DONALD R.  ROWLETT,  and each of them  individually,  his or her
attorney with full power to act for him or her and in his or her name, place and
stead,  to sign his name in the capacity or  capacities  set forth below to said
Form  10-K  and to any and all  amendments  thereto,  and  hereby  ratifies  and
confirms all that said attorney may or shall  lawfully do or cause to be done by
virtue hereof.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;IN        WITNESS
WHEREOF,  the undersigned have hereunto set their hands this 17th day of January
2001.</P>

<PRE>
Steven E. Moore, Chairman, Principal
  Executive Officer and Director                  / s / Steven E. Moore
                                              ----------------------------------

Herbert H. Champlin, Director                     / s / Herbert H. Champlin
                                              ----------------------------------

Luke R. Corbett, Director                         / s / Luke R. Corbett
                                              ----------------------------------

William E. Durrett, Director                      / s / William E. Durrett
                                              ----------------------------------

Martha W. Griffin, Director                       / s / Martha W. Griffin
                                              ----------------------------------

Hugh L. Hembree, III, Director                    / s / Hugh L. Hembree, III
                                              ----------------------------------

Robert Kelley, Director                           / s / Robert Kelley
                                              ----------------------------------

Bill Swisher, Director                            / s / Bill Swisher
                                              ----------------------------------

Ronald H. White, M.D., Director                   / s / Ronald H. White, M.D.
                                              ----------------------------------

James R. Hatfield, Principal
  Financial Officer                               / s / James R. Hatfield
                                              ----------------------------------

Donald R. Rowlett, Principal
  Accounting Officer                              / s / Donald R. Rowlett
                                              ----------------------------------

STATE OF OKLAHOMA   )
                    )  SS
COUNTY OF OKLAHOMA  )
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On    the    date
indicated above, before me, Debbie Peters,  Notary Public in and for said County
and State,  personally  appeared the above named  directors  and officers of OGE
ENERGY CORP., an Oklahoma  corporation,  and known to me to be the persons whose
names  are  subscribed  to  the  foregoing  instrument,   and  they,  severally,
acknowledged  to me that  they  executed  the  same as  their  own  free act and
deed.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;IN        WITNESS
WHEREOF,  I have  hereunto set my hand and affixed my official  seal on the 17th
day of January, 2001.</P>

<P ALIGN=CENTER>/s/ Debbie Peters<BR>
Debbie Peters<BR>
Notary Public in and for the County<BR>
of Oklahoma, State of Oklahoma</P>

<P ALIGN=LEFT>My Commission Expires:<BR>
May 3, 2003</P>

</BODY>
</HTML>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-24.01
<SEQUENCE>7
<FILENAME>0007.htm
<DESCRIPTION>POWER OF ATTORNEY
<TEXT>


<HTML>
<HEAD>
<TITLE>POWER OF ATTORNEY</TITLE>
</HEAD>

<BODY>

<P ALIGN=RIGHT><FONT SIZE=2><B>Exhibit 24.01</B></FONT></P>

<P ALIGN=CENTER><B>POWER OF ATTORNEY</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;WHEREAS,      OGE
ENERGY CORP., an Oklahoma corporation (herein referred to as the "Company"),  is
about to file with the Securities and Exchange Commission,  under the provisions
of the  Securities  Exchange Act of 1934, as amended,  its annual report on Form
10-K for the year ended December 31, 2000; and</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;WHEREAS,  each of
the undersigned  holds the office in the Company  herein-below  set opposite his
name;</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;NOW,   THEREFORE,
each of the undersigned  hereby  constitutes and appoints STEVEN E. MOORE, JAMES
R. HATFIELD and DONALD R. ROWLETT,  and each of them individually,  his attorney
with full  power to act for him and in his name,  place and  stead,  to sign his
name in the capacity or capacities  set forth below to said Form 10-K and to any
and all  amendments  thereto,  and hereby  ratifies  and  confirms all that said
attorney may or shall lawfully do or cause to be done by virtue hereof.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;IN        WITNESS
WHEREOF,  the undersigned has hereunto set his hand this 21st day of March
2001.</P>

<PRE>

J. D. Williams, Director                          / s / J. D. Williams
                                              ----------------------------------
<BR><BR><BR>



STATE OF OKLAHOMA  )
                   )  SS
COUNTY OF OKLAHOMA )
</PRE>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;On    the    date
indicated above, before me, Debbie Peters,  Notary Public in and for said County
and State,  personally appeared the above named director of OGE ENERGY CORP., an
Oklahoma corporation,  and known to me to be the person whose name is subscribed
to the foregoing instrument, and he acknowledged to me that he executed the same
as his own free act and deed.</P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;IN        WITNESS
WHEREOF,  I have  hereunto set my hand and affixed my official  seal on the 21st
day of March, 2001.</P>

<P ALIGN=CENTER>/s/ Debbie Peters<BR>
Debbie Peters<BR>
Notary Public in and for the County<BR>
of Oklahoma, State of Oklahoma</P>

<P ALIGN=LEFT>My Commission Expires:<BR>
May 3, 2003</P>

</BODY>
</HTML>
</TEXT>
</DOCUMENT>
<DOCUMENT>
<TYPE>EX-99.01
<SEQUENCE>8
<FILENAME>0008.htm
<DESCRIPTION>OG&AMP;E CAUTIONARY FACTORS
<TEXT>


<HTML>
<HEAD>
<TITLE> OKLAHOMA GAS AND ELECTRIC COMPANY CAUTIONARY FACTORS</TITLE></HEAD>

<BODY>

<P ALIGN=RIGHT><FONT SIZE=2><B>Exhibit 99.01</B></FONT></P>

<P ALIGN=CENTER><B>OGE Energy Corp. Cautionary Factors</B></P>

<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Private
Securities   Litigation  Reform  Act  of  1995  provides  a  "safe  harbor"  for
forward-looking  statements to encourage such disclosures  without the threat of
litigation  providing those statements are identified as forward-looking and are
accompanied by meaningful,  cautionary statements  identifying important factors
that could cause the actual results to differ materially from those projected in
the statement.  Forward-looking statements have been and will be made in written
documents  and oral  presentations  of OGE Energy Corp.  (the  "Company").  Such
statements are based on management's  beliefs as well as assumptions made by and
information  currently  available  to  management.  When  used in the  Company's
documents or oral presentations,  the words "anticipate",  "estimate", "expect",
"objective"  and similar  expressions  are intended to identify  forward-looking
statements.  In  addition  to any  assumptions  and other  factors  referred  to
specifically in connection with such  forward-looking  statements,  factors that
could  cause the  Company's  actual  results  to differ  materially  from  those
contemplated  in any  forward-looking  statements  include,  among  others,  the
following:</P>
<UL>
<LI>Increased  competition  in  the  utility  industry,  including  effects  of:
decreasing margins as a result of competitive pressures;  industry restructuring
initiatives, including state legislation providing for retail customer choice of
electricity  providers;  transmission  system  operation  and/or  administration
initiatives;  recovery of investments made under traditional regulation;  nature
of competitors entering the industry;  retail wheeling; a new pricing structure;
and former customers entering the generation market;<BR><BR>

<LI>Changing  market  conditions and a variety of other factors  associated with
physical energy and financial trading activities including,  but not limited to,
price, basis, credit, liquidity, volatility,  capacity, transmission,  currency,
interest rate and warranty risks;<BR><BR>

<LI>Risks associated with price risk management strategies intended to mitigate
exposure to adverse movement in the prices of electricity and natural gas on
both a global and regional basis;<BR><BR>

<LI>Economic    conditions    including    inflation    rates    and    monetary
fluctuations;<BR><BR>

<LI>Customer business conditions including demand for their products or services
and  supply  of  labor  and  materials  used  in  creating  their  products  and
services;<BR><BR>

<LI>Financial  or regulatory  accounting  principles or policies  imposed by the
Financial  Accounting  Standards Board, the Securities and Exchange  Commission,
the Federal Energy  Regulatory  Commission,  state public  utility  commissions,
state entities which regulate natural gas transmission, gathering and processing
and similar entities with regulatory oversight.<BR><BR>

<LI>Availability  or cost of capital such as changes in: interest rates,  market
perceptions of the utility and energy-related  industries, the Company or any of
its subsidiaries or security ratings;<BR><BR>

<LI>Factors  affecting  utility  operations such as unusual weather  conditions;
catastrophic  weather-related  damage;  unscheduled generation outages,  unusual
maintenance  or repairs;  unanticipated  changes to fossil  fuel,  or gas supply
costs or availability due to higher demand,  shortages,  transportation problems
or other developments;  environmental incidents; or electric transmission or gas
pipeline system constraints;<BR><BR>

<LI>Employee  workforce factors including changes in key executives,  collective
bargaining agreements with union employees, or work stoppages;<BR><BR>

<LI>Rate-setting  policies  or  procedures  of  regulatory  entities,  including
environmental externalities;<BR><BR>

<LI>Social   attitudes   regarding   the   utility,   natural   gas  and   power
industries;<BR><BR>

<LI>Identification  of suitable  investment  opportunities to enhance shareowner
returns  and   achieve   long-term   financial   objectives   through   business
acquisitions;<BR><BR>

<LI>Some future  investments  made by the Company could take the form of minority
interests  which  would  limit  the   Company&#146;s   ability  to  control  the
development or operation of an investment;<BR><BR>

<LI>Costs   and  other   effects  of  legal  and   administrative   proceedings,
settlements,  investigations,  claims and matters,  including but not limited to
those described in Note 10 of the Notes to the Consolidated Financial Statements
of the Company&#146;s Annual Report on Form 10-K for the year ended December 31,
2000, under the caption Commitments and Contingencies;<BR><BR>

<LI>Technological  developments,  changing markets and other factors that result
in competitive disadvantages and create the potential for impairment of existing
assets;<BR><BR>

<LI>Other business or investment considerations that may be disclosed from time to
time in the Company&#146;s Securities and Exchange Commission filings or in
other publicly disseminated written documents.<BR><BR>
</UL>
<P>&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;The       Company
undertakes  no  obligation  to  publicly  update or revise  any  forward-looking
statements,   whether  as  a  result  of  new  information,   future  events  or
otherwise.</P>


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</SUBMISSION>
