SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D. C. 20549

                                    FORM 10-K

                        FOR ANNUAL AND TRANSITION REPORTS
                     PURSUANT TO SECTIONS 13 OR 15(d) OF THE
                         SECURITIES EXCHANGE ACT OF 1934
(Mark One)
[X]               ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934

                   For the fiscal year ended December 31, 2002

                                       OR

[ ]             TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934

           For the Transition Period From ___________ to _____________

                           Commission File No. 33-7591

                          Oglethorpe Power Corporation
                      (An Electric Membership Corporation)
             (Exact name of registrant as specified in its charter)

                 Georgia                                   58-1211925
     (State or other jurisdiction of                    (I.R.S. employer
     incorporation or organization)                    identification no.)

          Post Office Box 1349
        2100 East Exchange Place
             Tucker, Georgia                               30085-1349
(Address of principal executive offices)                   (Zip Code)

     Registrant's telephone number, including area code:          (770) 270-7600

     Securities registered pursuant to Section 12(b) of the Act:        None

     Securities registered pursuant to Section 12(g) of the Act:        None

     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. Yes  X     No
                                             -----     -----

     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. [ X ]

     Indicate by check mark whether the registrant is an  accelerated  filer (as
defined in Exchange Act Rule 12b-2).   Yes        No X
                                          -----     -----

     State the aggregate market value of the voting and non-voting common equity
held by  non-affiliates  computed by  reference to the price at which the common
equity was last sold, or the average bid and asked price of such common  equity,
as of the last business day of the registrant's  most recently  completed second
fiscal quarter. None

     Indicate  the  number of  shares  outstanding  of each of the  registrant's
classes of common stock, as of the latest  practicable date. The Registrant is a
membership corporation and has no authorized or outstanding equity securities.

     Documents Incorporated by Reference: None

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




                          OGLETHORPE POWER CORPORATION
                          2002 FORM 10-K ANNUAL REPORT
                                Table of Contents


ITEM                                                                              Page
- ----                                                                              ----
                                     PART I
                                                                                 
 1   Business ..................................................................    1
       Oglethorpe Power Corporation.............................................    1
       Oglethorpe's Power Supply Resources......................................    8
       The Members and Their Power Supply Resources.............................   12
       Factors Affecting the Electric Utility Industry..........................   17

 2   Properties.................................................................   23

 3   Legal Proceedings..........................................................   29
 4   Submission of Matters to a Vote of Security Holders........................   29

                                     PART II
 5   Market for Registrant's Common Equity and Related Stockholder Matters......   30
 6   Selected Financial Data....................................................   30
 7   Management's Discussion and Analysis of Financial Condition and Results
     of Operations..............................................................   31
7A   Quantitative and Qualitative Disclosures About Market Risk.................   46

 8   Financial Statements and Supplementary Data................................   51

 9   Changes in and Disagreements with Accountants on Accounting
     and Financial Disclosure...................................................   73

                                    PART III
10   Directors and Executive Officers of the Registrant.........................   73
11   Executive Compensation.....................................................   77
12   Security Ownership of Certain Beneficial Owners and Management.............   79
13   Certain Relationships and Related Transactions.............................   79
14   Controls and Procedures....................................................   79

                                     PART IV
15   Exhibits, Financial Statement Schedules, and Reports on Form 8-K...........   80


                                        i




                              SELECTED DEFINITIONS

The following terms used in this report have the meanings indicated below:

Term                Meaning
- ----                -------

APM        ACES Power Marketing
CFC        National Rural Utilities Cooperative Finance Corporation
EMC        Electric Membership Corporation
FERC       Federal Energy Regulatory Commission
FFB        Federal Financing Bank
GPC        Georgia Power Company
GPSC       Georgia Public Service Commission
GSOC       Georgia System Operations Corporation
GTC        Georgia Transmission Corporation (An Electric Membership Corporation)
LEM        LG&E Energy Marketing Inc.
MEAG       Municipal Electric Authority of Georgia
NRC        Nuclear Regulatory Commission
RUS        Rural Utilities Service
SEPA       Southeastern Power Administration
SONOPCO    Southern Nuclear Operating Company

                                       ii



                                     PART I


ITEM 1. BUSINESS

                          OGLETHORPE POWER CORPORATION

General

     Oglethorpe   Power   Corporation  (An  Electric   Membership   Corporation)
("Oglethorpe") is a Georgia electric membership corporation incorporated in 1974
and  headquartered  in  metropolitan  Atlanta.  Oglethorpe is owned by 39 retail
electric   distribution   cooperative  members  (the  "Members").   Oglethorpe's
principal business is providing wholesale electric power to the Members. As with
cooperatives   generally,   Oglethorpe  operates  on  a  not-for-profit   basis.
Oglethorpe is the largest electric  cooperative in the United States in terms of
operating  revenues,  assets,  kilowatt-hour  ("kWh")  sales  and,  through  the
Members, consumers served. Oglethorpe has 173 employees.

     The Members are local consumer-owned  distribution  cooperatives  providing
retail electric service on a not-for-profit basis. In general, the customer base
of the Members  consists of  residential,  commercial and  industrial  consumers
within specific  geographic  areas. The Members serve  approximately 1.5 million
electric consumers (meters) representing  approximately 3.7 million people. (See
"THE MEMBERS AND THEIR POWER SUPPLY RESOURCES.")

     In the second quarter of 2003,  Oglethorpe expects to acquire two gas-fired
generation facilities (aggregating approximately 1086 MW) utilizing $589 million
from loans guaranteed by the Rural Utilities  Service (the "RUS"). In connection
with the acquisition, Oglethorpe also would enter into limited amendments to its
existing Amended and Restated Wholesale Power Contracts with each of the Members
(the  "Wholesale  Power  Contracts")  and  other  agreements  with  its  Members
regarding  the  services  provided  by  Oglethorpe.  (See  "Expected  Facilities
Acquisitions, RUS Loans and Other New Arrangements.")

     Oglethorpe's  mailing address is 2100 East Exchange Place,  Post Office Box
1349, Tucker, Georgia 30085-1349, and its telephone number is (770) 270-7600.

Cooperative Principles

     Cooperatives  like  Oglethorpe  are business  organizations  owned by their
members,  which  are  also  either  their  wholesale  or  retail  customers.  As
not-for-profit  organizations,  cooperatives are intended to provide services to
their members at the lowest  possible cost, in part by  eliminating  the need to
produce  profits  or  a  return  on  equity.  Cooperatives  may  make  sales  to
non-members, the effect of which is generally to reduce costs to members. Today,
cooperatives  operate  throughout  the United  States in such  diverse  areas as
utilities, agriculture, irrigation, insurance and credit.

     All  cooperatives  are  based on  similar  business  principles  and  legal
foundations. Generally, an electric cooperative designs its rates to recover its
cost-of-service  and to collect a  reasonable  amount of  revenues  in excess of
expenses,  which constitutes  margins.  The margins increase  patronage capital,
which  is the  equity  component  of a  cooperative's  capitalization.  Any such
margins are considered capital  contributions (that is, equity) from the members
and are held for the accounts of the members and returned to them when the board
of directors of the cooperative deems it prudent to do so. The timing and amount
of any actual return of capital to the members depends on the financial goals of
the cooperative and the cooperative's loan and security agreements.

Power Supply Business

     Oglethorpe  provides  wholesale  electric  service to the 39 Members  for a
substantial  portion of their  requirements from a combination of its generation
assets and power purchased from power marketers and other suppliers.  Oglethorpe
provides  this  service  pursuant  to  long-term,  take-or-pay  Wholesale  Power
Contracts described below. The Wholesale Power Contracts obligate the Members on
a joint and several  basis to pay rates  sufficient  to recover all the costs of
owning  and  operating  Oglethorpe's  power  supply  business.  Pursuant  to the
Wholesale  Power  Contracts,  the  Members may satisfy all or a portion of their
requirements  above their  Oglethorpe  purchase  obligations with purchases from
other  suppliers.  Because  many Members  have  exercised  this option and other

                                       1


Members are  analyzing  this  option,  Oglethorpe  is not  currently  engaged in
long-term resource  procurement for any Member other than in connection with the
anticipated  acquisition of the two generation  facilities described above. (See
"THE MEMBERS AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources.")

     Oglethorpe has undivided  interests in seventeen  generating  units.  These
units provide  Oglethorpe  with a total of 3,658  megawatts  ("MW") of nameplate
capacity,   consisting  of  1,501  MW  of  coal-fired  capacity,   1,185  MW  of
nuclear-fueled capacity, 632 MW of pumped storage hydroelectric capacity, 325 MW
of gas-fired  combustion  turbine  capacity  and 15 MW of  oil-fired  combustion
turbine capacity.

     Oglethorpe  purchases a total of approximately  550 MW of power pursuant to
long-term power purchase  agreements.  Oglethorpe also has arrangements with two
power  marketers  to supply  power to  Oglethorpe  in amounts  that are based on
growth in the  Members'  requirements,  representing  about 30% of  Oglethorpe's
power supply  capability in 2003. These power marketer  arrangements also reduce
the cost of capacity and energy  delivered to the Members.  Oglethorpe meets its
supplemental  power supply needs through short-term power purchase contracts and
spot  market  purchases.   (See   "OGLETHORPE'S   POWER  SUPPLY  RESOURCES"  and
"PROPERTIES--Generating Facilities" in Item 2.)

     In 2002,  Cobb  EMC and  Jackson  EMC  accounted  for  11.3%  and  11.2% of
Oglethorpe's total revenues,  respectively.  None of the other Members accounted
for as much as 10% of Oglethorpe's total revenues in 2002.

Wholesale Power Contracts

     Oglethorpe has a substantially similar Amended and Restated Wholesale Power
Contract  with each  Member  extending  through  December  31,  2025.  Under the
Wholesale  Power  Contract,  each  Member is  unconditionally  obligated,  on an
express  "take-or-pay"  basis,  for a fixed  percentage  of the  capacity  costs
(referred to as a "percentage capacity  responsibility") of each of Oglethorpe's
generation  and  purchased  power  resources.   Each  Wholesale  Power  Contract
specifically provides that the Member must make payments whether or not power is
delivered and whether or not a plant has been sold or is otherwise  unavailable.
Oglethorpe is obligated to use its reasonable best efforts to operate,  maintain
and manage its resources in accordance with prudent utility practices.

     Percentage  capacity   responsibilities   have  been  assigned  to  all  of
Oglethorpe's  generation  and purchased  power  resources.  Percentage  capacity
responsibilities  for any  future  resource  will be  assigned  only to  Members
choosing to participate in that resource.  The Wholesale Power Contracts provide
that each Member is jointly and severally responsible for all costs and expenses
of all existing  generation and purchased  power  resources,  as well as for any
future resources  (whether or not such Member has elected to participate in such
future resource) that are approved by 75% of Oglethorpe's Board of Directors and
75% of the  Members.  For  resources  so approved in which less than all Members
participate,  costs are shared first among the participating Members, and if all
participating  Members  default,  each  non-participating  Member  is  expressly
obligated to pay a proportionate share of such default.

     Under the Wholesale Power Contracts, Oglethorpe is not obligated to provide
all of the Members' capacity and energy requirements and Members have the option
of  satisfying  all or a portion of their  requirements  above their  Oglethorpe
purchase obligations from other suppliers. The Members also have various options
regarding the purchase of joint  planning and resource  management  services and
participation  in a capacity and energy pool. For more  information  about these
options  see  "Expected  Facilities   Acquisition,   RUS  Loans  and  other  New
Arrangements", "OGLETHORPE'S POWER SUPPLY RESOURCES--Future Power Resources" and
"--Capacity   and  Energy   Pool"  and  "THE  MEMBERS  AND  THEIR  POWER  SUPPLY
RESOURCES--Member Power Supply Resources."

     Under the Wholesale Power  Contracts,  each Member must establish rates and
conduct  its  business  in a manner  that will  enable  the Member to pay (i) to

                                       2


Oglethorpe when due, all amounts payable by the Member under its Wholesale Power
Contract  and  (ii) any and all  other  amounts  payable  from,  or which  might
constitute a charge or a lien upon,  the revenues and receipts  derived from the
Member's electric system,  including all operation and maintenance  expenses and
the principal of, premium,  if any, and interest on all indebtedness  related to
the Member's electric system.

Electric Rates

     Each Member is required to pay Oglethorpe for capacity and energy furnished
under its Wholesale  Power  Contract in  accordance  with rates  established  by
Oglethorpe.  Oglethorpe  reviews  its  rates  at  such  intervals  as  it  deems
appropriate  but is required to do so at least once every  year.  Oglethorpe  is
required to revise its rates as necessary so that the revenues  derived from its
rates,  together with its revenues from all other sources, will be sufficient to
pay all costs of its system, to provide for reasonable  reserves and to meet all
financial requirements.

     Oglethorpe's   principal  financial   requirements  are  contained  in  the
Indenture,  dated  as of  March  1,  1997,  from  Oglethorpe  to  SunTrust  Bank
("SunTrust"), as trustee (as supplemented,  the "Mortgage Indenture"). Under the
Mortgage Indenture,  Oglethorpe is required, subject to any necessary regulatory
approval, to establish and collect rates which are reasonably expected, together
with other  revenues of  Oglethorpe,  to yield a Margins for Interest  Ratio for
each fiscal year equal to at least 1.10.  "Margins  for  Interest  Ratio" is the
ratio of "Margins for Interest" to total "Interest  Charges" for a given period.
Margins for Interest is the sum of:

o    net margins of Oglethorpe (which includes revenues of Oglethorpe subject to
     refund  at a later  date  but  excludes  provisions  for (i)  non-recurring
     charges to income,  including the non-recoverability of assets or expenses,
     except to the  extent  Oglethorpe  determines  to recover  such  charges in
     rates,  and (ii)  refunds  of  revenues  collected  or  accrued  subject to
     refund), plus

o    interest  charges,  whether  capitalized or expensed,  on all  indebtedness
     secured  under the  Mortgage  Indenture  or by a lien equal or prior to the
     lien of the Mortgage Indenture,  including amortization of debt discount or
     premium on issuance, but excluding interest charges on indebtedness assumed
     by GTC ("Interest Charges"), plus

o    any amount included in net margins for accruals for federal or state income
     taxes imposed on income after deduction of interest expense.

     Margins for Interest takes into account any item of net margin,  loss, gain
or expenditure  of any affiliate or subsidiary of Oglethorpe  only if Oglethorpe
has received such net margins or gains as a dividend or other  distribution from
such affiliate or subsidiary or if Oglethorpe has made a payment with respect to
such losses or expenditures.

     The formulary  rate  established  by Oglethorpe in the rate schedule to the
Wholesale Power Contracts  employs a rate methodology under which all categories
of costs are  specifically  separated as  components of the formula to determine
Oglethorpe's  revenue  requirements.  The  rate  schedule  also  implements  the
responsibility  for fixed costs  assigned to each Member  (that is, the Member's
percentage capacity responsibility).  The monthly charges for capacity and other
non-energy  charges are based on Oglethorpe's  annual budget.  Such capacity and
other  non-energy  charges  may  be  adjusted  by the  Board  of  Directors,  if
necessary,  during the year through an adjustment to the annual  budget.  Energy
charges reflect the  pass-through of actual energy costs,  including fuel costs,
variable  operations  and  maintenance  costs and purchased  energy costs.  (See
"MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS--General--Rates and Regulation" in Item 7.)

     The rate schedule formula also includes a prior period adjustment mechanism
designed  to ensure  that  Oglethorpe  achieves  the  minimum  1.10  Margins for
Interest Ratio.  Amounts, if any, by which Oglethorpe fails to achieve a minimum
1.10 Margins for Interest  Ratio are accrued as of December 31 of the applicable
year and collected from the Members during the period April through  December of

                                       3


the following  year.  The rate  schedule  formula is intended to provide for the
collection of revenues which, together with revenues from all other sources, are
equal to all costs and expenses  recorded by Oglethorpe,  plus amounts necessary
to achieve at least the minimum 1.10 Margins for Interest Ratio.

     Under  the  Mortgage   Indenture   and  related  loan  contract  with  RUS,
adjustments to Oglethorpe's rates to reflect changes in Oglethorpe's budgets are
generally  not subject to RUS approval.  Changes to the rate schedule  under the
Wholesale  Power Contracts are generally  subject to RUS approval.  Oglethorpe's
rates are not subject to the  approval of any other  federal or state  agency or
authority, including the Georgia Public Service Commission (the "GPSC").

Expected Facilities Acquisitions, RUS Loans and Other New Arrangements

     In the second quarter of 2003, Oglethorpe expects to acquire two generation
facilities now owned and being  developed by Talbot EMC and  Chattahoochee  EMC.
Talbot  EMC and  Chattahoochee  EMC  were  formed  in 2001 as  Georgia  electric
membership  corporations.  Talbot EMC is owned by 30 Members and is developing a
six-unit  gas-fired  combustion  turbine facility  designed to provide 618 MW of
capacity.  Four of the units have been operating  since June 2002, and the other
two units are  expected to be  operational  by June 2003.  Chattahoochee  EMC is
owned by 28 Members  and has  developed  a  gas-fired  combined  cycle  facility
designed to provide 468 MW of  capacity,  which became  operational  in February
2003. (See "Relationship with Smarr EMC, Talbot EMC and Chattahoochee EMC".)

     Oglethorpe  expects to finance these  acquisitions with loans guaranteed by
RUS,  for  which  Oglethorpe  has  obtained  commitments  in the  amount of $589
million.  These  loans  would be  secured  under  the  Mortgage  Indenture  (See
"MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS--Financial  Condition--Capital  Requirement--Financing for Talbot EMC
and Chattahoochee EMC" in Item 7.)

     Oglethorpe's  acquisition of these facilities has received  requisite Board
and Member approval, subject to final RUS approval and implementation of certain
new arrangements among Oglethorpe and the Members as described below.

     Proposed New Arrangements

     Oglethorpe and the Members have developed definitive terms of agreements to
implement the  acquisition  of the Talbot EMC and  Chattahoochee  EMC generating
facilities,  to document the conditions to that  acquisition  and to provide for
the new  arrangements  among  Oglethorpe  and the  Members.  At the  time of the
acquisition of the facilities and the initial advances under the  RUS-guaranteed
loans,  Oglethorpe  and the  Members  would  enter  into  Amended  and  Restated
Wholesale Power Contracts and a New Business Model Member Agreement.

     Amended and Restated  Wholesale Power  Contracts.  The proposed Amended and
Restated  Wholesale Power Contracts (the "Proposed  Wholesale Power  Contracts")
contain limited amendments and would not change the unconditional  obligation of
each Member,  on an express  "take-or-pay"  basis, to pay for a fixed percentage
responsibility  of the costs of  Oglethorpe's  generation  and  purchased  power
resources.  In the same  way as the  existing  Wholesale  Power  Contracts,  the
Proposed  Wholesale  Power  Contracts would continue to provide that each Member
would be jointly and  severally  responsible  for all costs and  expenses of all
resources (which would include the Talbot EMC and  Chattahoochee  EMC generation
facilities).  To acquire future resources, in addition to the approval of 75% of
Oglethorpe's  Directors and 75% of the Members that is now required,  Oglethorpe
would be required  to obtain the  approval  of Members  representing  75% of the
patronage capital of Oglethorpe. Certain resource modifications that now must be
approved by 75% of  Oglethorpe's  Directors and 75% of the Members could be made
by  Oglethorpe  if  approved  by more  than  50% of the  Members.  The  Proposed
Wholesale Power Contracts would no longer address Oglethorpe's  obligations with
respect to power supply  planning  services and  operating a capacity and energy
pool. The New Business Model Member Agreement would address these services.

                                       4


     New Business Model Member Agreement. The proposed New Business Model Member
Agreement  would require  Member  approval for  Oglethorpe to undertake  certain
activities but would not limit Oglethorpe's ability to own, manage,  control and
operate its  resources or perform its  functions  under the  Proposed  Wholesale
Power  Contracts.  No later than March 31, 2005,  Oglethorpe  would  discontinue
operating its capacity and energy pool,  providing  natural gas hedging for pool
and  non-pool  participants  and  providing  power supply  planning  services to
Members electing to receive these services.

     Oglethorpe  would not provide  services  unrelated to its  resources or its
functions  under the Proposed  Wholesale  Power Contracts if such services would
require  it to  incur  indebtedness,  provide  a  guarantee  or make any loan or
investment,  unless approved by 75% of Oglethorpe's  Board of Directors,  75% of
the  Members,   and  Members  representing  75%  of  the  patronage  capital  of
Oglethorpe.  Oglethorpe could provide any other such service to a Member so long
as (1) doing so would not create a conflict  of interest  with  respect to other
Members,  (2) such service was being provided to all Members or (3) such service
received the three-part 75% approval described above.

     Status of Arrangements

     Oglethorpe,  Talbot EMC,  Chattahoochee  EMC, and their respective  Members
have  approved  these  arrangements,  including  the  Proposed  Wholesale  Power
Contracts and the New Business  Model Member  Agreement.  RUS, whose approval of
certain of these  arrangements is required,  has indicated its satisfaction with
these  arrangements but is not expected to deliver its formal approval until the
closing of the first advance under the RUS-guaranteed  loans. The closing of the
acquisition of the Talbot EMC and  Chattahoochee  EMC generation  facilities and
the  delivery of the Proposed  Wholesale  Power  Contracts  and the New Business
Model  Member  Agreement  would  take place at that time.  The  development  and
execution  of  final  documentation  for  the  RUS-guaranteed   loans,  and  the
satisfaction  of all loan  conditions,  is currently  expected to occur in April
2003, but could take place later.

     While Oglethorpe  currently  expects that the Talbot EMC and  Chattahoochee
EMC  generation  facilities  will be acquired by Oglethorpe and financed by RUS,
Oglethorpe  cannot  state  with  certainty  that  RUS  loan  conditions  can  be
satisfied.  If for any  reason  these  new  arrangements  are  not  implemented,
Oglethorpe  would  continue to own,  operate,  manage and  control its  existing
resources,  including  generating  facilities  and  purchased  power  resources.
Oglethorpe  would not acquire the Talbot EMC and  Chattahoochee  EMC  generation
facilities,  but  would  continue  to manage  those  facilities  under  existing
management  contracts.  (See  "Relationships  with  Smarr  EMC,  Talbot  EMC and
Chattahoochee EMC".)

Relationships with Smarr EMC, Talbot EMC and Chattahoochee EMC

     Smarr EMC, Talbot EMC and Chattahoochee EMC are Georgia electric membership
corporations  owned by 37, 30 and 28 of Oglethorpe's  39 Members,  respectively.
Smarr EMC owns two combustion  turbine facilities with aggregate capacity of 709
MW. Talbot EMC owns a combustion  turbine facility designed to provide 618 MW of
capacity.  Chattahoochee  EMC owns a combined cycle facility designed to provide
468 MW of capacity. Oglethorpe provides construction,  operations, financial and
management  services for Smarr EMC, Talbot EMC and Chattahoochee  EMC. (See "THE
MEMBERS AND THEIR POWER SUPPLY Resources--Member Power Supply Resources")

     Oglethorpe is providing  interim loans to Talbot EMC and  Chattahoochee EMC
to finance  approximately fifty percent of the cost of the construction of their
generating   facilities.   Oglethorpe  is  guaranteeing  an  interim   financing

                                       5


arrangement between  Chattahoochee EMC and a financial  institution providing up
to  fifty  percent  of the  cost of  Chattahoochee  EMC's  generating  facility.
Oglethorpe expects to acquire the generating  facilities now owned by Talbot EMC
and Chattahoochee  EMC in the second quarter of 2003. (See "Expected  Facilities
Acquisitions, RUS Loans And Other New Arrangements" and "MANAGEMENT'S DISCUSSION
AND  ANALYSIS  OF  FINANCIAL  CONDITION  AND  RESULTS  OF  OPERATIONS--Financial
Condition--Capital Requirements--Financing for Talbot EMC and Chattahoochee EMC"
in Item 7.)

Relationship with GTC

     Oglethorpe  and  the  39  Members  are  members  of  Georgia   Transmission
Corporation (An Electric Membership  Corporation)  ("GTC"),  which was formed in
1997  to  own  and  operate  the  transmission   business  previously  owned  by
Oglethorpe.  GTC provides  transmission  services to the Members for delivery of
the Members' power purchases from Oglethorpe and other power suppliers. GTC also
provides transmission  services to Oglethorpe and third parties.  Oglethorpe has
entered into an agreement  with GTC to provide  transmission  services for third
party  transactions  and  for  service  to  Oglethorpe's  headquarters  and  the
administration  building  at the Rocky  Mountain  Pumped  Storage  Hydroelectric
Facility ("Rocky Mountain").

     GTC has rights in the  Integrated  Transmission  System,  which consists of
transmission  facilities  owned  by GTC,  Georgia  Power  Company  ("GPC"),  the
Municipal  Electric  Authority  of  Georgia  ("MEAG")  and the  City  of  Dalton
("Dalton").  Through  agreements,  common access to the combined facilities that
compose  the  Integrated  Transmission  System  enables  the owners to use their
combined resources to make deliveries to or for their respective  consumers,  to
provide  transmission  service to third parties and to make off-system purchases
and sales. The Integrated Transmission System was established in order to obtain
the  benefits  of  a  coordinated   development  of  the  parties'  transmission
facilities  and to make it  unnecessary  for any party to construct  duplicative
facilities.

Relationship with GSOC

     Oglethorpe, GTC and the 39 Members are members of Georgia System Operations
Corporation  ("GSOC"),  which was formed in 1997 to own and  operate  the system
operations  business  previously  owned by Oglethorpe.  GSOC operates the system
control  center  and  currently   provides   system   operations   services  and
administrative  support  services  to  Oglethorpe  and to  GTC.  Oglethorpe  has
contracted with GSOC to operate  Oglethorpe's  electric capacity and energy pool
and to schedule and dispatch  Oglethorpe's  resources.  (See "OGLETHORPE'S POWER
SUPPLY  RESOURCES--Capacity and Energy Pool"). GSOC provides support services to
Oglethorpe  in  the  areas  of  accounting,  auditing,   communications,   human
resources, facility management, telecommunications and information technology at
cost-based rates.

     GTC  has  contracted  with  GSOC to  provide  certain  transmission  system
operation services including reliability monitoring,  switching operations,  and
the real-time management of the transmission system.

     As  Oglethorpe  has  worked  with GSOC in the  implementation  of  resource
scheduling elections by Members, a need to consider changes in the relationships
among Oglethorpe, GSOC and the Members has been recognized. GSOC, Oglethorpe and
the  Members are  beginning  a process of  evaluating  how GSOC  implements  the
operations  necessary  to permit  Members to schedule  energy from  Oglethorpe's
resources.  This  evaluation  could result in changes in the Operation  Services
Agreement  between  Oglethorpe  and GSOC, as well as changes in the  contractual
relationships  among GSOC and the  Members.  It would not,  however,  change the
terms of Oglethorpe's Wholesale Power Contracts with the Members.

Relationship with RUS

     Historically,  federal loan programs  administered by RUS have provided the
principal source of financing for electric cooperatives. Loans guaranteed by RUS
and made by the  Federal  Financing  Bank  ("FFB")  have been a major  source of
funding for Oglethorpe.

                                       6


     Oglethorpe  entered into a loan contract  with RUS in  connection  with the
Mortgage  Indenture.  Under the loan  contract,  RUS has  approval  rights  over
certain significant actions and arrangements, including, without limitation,

o    significant additions to or dispositions of system assets,

o    significant power purchase and sale contracts,

o    changes to the  Wholesale  Power  Contracts,  including  the rate  schedule
     contained therein,

o    changes to plant ownership and operating agreements, and

o    in limited circumstances, issuance of additional secured debt.

     The extent of RUS's approval rights under the loan contract with Oglethorpe
is  substantially  less than the supervision  and control RUS has  traditionally
exercised over borrowers under its standard loan and security documentation.  In
addition,  the Mortgage Indenture improves  Oglethorpe's ability to borrow funds
in the public capital markets relative to RUS's standard mortgage.  The Mortgage
Indenture  constitutes  a lien on  substantially  all of the owned  tangible and
certain intangible property of Oglethorpe.

     Oglethorpe has obtained commitments for RUS-guaranteed loans to finance the
acquisition  of  the   generation   facilities  now  owned  by  Talbot  EMC  and
Chattahoochee EMC. (See "Expected Facilities  Acquisitions,  RUS Loans And Other
New  Arrangements"  and  "MANAGEMENT'S  DISCUSSION  AND  ANALYSIS  OF  FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--Financial Condition--Capital Requirements--
Financing for Talbot EMC and Chattahoochee EMC" in Item 7.)

Relationship with GPC

     Oglethorpe's  relationship  with GPC is a  significant  factor  in  several
aspects  of  Oglethorpe's  business.  All of  Oglethorpe's  co-owned  generating
facilities,  except Rocky Mountain, are operated by GPC on behalf of itself as a
co-owner and as agent for the other  co-owners.  GPC is also one of Oglethorpe's
suppliers of purchased power. GPC also supplies  services to Oglethorpe and GSOC
to support the  scheduling  and dispatch of  Oglethorpe's  resources,  including
off-system  transactions.  GPC and the Members are  competitors  in the State of
Georgia for electric  service to any new customer  that has a choice of supplier
under the Georgia  Territorial  Electric  Service Act, which was enacted in 1973
(the "Territorial Act"). For further  information  regarding the agreements with
GPC and Oglethorpe's and the Members'  relationships  with GPC, see "THE MEMBERS
AND  THEIR  POWER   SUPPLY   RESOURCES--Service   Area  and   Competition"   and
"OGLETHORPE'S    POWER    SUPPLY    RESOURCES--Power     Purchase    and    Sale
Arrangements--Power Purchases." Also see "PROPERTIES--Fuel Supply," "--Co-Owners
of the Plants--Georgia Power Company" and "--The Plant Agreements" in Item 2.

Seasonal Variations

     The demand for energy by the  Members is  influenced  by  seasonal  weather
conditions.  Historically,  Oglethorpe's  peak  sales have  occurred  during the
months of June through  August.  Energy  revenues track energy costs as they are
incurred  and also  fluctuate  month to month.  Capacity  revenues  reflect  the
recovery of Oglethorpe's fixed costs, which do not vary significantly from month
to month;  therefore,  capacity  charges are billed and  capacity  revenues  are
recognized in substantially equal monthly amounts.

                                       7


                       OGLETHORPE'S POWER SUPPLY RESOURCES

General

     Oglethorpe  supplies  capacity and energy to the Members from a combination
of  generating  plants  and from  power  purchased  under  long-term  contracts.
Oglethorpe  also has  arrangements  with power  marketers to supply power and to
reduce the cost of capacity  and energy  delivered  to the  Members.  Oglethorpe
meets its  supplemental  power supply needs through  short-term  power  purchase
contracts and spot-market purchases.

Generating Plants

     Oglethorpe's  seventeen generating units consist of 30% undivided interests
in the Edwin I. Hatch Plant ("Plant  Hatch"),  the Alvin W. Vogtle Plant ("Plant
Vogtle")  and  the Hal B.  Wansley  Plant  ("Plant  Wansley"),  a 60%  undivided
interest in the Robert W.  Scherer  Unit No. 1 ("Scherer  Unit No. 1"),  and the
Robert W. Scherer Unit No. 2 ("Scherer Unit No. 2"), a 74.61% undivided interest
in Rocky  Mountain  and a 100%  interest  in the Doyle I, LLC  Generating  Plant
("Plant Doyle"),  through a power purchase agreement that Oglethorpe treats as a
capital lease. Plant Hatch consists of two nuclear-fueled  units, with nameplate
ratings  of 810 MW and  820  MW,  respectively.  Plant  Vogtle  consists  of two
nuclear-fueled  units,  each with a nameplate  rating of 1,160 MW. Plant Wansley
consists of two coal-fired  units, each with a nameplate rating of 865 MW. Plant
Wansley also  includes a 49.2 MW oil-fired  combustion  turbine.  Plant  Scherer
consists  of four  coal-fired  units,  each with a  nameplate  rating of 818 MW.
Oglethorpe  has an interest  only in Scherer  Unit No. 1 and Scherer Unit No. 2.
Rocky  Mountain is a three-unit  pumped  storage  hydroelectric  facility with a
nameplate rating of 847.8 MW. Plant Doyle consists of five gas-fired  combustion
turbine units with an aggregate  nominal  contract  capacity of 325 MW. In 2002,
Oglethorpe decided to discontinue  operations at the Tallassee Project, a 2.1 MW
conventional hydroelectric facility ("Tallassee"). Oglethorpe expects to acquire
the  generation  facilities  of Talbot EMC and  Chattahoochee  EMC in the second
quarter of 2003.

     MEAG,  Dalton  and GPC also have  interests  in Plants  Hatch,  Vogtle  and
Wansley and  Scherer  Units No. 1 and No. 2. GPC serves as  operating  agent for
these units.  GPC also has an interest in Rocky  Mountain,  which is operated by
Oglethorpe.

     See  "PROPERTIES"  in Item 2 for a description of  Oglethorpe's  generating
facilities, fuel supply and the co-ownership arrangements.

Power Marketer Arrangements

     Oglethorpe utilizes power marketer arrangements to reduce the cost of power
to the  Members.  Oglethorpe  has power  marketer  agreements  with LG&E  Energy
Marketing Inc. ("LEM") for  approximately 50% of the load requirements of the 37
participating  Members  and with  Morgan  Stanley  Capital  Group Inc.  ("Morgan
Stanley") with respect to 50% of the 39 Members' load requirements forecasted at
the time  Oglethorpe  entered into the agreement.  The LEM agreement is based on
the actual  requirements of the participating  Members during the contract term,
whereas the Morgan Stanley agreement represents a fixed supply obligation.

     Generally,  these  arrangements  are benefiting the Members by limiting the
risk of unit  availability and by providing future power needs at a fixed price.
Under these power  marketer  agreements,  Oglethorpe  purchases  energy at fixed
prices covering a portion of the costs of energy to its Members.  LEM and Morgan
Stanley,  in  turn,  have  certain  rights  to  market  excess  energy  from the
Oglethorpe system. Most of Oglethorpe's generating facilities and power purchase
arrangements  are available for use by LEM and Morgan Stanley under the terms of
the respective agreements. Oglethorpe continues to be responsible for all of the
costs of its system resources but receives revenue, as described below, from LEM
and Morgan Stanley for the use of the  resources.  After taking into account the
Oglethorpe  resources  made  available to LEM and Morgan  Stanley for their use,
Oglethorpe  estimates that about 30% of its power supply capability in 2003 will
be provided by these contracts.

     LEM Agreement

     Effective  January  1,  1997,  Oglethorpe  entered  into a  power  marketer
agreement with LEM, an indirect,  wholly owned  subsidiary of LG&E Energy Corp.,

                                       8


which is a diversified  energy  services  company  headquartered  in Louisville,
Kentucky.  LG&E Energy  Corp.  is now an indirect  wholly  owned  subsidiary  of
Powergen plc, a British public limited company.

     Under the power  marketer  agreement,  LEM is  obligated  to  deliver,  and
Oglethorpe  is obligated  to take,  (i) 50% of the load  requirements  of the 37
participating Members, less (ii) the load requirements for certain customers who
have the right to choose electric  suppliers,  plus (iii) 50% of the 37 Members'
percentage  capacity  responsibility  shares of the delivery  obligations  under
Oglethorpe's existing firm power off-system sale contracts.  For certain smaller
customer choice loads, LEM is obligated to deliver, if Oglethorpe requests,  50%
of the associated load requirements. Oglethorpe has the option of purchasing the
energy  requirements  for  any  customer  choice  load  from  another  supplier.
Oglethorpe is obligated to sell and LEM is obligated to buy 50% of the output of
each of the 37 Members' percentage capacity  responsibility  shares of the "must
run" units  (primarily  nuclear  units).  Oglethorpe  is also  obligated to make
available the same share of most of Oglethorpe's other resources,  which LEM may
schedule.  LEM does  not have the  right  to the  output  of  upgrades  to these
resources.  LEM pays  Oglethorpe  the costs  associated  with the energy  taken,
subject  to  certain  adjustments.  Oglethorpe  must  pay  LEM  a  contractually
specified price for each megawatt-hour ("MWh") purchased.

     The LEM agreement has a term  extending  through 2011,  but pursuant to its
rights under the  agreement,  LEM has given notice to terminate the agreement as
of December 31, 2004.

     Morgan Stanley Agreement

     Effective May 1, 1997,  Oglethorpe  entered into a power marketer agreement
with Morgan  Stanley with respect to 50% of the Members'  then  forecasted  load
requirements. The agreement obligates Oglethorpe to purchase fixed quantities of
energy at fixed prices. Each Member selected a term for its obligation,  as well
as the portion of its then  forecasted  requirements  to be purchased as a fixed
quantity. Oglethorpe is obligated to sell and Morgan Stanley is obligated to buy
50% of the output, in contractually  fixed amounts,  of each Member's percentage
capacity  responsibility  share (for the term and portion selected) of the "must
run" units  (primarily  nuclear  units).  Oglethorpe  is also  obligated to make
available  the  same  share  of  most  of  Oglethorpe's   other  resources,   in
contractually fixed amounts,  which Morgan Stanley may schedule for each 24-hour
day. This schedule is set the day prior based on availability limitations in the
contract.  Morgan  Stanley pays a  contractually  fixed amount each month and an
amount  for the  scheduled  energy  based on  contractually  fixed  prices.  The
agreement has a term  extending to March 31, 2005, but the purchases for certain
Members decline to zero prior to that date.

     Oglethorpe  manages  the  portion  of the system  resources  covered by the
Morgan Stanley  agreement on behalf of participants in its electricity  capacity
and energy pool through  scheduling and dispatching  such resources.  Oglethorpe
makes  purchases  and sales on behalf of the pool  participants  to balance  the
fixed purchase  obligation  against the actual  requirements and to optimize the
use of the resources  after  receiving the daily  schedule from Morgan  Stanley.
(See "Capacity and Energy Pool" herein.)

     Morgan Stanley  Capital Group,  Inc. is a subsidiary of Morgan  Stanley,  a
diversified investment banking and financial services company. Morgan Stanley is
subject to the  informational  requirements  of the  Securities  Exchange Act of
1934,  as  amended,  and,  in  accordance  therewith,  files  reports  and other
information with the Commission.

Power Purchase and Sale Arrangements

     Power Purchases

     Oglethorpe  has an agreement  with GPC to purchase  capacity and associated
energy on a take-or-pay  basis.  Under this agreement,  Oglethorpe is purchasing
and will continue to purchase 250 MW until March 31, 2006.

     Oglethorpe has a contract through 2019 to purchase  approximately 300 MW of
capacity from  Hartwell  Energy  Limited  Partnership,  a joint venture  between

                                       9


Dynegy Inc. and American  National Power,  Inc., a subsidiary of National Power,
PLC.  This  capacity  is  provided by two 150 MW  gas-fired  combustion  turbine
generating units on a site near Hartwell,  Georgia.  Oglethorpe has the right to
dispatch the units.

     Oglethorpe  also  purchased 100 MW of capacity from each of Entergy  Power,
Inc. ("Entergy Power") and Big Rivers Electric Corporation ("Big Rivers"), under
agreements that terminated in June and July 2002, respectively.

     See Note 9 of Notes to Financial  Statements  in Item 8 for a discussion of
Oglethorpe's commitments under these power purchase agreements.

     In addition, Oglethorpe also purchases small amounts of capacity and energy
from "qualifying facilities" under the Public Utility Regulatory Policies Act of
1978  ("PURPA").  Under a  waiver  order  from  the  Federal  Energy  Regulatory
Commission  ("FERC"),  Oglethorpe  historically  made all  purchases the Members
would have  otherwise  been  required  to make under  PURPA and  Oglethorpe  was
relieved of its obligation to sell certain  services to "qualifying  facilities"
so long as the Members make those sales.  Oglethorpe  historically  provided the
Members with the necessary services to fulfill these sale obligations. Purchases
by  Oglethorpe  from  such  qualifying  facilities  provided  less  than 0.1% of
Oglethorpe's  energy requirements for the Members in 2002. Under their Wholesale
Power Contracts, the Members may make such purchases instead of Oglethorpe.

     Long-Term Power Sales

     Oglethorpe  has an  agreement  to sell 100 MW of base  capacity  to Alabama
Electric  Cooperative,  Inc. through  December 31, 2005.  During the term of the
power marketer agreements,  LEM and Morgan Stanley are responsible for supplying
Oglethorpe with sufficient power to fulfill this power sale.

     Other Power System Arrangements

     Oglethorpe has interchange,  transmission  and/or  short-term  capacity and
energy  purchase or sale  agreements  with  approximately  70  utilities,  power
marketers and other power suppliers.  The agreements  provide  variously for the
purchase  and/or  sale  of  capacity  and  energy  and/or  for the  purchase  of
transmission service.  Oglethorpe engages in these types of transactions for the
benefit of Members that  participate in  Oglethorpe's  capacity and energy pool.
Oglethorpe  is  currently  actively  trading  with  only  about  half  of  these
counterparties  due to  Oglethorpe's  risk  management  policies with respect to
netting  provisions  and credit  levels.  The  development  of and access to the
Integrated  Transmission System and the  interconnections  with other utilities,
through  transmission  contracts  with  GTC  and  others,  are key  elements  in
Oglethorpe's  ability to make off-system  sales and purchases for the benefit of
the Members participating in the pool.

Future Power Supply

     Under the Wholesale Power  Contracts,  Members can elect on an annual basis
whether to have  Oglethorpe  provide  joint  planning  and  resource  management
services. These services consist of bulk power supply planning,  future resource
procurement, and bulk power sales for the Members.

     Thirty-eight  Members have elected not to receive these  services for 2003.
Oglethorpe  is  providing  certain  basic  planning  services  under a  separate
contract with the remaining  Member.  Oglethorpe plans to discontinue  providing
these services at a future date. (See  "OGLETHORPE  POWER  CORPORATION--Expected
Facilities Acquisitions,  RUS Loans and Other New Arrangements" and "THE MEMBERS
AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources.")

Capacity and Energy Pool

     In  connection  with  scheduling  rights  granted  to  the  Members  in the
Wholesale Power Contracts  adopted in 1997,  Oglethorpe  established an electric
capacity  and  energy  pool,  which it may  elect to  discontinue  at any  time.
Pursuant to the  Wholesale  Power  Contracts  and the  policies  and  procedures
governing the pool,  the Members may elect either to  participate in the pool or

                                       10


to schedule  and  pseudo-dispatch  separately  the capacity  represented  by the
Member's percentage capacity responsibility under the Wholesale Power Contracts.
The Members may also elect to include  all or part of their other  resources  in
the pool.  Oglethorpe plans to discontinue  providing these services at a future
date. (See "OGLETHORPE POWER CORPORATION--Expected  Facilities Acquisitions, RUS
Loans  And Other New  Arrangements"  and "THE  MEMBERS  AND THEIR  POWER  SUPPLY
RESOURCES--Member Power Supply Resources.")

     Oglethorpe  buys and sells energy on behalf of Members that  participate in
the  pool.  Oglethorpe  is a  member  of ACES  Power  Marketing,  which  acts as
Oglethorpe's  agent to perform these services  pursuant to a service  agreement.
(See  "QUANTITATIVE  AND QUALITATIVE  DISCLOSURES  ABOUT MARKET  RISK--Commodity
Price  Risk--Risk  Management.")  Oglethorpe has contracted with GSOC to operate
the pool.

                                       11


                  THE MEMBERS AND THEIR POWER SUPPLY RESOURCES

Member Demand and Energy Requirements

     The Members are listed below and include 39 of the 42 electric distribution
cooperatives in the State of Georgia.



                                                                                   
Altamaha EMC                                    GreyStone Power Corporation, an EMC      Pataula EMC
Amicalola EMC                                   Habersham EMC                            Planters EMC
Canoochee EMC                                   Hart EMC                                 Rayle EMC
Carroll EMC                                     Irwin EMC                                Satilla Rural EMC
Central Georgia EMC                             Jackson EMC                              Sawnee EMC
Coastal EMC d/b/a Coastal Electric Cooperative  Jefferson Energy Cooperative, an EMC     Slash Pine EMC
Cobb EMC                                        Lamar EMC                                Snapping Shoals EMC
Colquitt EMC                                    Little Ocmulgee EMC                      Sumter EMC
Coweta-Fayette EMC                              Middle Georgia EMC                       Three Notch EMC
Diverse Power, Incorporated, an EMC (f/k/a      Mitchell EMC                             Tri-County EMC
   Troup EMC)
Excelsior EMC                                   Ocmulgee EMC                             Upson EMC
Flint EMC d/b/a Flint Energies                  Oconee EMC                               Walton EMC
Grady EMC                                       Okefenoke Rural EMC                      Washington EMC


     The Members serve  approximately  1.5 million electric  consumers  (meters)
representing  approximately  3.7  million  people.  The  Members  serve a region
covering  approximately  40,000 square miles,  which is approximately 70% of the
land area in the State of Georgia, encompassing 150 of the State's 159 counties.
Sales by the Members in 2002  amounted to  approximately  30 million  MWh,  with
approximately  66% to  residential  consumers,  32% to commercial and industrial
consumers and 2% to other consumers. The Members are the principal suppliers for
the  power  needs of rural  Georgia.  While the  Members  do not serve any major
cities,  portions of their service  territories  are in close proximity to urban
areas and are  experiencing  substantial  growth due to the  expansion  of urban
areas,  including  metropolitan  Atlanta,  into suburban areas and the growth of
suburban  areas into  neighboring  rural  areas.  The Members  have  experienced
average annual  compound  growth rates from 2000 through 2002 of 4% in number of
consumers, 5% in MWh sales and 6% in electric revenues.

     The following table shows the aggregate peak demand and energy requirements
of the Members for the years 2000  through  2002,  and also shows the amounts of
energy requirements  supplied by Oglethorpe.  From 2000 through 2002, demand and
energy  requirements  of the Members  increased  at an average  annual  compound
growth rate of 3% and 5%, respectively.

                        Member                    Member Energy
                       Demand (MW)             Requirements (MWh)
                      -----------    -------------------------------------------
                       Total(1)         Total(2)       Supplied by Oglethorpe(3)
                       --------         --------       -------------------------
2000.............      6,703           28,221,306              27,232,641
2001.............      6,532           28,332,257              26,950,149
2002.............      7,153           31,271,101              27,924,856

- ----------
(1)  System peak hour demand of the Members  measured at the  Members'  delivery
     points (net of system losses),  adjusted to include  requirements served by
     Oglethorpe and Member resources behind the delivery points.
(2)  Retail requirements served by Oglethorpe and Member resources,  adjusted to
     include  requirements  served by resources behind the delivery points. (See
     "Member Power Supply Resources" below.)
(3)  Includes energy supplied to Members for resale at wholesale.

                                       12


Service Area and Competition

     The  Territorial  Act regulates the service  rights of all retail  electric
suppliers  in the State of Georgia.  Pursuant to the  Territorial  Act, the GPSC
assigned  substantially  all areas in the State to specified  retail  suppliers.
With limited exceptions,  the Members have the exclusive right to provide retail
electric  service  in their  respective  territories,  which  are  predominately
outside of the municipal  limits  existing at the time the  Territorial  Act was
enacted in 1973.  The principal  exception to this rule of  exclusivity  is that
electric  suppliers  may compete for most new retail  loads of 900  kilowatts or
greater.  The GPSC may reassign territory only if it determines that an electric
supplier has breached the tenets of public  convenience and necessity.  The GPSC
may transfer  service for specific  premises  only if: (i) the GPSC  determines,
after joint  application  of electric  suppliers  and proper notice and hearing,
that the public convenience and necessity require a transfer of service from one
electric  supplier to another;  or (ii) the GPSC finds,  after proper notice and
hearing,  that an electric  supplier's  service to a premise is not  adequate or
dependable  or  that  its  rates,   charges,   service  rules  and   regulations
unreasonably  discriminate  in favor of or against the consumer  utilizing  such
premise and the electric  utility is unwilling or unable to comply with an order
from GPSC regarding such service.

     Since 1973,  the  Territorial  Act has allowed  limited  competition  among
electric  utilities in Georgia by allowing the owner of any new facility located
outside of  municipal  limits  and having a  connected  load upon  initial  full
operation  of 900  kilowatts  or greater to receive  electric  service  from the
retail  supplier of its choice.  The Members,  with  Oglethorpe's  support,  are
actively engaged in competition  with other retail electric  suppliers for these
new  commercial and  industrial  loads.  The number of commercial and industrial
loads  served  by  the  Members  continues  to  increase  annually.   While  the
competition  for  900-kilowatt  loads  represents  only limited  competition  in
Georgia,  this  competition has given Oglethorpe and the Members the opportunity
to develop  resources and strategies to operate in an  increasingly  competitive
market.  (See "FACTORS  AFFECTING THE ELECTRIC  UTILITY  INDUSTRY--General"  and
"MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS--Miscellaneous --Competition" in Item 7.)

     From time to time,  utilities are approached by other parties interested in
purchasing  their systems.  Some of the Members have been approached in the past
by third  parties  indicating  an  interest in  purchasing  their  systems.  The
Wholesale Power Contracts  provide that a Member may not dissolve,  liquidate or
otherwise wind up its affairs without Oglethorpe's  approval. A Member generally
must obtain approval from Oglethorpe before it may consolidate or merge with any
person or  reorganize  or change the form of its business  organization  from an
electric membership corporation or sell, transfer, lease or otherwise dispose of
all or  substantially  all of its  assets  to any  person,  whether  in a single
transaction or series of  transactions.  The Member may enter such a transaction
without Oglethorpe`s approval if specified conditions are satisfied,  including,
but not limited to, an agreement by the transferee,  satisfactory to Oglethorpe,
to assume the  performance and observance of every covenant and condition of the
Member under the Wholesale Power Contract,  and certifications of accountants as
to certain specified financial requirements of the transferee.

Cooperative Structure

     The Members are cooperatives that operate their systems on a not-for-profit
basis.  Accumulated  margins  derived  after  payment of operating  expenses and
provision for depreciation  constitute patronage capital of the consumers of the
Members.  Refunds of accumulated  patronage capital to the individual  consumers
may be made from time to time  subject to  limitations  contained  in  mortgages
between  the  Members  and RUS or loan  documents  with other  lenders.  The RUS
mortgages  generally  prohibit  such  distributions  unless  (1)  after any such
distribution, the Member's total equity will equal at least 30% (40% in the case
of Members that have the older form of RUS loan  documents) of its total assets,
or (2)  distributions  do not exceed 25% of the  margins and  patronage  capital
received by the Member in the preceding year and equity is at least 20% (the 20%

                                       13


equity  requirement  does not apply to  Members  that have the older form of RUS
loan documents). (See "Members' Relationship with RUS" below.)

     Oglethorpe   is  a  membership   corporation,   and  the  Members  are  not
subsidiaries  of  Oglethorpe.  Except  with  respect to the  obligations  of the
Members  under each  Member's  Wholesale  Power  Contract  with  Oglethorpe  and
Oglethorpe's rights under such contracts to receive payment for power and energy
supplied, Oglethorpe has no legal interest in, or obligations in respect of, any
of the assets,  liabilities,  equity,  revenues or margins of the Members.  (See
"OGLETHORPE POWER  Corporation--Wholesale Power Contracts.") The revenues of the
Members are not pledged as security to Oglethorpe  but are the source from which
moneys are derived by the Members to pay for power supplied by Oglethorpe  under
the Wholesale Power  Contracts.  Revenues of the Members are,  however,  pledged
under their respective RUS mortgages or loan documents with other lenders.

Rate Regulation of Members

     Through provisions in the loan documents securing loans to the Members, RUS
exercises  control and  supervision  over the rates for the sale of power of the
Members that borrow from it. The RUS  mortgages of such Members  require them to
design rates with a view to maintaining  an average Times Interest  Earned Ratio
and an  average  Debt  Service  Coverage  Ratio  of not  less  than  1.25 and an
Operating  Times Interest  Earned Ratio and an Operating  Debt Service  Coverage
Ratio of not less than 1.10, in each case for the two highest out of every three
successive years. Members that have the older form of RUS loan documents are not
required to maintain the Operating ratios.

     The Georgia  Electric  Membership  Corporation Act, under which each of the
Members was formed,  requires the Members to operate on a  not-for-profit  basis
and to set rates at levels  that are  sufficient  to recover  their costs and to
provide  for  reasonable  reserves.  The  setting of rates by the Members is not
subject to approval by any federal or state agency or authority  other than RUS,
but the Territorial Act prohibits the Members from  unreasonable  discrimination
in the setting of rates, charges,  service rules or regulations and requires the
Members to obtain GPSC approval of long-term borrowings.

     Cobb EMC,  Mitchell EMC, Oconee EMC,  Snapping  Shoals EMC,  Diverse Power,
Incorporated,  an EMC  ("Diverse  Power")  and  Walton  EMC have paid  their RUS
indebtedness  and are no longer RUS  borrowers.  Each of these Members now has a
rate  covenant  with its  current  lender.  Other  Members  may also pursue this
option.  To the  extent  that a Member  who is not an RUS  borrower  engages  in
wholesale sales or transmission in interstate  commerce,  it would be subject to
regulation by FERC under the Federal Power Act.

Members' Relationship with RUS

     Through provisions in the loan documents securing loans to the Members, RUS
also exercises  control and supervision  over the Members that borrow from it in
such areas as accounting,  other  borrowings,  construction  and  acquisition of
facilities, and the purchase and sale of power.

     Historically,  federal  loan  programs  providing  direct loans from RUS to
electric cooperatives have been a major source of funding for the Members. Under
the current RUS loan  program,  interest  rates are based on rates being paid on
municipal bonds with comparable  maturities.  Certain  borrowers with either low
consumer density or higher-than-average  rates and  lower-than-average  consumer
income are eligible for special  loans at 5%.  Distribution  borrowers  are also
eligible  for  loans  made  by FFB or  other  lenders  and  guaranteed  by  RUS.
Oglethorpe cannot predict the future cost, availability and amount of RUS direct
and guaranteed loans that may be available to the Members.

Members' Relationships with GTC and GSOC

     GTC  provides  transmission  services to the  Members  for  delivery of the
Members' power purchases from Oglethorpe and other power suppliers.  GTC and the
Members have entered into Member Transmission Service Agreements under which GTC
provides  transmission service to the Members pursuant to a transmission tariff.

                                       14


The Member  Transmission  Service  Agreements  have a minimum  term for  network
service for current load until  December 31, 2025.  After an initial term ending
in 2006, load growth above 1995  requirements may, with notice to GTC, be served
by others. The Member  Transmission  Service Agreements provide that if a Member
elects  to  purchase  a part of its  network  service  elsewhere,  it  must  pay
appropriate  stranded  costs to protect the other Members from any rate increase
that could otherwise occur. Under the Member  Transmission  Service  Agreements,
Members  have  the  right  to  design,   construct  and  own  new   distribution
substations.

     GSOC  provides  operation  services for the benefit of the Members  through
agreements with  Oglethorpe,  including  dispatch of Oglethorpe's  resources and
other power supply resources owned by the Members.

     For additional  information about the Members' relationships with GSOC, see
"OGLETHORPE POWER CORPORATION--Relationship with GSOC."

Member Power Supply Resources

     Oglethorpe Power Corporation

     Oglethorpe  currently  supplies  a  substantial  portion  of  the  Members'
requirements.   Each  Member  has  a  take-or-pay,   fixed  percentage  capacity
responsibility for all of Oglethorpe's  existing resources.  Members may satisfy
all  or  a  portion  of  their  requirements  above  their  Oglethorpe  purchase
obligations  with  purchases  from  other  suppliers.   (See  "OGLETHORPE  POWER
CORPORATION--Wholesale Power Contracts.")

     Contracts with SEPA

     The  Members  purchase  hydroelectric  power  from the  Southeastern  Power
Administration  ("SEPA")  under  contracts  that extend until 2016. In 2002, the
aggregate SEPA allocation to the Members was 564 MW plus associated  energy.  An
additional aggregate of 54 MW is available to the Members pending arrangement of
firm transmission service. Each Member must schedule its energy allocation,  and
each Member has designated  Oglethorpe to perform this  function.  Pursuant to a
separate  agreement,  Oglethorpe will schedule,  through GSOC, the Members' SEPA
power deliveries.  Further,  each Member may be required,  if certain conditions
are met, to  contribute  funds for capital  improvements  for Corps of Engineers
projects from which its allocation is derived in order to retain the allocation.

     Smarr EMC

     The Members participating in the facilities owned by Smarr EMC purchase the
output of those  facilities  pursuant to long-term,  take-or-pay  power purchase
agreements.  Smarr EMC owns Smarr Energy Facility, a two-unit,  217 MW gas-fired
combustion  turbine facility (with 36 participating  Members),  and Sewell Creek
Energy Facility, a four-unit, 492 MW gas-fired combustion turbine facility (with
31 participating  Members).  Smarr Energy Facility began commercial operation in
June 1999, and Sewell Creek Energy Facility began  commercial  operation in June
2000.

     Talbot EMC and Chattahoochee EMC

     Thirty of  Oglethorpe's  Members  formed  Talbot  EMC,  a Georgia  electric
membership  corporation,  in 2001 to  construct  and  own a  six-unit  gas-fired
combustion turbine facility designed to provide 618 MW of capacity.  Four of the
combustion turbines have been operating since June 2002, and the other two units
are  expected  to be  operational  by June 2003.  The Members of Talbot EMC have
entered into long-term,  take-or-pay  power purchase  agreements with Talbot EMC
pursuant  to which  the  Members  pay all  costs  of  constructing,  owning  and
operating the facility and are entitled to the output of the facility when it is
completed.

     Twenty eight of Oglethorpe's  Members formed  Chattahoochee  EMC, a Georgia
electric  membership  corporation,  in 2001  to  construct  and own a  gas-fired
combined  cycle  facility  designed to provide 468 MW of capacity.  The combined
cycle facility became operational in February 2003. The Members of Chattahoochee
EMC have entered into  long-term,  take-or-pay  power purchase  agreements  with
Chattahoochee  EMC pursuant to which the Members pay all costs of  constructing,
owning  and  operating  the  facility  and are  entitled  to the  output  of the
facility.

                                       15


     For information  regarding  services and financial  support that Oglethorpe
provides to Talbot EMC and  Chattahoochee  EMC and the expected  acquisition  of
their   generation    facilities   by   Oglethorpe,    see   "OGLETHORPE   POWER
CORPORATION--Expected   Facilities   Acquisitions,   RUS  Loans  And  Other  New
Arrangements",  "--Relationships  with Smarr EMC,  Talbot EMC and  Chattahoochee
EMC" and  "MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF  FINANCIAL  CONDITION  AND
RESULTS OF OPERATIONS--Financial Condition--Capital  Requirements--Financing for
Talbot EMC and Chattahoochee EMC " in Item 7.

     GPC Block Purchase

     Thirty Members have entered into long-term power supply contracts with GPC,
under which the Members  will  purchase an  aggregate  of 750 MW of capacity and
associated energy. Delivery under the agreement is scheduled to begin in 2005.

     Other Member Resources

     Members not  participating in Oglethorpe's  capacity and energy pool obtain
their power supply requirements above their Oglethorpe purchase obligations from
other  sources.  A number of Members  have  entered  into  contracts  with third
parties  for  all  of  their  incremental  power  requirements.  Other  Members,
including  participants  in  the  pool,  have  developed  their  own  generation
facilities or have other power purchase contracts.

     Oglethorpe  has not  undertaken  to obtain a complete  list of Member power
supply  resources.  Any of the  Members  may have  committed  or may  commit  to
additional power supply obligations not described above.

Member Memorandum of Understanding

     One of Oglethorpe's  Members, Cobb EMC, has provided Oglethorpe a copy of a
Memorandum  of  Understanding  between it and another of  Oglethorpe's  Members,
Diverse Power entered into in September  2002. The  Memorandum of  Understanding
calls for the two  Members  to use their best  efforts to enter into  definitive
agreements  for a proposed  transaction  in which Cobb EMC would assume  Diverse
Power's  rights  and  obligations   under  its  Wholesale  Power  Contract  with
Oglethorpe beginning April 1, 2005. In consideration, Diverse Power would assume
Cobb EMC's rights and obligations  regarding  allocations of hydroelectric power
from the Southeastern  Power  Administration on the same date. See "Member Power
Supply  Resources - Contracts  with SEPA".  Among other elements of the proposed
transaction,  Diverse  Power has a stated  objective  of being  relieved  of all
liability under its Wholesale Power Contract with Oglethorpe.

     Neither of the Members has asked Oglethorpe to take any action with respect
to the Memorandum of  Understanding.  Oglethorpe  has existing  provisions for a
Member to withdraw and to assign its rights and obligations  under its Wholesale
Power Contract with Oglethorpe to another person.  These provisions  require the
assignee  to have  certain  published  credit  ratings  and to assume all of the
withdrawing  Member's  obligations  under  its  Wholesale  Power  Contract  with
Oglethorpe.  Any such  assignment  must be  approved  by  Oglethorpe's  Board of
Directors and RUS.  Diverse  Power has not asked to withdraw from  Oglethorpe in
accordance with these procedures.

     In  2002,  Diverse  Power  represented  approximately  1.4 %,  and Cobb EMC
represented  approximately  11.3  %,  of  Oglethorpe's  revenues  from  Members.
Oglethorpe  cannot  predict  whether  Diverse  Power will request to withdraw or
whether  the two  Members  will  request  that  Oglethorpe  take any action with
respect to the transaction as proposed in the Memorandum of Understanding.

                                       16


                 FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY

General

     The electric  utility  industry has been and in the future will continue to
be  affected  by a number of factors  that  could have an impact on an  electric
utility  such as  Oglethorpe.  These  factors  likely  would  affect  individual
utilities in different ways. Such factors include, among others:

o    the  transition to increasing  competition in the generation of electricity
     and the  corresponding  increase in  competition  from other  suppliers  of
     electricity,

o    fluctuations in the market price for electricity,

o    difficulties in the development of efficient energy trading markets,

o    effects of compliance with changing environmental, licensing and regulatory
     requirements,

o    regulatory and other changes in national and state energy policy, including
     open access transmission and electricity market design,

o    credit quality of utilities and power marketers,

o    tightening of access to financing for capital  expenditures and replacement
     of aging fixed assets,

o    increases in operating costs, including the cost of fuel for the generation
     of electric energy,

o    uncertain recovery of the cost of existing facilities,

o    limitations on purchasing  and selling  energy from and to other  suppliers
     due to transmission constraints,

o    limitations on supply of equipment and available sites for  construction of
     generation resources,

o    fluctuations  in demand,  including  rates of load  growth  and  changes in
     competitive market share,

o    unbundling  of  services  and   corresponding   corporate  and   functional
     restructurings by electric utility companies,

o    the effects of  conservation  and energy  management on the use of electric
     energy, and

o    the threat of  terrorist  attacks on  electric  generation  facilities  and
     corresponding increases in security and insurance costs.

     These factors present an increasing  challenge to companies in the electric
utility industry, including Oglethorpe and the Members, to reduce costs, improve
the management of resources and respond to the changing environment.

Competition

     (See  "MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF FINANCIAL  CONDITION  AND
RESULTS OF OPERATIONS--Miscellaneous --Competition" in Item 7.)

Environmental and Other Regulation

     General

     As is typical  for  electric  utilities,  Oglethorpe  is subject to various
federal,  state and local air and water quality  requirements which, among other
things,  regulate emissions of pollutants,  such as particulate  matter,  sulfur
dioxide and nitrogen  oxides into the air and  discharges  of other  pollutants,
including heat, into waters of the United States.  Oglethorpe is also subject to
federal, state and local waste disposal requirements that regulate the manner of
transportation, storage and disposal of various types of waste.

     In general, environmental requirements are becoming increasingly stringent.
New requirements may  substantially  increase the cost of electric  service,  by
requiring  changes in the design or operation of existing  facilities or changes
or delays in the location, design,  construction or operation of new facilities.
Failure to comply with these  requirements  could  result in the  imposition  of
civil and  criminal  penalties as well as the  complete  shutdown of  individual
generating units not in compliance.  Oglethorpe cannot provide assurance that it
will always be in compliance with current and future regulations.

                                       17


     Compliance  with  environmental  standards will continue to be reflected in
Oglethorpe's   capital   expenditures  and  operating  costs.   Oglethorpe  made
environmental-related  capital expenditures of approximately $40 million in 2002
and  expects  to spend $53  million  in 2003 and $2  million  in 2004 to achieve
compliance  with  current   environmental   requirements.   (See   "MANAGEMENT'S
DISCUSSION    AND   ANALYSIS   OF   FINANCIAL    CONDITION    AND   RESULTS   OF
OPERATIONS--Financial  Condition--Capital Requirements" in Item 7.) Based on the
current status of regulatory  requirements,  Oglethorpe does not anticipate that
these  capital  expenditures  will  have a  material  effect on its  results  of
operations or its  financial  condition.  However,  as discussed  below,  future
regulations could require Oglethorpe to make additional capital expenditures.

     Clean Air Act

     Environmental concerns of the public, the scientific community and Congress
have resulted in the enactment of legislation  that has had and will continue to
have a significant impact on the electric utility industry. The most significant
environmental  legislation applicable to Oglethorpe is the Clean Air Act. One of
the  purposes of the Clean Air Act is to improve  air  quality by  reducing  the
emissions of sulfur  dioxide and nitrogen  oxides from affected  utility  units,
which include the coal-fired units at Plants Wansley and Scherer.

     Sulfur  dioxide  reductions  are being  imposed  through  a sulfur  dioxide
emission  allowance  trading  program.  An emission  allowance,  which gives the
holder the authority to emit one ton of sulfur  dioxide  during a calendar year,
is transferable and can be bought, sold or banked for use in the years following
its issuance.  Allowances are issued by the U.S. Environmental Protection Agency
("EPA") to impose  stringent  reductions  on all affected  units.  The aggregate
emissions  of sulfur  dioxide  from all  affected  units  are now  capped at 8.9
million tons per year.  Oglethorpe is now  complying  with this program by using
lower-sulfur fuel, coupled with the use of emission allowances  (issued,  banked
or purchased,  if needed).  Installation of flue gas  desulfurization  equipment
remains a possibility for compliance in the more distant future.

     Reductions in nitrogen oxides emissions are also being imposed,  as part of
Georgia's  State  Implementation  Plan,  in an effort to bring the  metropolitan
Atlanta area, currently classified as a "serious nonattainment area" pursuant to
the one-hour  National Ambient Air Quality  Standards  ("NAAQS") for ozone, into
attainment.  As part of this Plan,  both Plants Wansley and Scherer are included
in stringent nitrogen oxides emissions averaging plans,  requiring the co-owners
of the plants to install new control  equipment at both plants no later than May
2003.  Installation of control equipment to comply with these requirements is on
schedule.  The  expected  costs  to  install  this  equipment  are  included  in
Oglethorpe's  expected   environmental-related  capital  expenditures  described
above.

     A number of recently finalized regulations,  proposed regulations and other
actions  could result in more  stringent  controls on all  emissions,  including
utility  emissions.  The  actions  that  appear to be the most  significant  are
described below.

     EPA attempted to tighten the NAAQS for both ozone and  particulate  matter,
an action  that could  affect any source that emits  nitrogen  oxides and sulfur
dioxide,  including utility units. Court challenges to both standards were made.
On appeal,  the U.S.  Supreme  Court  reversed a  successful  challenge of these
revised NAAQS. The Court of Appeals denied further petitions for review, leaving
EPA to proceed  with  implementation  of both NAAQS.  With  respect to the ozone
NAAQS, EPA must harmonize provisions in the Clean Air Act imposing the old ozone
NAAQS with its proposed standard before the new standard can be implemented.  In
conjunction  with these NAAQS,  EPA plans to designate  areas as  attainment  or
nonattainment  with these standards in 2004, based on air quality data collected
for 2001 through 2003. Some areas that will be designated as  nonattainment  for
either ozone or particulate  matter may require  further  reductions on nitrogen
oxides,  sulfur dioxide, or both from Plants Wansley and/or Scherer.  The impact
of any new  designations  will depend on the development and  implementation  of

                                       18


applicable regulations and cannot be determined at this time.

     In 1998,  EPA  issued a  regulation  calling  for  regional  reductions  in
nitrogen oxides  emissions from 22 states,  including  Georgia,  which imposes a
fixed cap on nitrogen  oxides  emissions from such states  beginning in the year
2005.  States  remain free to choose the  sources on which to impose  reductions
needed to stay below the cap. The Georgia Environmental  Protection Division has
indicated that if Georgia must adhere to the  regulation,  it will require large
fossil  fuel-fired  units,  including  those at Plants  Wansley and Scherer,  to
participate in achieving the required  reductions.  On appeal,  EPA's regulation
was upheld in part,  with that  portion  of the rule that would have  applied to
Georgia  sent back to EPA for  further  consideration.  EPA has  proposed a rule
reinstating the cap for Georgia, which would delay implementation until 2005. In
a related  rulemaking,  EPA issued a final rule that  concluded  that the growth
rates used to compute the cap for Georgia and other states were reasonable. That
second  rule has been  challenged  by various  parties in the Court of  Appeals,
seeking  to  have  it  remanded  back to EPA  for  further  consideration.  This
challenge may delay Georgia's implementation date. Georgia's implementation plan
for this regulation will depend on how this proposed rulemaking is finalized and
how the current  litigation  is  resolved.  Therefore,  it is not yet known what
additional controls, if any, would be needed at Plants Wansley and/or Scherer to
comply with this  regional  nitrogen  oxides  reduction  program.  However,  the
co-owners of Plant Scherer are converting  Units No. 1 and No. 2 from bituminous
coal to sub-bituminous coal, which will substantially reduce the nitrogen oxides
emissions from these units.

     EPA has also  announced  its  intention  to  propose a  regional  transport
regulation  for  particulate  matter  by the end of 2003,  and to  finalize  the
regulation  by 2005.  This rule would likely  require year round  reductions  in
emissions of sulfur  dioxide and nitrogen  oxide from power  plants,  perhaps as
early as 2010. The rule could affect Georgia's plans for attaining the NAAQS for
ozone and  particulate  matter  discussed  above,  which in turn  could  lead to
further controls on Plants Wansley and/or Scherer.

     In 1999,  EPA  promulgated  a new  regional  haze  rule,  which  would have
affected any source that emits  nitrogen  oxides or sulfur  dioxide and that may
contribute to the degradation of visibility in mandatory  federal Class I areas,
including  utility units. As a result of challenges to this rule,  however,  the
Court of Appeals  has  vacated  part of the rule,  remanding  it back to EPA for
further consideration  consistent with its opinion.  Until further rulemaking in
response to this decision is conducted,  Oglethorpe will not know what controls,
if any, must be installed at Plants  Wansley  and/or Scherer to comply with this
rule.

     Although EPA had decided not to impose a new NAAQS for sulfur dioxide, that
decision  has  been  remanded  to EPA for  further  rulemaking,  so it is  still
possible that a new short-term standard for sulfur dioxide could be established.

     Several  studies  required by the Clean Air Act examined the health effects
of power plant emissions of certain hazardous air pollutants.  In late 2000, EPA
concluded that mercury emissions from coal and oil-fired  electric utility steam
generating  units  should  be  regulated.   Emissions  of  other  hazardous  air
pollutants,  such as nickel and cadmium, may also become regulated.  EPA expects
to follow a rulemaking  schedule  that would  require  compliance  by 2007-2008.
Depending on the outcome of such rulemaking,  significant  capital  expenditures
might be incurred at Plants Wansley and/or Scherer.

     On November 3, 1999,  the United States  Justice  Department,  on behalf of
EPA, filed  lawsuits  against GPC and some of its  affiliates,  as well as other
utilities.  The lawsuits allege  violations of the new source review  provisions
and the new source  performance  standards  of the Clean Air Act at, among other
facilities,  Scherer Unit Nos. 3 and 4. Oglethorpe is not currently named in the
lawsuits and Oglethorpe  does not have an ownership  interest in the named units
of Plant Scherer. However,  Oglethorpe can give no assurance that units in which
Oglethorpe  has an ownership  interest will not be affected by this or a related
lawsuit in the future. The resolution of this matter is highly uncertain at this

                                       19


time, as is any  responsibility  of Oglethorpe  for a share of any penalties and
capital  costs  required  to remedy any  violations  at  facilities  co-owned by
Oglethorpe.

     On  December   30,   2002,   the  Sierra   Club,   Physicians   for  Social
Responsibility,  Georgia Forest Watch and one  individual  filed suit in Federal
Court in Georgia against GPC, alleging  violations of the Clean Air Act at Plant
Wansley.  The complaint  alleges  violations of opacity  limits at both the coal
fired units, in which Oglethorpe is a co-owner,  and other violations at several
of the combined cycle units where neither  Oglethorpe nor  Chattahoochee EMC has
an ownership  interest.  This civil action  requests  injunctive and declaratory
relief,  civil penalties,  a supplemental  environmental  project and attorneys'
fees. While Oglethorpe  believes that Plant Wansley has complied with applicable
laws and regulations, resolution of this matter is uncertain at this time, as is
any  responsibility  of  Oglethorpe  for a share of any penalties or other costs
that might be assessed against GPC.

     On January 16, 2003, the Sierra Club appealed an unsuccessful  challenge to
an air operating  permit for the combined cycle facility owned by  Chattahoochee
EMC to the United States Court of Appeals for the Eleventh  Circuit.  Oglethorpe
expects to acquire this facility in the second quarter of 2003. See  "OGLETHORPE
POWER  CORPORATION--Expected  Facilities  Acquisitions,  RUS Loans and Other New
Arrangements."  Oglethorpe has intervened in the appeal. The petitioner seeks to
have  the air  permit  invalidated  and  remanded  back  to EPA and the  Georgia
Environmental  Protection Division ("EPD").  Although Oglethorpe believes that a
favorable  outcome  in this  appeal  is  likely,  an  unfavorable  ruling  could
temporarily affect the ability of the facility to continue to operate.

     Depending   on  the  final   outcome   of  these   developments,   and  the
implementation  approach  selected by EPA and the State of Georgia,  significant
capital  expenditures  and  increased  operation  expenses  could be incurred by
Oglethorpe for the continued  operation of Plants Wansley  and/or  Scherer.  The
power marketer  arrangements  generally do not provide for the recovery from the
power marketers of increased  environmental costs. (See "MEMBER REQUIREMENTS AND
POWER  SUPPLY   Resources--Power   Marketer   Arrangements.")   Because  of  the
uncertainty  associated with these various  developments,  Oglethorpe cannot now
predict  the effect  that any of these  potential  requirements  may have on the
operations of Plants Wansley and Scherer.

     Compliance  with the  requirements  of the Clean  Air Act may also  require
increased  capital or operating  expenses on the part of GPC.  Any  increases in
GPC's  capital or operating  expenses may cause an increase in the cost of power
purchased from GPC. (See "MEMBER REQUIREMENTS AND POWER SUPPLY  RESOURCES--Power
Purchase and Sale Arrangements--Power Purchases.")

     Nuclear Regulation

     Oglethorpe  is subject to the  provisions of the Atomic Energy Act of 1954,
as amended (the "Atomic Energy Act"),  which vests  jurisdiction  in the Nuclear
Regulatory  Commission  ("NRC") over the  construction  and operation of nuclear
reactors,  particularly  with  regard  to  certain  public  health,  safety  and
antitrust matters.  The National  Environmental Policy Act has been construed to
expand the  jurisdiction  of the NRC to consider the  environmental  impact of a
facility licensed under the Atomic Energy Act. Plants Hatch and Vogtle are being
operated  under  licenses  issued by the NRC. All aspects of the  operation  and
maintenance of nuclear power plants are regulated by the NRC. From time to time,
new NRC regulations require changes in the design,  operation and maintenance of
existing nuclear reactors.  Operating  licenses issued by the NRC are subject to
revocation,  suspension or modification, and the operation of a nuclear unit may
be suspended if the NRC determines that the public interest, health or safety so
requires. The operating licenses issued for each unit of Plants Hatch and Vogtle
expire in 2034 and 2038 and 2027 and 2029, respectively.  The licenses for Plant
Hatch were extended to their current expiration dates in January 2002.

     Pursuant to the Nuclear Waste Policy Act of 1982,  as amended,  the federal
government  has the  regulatory  responsibility  for the  final  disposition  of
commercially  produced high-level  radioactive waste materials,  including spent

                                       20


nuclear  fuel.  This Act requires the owner of nuclear  facilities to enter into
disposal  contracts  with the  Department of Energy  ("DOE") for such  material.
These  contracts  require each such owner to pay a fee,  which is currently  one
dollar  per  MWh  for  the net  electricity  generated  and  sold by each of its
reactors.

     Contracts with DOE have been executed to provide for the permanent disposal
of spent nuclear fuel  produced at Plants Hatch and Vogtle.  DOE failed to begin
disposing of spent fuel in 1998 as required by the contracts,  and GPC, as agent
for the  co-owners of the plants,  is pursuing  legal  remedies  against DOE for
breach of contract.

     Plants  Hatch and Vogtle  currently  have  on-site  spent-fuel  wet storage
capacity  and Plant Hatch has an on-site dry storage  facility.  Based on normal
operations and retention of all spent fuel in the reactor,  sufficient  capacity
is believed to be available to continue  dry storage  operations  at Plant Hatch
for the currently  anticipated life of the plant. Plant Vogtle's spent fuel pool
storage is  expected  to be  sufficient  until  2014.  Oglethorpe  expects  that
procurement  of on-site dry storage  capacity at Plant  Vogtle will  commence in
sufficient  time to maintain  full-core  discharge  capability to the spent fuel
pool. (See Note 1 of Notes to Financial Statements in Item 8.)

     For  information  concerning  nuclear  insurance,  see  Note 8 of  Notes to
Financial  Statements  in Item 8. For  information  regarding  NRC's  regulation
relating  to   decommissioning   of  nuclear   facilities  and  regarding  DOE's
assessments   pursuant  to  the  Energy  Policy  Act  for   decontamination  and
decommissioning  of nuclear fuel enrichment  facilities,  see Note 1 of Notes to
Financial Statements in Item 8.

     Other Environmental Regulation

     EPA  has  now  indicated  that  although  coal  ash  should  be  considered
non-hazardous,  national regulations are warranted.  Depending on the outcome of
such rulemaking, substantial additional costs for the management of these wastes
might be required of  Oglethorpe,  although  the full impact would depend on the
subsequent development of such rules.

     Under the Clean Water Act, EPA is developing  new rules  intended to reduce
the  impingement and entrainment of fish and fish larvae at cooling water intake
structures.  As proposed,  those rules will require numerous  biological studies
and perhaps  retrofits  to some intake  structures  at  existing  power  plants,
including Plants Wansley and Scherer. The new rule was proposed in February 2002
and is scheduled to be finalized in 2004.  The impact of any new standards  will
depend on the development and implementation of such rules.

     Also under the Clean Water Act,  EPA and state  environmental  agencies are
developing  total maximum daily loads (TMDLs) for certain impaired state waters.
The  establishment  of TMDLs  and/or  additional  measures to control  non-point
source pollution may result in a tightening of limits in water discharge permits
for power  plants,  including  Plants  Wansley and  Scherer.  As the impact will
depend on the actual TMDLs and the  corresponding  permit  limitations  that are
established, the effects of such developments cannot be predicted at this time.

     Oglethorpe is subject to other environmental  statutes  including,  but not
limited to, the Clean Water Act,  the Georgia  Water  Quality  Control  Act, the
Georgia  Hazardous  Site  Response  Act, the Toxic  Substances  Control Act, the
Resource   Conservation  &  Recovery  Act,  the  Endangered   Species  Act,  the
Comprehensive  Environmental  Response,  Compensation  and  Liability  Act,  the
Emergency  Planning  and  Community  Right to Know Act,  and to the  regulations
implementing  these  statutes.  Oglethorpe does not believe that compliance with
these  statutes and  regulations  will have a material  impact on its  financial
condition or results of operations.  Changes to any of these laws, some of which
are  being  reviewed  by  Congress,  could  affect  many  areas of  Oglethorpe's
operations.  Although compliance with new environmental legislation could have a
significant  impact on Oglethorpe,  those impacts cannot be fully  determined at
this time and would depend in part on the final  legislation and the development
of implementing regulations.

     The  scientific  community,  regulatory  agencies and the electric  utility
industry are continuing to examine the issues of global warming and the possible

                                       21


health  effects  of  electromagnetic  fields.  While  no  definitive  scientific
conclusions  have been  reached,  it is  possible  that new laws or  regulations
pertaining to these matters  could  increase the capital and operating  costs of
electric  utilities,  including  Oglethorpe  or entities  from which  Oglethorpe
purchases  power. In addition,  the potential for liability exists from lawsuits
that might be brought alleging damages from electromagnetic fields.  Oglethorpe,
or generating facilities in which Oglethorpe has an interest,  are also subject,
from time to time,  to claims  relating to  emissions of  pollutants,  including
actions by citizens to enforce environmental regulations and claims for personal
injury due to  emissions  from the  facilities.  Oglethorpe  cannot  predict the
outcome of current or future  actions,  the  responsibility  of Oglethorpe for a
share of any damages awarded or any impact on facility  operations.  Oglethorpe,
however,  does not believe that the current actions will have a material adverse
effect on the financial position or results of operations of Oglethorpe.








                                       22


ITEM 2. PROPERTIES

Generating Facilities

     The  following  table  sets  forth  certain  information  with  respect  to
Oglethorpe's generating facilities, all of which are in commercial operation.



                                                                   Oglethorpe's
                                                                     Share of
                                                                    NamePlate       Commercial       License
                                            Type of    Percentage    Capacity        Operation     Expiration
Facilities                                   Fuel      Interest        (MW)            Date            Date
- ----------                                   ----      --------        ----            ----            ----
Plant Hatch (near Baxley, Ga.)
                                                                                       
   Unit No. 1..........................   Nuclear         30            243.0          1975           2034
   Unit No. 2..........................   Nuclear         30            246.0          1979           2038
Plant Vogtle (near Waynesboro, Ga.)
   Unit No. 1..........................   Nuclear         30            348.0          1987           2027
   Unit No. 2..........................   Nuclear         30            348.0          1989           2029
Plant Wansley (near Carrollton, Ga.)
   Unit No. 1..........................     Coal          30            259.5          1976          N/A(1)
   Unit No. 2..........................     Coal          30            259.5          1978          N/A(1)
   Combustion Turbine..................     Oil           30             14.8          1980          N/A(1)
Plant Scherer (near Forsyth, Ga.)
   Unit No. 1..........................     Coal          60            490.8          1982          N/A(1)
   Unit No. 2..........................     Coal          60            490.8          1984          N/A(1)
Rocky Mountain (near Rome, Ga.)........    Pumped
                                          Storage
                                           Hydro          74.61         632.5          1995           2027
Plant Doyle (near Monroe, Ga.) ........     Gas          100            325.0(2)       2000          N/A(1)
                                                                      -------
   Total Ownership                                                    3,657.9
                                                                      =======
<FN>
- ----------
(1)  Fossil-fired units do not operate under operating licenses similar to those
     granted to nuclear units by the NRC and to hydroelectric plants by FERC.

(2)  Nominal plant capacity  identified in the Power Purchase and Sale Agreement
     with Doyle I, LLC. See "The Plant Agreements--Doyle".
</FN>


     Oglethorpe  expects  to acquire a  six-unit,  618 MW  gas-fired  combustion
turbine  facility and a 468 MW gas-fired  combined  cycle facility in the second
quarter  of  2003.  See  "OGLETHORPE  POWER   CORPORATION--Expected   Facilities
Acquisitions, RUS Loans And Other New Arrangements" in Item 1.

                                       23


Plant Performance

     The following table sets forth certain operating performance information of
each of Oglethorpe's generating facilities:

                      Equivalent
                    Availability(1)        Capacity Factor(2)
                    ---------------        ------------------
Unit              2002   2001    2000    2002   2001  2000
- ----              ----   ----    ----    ----   ----  ----
Plant Hatch
 Unit No. 1        87%     99%    84%     88%     99%   85%
 Unit No. 2        97      86     89      97      86    90
Plant Vogtle
 Unit No. 1        84      99     86      86     101    91
 Unit No. 2        82      92    100      84      94   102
Plant Wansley
 Unit No. 1        88      83     83      80      78    77
 Unit No. 2        79      87     78      74      81    72
Plant Scherer
 Unit No. 1        95      81    100      78      58    79
 Unit No. 2        83      94     90      66      71    73
Rocky
Mountain(3)
 Unit No. 1        99      94     94      15      24    26
 Unit No. 2        91      99     91      18      21    20
 Unit No. 3       100      95     94      27      17    17
Plant
Doyle(3,4)
 Unit No. 1       100     100    100       8       4     2
 Unit No. 2       100     100     97       8       5     8
 Unit No. 3       100     100     92       7       4     7
 Unit No. 4       100     100    100      11       6     9
 Unit No. 5       100     100    100      10       6     8

- ----------
(1)  Equivalent  Availability is a measure of the percentage of time that a unit
     was  available  to generate if called  upon,  adjusted for periods when the
     unit is partially derated from the "maximum dependable capacity" rating.

(2)  Capacity Factor is a measure of the output of a unit as a percentage of the
     maximum output, based on the "maximum dependable capacity" rating, over the
     period of measure.

(3)  Rocky Mountain and Plant Doyle primarily  operate as peaking plants,  which
     results in low capacity factors.

(4)  Equivalent  Availability  of each Doyle unit is  measured  only  during the
     period May 15 -  September  15,  reflecting  the  contractual  availability
     commitment  of Doyle I,  LLC.  The units may be  dispatched  by  Oglethorpe
     during other periods if the units are available.

     The nuclear  refueling  cycle for Plants  Hatch and Vogtle  exceeds  twelve
months.  Therefore,  in some  calendar  years the units at these  plants are not
taken out of service for  refueling,  resulting in higher  levels of  equivalent
availability and capacity factor.

Fuel Supply

     Coal.  Coal for  Plant  Wansley  is  currently  purchased  under  long-term
contracts and in spot market transactions.  As of February 28, 2003, there was a
30-day coal supply at Plant Wansley based on nameplate rating.

     Low-sulfur "compliance" coal for Scherer Units No. 1 and No. 2 is purchased
under long-term  contracts and in spot market  transactions.  As of February 28,
2003,  the coal  stockpile at Plant  Scherer  contained a 33-day supply based on
nameplate rating.  Plant Scherer burns both sub-bituminous and bituminous coals,
and a separate stockpile of sub-bituminous coal is maintained in addition to the
stockpile of bituminous  coal. The co-owners of Plant Scherer have  undertaken a
project to convert Units No. 1 and No. 2 at Plant Scherer to burn sub-bituminous
coal, and will thus not then maintain  separate stock piles.  Oglethorpe  leases
approximately  700 rail cars to transport coal to Plants Scherer and Wansley and
has plans to acquire approximately 500 additional rail cars in 2003.

     The Plant Scherer and Wansley ownership and operating agreements allow each
co-owner  (i) to  dispatch  separately  its  respective  ownership  interest  in
conjunction with contracting separately for long-term coal purchases procured by
GPC  and  (ii)  to  procure  separately  long-term  coal  purchases.  Oglethorpe
separately  dispatches Plant Scherer and Plant Wansley, but continues to use GPC
as its agent for fuel procurement.

     For information  relating to the impact that the Clean Air Act will have on
Oglethorpe, see "FACTORS AFFECTING THE ELECTRIC UTILITY  INDUSTRY--Environmental
and Other Regulations--Clean Air Act" in Item 1.

     Nuclear Fuel. GPC, as operating  agent, has the  responsibility  to procure
nuclear  fuel for Plants  Hatch and Vogtle.  GPC has  contracted  with  Southern
Nuclear  Operating  Company to operate  these  plants,  including  nuclear  fuel
procurement.  SONOPCO  employs both spot  purchases and  long-term  contracts to
satisfy nuclear fuel requirements.  The nuclear fuel supply and related services
are  expected to be adequate to satisfy  current and future  nuclear  generation
requirements.
                                       24


     Natural Gas. Oglethorpe purchases the natural gas, including transportation
and other related services,  needed to operate Doyle and the combustion turbines
owned by Hartwell Energy Limited  Partnership.  Oglethorpe purchases natural gas
in the spot  market and under  agreements  at  indexed  prices.  Oglethorpe  has
entered  into hedge  agreements  to manage its exposure to  fluctuations  in the
market price of natural gas.  Oglethorpe  expects to continue to manage exposure
to such risks only with respect to Members that participate in Oglethorpe's pool
and elect to receive such services. See "OGLETHORPE POWER  CORPORATION--Expected
Facilities  Acquisitions,  RUS Loans And Other New  Arrangements"  in Item 1 and
"QUANTITATIVE  AND QUALITATIVE  DISCLOSURES ABOUT MARKET  RISK--Commodity  Price
Risk." in Item 7A


Co-Owners of the Plants

     Plants  Hatch,  Vogtle,  Wansley  and  Scherer  Units  No.  1 and No. 2 are
co-owned by Oglethorpe,  GPC, MEAG and Dalton, and Rocky Mountain is co-owned by
Oglethorpe and GPC. Each such co-owner owns or leases undivided interests in the
amounts  shown  in  the  following  table  (which  excludes  the  Plant  Wansley
combustion turbine).  Oglethorpe is the operating agent for Rocky Mountain.  GPC
is the operating agent for each of the other plants.



                         Nuclear                           Coal-Fired                         Pumped Storage
               ---------------------------        --------------------------------     -------------------------
                  Plant           Plant               Plant         Scherer Units           Rocky
                  Hatch          Vogtle              Wansley        No. 1 & No. 2         Mountain         Total
               -----------    ------------        -------------    ---------------      -------------     -----
                %    MW(1)     %     MW(1)         %      MW(1)      %       MW(1)       %      MW(1)      MW(1)
               ---   -----    ---    -----        ---     -----     ---      -----      ---     -----      -----

                                                                         
Oglethorpe... 30.0    489    30.0     696        30.0      519      60.0      982      74.61    633       3,319
GPC.......... 50.1    817    45.7   1,060        53.5      926       8.4      137      25.39    215       3,155
MEAG......... 17.7    288    22.7     527        15.1      261      30.2      494       --     --         1,570
Dalton         2.2     36     1.6      37         1.4       24       1.4       23       --     --           120
- ---------------------------------------------------------------------------------------------------------------
Total.....   100.0  1,630   100.0   2,320       100.0    1,730     100.0    1,636     100.00    848       8,164
===============================================================================================================

- ----------
<FN>
(1) Based on nameplate ratings.
</FN>


     Georgia Power Company

     GPC is a wholly  owned  subsidiary  of The Southern  Company,  a registered
holding  company under the Public  Utility  Holding  Company Act, and is engaged
primarily  in  the   generation   and  purchase  of  electric   energy  and  the
transmission,  distribution  and sale of such energy.  GPC distributes and sells
energy within the State of Georgia at retail in over 600 communities  (including
Athens,  Atlanta,  Augusta,  Columbus,  Macon, Rome and Valdosta), as well as in
rural areas, and at wholesale to Oglethorpe, MEAG and two municipalities. GPC is
the  largest  supplier  of  electric  energy  in  the  State  of  Georgia.  (See
"OGLETHORPE POWER CORPORATION--Relationship with GPC" in Item 1.) GPC is subject
to the  informational  requirements  of the Securities  Exchange Act of 1934, as
amended, and, in accordance therewith,  files reports and other information with
the Commission.

     Municipal Electric Authority of Georgia

     MEAG,  an  instrumentality  of the State of  Georgia,  was  created for the
purpose  of  providing   electric   capacity  and  energy  to  those   political
subdivisions  of  the  State  of  Georgia  that  owned  and  operated   electric
distribution  systems at that time.  MEAG, also known as MEAG Power, has entered
into power sales contracts with each of 48 cities and one county in the State of
Georgia. Such political subdivisions, located in 39 of the State's 159 counties,
collectively serve approximately 290,000 electric consumers (meters).

     City of Dalton, Georgia

     The  City of  Dalton,  located  in  northwest  Georgia,  supplies  electric
capacity  and energy to  consumers  in Dalton,  and  presently  serves more than
10,000 residential, commercial and industrial customers.

                                       25


The Plant Agreements

     Hatch, Wansley, Vogtle and Scherer

     Oglethorpe's rights and obligations with respect to Plants Hatch,  Wansley,
Vogtle and Scherer are contained in a number of contracts between Oglethorpe and
GPC and,  in some  instances,  MEAG and  Dalton.  Oglethorpe  is a party to four
Purchase and Ownership Participation  Agreements ("Ownership  Agreements") under
which it acquired  from GPC a 30%  undivided  interest in each of Plants  Hatch,
Wansley and Vogtle,  a 60%  undivided  interest in Scherer Units No. 1 and No. 2
and a 30% undivided interest in those facilities at Plant Scherer intended to be
used in common  by  Scherer  Units  No. 1, No. 2, No. 3 and No. 4 (the  "Scherer
Common Facilities").  Oglethorpe has also entered into four Operating Agreements
("Operating  Agreements")  relating to the operation and  maintenance  of Plants
Hatch, Wansley, Vogtle and Scherer,  respectively.  The Ownership Agreements and
Operating  Agreements  relating  to  Plants  Hatch  and  Wansley  are  two-party
agreements  between  Oglethorpe and GPC. The Ownership  Agreements and Operating
Agreements   relating  to  Plants  Vogtle  and  Scherer  are  agreements   among
Oglethorpe,  GPC, MEAG and Dalton.  The parties to each Ownership  Agreement and
Operating  Agreement are referred to as "participants" with respect to each such
agreement.

     In 1985,  in four  transactions,  Oglethorpe  sold its entire 60% undivided
ownership  interest in Scherer  Unit No. 2 to four  separate  owner  trusts (the
"Lessors") established by four different  institutional investors (the "Sale and
Leaseback  Transaction").  Oglethorpe retained all of its rights and obligations
as a  participant  under the  Ownership  and  Operating  Agreements  relating to
Scherer  Unit No. 2 for the term of the leases.  Oglethorpe's  leases  expire in
2013,  with options to renew for a total of 8.5 years.  Oglethorpe also has fair
market value purchase options at specified dates,  including 2013 and the end of
lease  renewal  terms.  These  transactions  are  treated as  capital  leases by
Oglethorpe for financial reporting  purposes.  (See Note 4 of Notes to Financial
Statements in Item 8.) (In the following discussion,  references to participants
"owning" a specified  percentage of interests include  Oglethorpe's  rights as a
deemed owner with respect to its leased interests in Scherer Unit No. 2.)

     The  Ownership  Agreements  appoint  GPC as agent with sole  authority  and
responsibility  for,  among  other  things,  the  planning,  licensing,  design,
construction,  renewal,  addition,  modification  and disposal of Plants  Hatch,
Vogtle,  Wansley  and  Scherer  Units  No.  1 and No. 2 and the  Scherer  Common
Facilities.  Each Operating  Agreement  gives GPC, as agent,  sole authority and
responsibility  for the  management,  control,  maintenance and operation of the
plant to which it relates. Each Operating Agreement also provides for the use of
power and energy from the plant and the sharing of the costs of the plant by the
participants  in accordance  with their  respective  interests in the plant.  In
performing its  responsibilities  under the Ownership and Operating  Agreements,
GPC is required to comply with prudent utility practices. GPC's liabilities with
respect to its duties under the Ownership and Operating  Agreements  are limited
by the terms thereof.

     Under the Ownership Agreements, Oglethorpe is obligated to pay a percentage
of capital costs of the respective plants, as incurred,  equal to the percentage
interest  which it owns or  leases at each  plant.  GPC has  responsibility  for
budgeting capital  expenditures for Scherer Units No. 1 and 2 subject to certain
limited rights of the participants to disapprove capital budgets proposed by GPC
and to  substitute  alternative  capital  budgets.  GPC has  responsibility  for
budgeting capital expenditures for Plants Hatch and Vogtle, subject to the right
of any co-owner to disapprove large discretionary capital improvements.

In 1993,  the co-owners of Plants Hatch and Vogtle  entered into the Amended and
Restated Nuclear  Managing Board Agreement,  which provides for a managing board
to coordinate the implementation and administration of the Plant Hatch and Plant
Vogtle Ownership and Operating Agreements, provides for increased rights for the
co-owners  regarding  certain  decisions and allows GPC to contract with a third
party for the  operation of the nuclear  units.  In March 1997,  GPC  designated

                                       26


SONOPCO as the  operator  of Plants  Hatch and  Vogtle,  pursuant to the Nuclear
Operating Agreement between GPC and SONOPCO,  which the co-owners had previously
approved.  In connection with the amendments to the Plant Scherer  Ownership and
Operating  Agreements,  the  co-owners of Plant  Scherer  entered into the Plant
Scherer  Managing  Board  Agreement  which  provides  for a  managing  board  to
coordinate the  implementation and administration of the Plant Scherer Ownership
and Operating  Agreements  and provides for  increased  rights for the co-owners
regarding certain decisions, but does not alter GPC's role as agent with respect
to Plant Scherer.

     The  Operating   Agreements  provide  that  Oglethorpe  is  entitled  to  a
percentage of the net capacity and net energy output of each plant or unit equal
to its percentage undivided interest owned or leased in such plant or unit. GPC,
as  agent,  schedules  and  dispatches  Plants  Hatch  and  Vogtle.   Oglethorpe
separately  dispatches its ownership  share of Scherer Units No. 1 and No. 2 and
of Plant Wansley. (See "Fuel Supply" herein.)

     For  Plants  Hatch  and  Vogtle,  each  participant  is  responsible  for a
percentage of Operating Costs (as defined in the Operating  Agreements) and fuel
costs of each plant or unit equal to the  percentage of its  undivided  interest
which is owned or leased in such plant or unit.  For Scherer Units No. 1 and No.
2 and for Plant Wansley,  each party is  responsible  for its fuel costs and for
variable  Operating  Costs  in  proportion  to the  net  energy  output  for its
ownership interest, and is responsible for a percentage of fixed Operating Costs
equal to the  percentage of its undivided  interest  which is owned or leased in
such plant or unit. GPC is required to furnish budgets for Operating Costs, fuel
plans and scheduled  maintenance  plans.  In the case of Scherer Units No. 1 and
No. 2, the participants  have limited rights to disapprove such budgets proposed
by GPC and to  substitute  alternative  budgets.  The Ownership  Agreements  and
Operating Agreements provide that, should a participant fail to make any payment
when due, among other things, such nonpaying  participant's  rights to output of
capacity and energy would be suspended.

     The Operating  Agreement for Plant Hatch will remain in effect with respect
to Hatch Units No. 1 and No. 2 until 2009 and 2012, respectively. Oglethorpe has
entered  into an  agreement  with GPC,  subject to RUS  approval,  to extend the
Operating  Agreement  for so long as an NRC  operating  license  exists for each
unit. (See "FACTORS AFFECTING THE ELECTRIC UTILITY  INDUSTRY--Environmental  and
Other Regulation--Nuclear Regulation.") The Operating Agreement for Plant Vogtle
will remain in effect with respect to each unit at Plant Vogtle until 2018.  The
Operating  Agreement  for Plant  Wansley  will remain in effect with  respect to
Wansley Units No. 1 and No. 2 until 2016 and 2018,  respectively.  The Operating
Agreement  for Scherer  Units No. 1 and No. 2 will remain in effect with respect
to  Scherer  Units  No. 1 and No.  2 until  2022 and  2024,  respectively.  Upon
termination of each Operating  Agreement,  following any extension  agreed to by
the parties, GPC will retain such powers as are necessary in connection with the
disposition  of the  property  of the  applicable  plant,  and  the  rights  and
obligations  of the parties shall  continue with respect to actions and expenses
taken or incurred in connection with such disposition.

     Rocky Mountain

     Oglethorpe owns a 74.61% undivided  interest in Rocky Mountain and GPC owns
the remaining 25.39% undivided interest.

     The Rocky Mountain  Pumped Storage  Hydroelectric  Ownership  Participation
Agreement,  by and between  Oglethorpe  and GPC (the "Rocky  Mountain  Ownership
Agreement")  appoints Oglethorpe as agent with sole authority and responsibility
for,  among  other  things,  the  planning,   licensing,  design,  construction,
operation, maintenance and disposal of Rocky Mountain. The Rocky Mountain Pumped
Storage Hydroelectric Project Operating Agreement (the "Rocky Mountain Operating
Agreement") gives Oglethorpe,  as agent, sole authority and  responsibility  for
the management, control, maintenance and operation of Rocky Mountain.

                                       27


     In general,  each  co-owner is  responsible  for payment of its  respective
ownership  share of all Operating  Costs and Pumping Energy Costs (as defined in
the Rocky Mountain Operating  Agreement) as well as costs incurred as the result
of any separate  schedule or  independent  dispatch.  A co-owner's  share of net
available  capacity  and net  energy  is the  same as its  respective  ownership
interest under the Rocky Mountain Ownership  Agreement.  Oglethorpe and GPC have
each elected to schedule separately their respective  ownership  interests.  The
Rocky  Mountain  Operating  Agreement will terminate in 2035. The Rocky Mountain
Ownership and Operating  Agreements provide that, should a co-owner fail to make
any payment when due, among other things,  such non-paying  co-owner's rights to
output of capacity and energy or to exercise any other right of a co-owner would
be suspended  until all amounts due, with interest,  had been paid. The capacity
and energy of a non-paying  Co-Owner  may be  purchased by a paying  co-owner or
sold to a third party.

     In late 1996 and early 1997,  Oglethorpe  completed lease  transactions for
its  74.61%  undivided   ownership   interest  in  Rocky  Mountain.   The  lease
transactions are  characterized as a sale and leaseback for income tax purposes,
but not for financial reporting purposes. Under the terms of these transactions,
Oglethorpe leased the facility to three  institutional  investors for the useful
life of the facility,  who in turn leased it back to Oglethorpe for a term of 30
years. Oglethorpe will continue to control and operate Rocky Mountain during the
leaseback term.  Oglethorpe  intends to exercise its fixed price purchase option
at the end of the leaseback period so as to retain all other rights of ownership
with respect to the plant if it is advantageous  for Oglethorpe to exercise such
option.  For more information  about the structure of these lease  transactions,
see "MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Financial    Condition--Capital    Requirements--Off-Balance   Sheet
Arrangements" in Item 7.

     Doyle

     Oglethorpe has an agreement with Doyle I, LLC, a limited  liability company
owned by one of  Oglethorpe's  Members,  Walton EMC, to purchase the output of a
gas-fired  combustion turbine generating facility with a nominal contract rating
of 325 MW over a 15-year term. Delivery commenced May 15, 2000.

     During the term of the  agreement,  Oglethorpe has the right and obligation
to purchase  all of the  capacity and energy from the  facility.  Oglethorpe  is
obligated to pay to Doyle I each month a capacity  charge based on a performance
rating  and an energy  charge  equal to all  costs of  operating  the  facility.
Oglethorpe is also obligated to pay the actual  operation and maintenance  costs
and the costs of capital  improvements.  Oglethorpe is responsible for supplying
all natural gas necessary to operate the facility.  Oglethorpe  has the right to
dispatch the facility.

     Doyle I operates the facility.  Doyle I must make the units  available from
May 15 to September 15 each year.  Subject to air permit and other  limitations,
Oglethorpe  may  dispatch  the  facility  at other  times to the extent that the
facility is available.

     Oglethorpe has an option to purchase the facility at the end of the term of
the agreement at a fixed price.  This agreement is treated as a capital lease of
the facility by Oglethorpe  for  financial  reporting  purposes.  (See Note 4 of
Notes to Financial Statements in Item 8.)

                                       28


ITEM 3. LEGAL PROCEEDINGS

     Oglethorpe is a party to various actions and proceedings  incidental to its
normal business.  Liability in the event of final adverse  determinations in any
of  these  matters  is  either  covered  by  insurance  or,  in the  opinion  of
Oglethorpe's  management,  after  consultation  with counsel,  should not in the
aggregate have a material adverse effect on the financial position or results of
operations of Oglethorpe.


ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     Not applicable.

                                       29


                                    PART II


ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITYAND RELATED STOCKHOLDER MATTERS

               Not Applicable.


ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected  historical  financial data of Oglethorpe.
The financial data presented as of the end of and for each year in the five-year
period ended  December 31,  2002,  have been derived from the audited  financial
statements  of  Oglethorpe.  These data should be read in  conjunction  with the
financial  statements of Oglethorpe and the notes thereto included in Item 8 and
"MANAGEMENT'S  DISCUSSION  AND  ANALYSIS OF FINANCIAL  CONDITION  AND RESULTS OF
OPERATIONS" in Item 7.




                                                                            (dollars in thousands)

                                                 2002               2001              2000               1999             1998
================================================================================================================================
Operating revenues:
                                                                                                      
     Sales to Members                       $ 1,127,519        $ 1,080,478       $ 1,146,064        $ 1,122,336      $ 1,095,904
     Sales to non-Members                        35,802             58,811            53,333             53,896           48,263
- --------------------------------------------------------------------------------------------------------------------------------
Total operating revenues                      1,163,321          1,139,289         1,199,397          1,176,232        1,144,167
- --------------------------------------------------------------------------------------------------------------------------------
Operating expenses:
     Fuel                                       225,008            221,449           230,729            196,182          191,399
     Production                                 232,312            218,480           220,221            215,517          198,378
     Purchased power                            357,491            414,382           377,805            401,719          387,662
     Depreciation and amortization              140,058            133,731           143,703            130,883          124,074
     Income taxes                                   -              (63,485)              -                  -                -
- --------------------------------------------------------------------------------------------------------------------------------
Total operating expenses                        954,869            924,557           972,458            944,301          901,513
- --------------------------------------------------------------------------------------------------------------------------------
Operating margin                                208,452            214,732           226,939            231,931          242,654
Other income, net                                35,911             51,345            62,431             50,545           42,293
Net interest charges                           (226,823)          (247,660)         (269,392)          (262,538)        (263,867)
- --------------------------------------------------------------------------------------------------------------------------------
Net margin                                  $    17,540        $    18,417       $    19,978        $    19,938      $    21,080
================================================================================================================================
Electric plant, net:
     In service                             $ 3,123,630        $ 3,224,634       $ 3,339,364        $ 3,312,669      $ 3,429,704
     Construction work in progress               69,282             38,564            24,841             18,299           20,948
- --------------------------------------------------------------------------------------------------------------------------------
Total electric plant                        $ 3,192,912        $ 3,263,198       $ 3,364,205        $ 3,330,968      $ 3,450,652
================================================================================================================================
Total assets                                $ 4,518,551        $ 4,712,831       $ 4,681,194        $ 4,551,711      $ 4,494,228
================================================================================================================================
Capitalization:
     Long-term debt                         $ 2,835,997        $ 2,929,316       $ 3,019,019        $ 3,103,590      $ 3,177,883
     Obligation under capital leases            358,676            373,837           387,756            275,224          282,299
     Other obligations                           72,698             68,032            63,665             59,579           55,755
     Patronage capital and membership fees      371,818            367,668           392,682            370,025          352,701
- --------------------------------------------------------------------------------------------------------------------------------
Total capitalization                        $ 3,639,189        $ 3,738,853       $ 3,863,122        $ 3,808,418      $ 3,868,638
================================================================================================================================
Property additions                          $   100,145        $    69,824      $     70,738        $    41,829      $    43,904
================================================================================================================================
Energy supply (megawatt-hours):
     Generated                               18,969,282         19,157,910        19,802,501         18,295,514       17,781,896
     Purchased                               10,845,701         11,448,219        11,234,860          7,971,583        8,544,714
- --------------------------------------------------------------------------------------------------------------------------------
     Available for sale                      29,814,983         30,606,129        31,037,361         26,267,097       26,326,610
================================================================================================================================
Member revenue per kWh sold                     4.04(cent)        4.01(cent)        4.21(cent)         4.53(cent)       4.70(cent)
================================================================================================================================


                                       30


ITEM 7. MANAGEMENT'S  DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS


Summary of Critical Accounting Policies and Cooperative Operations

     Basis of Accounting

     Oglethorpe   Power   Corporation  (An  Electric   Membership   Corporation)
(Oglethorpe) follows generally accepted accounting  principles and the practices
prescribed in the Uniform  System of Accounts of the Federal  Energy  Regulatory
Commission (FERC) as modified and adopted by the Rural Utilities Service (RUS).

     The  preparation  of financial  statements  in  conformity  with  generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions  that  affect the  reported  amounts of assets and  liabilities  and
disclosure of contingent assets and liabilities as of December 31, 2002 and 2001
and the  reported  amounts of revenues  and expenses for each of the three years
ending December 31, 2002. Actual results could differ from those estimates.

     Regulatory Assets and Liabilities.  Oglethorpe is subject to the provisions
of Statement of Financial  Accounting  Standards (SFAS) No. 71,  "Accounting for
the Effects of Certain Types of Regulation."  SFAS No. 71 permits  Oglethorpe to
record  regulatory  assets and  regulatory  liabilities  to reflect  future cost
recovery or refunds that  Oglethorpe has a right to pass through to the Members.
At December 31, 2002,  Oglethorpe's  regulatory  assets and liabilities  totaled
$289  million and $76  million,  respectively.  See Note 1 of Notes to Financial
Statements.  In the  event  that  competitive  or other  factors  result in cost
recovery  practices under which Oglethorpe can no longer apply the provisions of
SFAS No. 71, Oglethorpe would be required to eliminate all regulatory assets and
liabilities  that could not otherwise be recognized as assets and liabilities by
businesses in general.  In addition,  Oglethorpe  would be required to determine
any impairment to other assets, including plant, and write-down those assets, if
impaired, to their fair value.

     Nuclear   Decommissioning.   Oglethorpe   owns  interests  in  two  nuclear
facilities,  Plant  Vogtle  and Plant  Hatch.  Oglethorpe  will  incur  costs to
decommission  these  plants when their  licenses  expire.  Oglethorpe  currently
expects that Plant Vogtle and Plant Hatch will begin the decommissioning process
in 2027 and 2034, respectively. Based on a 2000 site study, Oglethorpe estimates
its portion of the costs of  decommissioning to be $308 million for Plant Vogtle
and $314 million for Plant Hatch. The  decommissioning  cost estimates are based
on prompt  dismantlement  and  removal  of the plant  from  service.  The actual
decommissioning  costs may vary from these  estimates  because of changes in the
assumed date of decommissioning,  changes in regulatory requirements, changes in
technology, and changes in costs of labor, materials and equipment.

     In compliance with NRC regulations,  Oglethorpe maintains an external trust
fund to  provide  for a  portion  of the  cost of  decommissioning  its  nuclear
facilities. The NRC regulations require funding levels based on average expected
cost  to  decommission  only  the  radioactive  portions  of a  typical  nuclear
facility.  Based on the most recent Nuclear Regulatory  Commission (NRC) funding
requirement, the balance in the decommissioning reserve at December 31, 2002 was
approximately  $11.5  million  less  than the NRC  minimum  funding  requirement
primarily  due to unrealized  losses in the market value of certain  investments
held in Oglethorpe's external  decommissioning trust fund. These projections are
based on an assumed cost escalation rate of 4.72% and an assumed return on trust
assets of 8%.  Oglethorpe  is  currently  examining  the  allocation  of funding
between  nuclear  units,  a  possible  license  extension  at Plant  Vogtle  and
investment earnings assumptions to determine whether additional contributions to
the  external  fund may be  necessary  in the  future.  Oglethorpe's  management
believes that any increase in cost estimates of decommissioning can be recovered
in future rates.

     Accounting for Asset Retirement Obligations. In June of 2001, the Financial
Accounting  Standards  Board (FASB) issued SFAS No. 143,  "Accounting  for Asset
Retirement   Obligations."  The  statement  provides  accounting  and  reporting
standards  for  recognizing  obligations  related to costs  associated  with the
retirement of long-lived assets.  SFAS No. 143 requires  obligations  associated
with the retirement of long-lived assets to be recognized at their fair value in

                                       31


the period in which they are incurred if a reasonable estimate of fair value can
be made.  The fair value of the asset  retirement  costs must be  capitalized as
part of the carrying amount of the long-lived asset and  subsequently  allocated
to expense using a systematic and rational  method over the asset's useful life.
Any subsequent changes to the fair value of the liability due to passage of time
or changes in the amount or timing of estimated cash flows must be recognized as
an accretion expense.

     In January  2003,  Oglethorpe  adopted  SFAS No. 143. The fair value of the
legal obligation recognized under SFAS No. 143 primarily relates to Oglethorpe's
nuclear facilities.  In addition,  Oglethorpe recognized retirement  obligations
for ash handling  facilities at the coal-fired  plants and solid waste landfills
located at certain  generating  facilities.  The  cumulative  effect of adoption
resulted  in   Oglethorpe   recording  a  regulatory   asset  of   approximately
$23,700,000,   capitalized   asset   retirement   costs,   net  of   accumulated
amortization,  of  approximately  $45,100,000  and  increased  asset  retirement
obligations of  approximately  $68,800,000.  At December 31, 2002,  Oglethorpe's
recognized  liability for nuclear  decommissioning was $166,299,000.  Oglethorpe
continues to  recognize  the  accumulated  removal  costs for other  obligations
(regulatory   liabilities)   as  part  of  the  accumulated   depreciation   and
amortization reserve in accordance with RUS prescribed  regulatory treatment for
these costs. At December 31, 2002, that amount was $38,200,000.

     Under SFAS No. 71, Oglethorpe may record an offsetting  regulatory asset or
liability to reflect the  difference  in timing of  recognition  of the costs of
decommissioning for financial statement purposes and for ratemaking purposes for
both  the   cumulative   effect  of  adoption  and  for  future  periods  timing
differences.  While RUS has not issued regulatory  guidance for adoption of SFAS
No.  143,  Oglethorpe's  management  expects to receive  permission  from RUS to
implement the provisions SFAS No. 71 with respect to timing differences  arising
from cost recognition under SFAS No. 143 and for ratemaking purposes. Oglethorpe
estimates that the annual difference will be approximately $5,000,000.

     Accounting for Derivatives.  As of January 1, 2001, Oglethorpe adopted SFAS
No. 133,  "Accounting for Derivative  Instruments and Hedging  Activities."  The
standard  establishes  accounting  and  reporting  requirements  for  derivative
instruments,   including  certain  derivative   instruments  embedded  in  other
contracts, and hedging activities. It requires the recognition of all derivative
instruments  as  assets  or  liabilities  in  Oglethorpe's   balance  sheet  and
measurement  of those  instruments at fair value.  The  accounting  treatment of
changes in fair value is dependent  upon whether or not a derivative  instrument
is  designated  as a hedge and if so, the type of hedge.  Oglethorpe's  interest
rate swap arrangements in place at December 31, 2002 are designated as cash flow
hedges.  Adoption  of SFAS No. 133 on January 1,  2001,  resulted  in  recording
$33,515,000 of decline in fair value to accumulated other  comprehensive  income
and a comparable  increase in other  liabilities  related to the  interest  rate
swaps.  The fair value of the interest  rate swap  arrangements  at December 31,
2002 was an  unrealized  loss of  $58,443,000.  See Note 2 of Notes to Financial
Statements.

     Oglethorpe  has entered  into  natural  gas  financial  contracts  that are
classified  as cash flow  hedges.  Oglethorpe  utilizes  natural  gas  financial
contracts  in managing  its  exposure  to  fluctuations  in the market  price of
natural gas. At December 31, 2002,  Oglethorpe  recorded an  unrealized  gain in
other comprehensive  margin of $8,507,000 and a corresponding  increase in other
current assets related to these natural gas financial contracts.

     The application of new rules for SFAS No. 133 is still evolving and further
guidance from the Financial  Accounting  Standards Board is expected which could
further impact Oglethorpe's financial statements.  In addition,  Oglethorpe will
continue to evaluate its use of derivatives,  including their  effectiveness for
hedging, and to apply appropriate procedures and methods for valuing them.

     Margins and Patronage Capital

     Oglethorpe  provides  wholesale  electric service to its 39 retail electric
distribution   cooperative   members   (Members).   Oglethorpe   operates  on  a
not-for-profit  basis  and,   accordingly,   seeks  only  to  generate  revenues
sufficient to recover its cost of service and to generate margins  sufficient to
establish reasonable reserves and meet certain financial coverage  requirements.
Revenues in excess of current  period  costs in any year are  designated  as net

                                       32


margin in  Oglethorpe's  statements  of  revenues  and  expenses  and  patronage
capital.  Retained net margins are designated on Oglethorpe's  balance sheets as
patronage capital, which is allocated to each of the Members on the basis of its
electricity  purchases from Oglethorpe.  Since its formation in 1974, Oglethorpe
has  generated a positive  net margin in each year and had a balance,  excluding
accumulated other comprehensive loss, of $428 million in patronage capital as of
December 31, 2002.  Oglethorpe's  equity ratio,  calculated as patronage capital
and membership fees (excluding  accumulated other comprehensive loss) divided by
total  capitalization,  increased  from 10.8% at  December  31, 2001 to 11.7% at
December 31, 2002.

     Patronage  capital  constitutes  the principal  equity of  Oglethorpe.  Any
distributions of patronage capital are subject to the discretion of the Board of
Directors.  However,  under  the  Indenture,  dated as of March  1,  1997,  from
Oglethorpe to SunTrust  Bank,  as trustee  (Mortgage  Indenture),  Oglethorpe is
prohibited from making any distribution of patronage  capital to the Members if,
at the time of or  after  giving  effect  to the  distribution,  (i) an event of
default exists under the Mortgage Indenture,  (ii) Oglethorpe's equity as of the
end of the immediately preceding fiscal quarter is less than 20% of Oglethorpe's
total  capitalization,  or (iii) the aggregate amount expended for distributions
on or  after  the  date  on  which  Oglethorpe's  equity  first  reaches  20% of
Oglethorpe's  total  capitalization  exceeds 35% of  Oglethorpe's  aggregate net
margins earned after such date. This last restriction,  however,  will not apply
if, after giving effect to such distribution,  Oglethorpe's equity as of the end
of the immediately preceding fiscal quarter is not less than 30% of Oglethorpe's
total capitalization.

     Rates and Regulation

     Pursuant to the Amended  and  Restated  Wholesale  Power  Contracts,  dated
August 1, 1996 (Wholesale Power Contracts)  entered into between  Oglethorpe and
each of the Members,  Oglethorpe is required to design capacity and energy rates
that  generate  sufficient  revenues  to recover  all costs,  to  establish  and
maintain  reasonable  margins and to meet its financial  coverage  requirements.
Oglethorpe  reviews its capacity rates at least annually to ensure that it meets
its net margin goals.

     The rate  schedule  under the  Wholesale  Power  Contracts  implements on a
long-term basis the assignment to each Member of responsibility for fixed costs.
The monthly  charges for  capacity and other  non-energy  charges are based on a
rate formula  using the  Oglethorpe  budget.  The Board of Directors  may adjust
these charges during the year through an adjustment to the annual budget. Energy
charges  are  based on actual  energy  costs,  including  fuel  costs,  variable
operations and maintenance costs, and purchased energy costs.

     Under the  Mortgage  Indenture,  Oglethorpe  is  required,  subject  to any
necessary  regulatory  approval,   to  establish  and  collect  rates  that  are
reasonably  expected,  together with other  revenues of  Oglethorpe,  to yield a
Margins for  Interest  Ratio for each  fiscal  year equal to at least 1.10.  The
Margins for Interest  Ratio is  determined  by dividing  Margins for Interest by
Interest  Charges.  Margins for Interest equal the sum of (i)  Oglethorpe's  net
margins (after certain defined adjustments), (ii) Interest Charges and (iii) any
amount  included in net margins for accruals for federal or state income  taxes.
The  definition  of Margins  for  Interest  takes into  account  any item of net
margin,  loss,  gain or expenditure of any affiliate or subsidiary of Oglethorpe
only if Oglethorpe has received such net margins or gains as a dividend or other
distribution  from such  affiliate or  subsidiary  or if  Oglethorpe  has made a
payment with respect to such losses or expenditures.

     The  rate  schedule  also  includes  a prior  period  adjustment  mechanism
designed  to ensure  that  Oglethorpe  achieves  the  minimum  1.10  Margins for
Interest Ratio.  Amounts, if any, by which Oglethorpe fails to achieve a minimum
1.10  Margins  for  Interest  Ratio  would be accrued as of  December  31 of the
applicable  year and collected  from the Members during the period April through
December of the following year. The rate schedule formula is intended to provide
for the  collection  of revenues  which,  together  with revenues from all other
sources,  are equal to all costs  and  expenses  recorded  by  Oglethorpe,  plus
amounts  necessary  to achieve at least the minimum  1.10  Margins for  Interest
Ratio.

     For 2002, 2001 and 2000,  Oglethorpe  achieved a Margins for Interest Ratio
of 1.10.

                                       33


     Under the  Mortgage  Indenture  and related  loan  contract  with the Rural
Utilities Service (RUS), adjustments to Oglethorpe's rates to reflect changes in
Oglethorpe's  budgets are generally not subject to RUS approval.  Changes to the
rate schedule under the Wholesale Power  Contracts are generally  subject to RUS
approval.  Oglethorpe's  rates  are not  subject  to the  approval  of any other
federal or state  agency or  authority,  including  the Georgia  Public  Service
Commission (the GPSC).


Results of Operations

     Power Marketer Arrangements

     Oglethorpe is utilizing  power marketer  arrangements to reduce the cost of
power to the Members. Oglethorpe has a power marketer agreement with LG&E Energy
Marketing Inc. (LEM), for  approximately  50% of the load  requirements of 37 of
the Members and an  additional  power  marketer  agreement  with Morgan  Stanley
Capital Group Inc. (Morgan Stanley),  effective May 1, 1997, with respect to 50%
of the 39 Members' then forecasted load requirements. The LEM agreement is based
on the actual  requirements  of the  participating  Members  during the contract
term, whereas the Morgan Stanley agreement represents a fixed supply obligation.
Generally,  these arrangements  benefit the Members by limiting the risk of unit
availability  and by  providing  future  power needs at a fixed  price.  Most of
Oglethorpe's generating facilities and power purchase arrangements are available
for use by LEM and Morgan  Stanley.  Oglethorpe  continues to be responsible for
all of the costs of its  system  resources  but  receives  revenue  from LEM and
Morgan  Stanley for the use of the  resources.  After  taking  into  account the
Oglethorpe  resources  made  available  toLEM and Morgan  Stanley for their use,
Oglethorpe  estimates that about 30% of its power supply capability in 2003 will
be provided by these contracts.

     In February 2001, LEM and its  affiliates  initiated a binding  arbitration
process  to  resolve   certain  issues  relating  to  the   interpretation   and
administration of the LEM agreement and a similar agreement with Oglethorpe that
expired by its terms in 1999.  In April 2002,  Oglethorpe  and LEM settled  this
arbitration.  As part  of the  settlement,  Oglethorpe  paid  LEM  approximately
$48,500,000.  Oglethorpe  recorded  a  reserve  of  $36,000,000  in 2001  and an
additional expense of $12,500,000 in 2002.

     Operating Revenues

     Sales to Members.  Oglethorpe's operating revenues generally fluctuate from
period to period based on factors  including weather and other seasonal factors,
growth  in  the  service   territories  of   Oglethorpe's   39  retail  electric
distribution cooperative members (the Members), operating costs, availability of
electric generation resources, Oglethorpe's decisions of whether to dispatch its
owned  or  purchased  resources  or  Member-owned  resources  over  which it has
dispatch  rights and by Members'  decisions  of whether to purchase a portion of
their growth requirements from Oglethorpe or from other suppliers and whether to
schedule separately their resources.  A large number of Members have now elected
to  schedule  separately  their  percentage  capacity   responsibilities  (their
pro-rata  shares) in  Oglethorpe  resources to serve their retail and  wholesale
customers, although approximately half of the elections were not effective until
June 1, 2002.

     Total revenues from sales to Members increased by 4.4% for 2002 compared to
2001 and decreased by 5.7% for 2001 compared to 2000.  The  components of Member
revenues were as follows:

                           2002      2001       2000
                           ----      ----       ----
                             (dollars in thousands)
Capacity revenues       $ 592,621   $ 537,392 $ 624,537
Energy revenues           534,898     543,086   521,527
                       ----------  ---------- ---------
 Total                 $1,127,519  $1,080,478 $1,146,064
                       ==========  ========== ==========


     Capacity revenues from Members increased 10.3% in 2002 compared to 2001 and
decreased  by 14.0%  from 2000 to 2001.  Capacity  revenues  in 2001 were  lower
primarily as a result of a credit to income tax expense.

     Energy  revenues  from  Members  decreased  by 1.5%  from  2001 to 2002 and
increased by 4.1% from 2000 to 2001.  Member energy revenues were higher in 2001
primarily  due to  higher  purchased  power  costs  related  to an  accrual  for
estimated damages payable to LEM resulting from the arbitration ruling.

                                       34


     The following table summarizes the amounts of kWh sold to Members and total
revenues per kWh during each of the past three years:

              Kilowatt-hours      Cents per
              (in thousands)     Kilowatt-hour

 2002           27,924,856            4.04
 2001           26,950,149            4.01
 2000           27,232,641            4.21

     In 2002 kWh sales to Members  increased 3.6% as a result of higher sales to
both scheduling Members and Members who participate in Oglethorpe's capacity and
energy pool. In 2001 mild weather,  combined with an increase in energy supplied
by Member-owned resources, mitigated by continued growth in the Members' service
territories,  resulted in a 1.0%  decrease in kWh sales to Members.  The average
revenue per kWh from sales to Members  increased  0.7% for 2002 compared to 2001
and decreased 4.8% for 2001 compared to 2000.

     The  energy  portion  of Member  revenues  per kWh  decreased  4.9% in 2002
compared to 2001 and increased 5.2% in 2001 compared to 2000.  Oglethorpe passes
through  actual  energy  costs to the Members  such that energy  revenues  equal
energy costs.  The decrease in 2002 of energy revenues per kWh was primarily due
to the pass-through of lower purchased power costs. The increase in 2001 for the
cost of energy supplied to the Members resulted  primarily from higher purchased
power costs. See "Operating Expenses" below.

     Sales to non-Members.  The following table summarizes  non-Member  revenues
for the past three years:

                        2002     2001     2000
                        ----     ----     ----
                     (dollars in thousands)
     Sales to power    $34,522  $55,057  $46,952
     companies
     Sales to LEM and    1,280    3,754    6,381
                       -------  -------  -------
     Morgan Stanley
      Total            $35,802  $58,811  $53,333
                       =======  =======  =======


     Sales to power  companies  represent  sales made  directly  by  Oglethorpe.
Oglethorpe  sells for its own account any energy  available  from the portion of
its  resources  dedicated  to Morgan  Stanley  that is not  scheduled  by Morgan
Stanley  pursuant to its power  marketer  arrangements.  Scheduling  Members are
entitled  to  schedule   energy   available  from  their   percentage   capacity
responsibilities  for both retail sales and for resale in the wholesale  market.
More of the Members were scheduling  Members in 2002 than in 2001,  resulting in
less energy being available to Oglethorpe to sell directly to non-Members.

     Sales to power marketers  represent the net energy transmitted on behalf of
LEM and Morgan  Stanley  off-system on an hourly basis from  Oglethorpe's  total
resources  under  the  LEM  and  Morgan  Stanley  power  marketer  arrangements.
Oglethorpe  sold this  energy to LEM at  Oglethorpe's  cost,  subject to certain
limitations, and to Morgan Stanley at a contractually fixed price. The volume of
sales to power marketers depends primarily on the power marketers' decisions for
servicing their load requirements.

     Operating Expenses

     Oglethorpe's operating expenses increased 3.3% in 2002 compared to 2001 and
decreased  4.9% in 2001 compared to 2000.  The increased  operating  expenses in
2002 resulted  primarily from higher  production  expenses and  depreciation and
amortization  costs offset somewhat by lower purchased power costs. The decrease
in  operating  expenses  in 2001  resulted  primarily  from  lower  fuel  costs,
depreciation  and  amortization  costs and from a credit to income  tax  expense
offset somewhat by higher purchased power costs.

     Production  expenses  increased  6.3% in 2002 compared to 2001.  The higher
production  expenses  resulted  primarily from higher  operation and maintenance
(O&M) costs.  The higher O&M costs  resulted from (1) a forced outage and diesel
generator repairs at Plant Hatch, (2) increased  security costs at Plants Vogtle
and Hatch  related to the events of  September  11,  2001,  (3)  one-time  costs
incurred   due  to  the   Southern   Nuclear   Operating   Company   engineering
reorganization efforts and (4) forced outages at Plants Scherer and Wansley.

     Total fuel costs  decreased  4.0% in 2001  compared to 2000  primarily as a
result of a 3.1% decrease in generation.  Purchased  power costs decreased 13.7%
in 2002 compared to 2001 and increased 9.7% in 2001 compared to 2000 as follows:

                                       35


                          2002        2001      2000
                          ----        ----      ----
                              (dollars in thousands)
Capacity costs            $74,232    $88,463     $93,771
Energy costs              283,259    325,919     284,034
                         --------   --------    --------
 Total                   $357,491   $414,382    $377,805
                         ========   ========    ========


     The decrease in purchased  power  capacity  costs for 2002 compared to 2001
resulted  primarily from the  termination of various power purchase  agreements.
Purchased  power capacity costs  decreased in 2001 as compared to 2000 primarily
due to the elimination on September 1, 2001 of 125 megawatts of capacity under a
power purchase agreement between Oglethorpe and GPC.

     Purchased  power energy costs  decreased 13.1% in 2002 compared to 2001 and
increased  14.7% in 2001 compared to 2000.  The average cost of purchased  power
energy per kWh decreased  8.3% in 2002  compared to 2001 and increased  12.6% in
2001 compared to 2000. The higher average costs in 2001 were primarily due to an
accrual for estimated  amounts  payable to LEM resulting  from  settlement of an
arbitration  proceeding  regarding  the LEM  power  marketing  arrangement.  The
volumes of purchased power decreased 5.3% in 2002 compared to 2001 and increased
1.9% in 2001 compared to 2000.

     Purchased  power  expenses for the years 2000 through 2002 include the cost
of  capacity  and  energy  purchases  under  various  long-term  power  purchase
agreements.  These long-term agreements have, in some cases, take-or-pay minimum
energy requirements.  For 2000 through 2002, Oglethorpe utilized its energy from
these  power  purchase  agreements  in excess of the  take-or-pay  requirements.
Oglethorpe's  capacity and energy  expenses under these  agreements  amounted to
approximately  $101  million in 2002,  $130  million in 2001 and $150 million in
2000. For a discussion of the power purchase agreements,  see Note 9 of Notes to
Financial Statements.

     Depreciation  and  amortization  increased  4.7% in 2002  compared  to 2001
primarily due to $9.2 million in  accelerated  depreciation  to write down Plant
Tallassee's  net book  value  and for  estimated  costs  associated  with  early
retirement.  The higher  depreciation and amortization in 2000 was primarily due
to $10.3 million of Board approved accelerated amortization of project costs for
the Vogtle  radioactive waste facility.  The amortization of these project costs
commenced  January 1, 1999.  For further  discussion  of the Vogtle  radioactive
waste facility see Note 1 of Notes to Financial Statements.

     The  credit  to  income  tax  expense  in 2001  resulted  from a change  in
Oglethorpe's  Bylaws to  determine  its  allocation  of patronage on a tax basis
method  rather  than the  historical  book  basis  method.  Due to this  change,
Oglethorpe anticipates that all future patronage source income will be offset by
the patronage exclusion.  Therefore,  Oglethorpe has reversed $63,485,000 of net
deferred tax  liabilities  and has  recognized  an income tax credit in the same
amount. See Note 3 of Notes to Financial Statements.

     Other Income (Expense)

     Investment  income  decreased  25.9% in 2002 compared to 2001 and decreased
27.8% in 2001  compared  to 2000.  The  decrease in 2002 was partly due to lower
cash and temporary  cash  investments  balances and partly due to lower interest
earnings on these  investments.  The decrease in 2001 was primarily due to lower
earnings from the decommissioning  fund.  Amortization of net benefit of sale of
income tax  benefits  decreased  $6 million in 2002  compared to 2001 due to the
amortization  of the safe harbor lease ending in March 2002. See Note 1 of Notes
to Financial Statements.

     Interest Charges

     Interest  on  long-term  debt and  capital  leases  decreased  6.9% in 2002
compared  to 2001  primarily  as a result of cost  savings  from lower  variable
interest rates on long-term debt. Other interest expense decreased 50.6% in 2001
compared to 2000.  The lower other  interest  expense in 2001 was primarily as a
result of a decrease in interest expense for decommissioning  (which is recorded
as an offset to interest earnings on the decommissioning fund).  Amortization of
debt discount and expense decreased 26.5% in 2002 compared to 2001 primarily due
to  accelerated  amortization  of $7 million and $24 million in premiums paid to
the Federal  Financing  Bank for  refinancing  $89  million and $424  million of
mortgage notes payable in 1999 and 1998,  respectively.  Such amortization ended
in the third and fourth quarters of 2001, respectively.

                                       36


     Net Margin

     Oglethorpe's  net margin for 2002,  2001 and 2000 was $17.5 million,  $18.4
million and $20.0  million,  respectively.  Oglethorpe's  margin  requirement is
based on a ratio applied to interest charges.  For 2002 compared to 2001 and for
2001 compared to 2000, the reduction in interest  charges  reduced  Oglethorpe's
margin requirement.


Financial Condition

     General

     The principal changes in Oglethorpe's  financial condition in 2002 were due
to  property  additions,  an increase in  patronage  capital,  a decrease in the
amount of commercial paper outstanding and a decrease in cash and temporary cash
investments.

     Property additions,  including nuclear fuel purchases, totaled $100 million
and were financed with funds from operations.

     Oglethorpe  achieved a net margin of $17.5 million in 2002, which increased
equity  (patronage  capital)  by a like  amount  for  total  patronage  capital,
excluding  accumulated other comprehensive loss, of $428 million at December 31,
2002.

     The amount of commercial  paper  outstanding  decreased by $56 million from
December 31, 2001 to December 31, 2002 due to payments  received from Talbot EMC
and Chattahoochee EMC in partial payment of interim loans being provided to them
by Oglethorpe.

     Oglethorpe's  cash and temporary cash  investments  totaled $151 million at
December 31, 2002, a decrease of $124 million from the prior  year-end  balance.
The decrease was primarily attributable to three events,  including 1) a payment
of $48.5 million to LEM in May 2002  relating to  settlement  of an  arbitration
case, 2) a $35 million payment received from  Chattahoochee EMC in December 2001
that was used in January 2002 to retire a like amount of Oglethorpe's commercial
paper, and 3) a transfer of $11.5 million in December 2002 from general funds to
the external nuclear  decommissioning  trust fund.  Included in the $151 million
year-end cash balance was $31 million in proceeds from the issuance of pollution
control bonds  ("PCBs") in December  2002. The PCB proceeds were used to repay a
like amount of PCB principal that matured on January 1, 2003.

     In addition to the $151  million in cash and  temporary  cash  investments,
Oglethorpe  had,  at  December  31,  2002,  $94  million  in  other   short-term
investments  which  represents a portion of its general  funds  invested with an
external  fund  manager.  The  funds  are  invested  primarily  in  high-quality
short-term notes and bonds with an average maturity of two years.

     Capital Requirements

     Capital Expenditures.  As part of its ongoing capital planning,  Oglethorpe
forecasts  expenditures  required for  generating  facilities  and other capital
projects.  The table below details these expenditure  forecasts for 2003 through
2005. Actual construction costs may vary from the estimates listed below because
of factors  such as changes in business  conditions,  fluctuating  rates of load
growth,  environmental  requirements,  design  changes  and rework  required  by
regulatory  bodies,   delays  in  obtaining  necessary   regulatory   approvals,
construction  delays,  cost of  capital,  equipment,  material  and  labor,  and
decisions whether to purchase or construct additional generation capacity.

                             Capital Expenditures(1)
                             (dollars in thousands)

          Existing     Environmental     Nuclear    General
Year    Generation(2)   Compliance        Fuel       Plant        Total
- ----    -------------   ----------        ----       -----        -----
2003      $ 22,000      $ 53,000       $ 48,000     $2,000      $125,000

2004        26,000         2,000         42,000      2,000        72,000

2005        23,000         5,000         48,000      2,000        78,000
- --------------------------------------------------------------------------------
Total     $ 71,000      $ 60,000       $138,000     $6,000      $275,000
================================================================================

- ----------
(1) Excludes allowance for funds used during construction.
(2) Consists of replacements and additions to facilities in-service.

     Oglethorpe  plans  to  acquire   approximately   500  rail  cars  for  coal
transportation  in 2003 at a cost of approximately  $29 million and is currently
analyzing  whether to lease or purchase the rail cars. This planned  expenditure
is not reflected in the table above.

     Oglethorpe's  investment  in  electric  plant,  net  of  depreciation,  was
approximately  $3.2 billion as of December 31, 2002.  Property  additions during
2002 amounted to $100 million and were funded with funds from operations.  These
expenditures   were  primarily  for  additions  and   replacements  to  existing

                                       37


generation   facilities,   purchases  of  nuclear  fuel  and   compliance   with
environmental regulations.

     Financing  for Talbot EMC and  Chattahoochee  EMC.  Thirty of  Oglethorpe's
Members formed Talbot EMC, a Georgia electric membership corporation, in 2001 to
construct and own a six-unit  gas-fired  combustion turbine facility designed to
provide 618 MW of  capacity.  Four of the six  combustion  turbines  were placed
in-service  in June 2002,  with the other two expected to be  in-service  by the
summer of 2003.

     Twenty-eight of Oglethorpe's  Members formed  Chattahoochee  EMC, a Georgia
electric  membership  corporation,  in 2001  to  construct  and own a  gas-fired
combined  cycle  facility  designed to provide 468 MW of capacity.  The combined
cycle facility was placed in-service on February 15, 2003.

     The expected combined cost of constructing the six combustion  turbines and
the combined cycle facility  totals  approximately  $600 million.  Oglethorpe is
providing  loans to Talbot  EMC and  Chattahoochee  EMC to fund,  on an  interim
basis,  approximately fifty percent of the cost of each facility.  Oglethorpe is
funding  these loans under its  commercial  paper  program,  and at December 31,
2002, $298 million of commercial  paper was  outstanding  for this purpose.  The
loans are included in Notes receivable on Oglethorpe's balance sheet.

     Two  bridge  loans  are  funding  the  remaining  portion  of the  cost  of
constructing these facilities.  The National Rural Utilities Cooperative Finance
Corporation  (CFC) is  providing a $141  million  bridge loan to Talbot EMC, and
Pitney Bowes  Credit  Corporation  is  providing a $160  million  bridge loan to
Chattahoochee  EMC.  Oglethorpe's  loans to Talbot EMC and Chattahoochee EMC are
subordinated  to the CFC and Pitney Bowes  loans,  respectively.  Oglethorpe  is
providing a guarantee of the $160 million bridge loan to Chattahoochee EMC.

     In 2000, Oglethorpe submitted loan applications to RUS to provide permanent
financing  for  these  two  facilities.  The loan  applications  were  initially
submitted  on  behalf  of either  Oglethorpe  or  related  entities  that  might
ultimately  own these  facilities.  During the process of  evaluating  the terms
proposed by RUS for providing loans to Talbot EMC and Chattahoochee  EMC, it was
determined that the terms of the financing would be more favorable if Oglethorpe
owned the  facilities  and obtained the RUS  financing.  In September  2002, RUS
issued two RUS-guaranteed  loan commitments  totaling $589 million to Oglethorpe
for these generating facilities. The proceeds from these RUS loans will first be
used to repay  the  bridge  loans and then to  retire  Oglethorpe's  outstanding
commercial paper.

     Concurrently with the funding of these loans, which is expected to occur in
the  second  quarter  of  2003,  Oglethorpe  will  acquire  the  two  generating
facilities of Talbot EMC and Chattahoochee EMC. Oglethorpe's  acquisition of the
facilities  is  conditioned  upon   implementation  of  new  arrangements  among
Oglethorpe  and the Members,  including 1) limited  amendments  to the Wholesale
Power Contracts that do not involve any change in the payment obligations of the
Members and 2) other  agreements  as to the future  provision of services to the
Members  by  Oglethorpe.   The  definitive   agreements   regarding   these  new
arrangements have been approved by the Members. Certain of the arrangements must
be  approved  by RUS,  prior to  funding  of the loans.  RUS has  indicated  its
satisfaction  with these  arrangements but is not expected to deliver its formal
approval until the loans are funded.

     The acquisition of these generating  facilities will increase  Oglethorpe's
assets and  liabilities  by  approximately  $600  million.  The new debt will be
secured  under  Oglethorpe's  Mortgage  Indenture.   Since  Oglethorpe's  margin
requirement  is based on a ratio applied to interest  charges  incurred for debt
secured  under the  Mortgage  Indenture,  the increase in debt will result in an
increase in the margin  requirement of less than $3 million in the first year of
the loan. The increase in assets and debt will decrease  Oglethorpe's  equity to
capitalization  ratio and  equity  to asset  ratio by  approximately  3% and 2%,
respectively.

     Contractual  Obligations.  In  addition  to the  capital  expenditures  and
interim  financing for Talbot EMC and  Chattahoochee  EMC discussed  above,  the
table  below  summarizes,  as of December  31,  2002,  Oglethorpe's  contractual
obligations for the periods indicated.

                                       38



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

  Contractual                                         2008
  Obligations                                         and
As of 12/31/02      2003          2004-2007          beyond          Total
- --------------------------------------------------------------------------------
Long-Term Debt    $123,197         $573,171        $2,262,826      $2,959,194

Capital Leases      44,322          177,202           419,399         640,923

Operating
Leases               2,877           11,757            35,108          49,742

Unconditional
Power Purchases     46,239          152,599           327,839         526,677

Rocky Mountain
Transactions (1)    72,698            NA                NA             72,698
- --------------------------------------------------------------------------------
Total             $289,333         $914,729        $3,045,172      $4,249,234
================================================================================

1)   Oglethorpe's  balance  sheet  contains an identical  asset  representing  a
     funding  agreement  entered into with a triple-A  rated entity to fund this
     obligation.   For   additional   information,    see   "Off-Balance   Sheet
     Arrangements."

     Contingent  Commitments.  Oglethorpe is also liable, on a contingent basis,
for certain other contractual obligations. In each case, another party is liable
for these obligations, and Oglethorpe would be expected to pay only if the other
party  fails to satisfy  the  obligations.  These  obligations  are not shown on
Oglethorpe's balance sheet.

     Several of these contingent liabilities are in connection with Oglethorpe's
transfer  of the  generation  facilities  under  construction  to Talbot EMC and
Chattahoochee EMC and the related  assignment of contracts.  As discussed above,
at the time the RUS loan is  funded,  the Talbot  and  Chattahoochee  generation
facilities will be acquired by Oglethorpe. At that point, the related contingent
liabilities will become direct obligations of Oglethorpe.

     The contingent  liabilities under construction contracts for Talbot EMC and
Chattahoochee EMC were $15 million and $15 million, respectively, as of March 7,
2003. Substantially all of these amounts will be paid by the final acceptance of
the respective  facilities.  As discussed above,  bridge loans to Talbot EMC and
Chattahoochee EMC are funding the remaining cost of construction.

     Oglethorpe  also remains  liable,  on a contingent  basis,  for obligations
under other operational  agreements  relating to the Chattahoochee EMC facility.
The combined  obligation under these agreements totals $54 million through 2004,
and $20 million annually thereafter through approximately 2015.

     In connection with a corporate  restructuring  in 1997 in which  Oglethorpe
sold its  transmission  assets to GTC, GTC assumed a portion of the indebtedness
associated with PCBs. Oglethorpe was not legally released from its obligation to
pay this debt. See Note 5 of Notes to Financial Statements.  Oglethorpe also has
contractual commitments on a corresponding portion of Oglethorpe's interest rate
swaps assumed by GTC.

     Oglethorpe  has entered  into natural gas hedges with respect to Smarr EMC,
Talbot EMC and Chattahoochee EMC. See "QUANTITATIVE AND QUALITATIVE  DISCLOSURES
ABOUT MARKET RISK" in Item 7A.

     Off-Balance  Sheet  Arrangements.   In  December  1996  and  January  1997,
Oglethorpe entered into a total of six lease transactions relating to its 74.61%
undivided  interest  in Rocky  Mountain  pumped  storage  hydroelectric  project
("Rocky  Mountain").  In each  transaction,  Oglethorpe  leased a portion of its
undivided  interest  in Rocky  Mountain  to an owner trust for the benefit of an
investor  for a term  equal  to  120% of the  estimated  useful  life  of  Rocky
Mountain, in exchange for one-time rental payments aggregating $794 million made
at the time the leases were entered into. Each owner trust financed a portion of
its payment to Oglethorpe through a loan from a bank.  Immediately following the
leases to the owner trusts, the owner trusts leased their undivided interests in
Rocky Mountain to an Oglethorpe  subsidiary,  Rocky Mountain Leasing Corporation
("RMLC"),  for a term of 30 years under separate leases (the "Facility Leases").
RMLC then subleased the undivided  interests back to Oglethorpe for an identical
term also under separate leases (the "Facility Subleases").

     Oglethorpe used a portion of the one-time rental payments paid to it by the
owner  trusts to acquire  the capital  stock of RMLC and to make a $698  million
capital  contribution  to RMLC.  RMLC in turn used the capital  contribution  to
enter into payment  undertaking  agreements and funding  agreements that provide
for third parties (whose claims paying  abilities or senior debt obligations are
rated "AAA" by S&P and "Aaa" by Moody's) to pay substantially all of:

o    RMLC's periodic basic rent payments under the Facility Leases; and

                                       39


o    the fixed  purchase  price of the undivided  interests in Rocky Mountain at
     the end of the terms of the Facility  Leases if  Oglethorpe  causes RMLC to
     exercise its option to purchase these interests at that time.

     As  a  result  of  these  lease  transactions,  after  making  the  capital
contribution to RMLC, Oglethorpe had $92 million remaining of the amount paid by
the  owner  trusts  which it used to prepay  FFB  indebtedness  while  retaining
possession of, and entitlement to, its portion of the output of Rocky Mountain.

     The  Facility  Subleases  require  Oglethorpe  to make  semi-annual  rental
payments to RMLC. In turn, RMLC is required to make equal rental payments to the
owner  trusts  under the  Facility  Leases.  In 2002,  the  amount of the rental
payments  under the  Facility  Subleases  and  Facility  Leases each totaled $49
million.  The  payment  undertaking  agreements  require  the other  party  (the
"payment  undertaker")  to pay the rent  payments  directly to the lender of the
owner trust in satisfaction of RMLC's rent payment obligation under the Facility
Lease and the applicable  owner trust's  repayment  obligation under the loan to
it.  Because  RMLC funds these rent  payments  through  the payment  undertaking
agreements,  RMLC returns to Oglethorpe  amounts  received by it pursuant to the
Facility  Subleases.  RMLC  remains  liable  for all rental  payments  under the
Facility Leases if the payment undertaker fails to make such payments,  although
the  owner  trusts  have  agreed to use due  diligence  to  pursue  the  payment
undertaker before pursuing payment from RMLC or Oglethorpe.

     As a wholly owned  subsidiary of  Oglethorpe,  the financial  condition and
results of operations of RMLC are fully consolidated into Oglethorpe's financial
statements.  The financial  statements of RMLC and Oglethorpe do not reflect the
payment undertaking  agreements,  the payments made by the payment undertaker or
the payment of rent under the Facility Subleases or Facility Leases. At December
31, 2002,  if RMLC's rent  payment  obligations  under the  Facility  Leases and
RMLC's interests in the related payment undertaking agreements were reflected on
the financial  statements of RMLC and Oglethorpe,  both amounts would equal $705
million.

     At the end of the term of each Facility Lease, Oglethorpe has the option to
cause RMLC to purchase any owner trust's  undivided  interests in Rocky Mountain
at fixed  purchase  option  prices  that  aggregate  $1.088  billion for all six
Facility Leases. The payment undertaking agreements and funding agreements would
fund $716  million  and $372  million of this  amount,  respectively,  and these
amounts  would be paid to the owner trusts over five  installments  in 2027.  If
Oglethorpe does not elect to cause RMLC to purchase any owner trust's  undivided
interest  in Rocky  Mountain,  GPC has an  option  to  purchase  that  undivided
interest.

     If Oglethorpe returns through RMLC any undivided interest in Rocky Mountain
to an owner trust,  that owner trust has several  options it can elect.  Each of
these  options is  structured  to assure  that the owner  trust's  net  economic
benefit will be no less than if RMLC had purchased  that  undivided  interest in
Rocky  Mountain under the purchase  option set forth in the applicable  Facility
Lease. The options available to the owner trust include:

o    causing  RMLC and  Oglethorpe  to renew  the  related  Facility  Lease  and
     Facility  Sublease for up to an additional 16 years and provide  collateral
     satisfactory to the owner trusts,

o    leasing its undivided  interest to a third party under a replacement lease,
     or

o    retaining the undivided interest for its own benefit.

     Under the first two of these options  Oglethorpe must arrange new financing
for the  outstanding  loans to the owner  trusts.  The  aggregate  amount of the
outstanding  loans  to all of the  owner  trusts  at the end of the  term of the
Facility  Leases is anticipated to be $666 million.  If new financing  cannot be
arranged,  the owner trusts can ultimately  cause Oglethorpe to purchase 49%, in
the case of the first  option  above,  or all, in the case of the second  option
above,  of the debt or cause RMLC to exercise  its  purchase  option or RMLC and
Oglethorpe to renew the Facility Leases and Facility Subleases, respectively.


                                       40


     Liquidity and Sources of Capital

     Sources of Capital.  Oglethorpe  has obtained the majority of its long-term
financing from RUS guaranteed loans funded by FFB.  Oglethorpe has also obtained
a substantial portion of its long-term financing  requirements from the issuance
of PCBs.

     In addition,  Oglethorpe's  operations have consistently provided a sizable
contribution  to its  funding  of  capital  requirements,  such that  internally
generated funds have provided  interim funding or long-term  capital for nuclear
fuel reloads,  general plant facilities,  replacements and additions to existing
facilities,  and retirement of long-term debt.  Oglethorpe  anticipates  that it
will continue to meet these types of capital requirements through 2005 primarily
with  funds  generated  from  operations  and,  if  necessary,  with  short-term
borrowings.  However,  in  the  future  Oglethorpe  may  also  pursue  long-term
financing for these types of capital expenditures.  In addition,  Oglethorpe may
finance some of its prior and future environmental-related  capital expenditures
by issuing long-term debt, some of which may be tax-exempt.

     As discussed above,  Oglethorpe is currently  providing interim  financing,
through its commercial  paper program,  for  approximately  fifty percent of the
cost of the new generation facilities owned by Talbot EMC and Chattahoochee EMC.
This interim  financing will remain in place until  permanent  funding under the
RUS loan  commitments  is  obtained,  which is  expected  to occur in the second
quarter of 2003.

     To meet short-term cash needs and liquidity  requirements,  Oglethorpe had,
as of December 31, 2002,  (i)  approximately  $151 million in cash and temporary
cash investments,  (ii) $94 million in other short-term investments and (iii) up
to $72 million available under the following committed credit facilities:

- --------------------------------------------------------------------------------
Committed Short-Term          Authorized          Available          Expiration
Credit Facilities               Amount             Amount               Date
- --------------------------------------------------------------------------------
                                            (dollars in millions)
Line of credit
supporting commercial
paper                           $320(1)             $22               9/24/03

 CFC Line of credit             $ 50                $50               8/14/03

- --------------------------------------------------------------------------------
1) Amount reduces to $290 million by June 30, 2003

     Under its commercial  paper program,  Oglethorpe may issue commercial paper
not to  exceed  the  amount  of the  backup  line of  credit  facility,  thereby
providing 100% credit support.  The current $320 million line of credit facility
is  provided  by a group of six banks that was  syndicated  by Bank of  America.
Along with the CFC line of credit, the facility  supporting the commercial paper
may also be used for general working capital needs.

     The commercial  paper line of credit  facility is structured  such that the
commitment  amount is reduced to $290  million  upon the earlier to occur of (i)
June 30, 2003,  or (ii) receipt by  Oglethorpe  of funds  totaling  $350 million
under the RUS loans for the Talbot and Chattahoochee  generating facilities.  As
discussed above,  Oglethorpe  anticipates that the RUS will provide this funding
prior to June 30, 2003. If the committed amount is reduced before the funding of
the RUS loans,  Oglethorpe  would use its cash or another line of credit to fund
the  difference  between the amount of its  outstanding  loans to Talbot EMC and
Chattahoochee EMC and the reduced  availability of commercial paper. This amount
would be approximately $10 million.

     Liquidity Covenants. Oglethorpe currently has three financial agreements in
place which contain liquidity covenants.  These agreements include interest rate
swaps   relating  to  two  PCB   transactions   and  the  Rocky  Mountain  lease
transactions.  The amount of liquidity  required under these  agreements was $76
million as of December 31, 2002,  and  Oglethorpe  had  sufficient  liquidity to
satisfy these requirements.

     Credit Rating Risk

     Oglethorpe has financial  agreements and  commercial  contracts  containing
provisions  which,  upon a credit rating downgrade below specified  levels,  may
require  the  posting of  collateral  (in the form of either  letters of credit,
surety  bonds or cash) or  termination  of the  agreement.  The table below sets
forth  Oglethorpe's  current ratings and the more  significant  ratings triggers
contained in Oglethorpe's agreements and contracts.

                                       41


                                S&P      Moody's   Fitch
- --------------------------------------------------------------------------------
Oglethorpe Ratings
     Senior Secured             A        A3        A
     Senior Unsecured           NRA(1)   Baa1(2)   NRA(1)
     Short-term                 A-1      P-2       F-1
- --------------------------------------------------------------------------------
Rating Triggers
  Interest Rate Swaps
    Senior Secured              BBB-     Baa3      NA (3)
 Rocky Mountain Lease
    Senior Secured              BBB      Baa2      BBB
    Senior Unsecured            BBB-     Baa3      BBB-
Morgan Stanley Power Mar-
 Keting Agreement
     Senior Secured             BBB+     Baa1      BBB+
- --------------------------------------------------------------------------------
1) NRA = no rating assigned
2) Moody's also assigns Oglethorpe an "Issuer Rating" of Baa1
3) NA = rating not included as a trigger in agreement

     Under the interest  rate swap  arrangements,  if  Oglethorpe's  rating from
Standard & Poor's or Moody's  falls below the levels  shown in the table  above,
the swap  counterparty  has the option of 1) making  swap  payments  based on an
index rather than the actual  variable rate on the bonds, or 2) causing an early
termination of the swaps. In the event of a termination,  either party could owe
the other party a termination  payment depending on the market value of the swap
position.  Oglethorpe  estimates  that as of December 31, 2002, a termination of
the swap would require Oglethorpe to make a termination payment of approximately
$58  million.  Except  in  situations  where  Oglethorpe  voluntarily  elects to
terminate  the  interest  rate swaps  early,  Oglethorpe  has the right to pay a
termination  payment  due to the  swap  counterparty  over a term  of up to five
years.

     Provisions  in  the  Rocky  Mountain  lease   transactions   could  require
Oglethorpe to put up additional  surety bonds or letters of credit in the amount
of $50 million if Oglethorpe fails to maintain at least two of the three ratings
shown in the table  above or if it fails to maintain  $50 million in  liquidity.

     Under the Morgan Stanley power marketing  arrangements,  which expire March
31, 2005,  Oglethorpe  could be required to provide  credit  assurance up to $45
million if Oglethorpe  fails to maintain at least two of the three ratings shown
in the table above.

     Provisions  in other  loan and  power  purchase  agreements  of  Oglethorpe
contain  covenants  based on credit  ratings  that  could  result  in  increased
interest rates or restrictions  on issuing debt, or could require  Oglethorpe to
give  performance  assurances,  but would  not  result  in  acceleration  of any
obligations  or  termination of any  agreements.  The ratings  triggers in these
agreements  are at or  below  the  minimum  levels  required  by the  agreements
reflected in the table above.

     Given  its  current  level of  ratings,  Oglethorpe's  management  does not
believe  that  the  rating  triggers  contained  in any of  its  agreements  and
contracts  will have a material  adverse  effect on its results of operations or
financial  condition.  However,  Oglethorpe's  ratings  reflect the views of the
rating agencies and not of Oglethorpe,  and therefore Oglethorpe cannot give any
assurance  that its ratings will be maintained at current  levels for any period
of time.

     Refinancing Transactions

     Oglethorpe  has a program  under  which it is  refinancing,  on a continued
tax-exempt basis, the annual principal maturities of serial bonds and the annual
sinking fund payments of term bonds originally issued on behalf of Oglethorpe by
various county development  authorities.  The refinancing of these PCB principal
maturities  allows  Oglethorpe to preserve a low-cost  source of  financing.  To
date,  Oglethorpe has refinanced  approximately $164 million under this program,
including  $31  million  of PCB  principal  that  matured  on  January  1, 2003.
Oglethorpe  plans to continue this  refinancing  program  through at least 2007,
covering an additional $141 million in PCB principal maturities.

     Under an indemnity  agreement  executed in connection with GTC's assumption
of PCB  indebtedness  in the 1997  corporate  restructuring,  GTC is entitled to
participate  in any  refinancing  of this PCB debt by  Oglethorpe by agreeing to

                                       42


assume a portion of the refinancing debt. However, to-date GTC has agreed not to
participate  in  Oglethorpe's  refinancing  of  the  PCB  principal  maturities.
Pursuant to this agreement, Oglethorpe provided a discount of approximately $1.5
million and  received  cash of $3.6  million on the $5.1 million due from GTC in
connection with the principal payments due January 1, 2003. GTC has also elected
not to participate in the  refinancing of the PCB principal  maturities  through
2007.

     Oglethorpe  issued  $92  million  of  tax-exempt  PCBs in  October  2002 to
refinance  two  medium-term  loans,  one from  CoBank  and one from CFC,  of $46
million each.  Proceeds from the medium-term  loans were used to legally defease
$92 million of Series 1992  tax-exempt  PCB's in  connection  with  Oglethorpe's
corporate  restructuring in 1997. The funds from the defeasance were put into an
escrow account, and the remaining amounts in escrow at January 1, 2003 were used
to fully redeem the outstanding Series 1992 PCBs.

     The average interest rate on long-term debt,  capital lease obligations and
notes payable was 5.33% at December 31, 2002.

     Other Planned Financings

     Oglethorpe is currently  considering  a financing in 2003 of  approximately
$100 million of capital expenditures  previously made or to be made in complying
with  environmental  regulations at its fossil and nuclear  facilities.  A small
portion of this amount may be eligible to finance as tax-exempt  PCBs,  with the
remainder  financed as taxable debt. If issued,  this debt will be secured under
the Mortgage Indenture.


Miscellaneous

     Competition

     The electric  utility  industry in the United  States  continues to undergo
fundamental  changes.  These  changes  have been  promoted  by several  factors,
including:

o    the Energy Policy Act of 1992;

o    Federal Energy Regulatory  Commission  ("FERC") policies regarding mergers,
     transmission access and pricing,  regional  transmission  organizations and
     electricity market design;

o    federal and state deregulation initiatives;

o    consolidation and mergers of electric utilities;

o    credit quality of utilities and power marketers;

o    difficulties in the development of efficient energy trading markets;

o    the presence of power marketers and independent power producers;

o    generation  surpluses and deficits and transmission  constraints in certain
     regional markets;

o    improvements in generation technology.

     Oglethorpe is not obligated to provide all of the Members' requirements and
the  Members  have the  option to  satisfy  all or a portion  of their  existing
Oglethorpe  purchase  obligations  from other  suppliers.  As a  consequence  of
Members' exercise of options under the Wholesale Power Contracts,  Oglethorpe is
not currently  engaged in long-term  resource  procurement  for any Member other
than in  connection  with the  anticipated  acquisition  of the  Talbot  EMC and
Chattahoochee EMC generation  facilities.  A number of Members have entered into
long-term  contracts  with third  parties for all of their future  requirements.
Accordingly,  Oglethorpe does not expect to have significant  direct exposure to
future  changes  in  electricity  prices or  competition  from  other  wholesale
suppliers.

     Recently,  many power  marketers  and traders  have  experienced  financial
difficulties,  which has  reduced the  liquidity  of  electric  energy  markets.
Oglethorpe has not suffered any material adverse effect in the energy trading it
conducts  through ACES Power Marketing on behalf of Members that  participate in
Oglethorpe's pool. Some of the Members may, however,  have exposure to increased
market prices due to these developments.

     Some states have  implemented  varying  forms of retail  competition  among
power  suppliers.  No  legislation  related to retail  competition  has yet been
enacted in Georgia,  and no bill is currently pending in the Georgia legislature
which would amend the Georgia Territorial Electric Service Act (the "Territorial
Act") or otherwise  affect the exclusive right of the Members to supply power to
their current  service  territories.  The GPSC does not have the authority under

                                       43


Georgia law to order retail competition or amend the Territorial Act.

     Under current  Georgia law, the Members  generally have the exclusive right
to provide retail electric service in their respective territories.  Since 1973,
however,  the Territorial Act has permitted  limited  competition among electric
utilities  located  in  Georgia  for  sales  of  electricity  to  certain  large
commercial  or industrial  customers.  The owner of any new facility may receive
electric  service  from the power  supplier  of its  choice if the  facility  is
located  outside of municipal  limits and has a connected load upon initial full
operation of 900 kilowatts or more. The Members,  with Oglethorpe's support, are
actively engaged in competition  with other retail electric  suppliers for these
new commercial and industrial  loads.  While the  competition  for  900-kilowatt
loads represents only limited competition in Georgia, this competition has given
Oglethorpe and the Members the  opportunity to develop  resources and strategies
to prepare for an increasingly competitive market.

     Oglethorpe  cannot  predict  at  this  time  the  outcome  of  the  various
developments  that may lead to increased  competition  in the  electric  utility
industry  or the  effect of such  developments  on  Oglethorpe  or the  Members.
Nonetheless,  Oglethorpe has taken several steps to prepare for and adapt to the
fundamental changes that have occurred or appear likely to occur in the electric
utility  industry and to reduce  stranded  costs.  In 1997,  Oglethorpe  divided
itself into separate generation, transmission and system operations companies in
order to better serve its Members in a deregulated and competitive  environment.
Oglethorpe  also has  pursued an  interest  cost  reduction  program,  which has
included  refinancings  and  prepayments  of various debt  issues,  and that has
provided significant cost savings. Oglethorpe has also entered into arrangements
with  power  marketers  to reduce  power  costs and to provide  for future  load
requirements without taking all the risk associated with traditional  suppliers.
(See "Results of Operations--Power Marketer Arrangements.")

     Oglethorpe  and/or the  Members  continue to consider a wide array of other
potential  actions to meet future power supply needs, to reduce costs, to reduce
risks of the increasingly  competitive  generation  business and to respond more
effectively  to increasing  competition.  Alternatives  that could be considered
include:

o    additional power marketing arrangements or other alliance arrangements;

o    whether   potential  load  fluctuation   risks  in  a  competitive   retail
     environment can be shifted to other wholesale suppliers;

o    whether  power supply  requirements  will continue to be met by the current
     mix of ownership and purchase arrangements;

o    whether  future power supply  resources  will be owned by  Oglethorpe or by
     other entities;

o    whether disposition of existing assets or asset classes would be advisable;

o    the effects of nuclear license extensions;

o    ways to extend the maturity of  RUS-guaranteed  indebtedness  in connection
     with extension(s) of plant operating licenses;

o    the potential to prepay debt;

o    the  effects of  proliferation  of  non-core  services  offered by electric
     utilities; and

o    other  regulatory and business  changes that may affect  relative values of
     generation classes or have impacts on the electric industry.

Such  consideration  necessarily would take account of and are subject to legal,
regulatory  and  contractual   (including   financing  and  plant   co-ownership
arrangements) considerations.

     Many  Members  are also  providing  or  considering  proposals  to  provide
non-traditional  products  and  services  such as  telecommunications  and other
services.  In 2002, the Georgia legislature  enacted legislation  empowering the
GPSC to authorize Member  affiliates to market natural gas. The GPSC is required
to   condition   such   authorization   on  terms   designed   to  ensure   that
cross-subsidizations  do not occur between the electricity  services of a Member
and the gas activities of its gas affiliates.

                                       44


     Depending on the nature of future  competition  in Georgia,  there could be
reasons for the Members to separate  their physical  distribution  business from
their energy  business,  or otherwise  restructure  their current  businesses to
operate more effectively under retail competition.

     Oglethorpe will continue to consider industry trends and developments,  but
cannot  predict  at this  time  the  results  of  these  matters  or any  action
Oglethorpe might take based thereon.

     Other New Accounting Pronouncements

     In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No.  4,  44,  and  64,  Amendment  of  FASB  Statement  No.  13,  and  Technical
Corrections." Among other things, this statement rescinds SFAS No. 4, "Reporting
Gains and Losses from  Extinguishment  of Debt" (SFAS No. 4), which required all
gains and losses from  extinguishment of debt to be aggregated and, if material,
classified as an extraordinary  item, net of the related income tax effect. As a
result,  the criteria in Accounting  Principles Board Opinion No. 30, "Reporting
the Results of  Operations - Reporting the Effects of Disposal of a Segment of a
Business,  and  Extraordinary,  Unusual and  Infrequently  Occurring  Events and
Transactions,"  which requires gains and losses on extinguishments of debt to be
classified as income or loss from  continuing  operations,  will now be applied.
SFAS  No.  71  permits   Oglethorpe  to  record  gains  and  losses  from  early
extinguishment  of  debt  as  regulatory  assets  and  regulatory   liabilities.
Oglethorpe   anticipates   that  any  future   gains  and   losses   from  early
extinguishment  of debt will be recorded  as  regulatory  assets and  regulatory
liabilities.  Oglethorpe is required to adopt SFAS No. 145 effective  January 1,
2003.

     In July  2002,  the  FASB  issued  SFAS  No.  146,  "Accounting  for  Costs
Associated  with Exit or  Disposal  Activities"(SFAS  No.146),  which  addresses
financial  accounting and reporting for costs  associated  with exit or disposal
activities and nullifies  Emerging Issues Task Force Issue No. 94-3,  "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring"  (EITF 94-3). The
principal  difference  between  SFAS No.  146 and EITF 94-3  relates to SFAS No.
146's  requirements for recognition of a liability for a cost associated with an
exit or disposal  activity.  SFAS No. 146 requires  that a liability  for a cost
associated with an exit or disposal activity be recognized when the liability is
incurred.  Under EITF 94-3, a liability for an exit cost as generally defined in
EITF 94-3 was recognized at the date of an entity's  commitment to an exit plan.
Oglethorpe  is required to adopt SFAS No. 146  effective  January 1, 2003.  This
pronouncement currently does not affect Oglethorpe's financial statements.

     Inflation

     As with  utilities  generally,  inflation has the effect of increasing  the
cost  of  Oglethorpe's  operations  and  construction  program.   Operating  and
construction  costs have been less affected by inflation over the last few years
because rates of inflation have been relatively low.

     Forward-Looking Statements and Associated Risks

     This  Annual  Report  on Form  10-K  contains  forward-looking  statements,
including  statements  regarding,  among other items, (i) anticipated  trends in
Oglethorpe's  business,  (ii)  Oglethorpe's and the Members' future power supply
requirements,  resources and arrangements and (iii) disclosures regarding market
risk included in Item 7A. Some  forward-looking  statements can be identified by
use of  terms  such as  "may,"  "will,"  "expects,"  "anticipates,"  "believes,"
"intends,"   "projects,"   "plans"  or  similar  terms.  These   forward-looking
statements  are based  largely  on  Oglethorpe's  current  expectations  and are
subject  to a number  of risks  and  uncertainties,  some of  which  are  beyond
Oglethorpe's control. For some of the factors that could cause actual results to
differ  materially from those anticipated by these  forward-looking  statements,
see "Summary of Critical  Accounting  Policies and  Cooperative  Operations" and
"Miscellaneous-Competition"  herein and "FACTORS  AFFECTING THE ELECTRIC UTILITY
INDUSTRY" in Item 1. In light of these risks and  uncertainties,  Oglethorpe can
give no assurance  that events  anticipated  by the  forward-looking  statements
contained in this Annual Report will in fact  transpire.

                                       45


ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     Oglethorpe is exposed to market risk,  including changes in interest rates,
in the value of  equity  securities,  and in the  market  price of  electricity.
Oglethorpe's  use of derivative  financial or commodity  instruments  is for the
purpose of mitigating business risks and is not for speculative purposes.

     Oglethorpe's  Risk  Management   Committee   provides  general   management
oversight and policy  decision over all risk  management  activities,  including
commodity trading, fuels management,  insurance,  debt management and investment
portfolio  management.  The  committee  consists of senior  executive  officers,
including  the Chief  Executive  Officer and the Chief  Operating  Officer.  The
committee has implemented a comprehensive risk management policy, which includes
authority limits and credit  policies.  The committee  regularly meets,  reviews
risk  management  reports and reports  activities to the Audit  Committee of the
Board of Directors.

     Interest Rate Risk

     Oglethorpe  is exposed to the risk of changes in interest  rates due to the
significant amount of financing obligations it has entered into, including fixed
and  variable  rate  debt and  interest  rate  swap  transactions.  Oglethorpe's
objective in managing  interest  rate risk is to maintain a balance of fixed and
variable rate debt that will lower its overall borrowing costs within reasonable
risk  parameters.  As part of this debt  management  strategy,  Oglethorpe has a
guideline  of having  between 15% and 30% variable  rate debt to total debt.  At
December 31, 2002,  Oglethorpe  had 23% of its debt in a variable rate mode. The
amount of variable rate debt is expected to decrease to  approximately  13% when
the   RUS-guaranteed   loans  fund  the   acquisition  of  the  Talbot  EMC  and
Chattahoochee  EMC generation  facilities  and  Oglethorpe  uses the proceeds to
retire  commercial  paper,  which is expected to occur in the second  quarter of
2003.

     The table below details Oglethorpe's existing debt instruments and provides
the fair value at December 31, 2002,  the  outstanding  balance at the beginning
and end of each year and the annual principal  maturities and associated average
interest rates.






                                                            (dollars in thousands)
                            Fair Value                                       Cost
                            ----------     ------------------------------------------------------------------------------------
                               2002            2003            2004          2005         2006          2007        Thereafter
                               ----            ----            ----          ----         ----          ----        ----------
Fixed Rate Debt
                                                                                              
Beginning of year                          $ 2,186,016     $ 2,071,836   $ 1,951,023   $ 1,820,377   $ 1,684,081   $ 1,539,888
Maturities                                    (114,180)       (120,813)     (130,646)     (136,296)     (144,193)
                                           -----------     -----------   -----------   -----------   -----------
End of year                 $ 2,657,314    $ 2,071,836     $ 1,951,023   $ 1,820,377   $ 1,684,081   $ 1,539,888
                                           -----------     -----------   -----------   -----------   -----------
Average interest rate(1)                          6.02%           6.04%         6.06%         6.08%         6.11%         6.47%

Variable Rate Debt
Beginning of year                          $   521,758     $   517,625   $   513,471   $   509,293   $   505,088   $   500,853
Maturities                                      (4,133)         (4,154)       (4,178)       (4,205)       (4,235)
                                           -----------     -----------   -----------   -----------   -----------
End of year                 $   469,245    $   517,625     $   513,471   $   509,293   $   505,088   $   500,853
                                           -----------     -----------   -----------   -----------   -----------
Average interest rate(1)(2)                       4.41%           4.58%         4.58%         4.79%         4.79%         3.94%

Interest Rate Swaps
Beginning of year                          $   251,420     $   246,536   $   241,315   $   238,343   $   232,191   $   222,086
Maturities                                      (4,884)         (5,221)       (2,972)       (6,152)      (10,105)
                                           -----------     -----------   -----------   -----------   -----------
End of year                 $   251,420    $   246,536     $   241,315   $   238,343   $   232,191   $   222,086
                                           -----------     -----------   -----------   -----------   -----------
Average interest  rate(1)                         5.83%           5.83%         5.67%         5.83%         5.77%         5.80%
Unrealized loss on swaps    $   (58,443)

- ----------
<FN>
(1)  Average interest rates relate to the applicable principal maturities.
(2)  Future  variable debt interest  rates are adjusted  based on a forward U.S.
     Treasury yield curve.
</FN>

                                       46



     Interest Rate Swap Transactions

     Oglethorpe   has  two  interest   rate  swap   transactions   with  a  swap
counterparty,  AIG Financial Products Corp.  ("AIG-FP"),  which were designed to
create a  contractual  fixed rate of interest on $322  million of variable  rate
PCBs.  These  transactions  were entered into in early 1993 on a forward  basis,
pursuant to which  approximately  $200 million of variable rate PCBs were issued
on November 30, 1993 and  approximately  $122 million of variable rate PCBs were
issued on December 1, 1994. Oglethorpe is obligated to pay the variable interest
rate that  accrues  on these  PCBs;  however,  the swap  arrangements  provide a
mechanism for Oglethorpe to achieve a contractual fixed rate which is lower than
Oglethorpe would have obtained had it issued fixed rate bonds.  Oglethorpe's use
of  interest  rate   derivatives   is  currently   limited  to  these  two  swap
transactions.

     In connection  with GTC's  assumption of liability on a portion of the PCBs
pursuant to the corporate  restructuring by which GTC became a separate company,
commencing  April 1, 1997,  GTC  assumed and agreed to pay 16.86% of any amounts
due from  Oglethorpe  under  these  swap  arrangements,  including  the net swap
payments and termination  payments described below. Should GTC fail to make such
payments under the assumption,  Oglethorpe remains obligated for the full amount
of such payments.

     Under the swap  arrangements,  Oglethorpe  is  obligated  to make  periodic
payments to AIG-FP based on a notional  principal  amount equal to the aggregate
principal  amount of the bonds  outstanding  during the period and a contractual
fixed rate ("Fixed Rate"),  and AIG-FP is obligated to make periodic payments to
Oglethorpe based on a notional principal amount equal to the aggregate principal
amount of the bonds  outstanding  during the period and a variable rate equal to
the variable rate of interest accruing on the bonds during the period ("Variable
Rate").  These payment obligations are netted, such that if the Variable Rate is
less than the Fixed Rate, Oglethorpe makes a net payment to AIG-FP. Likewise, if
the  Variable  Rate is higher  than the Fixed  Rate,  Oglethorpe  receives a net
payment from AIG-FP.  Thus, although changes in the Variable Rate affect whether
Oglethorpe  is  obligated  to make  payments to AIG-FP or is entitled to receive
payments from AIG-FP,  the effective  interest rate Oglethorpe pays with respect
to the PCBs is not affected by changes in interest rates. The Fixed Rate for the
$200  million of variable  rate bonds issued in 1993 is 5.67% and the Fixed Rate
for the $122 million of variable rate bonds issued in 1994 is 6.01%. At December
31, 2002,  the bonds issued in 1993 carried a variable  rate of interest of 1.5%
and the bonds  issued in 1994 carried a variable  rate of interest of 1.6%.  For
the three years ended December 31, 2000,  2001 and 2002,  Oglethorpe has made in
connection with both interest rate swap arrangements  combined net swap payments
to AIG-FP  (net of amounts  assumed by GTC) of $4.3  million,  $8.1  million and
$11.2 million, respectively.

     The  swap  arrangements  extend  for the life of  these  PCBs.  If the swap
arrangements  were to be  terminated  while  the  PCBs  are  still  outstanding,
Oglethorpe or AIG-FP may owe the other party a termination  payment depending on
a number of factors,  including  whether the fixed rate then being offered under
comparable swap  arrangements is higher or lower than the Fixed Rate.  Under the
terms of the swap  agreements,  AIG-FP has limited rights to terminate the swaps
only upon the  occurrence  of  specified  events of  default or a  reduction  in
ratings on Oglethorpe's  PCBs,  without credit  enhancement,  to a level that is
below  investment  grade.   Oglethorpe  estimates  that  its  maximum  aggregate
liability (net of GTC's assumed percentage) for termination  payments under both
swap  arrangements  had such  payments  been due on December 31, 2002 would have
been   approximately   $58  million.   Except  in  situations  where  Oglethorpe
voluntarily  elects to terminate the interest rate swaps early,  Oglethorpe  has
the right to a term-out of any termination  payment due to the swap counterparty
for a term of up to five years.

                                       47



     Capital Leases

     In December 1985,  Oglethorpe sold and  subsequently  leased back from four
purchasers  its 60%  undivided  ownership  interest  in Scherer  Unit No. 2. The
capital leases provide that  Oglethorpe's  rental payments vary to the extent of
interest  rate changes  associated  with the debt used by the lessors to finance
their  purchase of undivided  ownership  shares in the unit.  The debt currently
consists of $169,185,000 in serial facility bonds due June 30, 2011 with a 6.97%
fixed rate of interest.

     Oglethorpe  entered into a power  purchase and sale agreement with Doyle I,
LLC (Doyle  Agreement) to purchase all of the output from a five-unit  gas-fired
generation  facility.  The Doyle Agreement is reported on  Oglethorpe's  balance
sheet as a capital  lease.  The lease  payments  vary to the extent the interest
rate on the lessor's debt varies from 6.00%.  At December 31, 2002, the weighted
average interest rate on the lease obligation was 6.61%.

Equity Price Risk

     Oglethorpe  maintains  trust funds, as required by the NRC, to fund certain
costs of nuclear decommissioning. (See Note 1 of Notes to Financial Statements.)
As of December 31, 2002, these funds were invested primarily in U.S.  Government
and corporate debt  securities and  asset-backed  securities and domestic equity
securities.   By  maintaining  a  portfolio  that  includes   long-term   equity
investments,  Oglethorpe  intends to maximize the returns to be utilized to fund
nuclear  decommissioning,  which  in the  long-term  will  better  correlate  to
inflationary  increases in decommissioning costs. However, the equity securities
included in  Oglethorpe's  portfolio are exposed to price  fluctuation in equity
markets.  A 10%  decline  in the value of the  fund's  equity  securities  as of
December 31, 2002 would  result in a loss of value to the fund of  approximately
$7 million.  Oglethorpe  actively  monitors its  portfolio by  benchmarking  the
performance of its investments  against certain indexes and by maintaining,  and
periodically reviewing,  established target allocation percentages of the assets
in its trusts to various  investment  options.  Because  realized and unrealized
gains and losses from investment securities held in the decommissioning fund are
directly added to or deducted from the decommissioning reserve,  fluctuations in
equity prices do not affect Oglethorpe's net margin in the short-term.

Commodity Price Risk

     Electricity

     The market price of electricity is subject to price  volatility  associated
with changes in supply and demand in electricity markets.  Oglethorpe's exposure
to  electricity  price  risk  relates  to  managing  the supply of energy to the
Members.  To secure a firm supply of electricity  and to limit price  volatility
associated with  electricity  purchases,  Oglethorpe has taken several  actions.
Oglethorpe  obtains  substantially  all of the power it  supplies to the Members
from a combination  of generating  plants and power  purchased  under  long-term
contracts  with power  marketers and other power  suppliers.  Therefore,  only a
small  percentage of  Oglethorpe's  requirements  is purchased in the short-term
market,  and further only a small  portion of these  requirements  is covered by
derivative commodity instruments.  Oglethorpe enters into short-term options and
forward  contracts  for the  delivery  of  energy  on  behalf  of  Members  that
participate in  Oglethorpe's  pool.  Oglethorpe's  market price risk exposure on
these instruments is not material.  See "OGLETHORPE POWER  Corporation--Expected
Facilities Acquisitions, RUS Loans And Other New Arrangements" in Item 1.

     Coal

     Oglethorpe is also exposed to risks of changing prices for fuels, including
coal and  natural  gas.  Oglethorpe  has  interests  in  1,501 MW of  coal-fired
capacity (Plants Scherer and Wansley). Oglethorpe purchases coal under long-term
contracts and in spot-market transactions. Oglethorpe's long-term coal contracts
provide volume  flexibility and fixed prices.  Oglethorpe  anticipates  that its
existing long-term  contracts will provide fixed prices for substantially all of
its coal  requirements  for  Plant  Wansley  through  2005.  Additionally,  such
contracts will provide about 50% of the forecasted coal  requirements  for Plant

                                       48



Scherer in 2004 and 2005 and all of the expected  requirements for Plant Scherer
in 2003.

     The  objective  of  Oglethorpe's  coal  procurement  strategy  is to ensure
reliable  coal supply and some price  stability  for the  Members.  Its strategy
focuses on hedging  requirements  over a three-year  time  horizon,  but permits
opportunities to make purchases up to six years into the future. The procurement
guidelines  provide for  layering  in fixed  prices by  annually  entering  into
forward contracts for between 25% and 35% of the forecasted requirements,  for a
rolling three-year period.

     Natural Gas

     Oglethorpe has two power purchase  contracts under which  approximately 625
MW of capacity and associated  energy is supplied by gas-fired  facilities,  the
power  purchase  contracts  with Doyle I (which  Oglethorpe  treats as a capital
lease) and Hartwell.  Under these  contracts,  Oglethorpe is exposed to variable
energy  charges,   which   incorporate  each  facility's  actual  operation  and
maintenance and fuel costs. Oglethorpe has the right to purchase natural gas for
the Doyle and Hartwell  facilities and exercises this right from time to time to
actively  manage  the cost of  energy  supplied  from  these  contracts  and the
underlying natural gas price and operational risks.

     In  providing  operation  management  services  for Smarr  EMC,  Oglethorpe
purchases natural gas, including  transportation and other related services,  on
behalf of Smarr EMC and ensures that the Smarr  facilities  have fuel  available
for  operations.  Oglethorpe  is providing  similar  services for Talbot EMC and
Chattahoochee  EMC.  (See  "OGLETHORPE  POWER  CORPORATION--Expected  Facilities
Acquisitions,  RUS Loans And Other New  Arrangements" and "THE MEMBERS AND THEIR
POWER  SUPPLY   RESOURCES--Member   Power  Supply   Resources"  in  Item  1  and
"PROPERTIES--Generating Facilities" and "--Fuel Supply" in Item 2.)

     Oglethorpe has entered into natural gas swap arrangements (1) to manage its
exposure  to  fluctuations  in the  market  price  of  natural  gas  related  to
Oglethorpe resources and (2) to assist Members in managing such exposure related
to Smarr EMC,  Talbot EMC and  Chattahoochee  EMC. Under these swap  agreements,
Oglethorpe  pays the  counterparty  contractually  a fixed  price for  specified
natural gas  quantities  and receives a payment for such  quantities  based on a
market price  index.  These  payment  obligations  are netted,  such that if the
market  price index is lower than the fixed  price,  Oglethorpe  will make a net
payment,  and if the  market  price  index  is  higher  than  the  fixed  price,
Oglethorpe  will  receive  a net  payment.  If the  natural  gas  swaps had been
terminated at December 31, 2002, Oglethorpe would have received a net payment of
$972,000  on  the  portion  of the  natural  gas  swaps  related  to  Oglethorpe
resources.  This  amount  does not  include a net  payment  of  $3,011,000  that
Oglethorpe  would have received for the portion of the natural gas swaps related
to Smarr  EMC,  Talbot  EMC and  Chattahoochee  EMC.  Oglethorpe  remains  fully
obligated for any payments due under the swaps related to Smarr EMC,  Talbot EMC
and  Chattahoochee  EMC, but is entitled to recover such amounts from Smarr EMC,
Talbot EMC and  Chattahoochee  EMC.  Oglethorpe's  market price risk exposure on
these  agreements  is not  material.  Oglethorpe  expects to  continue to manage
exposures  to natural gas price  risks only for a few of its  Members  that have
elected to receive such services.

     ACES Power Marketing

     Oglethorpe has a service  agreement with ACES Power Marketing ("APM") under
which APM acts as  Oglethorpe's  agent in the  purchase  and sale of  short-term
wholesale power on behalf of Members that participate in the Oglethorpe capacity
and energy pool. (See "OGLETHORPE'S POWER SUPPLY  RESOURCES--Capacity and Energy
Pool" in Item 1.) APM also provides  related risk  management  services.  APM is
subject to Oglethorpe's  risk management  policies,  including trading authority
limits.  APM is an  organization  owned by several  generation and  transmission
cooperatives (including Oglethorpe) that provides energy trading and natural gas
management services to rural electric cooperatives and others.

     Oglethorpe  has an additional  service  agreement  with APM under which APM
provides  services  related to natural gas planning and  procurement and acts as

                                       49



Oglethorpe's agent for executing emergency system balancing transactions.

Changes in Risk Exposure

     Oglethorpe's  exposure  to changes in interest  rates,  the price of equity
securities it holds, and commodity  prices have not changed  materially from the
previous reporting period. Oglethorpe is not aware of any facts or circumstances
that would significantly impact these exposures in the near future.

                                       50



ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                          Index To Financial Statements
                                                                          Page
Statements of Revenues and Expenses,
   For the Years Ended December 31, 2002, 2001 and 2000..................   53
Balance Sheets, As of December 31, 2002 and 2001.........................   54
Statements of Capitalization, As of December 31, 2002 and 2001...........   56
Statements of Cash Flows,
   For the Years Ended December 31, 2002, 2001 and 2000 .................   57
Statements of Patronage Capital and Membership Fees
   and Accumulated Other Comprehensive Margin
   For the Years Ended December 31, 2002, 2001 and 2000 .................   58
Notes to Financial Statements............................................   59
Report of Management.....................................................   72
Report of Independent Accountants........................................   72

                                       51





                      [This Page Intentionally Left Blank]



                                       52




STATEMENTS OF REVENUES AND EXPENSES

For the years ended December 31, 2002, 2001 and 2000



                                                                                            (dollars in thousands)
                                                                                 2002                2001                 2000
====================================================================================================================================
Operating revenues (Note 1):
                                                                                                              
     Sales to Members                                                         $ 1,127,519         $ 1,080,478          $ 1,146,064
     Sales to non-Members                                                          35,802              58,811               53,333
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues                                                        1,163,321           1,139,289            1,199,397
- ------------------------------------------------------------------------------------------------------------------------------------
Operating expenses:
     Fuel                                                                         225,008             221,449              230,729
     Production                                                                   232,312             218,480              220,221
     Purchased power (Note 9)                                                     357,491             414,382              377,805
     Depreciation and amortization                                                140,058             133,731              143,703
     Income taxes (Note 3)                                                            -               (63,485)                 -
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating expenses                                                          954,869             924,557              972,458
- ------------------------------------------------------------------------------------------------------------------------------------
Operating margin                                                                  208,452             214,732              226,939
- ------------------------------------------------------------------------------------------------------------------------------------
Other income (expense):
     Investment income                                                             23,787              32,113               44,489
     Amortization of deferred gains (Notes 1 and 4)                                 2,475               2,475                2,475
     Amortization of net benefit of sale of income
         tax benefits (Note 1)                                                      5,188              11,195               11,195
     Allowance for equity funds used during
         construction (Note 1)                                                        452                 290                  204
     Other                                                                          4,009               5,272                4,068
- ------------------------------------------------------------------------------------------------------------------------------------
Total other income                                                                 35,911              51,345               62,431
- ------------------------------------------------------------------------------------------------------------------------------------
Interest charges:
     Interest on long-term debt and capital leases                                205,360             220,525              227,877
     Other interest                                                                10,594              10,839               21,954
     Allowance for debt funds used during construction (Note 1)                    (3,152)             (2,786)              (1,930)
     Amortization of debt discount and expense                                     14,021              19,082               21,491
- ------------------------------------------------------------------------------------------------------------------------------------
Net interest charges                                                              226,823             247,660              269,392
- ------------------------------------------------------------------------------------------------------------------------------------
Net margin                                                                    $    17,540         $    18,417          $    19,978
====================================================================================================================================


The accompanying notes are an integral part of these financial statements.

                                       53


BALANCE SHEETS
December 31, 2002 and 2001


                                                                                                       (dollars in thousands)
                                                                                                     2002                   2001
===================================================================================================================================
Assets
Electric plant (Notes 1, 4 and 6):
                                                                                                                  
     In service                                                                                  $ 5,030,333            $ 5,029,192
     Less: Accumulated provision for depreciation                                                 (1,983,950)            (1,881,918)
- -----------------------------------------------------------------------------------------------------------------------------------
                                                                                                   3,046,383              3,147,274
     Nuclear fuel, at amortized cost                                                                  77,247                 77,360
     Construction work in progress                                                                    69,282                 38,564
- -----------------------------------------------------------------------------------------------------------------------------------
Total electric plant                                                                               3,192,912              3,263,198
- -----------------------------------------------------------------------------------------------------------------------------------
Investments and funds (Notes 1 and 2):
     Decommissioning fund, at market                                                                 154,061                150,668
     Deposit on Rocky Mountain transactions, at cost                                                  72,698                 68,032
     Bond, reserve and construction funds, at market                                                  26,505                 28,691
     Investment in associated companies, at cost                                                      28,244                 22,918
- -----------------------------------------------------------------------------------------------------------------------------------
Total investments and funds                                                                          281,508                270,309
- -----------------------------------------------------------------------------------------------------------------------------------
Current assets:
     Cash and temporary cash investments, at cost (Note 1)                                           151,311                275,786
     Other short-term investments, at market                                                          94,301                 88,589
     Receivables                                                                                      91,798                 73,039
     Inventories, at average cost (Note 1)                                                            83,219                 81,768
     Notes receivable (Note 5)                                                                       310,662                340,396
     Prepayments and other current assets                                                              3,841                  4,346
- -----------------------------------------------------------------------------------------------------------------------------------
Total current assets                                                                                 735,132                863,924
- -----------------------------------------------------------------------------------------------------------------------------------
Deferred charges:
     Premium and loss on reacquired debt, being amortized (Note 5)                                   151,118                162,690
     Deferred amortization of capital leases (Note 4)                                                109,567                107,254
     Deferred debt expense, being amortized (Note 1)                                                  18,376                 16,475
     Deferred nuclear outage costs, being amortized (Note 1)                                          22,778                 17,313
     Other                                                                                             7,160                 11,668
- -----------------------------------------------------------------------------------------------------------------------------------
Total deferred charges                                                                               308,999                315,400
- -----------------------------------------------------------------------------------------------------------------------------------
Total assets                                                                                     $ 4,518,551            $ 4,712,831
===================================================================================================================================


The accompanying notes are an integral part of these financial statements.

                                       54


BALANCE SHEETS




                                                                                                            (dollars in thousands)
                                                                                                          2002                2001
====================================================================================================================================
Equity and Liabilities
Capitalization (see accompanying statements):
                                                                                                                    
     Patronage capital and membership fees (Note 1)                                                   $  371,818          $  367,668
     Long-term debt                                                                                    2,835,997           2,929,316
     Obligation under capital leases (Note 4)                                                            358,676             373,837
     Obligation under Rocky Mountain transactions                                                         72,698              68,032
- ------------------------------------------------------------------------------------------------------------------------------------
Total capitalization                                                                                   3,639,189           3,738,853
- ------------------------------------------------------------------------------------------------------------------------------------
Current liabilities:
     Long-term debt and capital leases due within one year (Note 5)                                      140,241             127,621
     Accounts payable                                                                                     53,283              68,023
     Notes payable (Note 5)                                                                              297,776             353,680
     Power marketer reserve (Note 9)                                                                           -              36,000
     Accrued interest                                                                                      6,958               7,793
     Other current liabilities                                                                            13,267              16,461
- ------------------------------------------------------------------------------------------------------------------------------------
Total current liabilities                                                                                511,525             609,578
- ------------------------------------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities:
     Gain on sale of plant, being amortized (Note 4)                                                      48,383              50,858
     Net benefit of sale of income tax benefits, being amortized (Note 1)                                      -               2,002
     Net benefit of Rocky Mountain transactions, being amortized (Note 1)                                 76,448              79,633
     Decommissioning reserve (Note 1)                                                                    166,299             174,506
     Interest rate swap arrangements (Note 2)                                                             58,443              36,859
     Other                                                                                                18,264              20,542
- ------------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities                                                             367,837             364,400
- ------------------------------------------------------------------------------------------------------------------------------------
Total equity and liabilities                                                                          $4,518,551          $4,712,831
====================================================================================================================================
Commitments and Contingencies (Notes 1, 5 and 9)
- ------------------------------------------------------------------------------------------------------------------------------------


                                       55


STATEMENTS OF CAPITALIZATION
December 31, 2002 and 2001



                                                                                                          (dollars in thousands)
                                                                                                           2002            2001
====================================================================================================================================
Long-term debt (Note 5):
     Mortgage notes payable to the Federal Financing Bank (FFB) at interest
         rates varying from 2.81% to 8.43% (average rate of 6.34% at December
         31, 2002) due
                                                                                                                 
         in quarterly installments through 2023                                                       $ 2,050,969      $ 2,141,746
     Mortgage notes payable to Rural Utilities Service (RUS) at an interest rate of
         5% due in monthly installments through 2021                                                       12,473           12,919
     Mortgage notes issued in conjunction with the sale by public authorities of pollution
         control revenue bonds (PCBs):
         o Series 1992A
             Serial bonds, 6.20% to 6.80%, due serially from 2003 through 2012                             94,915          101,555*
         o Series 1993
             Serial bonds, 4.60% to 5.25%, due serially from 2003 through 2013                             30,510           32,060*
         o Series 1993A
             Adjustable tender bonds, 1.50%, due 2003 through 2016                                        186,710          189,660*
         o Series 1993B
             Serial bonds, 4.60% to 5.05%, due serially from 2003 through 2008                             86,525           96,900*
         o Series 1994
             Serial bonds, 6.25% to 7.125%, due serially from 2003 through 2015                             8,560            8,560*
             Term bonds, 7.15%, due 2016 to 2021                                                           11,550           11,550*
         o Series 1994A
             Adjustable tender bonds, 1.60%, due 2003 to 2019                                             115,710          118,270*
         o Series 1994B
             Serial bonds, 6.25% to 6.45%, due serially from 2003 through 2005                              5,670            5,970*
         o Series 1998A and 1998B
             Adjustable tender bonds, 1.05% to 1.70%, due 2019                                            216,925          216,925*
         o Series 1999A and 1999B
             Adjustable tender bonds, 1.80%, due 2020                                                      88,775           88,775
         o Series 2000
             Adjustable tender bonds, 1.80%, due 2021                                                      21,950           21,950
         o Series 2001
             Adjustable tender bonds, 1.80%, due 2022                                                      22,825           22,825
         o Series 2002A and 2002B
             Auction rate bonds, 1.40% to 1.45%, due 2018                                                  91,990                -
     Unsecured notes issued in conjunction with the sale by public authorities of pollution
         control revenue bonds:
         o Series 2002 and 2002C
             Adjustable tender bonds, 1.60% to 1.80%, due 2018                                             30,075                -
     CoBank, ACB notes payable:
         o Headquarters mortgage note payable: fixed at 3.90% through February 2, 2003,
             due in quarterly installments through January 1, 2009                                          2,433            2,823
         o Transmission mortgage note payable: fixed at 3.81% through March 2, 2003, due in
             bimonthly installments through November 1, 2018                                                1,705            1,740
         o Transmission mortgage note payable: fixed at 3.81% through March 2, 2003, due in
             bimonthly installments through September 1, 2019                                               6,597            6,713
         o Medium Term Loan
             Variable rate, due March 31, 2003                                                                  -           46,065
     National Rural Utilities Cooperative Finance Corporation mortgage note payable:
         o Medium-term loan, Fixed rate, due March 31, 2003                                                     -           46,065
- ------------------------------------------------------------------------------------------------------------------------------------
                                                                                                        3,086,867        3,173,071
     Less: Portion (16.86%) of PCBs assumed by Georgia Transmission Corporation                          (127,673)        (131,784)
- ------------------------------------------------------------------------------------------------------------------------------------
     Total long-term debt, net                                                                          2,959,194        3,041,287
         Less: Long-term debt due within one year                                                        (123,197)        (111,971)
- ------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt, excluding amount due within one year                                              2,835,997        2,929,316
Obligation under capital leases, long-term (Note 4)                                                       358,676          373,837
Obligation under Rocky Mountain transactions, long-term (Note 1)                                           72,698           68,032
Patronage capital and membership fees (Note 1)                                                            371,818          367,668
- ------------------------------------------------------------------------------------------------------------------------------------
Total capitalization                                                                                  $ 3,639,189      $ 3,738,853
====================================================================================================================================


The accompanying notes are an integral part of these financial statements.

                                       56


STATEMENTS OF CASH FLOWS

For the years ended December 31, 2002, 2001 and 2000



                                                                                                   (dollars in thousands)

                                                                                             2002             2001           2000
====================================================================================================================================
Cash flows from operating activities:
     Net margin                                                                           $  17,540       $  18,417       $  19,978
- ------------------------------------------------------------------------------------------------------------------------------------
     Adjustments to reconcile net margin to net cash provided by
         operating activities:
                                                                                                                   
             Depreciation and amortization                                                  189,607         198,113         213,351
             Interest on decommissioning reserve                                                851             168          11,007
             Amortization of deferred gains                                                  (2,475)         (2,475)         (2,475)
             Amortization of net benefit of sale of income tax benefits                      (5,188)        (11,195)        (11,195)
             Allowance for equity funds used during construction                               (452)           (290)           (204)
             Deferred income taxes                                                                -         (63,485)            283
             Gain on sale of generation equipment                                                 -            (221)              -
             Other                                                                           (1,274)          1,215             453
     Change in operating assets and liabilities:
             Receivables                                                                    (18,758)         70,315         (33,649)
             Inventories                                                                     (1,451)         (6,379)         14,377
             Prepayments and other current assets                                               505             204           1,832
             Accounts payable                                                               (14,740)        (34,596)         45,975
             Power marketer reserve                                                         (36,000)         36,000               -
             Accrued interest                                                                  (835)        (59,601)         17,192
             Accrued and withheld taxes                                                        (622)              4             648
             Other current liabilities                                                        5,936         (14,770)         13,698
             Deferred nuclear outage costs                                                  (29,139)        (19,167)        (24,481)
- ------------------------------------------------------------------------------------------------------------------------------------
     Total adjustments                                                                       85,965          93,840         246,812
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities                                                   103,505         112,257         266,790
- ------------------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
         Property additions                                                                (100,145)        (69,824)        (70,738)
         Activity in decommissioning fund - Purchases                                      (812,473)       (532,355)       (735,352)
                                          - Proceeds                                        800,960         530,660         722,620
         Activity in bond, reserve and construction funds - Purchases                             -         (22,710)        (12,699)
                                                          - Proceeds                          1,677          23,699          15,319
         Increase in other short-term investments                                            (5,516)         (6,423)         (4,181)
         Increase in investment in associated organizations                                  (6,057)         (2,190)         (2,078)
         Decrease (increase) in notes receivable                                                 63               2            (143)
         Other - generation equipment deposits                                                    -         (16,783)        (42,929)
         Proceeds from sale of generation equipment                                               -          26,204               -
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities                                                      (121,491)        (69,720)       (130,181)
- ------------------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
         Debt proceeds, net                                                                  31,772          22,931          26,260
         Debt payments                                                                     (112,028)       (127,381)       (100,729)
         (Decrease) increase in notes payable (Note 5)                                      (55,904)        275,198          (9,997)
         Increase (decrease) in note receivable (Note 5)                                     29,671        (268,121)         55,665
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash used in financing activities                                                      (106,489)        (97,373)        (28,801)
- ------------------------------------------------------------------------------------------------------------------------------------
Net (decrease) increase in cash and temporary cash investments                             (124,475)        (54,836)        107,808
Cash and temporary cash investments at beginning of year                                    275,786         330,622         222,814
- ------------------------------------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year                                        $ 151,311       $ 275,786       $ 330,622
====================================================================================================================================
Supplemental cash flow information:
     Cash paid for -
         Interest (net of amounts capitalized)                                            $ 212,787       $ 278,785       $ 219,702
         Income taxes                                                                             -               -               -
     Non cash transaction -
         Capital lease                                                                            -               -         126,990
====================================================================================================================================


The accompanying notes are an integral part of these financial statements.

                                       57


STATEMENTS  OF  PATRONAGE  CAPITALAND  MEMBERSHIP  FEES  AND  ACCUMULATED  OTHER
COMPREHENSIVE MARGIN

For the years ended December 31, 2002, 2001 and 2000



                                                                                             (dollars in thousands)

                                                                               Patronage        Accumulated
                                                                               Capital and         Other
                                                                               Membership      Comprehensive
                                                                               Fees            Margin (Loss)     Total
====================================================================================================================================
                                                                                                      
Balance at December 31, 1999                                                  $ 371,634         $ (1,609)      $ 370,025
- ------------------------------------------------------------------------------------------------------------------------------------
Components of comprehensive margin in 2000
     Net margin                                                                  19,978                           19,978
     Unrealized gain on available-for-sale securities                                              2,679           2,679
- ------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive margin                                                                                        22,657
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000                                                    391,612            1,070         392,682
- ------------------------------------------------------------------------------------------------------------------------------------
Components of comprehensive margin in 2001
     Net margin                                                                  18,417                           18,417
     Cumulative effect of accounting change to record unrealized
         loss on interest rate swap arrangements as of January 1, 2001                           (33,515)        (33,515)
     Unrealized loss on interest rate swap arrangements                                           (3,344)         (3,344)
     Unrealized gain on available-for-sale securities                                                965             965
     Unrealized loss on financial gas hedges                                                      (7,537)         (7,537)
- ------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive margin                                                                                       (25,014)
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001                                                    410,029          (42,361)        367,668
- ------------------------------------------------------------------------------------------------------------------------------------
Components of comprehensive margin in 2002
     Net margin                                                                  17,540                           17,540
     Unrealized loss on interest rate swap arrangements                                          (21,584)        (21,584)
     Unrealized loss on available-for-sale securities                                               (313)           (313)
     Unrealized gain on financial gas hedges                                                       8,507           8,507
- ------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive margin                                                                                         4,150
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002                                                  $ 427,569        $ (55,751)      $ 371,818
====================================================================================================================================


The accompanying notes are an integral part of these financial statements.

                                       58


NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2002, 2001 and 2000



1.  Summary of significant accounting policies:
a. Business description

     Oglethorpe  Power  Corporation   (Oglethorpe)  is  an  electric  membership
corporation   incorporated  in  1974  and  headquartered  in  suburban  Atlanta.
Oglethorpe  provides wholesale electric power, on a not-for-profit  basis, to 39
of Georgia's 42 Electric  Membership  Corporations  (EMCs) from a combination of
generating units totaling 3,657.9  megawatts (MW) of capacity and power purchase
agreements  totaling  550  MW  of  capacity.   These  39  electric  distribution
cooperatives   (Members)  in  turn  distribute  energy  on  a  retail  basis  to
approximately 3.7 million people across  two-thirds of the State.  Oglethorpe is
the  nation's  largest  electric  cooperative  in terms of  operating  revenues,
assets, kilowatt-hour sales and, through its Members, consumers served.

b. Basis of accounting

     Oglethorpe  follows  generally  accepted  accounting   principles  and  the
practices  prescribed  in the Uniform  System of Accounts of the Federal  Energy
Regulatory  Commission  (FERC) as modified  and  adopted by the Rural  Utilities
Service (RUS).
     The  preparation  of financial  statements  in  conformity  with  generally
accepted  accounting  principles  requires  management  to  make  estimates  and
assumptions  that  affect the  reported  amounts of assets and  liabilities  and
disclosure of contingent assets and liabilities as of December 31, 2002 and 2001
and the  reported  amounts of revenues  and expenses for each of the three years
ending December 31, 2002. Actual results could differ from those estimates.

c. Patronage capital and membership fees

     Oglethorpe is organized and operates as a  cooperative.  The Members paid a
total of $195 in membership fees. Patronage capital includes retained net margin
of Oglethorpe and other comprehensive  margin,  excluding securities held in the
decommissioning  fund. For 2002,  2001 and 2000 the  unrealized  gain or loss in
other  comprehensive  margin was ($55,751,000),  ($42,361,000),  and $1,070,000,
respectively.  (See "Fair value of financial instruments" in Note 2.) Any excess
of revenue over  expenditures  from operations is treated as advances of capital
by the  Members  and is  allocated  to  each  of  them  on the  basis  of  their
electricity purchases from Oglethorpe.
     Any distributions of patronage capital are subject to the discretion of the
Board of  Directors,  subject  to  Mortgage  Indenture  requirements.  Under the
Mortgage  Indenture,  Oglethorpe is prohibited  from making any  distribution of
patronage  capital  to the  Members  if, at the time  thereof  or giving  effect
thereto,  (i) an event of default  exists  under the  Mortgage  Indenture,  (ii)
Oglethorpe's equity as of the end of the immediately preceding fiscal quarter is
less than 20% of  Oglethorpe's  total  capitalization,  or (iii)  the  aggregate
amount  expended for  distributions  on or after the date on which  Oglethorpe's
equity first reaches 20% of  Oglethorpe's  total  capitalization  exceeds 35% of
Oglethorpe's   aggregate  net  margins   earned  after  such  date.   This  last
restriction,   however  will  not  apply  if,   after  giving   effect  to  such
distribution,  Oglethorpe's  equity as of the end of the  immediately  preceding
fiscal quarter is not less than 30% of Oglethorpe's total capitalization.

d. Margin policy

     For the years 2000 through 2002 under the  Mortgage  Indenture,  Oglethorpe
was required to produce a Margins for Interest (MFI) Ratio of at least 1.10.

e. Operating revenues

     Operating  revenues  consist  primarily of  electricity  sales  pursuant to
long-term wholesale power contracts which Oglethorpe  maintains with each of its
Members.  These wholesale power contracts obligate each Member to pay Oglethorpe
for  capacity and energy  furnished  in  accordance  with rates  established  by
Oglethorpe.  Energy  furnished is determined  based on meter  readings which are
conducted  at the end of each month.  Actual  energy  costs are  compared,  on a
monthly basis, to the billed energy costs, and an adjustment to revenues is made
such that energy revenues are equal to actual energy costs.
     Revenues  from  Cobb EMC and  Jackson  EMC,  two of  Oglethorpe's  Members,
accounted for 11.3% and 11.2% in 2002,  11.6% and 12.1% in 2001, 11.9% and 11.8%
in 2000, respectively, of Oglethorpe's total operating revenues.

f. Nuclear fuel cost

     The cost of nuclear fuel, including a provision for the disposal of spent
fuel, is being amortized to fuel expense based on usage. The total nuclear fuel
expense for 2002, 2001 and 2000 amounted to $43,931,000, $47,143,000 and
$47,105,000, respectively.
     Contracts  with the U.S.  Department  of Energy (DOE) have been executed to
provide for the permanent  disposal of spent  nuclear fuel.  DOE failed to begin
disposing  of spent fuel in  January  1998 as  required  by the  contracts,  and
Georgia  Power  Company  (GPC),  as agent for the  co-owners  of the plants,  is
pursuing legal remedies against DOE for breach of contract. Effective June 2000,
an on-site dry storage  facility  for Plant Hatch became  operational.  Based on
normal  operations and retention  of all  spent  fuel in the reactor, sufficient

                                       59


capacity is believed to be available to continue dry storage operations at Plant
Hatch for the life of the  plant.  Plant  Vogtle's  spent  fuel pool  storage is
expected to be sufficient  until 2014.  Oglethorpe  expects that  procurement of
on-site dry storage at Plant Vogtle will commence in sufficient time to maintain
full-core discharge capability to the spent fuel pool.

     The Energy Policy Act of 1992 required that  utilities  with nuclear plants
be assessed  over a 15-year  period an amount  which will be used by DOE for the
decontamination and  decommissioning of its nuclear fuel enrichment  facilities.
The  amount of each  utility's  assessment  was based on its past  purchases  of
nuclear fuel  enrichment  services  from DOE.  Based on its  ownership in Plants
Hatch and Vogtle, Oglethorpe has a remaining nuclear fuel asset of approximately
$6,759,000,  which is being  amortized  to nuclear  fuel expense over the next 6
years.  Oglethorpe  has also recorded an  obligation  to DOE which  approximated
$4,723,000 at December 31, 2002.

g. Nuclear decommissioning

     Nuclear decommissioning cost estimates are based on site studies and assume
prompt dismantlement and removal of both the radiated and non-radiated  portions
of the plant from  service.  Actual  decommis-sioning  costs may vary from these
estimates because of changes in the assumed date of decommissioning,  changes in
regulatory requirements,  changes in technology,  and changes in costs of labor,
materials and equipment. Information with respect to Oglethorpe's portion of the
estimated costs of decommissioning co-owned nuclear facilities is as follows:



==============================================================================================================
                                                                   (dollars in thousands)

                                               Hatch            Hatch              Vogtle            Vogtle
                                            Unit No. 1       Unit No. 2           Unit No. 1       Unit No. 2
==============================================================================================================
                                                                                              
Year of site study                               2000               2000               2000               2000
Expected start date
     of decommissioning                          2034               2038               2027               2029
Estimated costs based on site study:
In year 2000 dollars                        $ 139,000          $ 175,000          $ 137,000          $ 171,000
In projected future
     dollars                                  666,000          1,007,000            475,000            650,000
==============================================================================================================


     In projecting  future costs,  the escalation rate for labor,  materials and
equipment was assumed to be 4.72%.

     Oglethorpe's objective is to provide a reserve for nuclear decommis-sioning
at least  equal to the  Nuclear  Regulatory  Commission  (NRC)  minimum  funding
requirement and to fund, on a periodic basis,  such minimum in an external trust
fund. The external trust fund is maintained in compliance with NRC regulation to
provide  for  minimum   funding  levels  based  on  average   expected  cost  to
decommission  only the  radiated  portions  of a typical  nuclear  facility.  At
December  31,  2002,  the NRC  minimum  funding  requirement  was  approximately
$177,828,000. In calculating the minimum funding requirement,  future costs were
projected  using  the  same  escalation  rate  used in the site  study  estimate
referred  to  above  and were  discounted  at a rate of 8%.  Oglethorpe  has not
recorded any provision for decommissioning  during the years 2002, 2001 and 2000
because  its  decommissioning  reserve  has  exceeded  the NRC  minimum  funding
requirement.  At December 31, 2002, the balance in the  decommissioning  reserve
was  approximately  $11.5 million less than the NRC minimum funding  requirement
primarily  due to unrealized  losses in the market value of certain  investments
held  in  Oglethorpe's  external   decommissioning  trust  fund.  Oglethorpe  is
currently  examining the allocation of funding between nuclear units, a possible
license  extension  at Plant  Vogtle  and  investment  earnings  assumptions  to
determine whether additional contributions to the external fund may be necessary
in the  future.  Oglethorpe's  management  believes  that any  increase  in cost
estimates of decommissioning can be recovered in future rates.

h. Depreciation

     Depreciation is computed on additions when they are placed in service using
the composite straight-line method. Annual depreciation rates in effect in 2002,
2001 and 2000 were as follows:

================================================================================
                              2002                 2001                2000
================================================================================
Steam production                1.98%                1.98%                1.98%
Nuclear production              2.52%                2.68%                2.68%
Hydro production                2.00%                2.00%                2.00%
Other production                3.75%                3.75%                3.75%
Transmission                    2.75%                2.75%                2.75%
General                   2.00-33.33%          2.00-33.33%          2.00-33.33%
================================================================================

     In January 2002, the operating  license for Plant Hatch was extended for 20
years. Due to the license  extension,  effective  January 2002, the depreciation
rate for Plant Hatch has been revised from 2.99% to 1.92%.

                                       60


i. Electric plant

     Electric plant is stated at original  cost,  which is the cost of the plant
when  first  dedicated  to  public  service,  plus  the  cost of any  subsequent
additions. Cost includes an allowance for the cost of equity and debt funds used
during  construction.  The cost of equity  and debt funds is  calculated  at the
embedded cost of all such funds.
     Maintenance and repairs of property and  replacements and renewals of items
determined   to  be  less  than  units  of  property  are  charged  to  expense.
Replacements  and  renewals  of items  considered  to be units of  property  are
charged to the plant  accounts.  At the time  properties  are  disposed  of, the
original cost, plus cost of removal,  less salvage of such property,  is charged
to the accumulated provision for depreciation.

j. Bond, reserve and construction funds

     Bond,  reserve and construction  funds for pollution  control revenue bonds
(PCBs) are maintained as required by Oglethorpe's  bond  agreements.  Bond funds
serve as payment clearing accounts,  reserve funds maintain amounts equal to the
maximum annual debt service of each bond issue and construction  funds hold bond
proceeds  for which  construction  expenditures  have not yet been  made.  As of
December 31, 2002 and 2001, substantially all of the funds were invested in U.S.
Government securities.

k. Cash and temporary cash investments

     Oglethorpe  considers  all  temporary  cash  investments  purchased  with a
maturity  of  three  months  or  less  to be cash  equivalents.  Temporary  cash
investments  with  maturities of more than three months are  classified as other
short-term investments.
     At December 31, 2002 and 2001, $30,101,000 and $22,940,000 were utilized in
January 2003 and 2002 for payment of principal on certain PCBs, respectively.

l. Inventories

     Oglethorpe  maintains  inventories  of fossil fuels and spare parts for its
generation plants.  These inventories are stated at weighted average cost on the
accompanying balance sheets.
     At December 31, 2002 and 2001,  fossil fuels  inventories  were $21,011,000
and $18,829,000,  respectively. Inventories for spare parts at December 31, 2002
and 2001 were $62,208,000 and $62,939,000, respectively.

m. Deferred charges

     Oglethorpe  accounts  for nuclear  refueling  outage  costs on a normalized
basis. Under this method of accounting,  refueling outage costs are deferred and
subsequently  amortized  to expense over the  18-month  operating  cycle of each
unit.  Deferred  nuclear  outage  costs at  December  31,  2002  and  2001  were
$22,778,000 and $17,313,000, respectively.
     Oglethorpe  accounts  for debt  issuance  cost as  deferred  debt  expense.
Deferred  debt expense is being  amortized to expense on a  straight-line  basis
over the life of the respective debt issues.

n. Deferred credits

     In April 1982,  Oglethorpe sold to three  purchasers  certain of the income
tax benefits  associated  with Scherer Unit No.1 and related  common  facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act of
1981.  Oglethorpe  received a total of approximately  $110,000,000 from the safe
harbor  lease  transactions.  Oglethorpe  accounted  for the net  benefits  as a
deferred  credit and  amortized  the amount over the 20-year term of the leases.
The amortization of the safe harbor lease ended in March 2002.
     In December 1996 and January 1997,  Oglethorpe entered into long-term lease
transactions for its 74.6% undivided ownership interest in Rocky Mountain pumped
storage hydro facility (Rocky  Mountain),  through a wholly owned  subsidiary of
Oglethorpe,  Rocky Mountain Leasing  Corporation  (RMLC). The lease transactions
are characterized as a sale and lease-back for income tax purposes,  but not for
financial reporting purposes. As a result of these leases, Oglethorpe recorded a
net benefit of $95,560,000  which was deferred and is being  amortized to income
over the 30-year lease-back period.

o. Regulatory assets and liabilities

     Oglethorpe  is  subject  to  the   provisions  of  Statement  of  Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation." Regulatory assets represent certain costs that are assured to be
recoverable by Oglethorpe  from the Members in the future through the ratemaking
process. Regulatory liabilities represent certain items of income that are being
retained by  Oglethorpe  and that will be applied in the future to reduce Member
revenue  requirements.  The  following  regulatory  assets  and liabilities were


                                       61


reflected on the accompanying balance sheets as of December 31, 2002 and 2001:

                                                         (dollars in thousands)

                                                         2002            2001
================================================================================
Premium and loss on reacquired debt                   $ 151,118       $ 162,690
Deferred amortization of capital leases                 109,567         107,254
Discontinued projects                                     3,430           6,463
Other regulatory assets                                  25,424          20,461
Net benefit of sale of income tax benefits                    -          (2,002)
Net benefit of Rocky Mountain transactions              (76,448)        (79,633)
- --------------------------------------------------------------------------------
                                                      $ 213,091       $ 215,233
================================================================================

     In the event that  competitive  or other  factors  result in cost  recovery
practices under which  Oglethorpe can no longer apply the provisions of SFAS No.
71,  Oglethorpe  would be  required  to  eliminate  all  regulatory  assets  and
liabilities  that could not otherwise be recognized as assets and liabilities by
businesses in general.  In addition,  Oglethorpe  would be required to determine
any impairment to other assets, including plant, and write-down those assets, if
impaired, to their fair value.

p. Presentation

     Certain  prior year  amounts  have been  reclassified  to conform  with the
current year presentation.

q. New accounting pronouncements

     In June of 2001,  the Financial  Accounting  Standards  Board (FASB) issued
Statement of Financial  Accounting  Standards  (SFAS) No. 143,  "Accounting  for
Asset Retirement  Obligations." The statement provides  accounting and reporting
standards  for  recognizing  obligations  related to costs  associated  with the
retirement of long-lived assets.  SFAS No. 143 requires  obligations  associated
with the retirement of long-lived assets to be recognized at their fair value in
the period in which they are incurred if a reasonable estimate of fair value can
be made. The fair value of the asset  retirement costs is capitalized as part of
the  carrying  amount of the  long-lived  asset and  subsequently  allocated  to
expense using a systematic and rational method over the asset's useful life. Any
subsequent  changes to the fair value of the liability due to passage of time or
changes in the amount or timing of  estimated  cash  flows is  recognized  as an
accretion expense.

     Effective January 1, 2003,  Oglethorpe adopted SFAS No. 143. The fair value
of the legal  obligation  recognized  under  SFAS No. 143  primarily  relates to
Oglethorpe's nuclear facilities.  In addition,  Oglethorpe recognized retirement
obligations for ash handling facilities at the coal-fired plants and solid waste
landfills  located at certain  generating  facilities.  The cumulative effect of
adoption  resulted in Oglethorpe  recording a regulatory  asset of approximately
$23,700,000;   capitalized   asset   retirement   costs,   net  of   accumulated
amortization,  of  approximately  $45,100,000  and  increased  asset  retirement
obligations of  approximately  $68,800,000.  At December 31, 2002,  Oglethorpe's
recognized  liability for nuclear  decommissioning was $166,299,000.  Oglethorpe
continues to  recognize  the  accumulated  removal  costs for other  obligations
(regulatory   liabilities)   as  part  of  the  accumulated   depreciation   and
amortization reserve in accordance with RUS prescribed  regulatory treatment for
these costs. At December 31, 2002, that amount was $38,200,000.

     Under SFAS No. 71, Oglethorpe may record an offsetting  regulatory asset or
liability to reflect the  difference  in timing of  recognition  of the costs of
decommissioning for financial statement purposes and for ratemaking purposes for
both  the   cumulative   effect  of  adoption  and  for  future  periods  timing
differences.  While RUS has not issued regulatory  guidance for adoption of SFAS
No.  143,  Oglethorpe's  management  expects to receive  permission  from RUS to
implement the provisions SFAS No. 71 with respect to timing differences  arising
from cost recognition under SFAS No. 143 and for ratemaking purposes. Oglethorpe
estimates that the annual difference will be approximately $5,000,000.

     In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No.  4,  44  and  64,   Amendment  of  FASB  Statement  No.  13,  and  Technical
Corrections." Among other things, this statement rescinds SFAS No. 4, "Reporting
Gains and Losses from  Extinguishment  of Debt" (SFAS No. 4), which required all
gains and losses from  extinguishment of debt to be aggregated and, if material,
classified as an extraordinary  item, net of the related income tax effect. As a
result,  the criteria in Accounting  Principles Board Opinion No. 30, "Reporting
the Results of  Operations - Reporting the Effects of Disposal of a Segment of a
Business,  and  Extraordinary,  Unusual and  Infrequently  Occurring  Events and
Transactions,"  which requires gains and losses on extinguishments of debt to be
classified as income or loss from  continuing  operations,  will now be applied.
SFAS  No.  71  permits   Oglethorpe  to  record  gains  and  losses  from  early
extinguishment  of  debt  as  regulatory  assets  and  regulatory   liabilities.
Oglethorpe   anticipates   that  any  future   gains  and   losses   from  early
extinguishment  of debt will be recorded  as  regulatory  assets and  regulatory
liabilities.  Oglethorpe is required to adopt SFAS No. 145 effective  January 1,
2003.

                                       62

     In July  2002,  the  FASB  issued  SFAS  No.  146,  "Accounting  for  Costs
Associated  with Exit or Disposal  Activities"  (SFAS No. 146),  which addresses
financial  accounting and reporting for costs  associated  with exit or disposal
activities and nullifies  Emerging Issues Task Force Issue No. 94-3,  "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring"  (EITF 94-3). The
principal  difference  between  SFAS No.  146 and EITF 94-3  relates to SFAS No.
146's  requirements for recognition of a liability for a cost associated with an
exit or disposal  activity.  SFAS No. 146 requires  that a liability  for a cost
associated with an exit or disposal activity be recognized when the liability is
incurred.  Under EITF 94-3, a liability for an exit cost as generally defined in
EITF 94-3 was recognized at the date of an entity's  commitment to an exit plan.
Oglethorpe  is required to adopt SFAS No. 146  effective  January 1, 2003.  This
pronouncement currently does not affect Oglethorpe's financial statements.

     In November 2002,  the FASB issued  Interpretation  No. 45,  Accounting and
Disclosure  Requirements  for  Guarantees.  The  disclosure  provisions  of  the
interpretation are effective for financial statements of annual periods that end
after December 15, 2002. In addition, Interpretation No. 45 requires recognition
of a liability at inception for certain new or modified  guarantees issued after
or modified  after  December 31, 2002.  As of December 31, 2002,  in addition to
guarantees  disclosed  in Note 5 for a loan to  Chattahoochee  EMC and for  PCBs
assumed by Georgia Transmission Corporation (GTC) in connection with a corporate
restructuring,  Oglethorpe  is liable on a  contingent  basis for certain  other
contractual obligations.

     All of these  contingent  liabilities are in connection with the generation
facilities under  construction owned by Talbot EMC and Chattahoochee EMC and the
related  operational  contracts.  The contingent  liabilities under construction
contracts for Talbot EMC and Chattahoochee EMC were $15,000,000 and $15,000,000,
respectively.  Oglethorpe  also  remains  liable,  on a  contingent  basis,  for
obligations under other operational agreements relating to the Chattahoochee EMC
facility.  The combined  obligation  under these agreements  totals  $94,000,000
through 2006, and $20,000,000 annually thereafter through approximately 2015. As
discussed in Note 5, at the time the RUS loan is funded, Oglethorpe will acquire
the generation  facilities  owned by Talbot EMC and  Chattahoochee  EMC. At that
point,  the related  contingent  liabilities  will become direct  obligations of
Oglethorpe.

2.  Fair value of financial instruments:

A detail of the estimated fair values of Oglethorpe's  financial  instruments as
of December 31, 2002 and 2001 is as follows:

================================================================================
                                             Fair                       Fair
                                Cost        Value          Cost         Value
================================================================================
Cash and temporary
   cash investments:
   Commercial paper        $   150,247   $   150,247   $  238,514   $   238,514
   Cash and money
     market securities           1,064         1,064       37,272        37,272
- -------------------------------------------------------------------------------
Total                      $   151,311   $   151,311   $  275,786   $   275,786
================================================================================
Other short term
   investments             $    92,793   $    94,301   $   87,277   $    88,589
================================================================================
Bond, reserve and
   construction funds:
   U. S. Government
     securities            $     7,833   $     8,067   $   20,860   $    21,583
   Repurchase
     agreements                 18,458        18,438        7,108         7,108
- -------------------------------------------------------------------------------
Total                      $    26,291   $    26,505   $   27,968   $    28,691
================================================================================
Decommissioning fund:
   U. S. Government
     securities            $    38,525   $    39,884   $   30,767   $    31,088
   Foreign government
     securities                    616           680        1,514         1,542
   Commercial paper                  -             -        4,259         4,261
   Corporate bonds              12,242        13,098       13,036        13,575
   Equity securities            66,206        62,533       71,176        77,062
   Asset-backed
     securities                  3,905         3,979        9,389         9,470
   Other bonds                   2,364         2,422          -             -
   Cash and money
     market securities          31,465        31,465       13,670        13,670
- -------------------------------------------------------------------------------
Total                      $   155,323   $   154,061   $  143,811   $   150,668
================================================================================

Long-term debt             $ 2,835,997   $ 3,254,782   $2,929,316   $ 3,118,974
================================================================================
Interest rate swap         $         -   $   (58,443)  $        -   $   (36,859)
================================================================================
Financial gas
   hedges                  $         -   $       970   $        -   $    (7,537)
================================================================================

                                       63


     The  contractual  maturities  of  debt  securities  available  for  sale at
December 31, 2002 and 2001 are as follows:

================================================================================
                             (dollars in thousands)

                                         2002                     2001
                                                   Fair                   Fair
                                      Cost        Value       Cost        Value
================================================================================
Due within one year                  $35,698     $35,917     $14,215     $14,211
Due after one year
     through five years               19,565      20,118      31,965      33,080
Due after five years
     through ten years                11,425      12,445      14,511      14,858
Due after ten years                   15,527      16,366      21,983      22,217
- --------------------------------------------------------------------------------
                                     $82,215     $84,846     $82,674     $84,366
================================================================================

     Oglethorpe uses the methods and assumptions described below to estimate the
fair value of each class of financial  instruments.  For cash and temporary cash
investments,  the  carrying  amount  approximates  fair  value  because  of  the
short-term  maturity  of  those  instruments.  The fair  value  of  Oglethorpe's
long-term debt and the swap arrangements is estimated based on the quoted market
prices  for the same or  similar  issues  or on the  current  rates  offered  to
Oglethorpe for debt of similar maturities.
     Effective January 1, 2001, Oglethorpe adopted SFAS No. 133, "Accounting for
Derivative   Instruments  and  Hedging  Activities."  The  standard  establishes
accounting  and reporting  requirements  for derivative  instruments,  including
certain  derivative  instruments  embedded  in  other  contracts,   and  hedging
activities.  It requires the  recognition  of certain  derivatives  as assets or
liabilities on Oglethorpe's  balance sheet and measurement of those  instruments
at fair value.  The  accounting  treatment of changes in fair value is dependent
upon whether or not a derivative  instrument is classified as a hedge and if so,
the type of hedge.
     Under the interest rate swap arrangements, Oglethorpe makes payments to the
counterparty based on the notional  principal at a contractually  fixed rate and
the counterparty makes payments to Oglethorpe based on the notional principal at
the existing  variable rate of the refunding  bonds. The differential to be paid
or  received  is accrued  as  interest  rates  change  and is  recognized  as an
adjustment to interest  expense.  Oglethorpe  entered into the swap arrangements
for the  purpose of securing a fixed rate lower than  otherwise  would have been
available to  Oglethorpe  had it issued  fixed rate bonds.  For the Series 1993A
notes, the notional  principal at December 31, 2002 was  $186,710,000  (includes
the portion  assumed by GTC) and the fixed swap rate is 5.67% (the variable rate
at December 31, 2002 and 2001 was 1.50% and 1.60%,  respectively).  With respect
to the Series  1994A  notes,  the  notional  principal  at December 31, 2002 was
$115,710,000  (includes  the portion  assumed by GTC) and the fixed swap rate is
6.01% (the  variable  rate at  December  31,  2002 and 2001 was 1.60% and 1.60%,
respectively).  The notional  principal  amount is used to measure the amount of
the swap  payments  and  does  not  represent  additional  principal  due to the
counterparty.  The swap arrangements extend for the life of the refunding bonds,
with  reductions in the  outstanding  principal  amounts of the refunding  bonds
causing corresponding reductions in the notional amounts of the swap payments.
     A portion  (16.86%) of the interest rate swap  arrangements  was assumed by
GTC in connection with a corporate restructuring.  Oglethorpe has classified its
portion of two  interest  rate swap  arrangements,  pursuant to SFAS No. 133, as
cash flow hedges.  Accordingly,  as of January 1, 2001, Oglethorpe recorded as a
cumulative effect adjustment an unrealized loss in other comprehensive margin of
$33,515,000  and a  corresponding  increase in other  liabilities.  Oglethorpe's
portion of the  estimated  fair value of the swap  arrangements  at December 31,
2002 was an unrealized loss of $58,443,000  representing  the estimated  payment
Oglethorpe would pay if the swap arrangements were terminated.
     Oglethorpe  has entered  into  natural  gas  financial  contracts  that are
classified,  pursuant  to SFAS 133,  as cash flow  hedges.  Oglethorpe  utilizes
natural gas financial  contracts in managing its exposure to fluctuations in the
market price of natural gas. The fair value of Oglethorpe's financial gas hedges
is based on the quoted market value for such natural gas financial contracts. At
December 31, 2002, Oglethorpe recorded an unrealized gain in other comprehensive
margin of  $8,507,000  and a  corresponding  increase  in other  current  assets
related to these natural gas financial contracts.
     Oglethorpe may be exposed to losses in the event of  nonperfor-mance of the
counterparties  to its  derivative  instruments,  but does not  anticipate  such
nonperformance.
     Under SFAS No. 115,  "Accounting for Certain Investments in Debt and Equity
Securities,"  investment  securities held by Oglethorpe are classified as either
available-for-sale  or  held-to-maturity.   Available-for-sale   securities  are
carried at market value with unrealized gains and losses, net of any tax effect,
added to or deducted from patronage  capital.  Unrealized  gains and losses from
investment   securities  held  in  the  decommissioning  fund,  which  are  also
classified  as  available-for-sale,  are directly  added to or deducted from the
decommissioning  reserve.  Held-to-maturity  securities are carried at cost. All
realized  and  unrealized  gains and losses are  determined  using the  specific
identification  method.  Gross  unrealized gains and losses at December 31, 2002
were $8,008,000 and $7,548,000,  respectively. Gross unrealized gains and losses
at December  31,  2001 were  $12,569,000  and  $3,677,000,  respectively.  Gross
unrealized   gains  and  losses  at  December  31,  2000  were  $15,937,000  and


                                       64


$8,681,000,  respectively.  For  2002,  2001 and  2000  proceeds  from  sales of
available-for-sale    securities   totaled   $802,637,000,    $554,359,000   and
$737,939,000,  respectively. Gross realized gains and losses from the 2002 sales
were $13,337,000 and $15,342,000,  respectively. Gross realized gains and losses
from the 2001  sales  were  $14,585,000  and  $17,378,000,  respectively.  Gross
realized  gains and losses  from 2000 sales were  $19,556,000  and  $16,086,000,
respectively.
     Investments  in associated  companies  were as follows at December 31, 2002
and 2001:

================================================================================
                             (dollars in thousands)
                                                   2002         2001
================================================================================
National Rural Utilities
     Cooperative Finance Corp. (CFC)             $13,476      $13,476
CoBank, ACB                                        3,373        3,419
Georgia Transmission
     Corporation (GTC)                             6,601        4,899
Georgia System Operations
     Corporation (GSOC)                            3,560          731
Other                                              1,234          393
- --------------------------------------------------------------------------------
Total                                            $28,244      $22,918
================================================================================

     The CFC  investments are in the form of capital term  certificates  and are
required in conjunction with Oglethorpe's membership in CFC. Accordingly,  there
is no market for these investments.  The investments in CoBank and GTC represent
capital  credits.  Any  distributions  of  capital  credits  are  subject to the
discretion of the Board of Directors of CoBank and GTC. The  investments in GSOC
represent loan advances. The loan repayment schedule ends in December 2008.
     The deposit,  which is carried at cost, on the Rocky Mountain  transactions
(see Note 1 where  discussed)  is invested in a guaranteed  investment  contract
which will be held to maturity (the end of the 30-year  lease-back  period).  At
maturity, Oglethorpe intends to repurchase tax ownership and to retain all other
rights of ownership  with respect to the plant if it is  advantageous  to do so.
The assets of RMLC are not  available  to pay  creditors  of  Oglethorpe  or its
affiliates.
     In  addition,  from  the  proceeds  of  the  Rocky  Mountain  transactions,
Oglethorpe  paid  $640,611,000  to a  financial  institution.  In  return,  this
financial   institution  undertook  to  pay  a  portion  of  Oglethorpe's  lease
obligations.  Both Oglethorpe's  interest in this payment undertaking  agreement
and the  corresponding  lease  obligations have been  extinguished for financial
reporting purposes.

3.  Income taxes:

     Oglethorpe is a not-for-profit  membership  corporation  subject to federal
and state  income  taxes.  As a taxable  electric  cooperative,  Oglethorpe  has
annually allocated its income and deductions between patronage and non-patronage
activities.

     In November 2001,  Oglethorpe  changed its Bylaws to provide  allocation of
patronage on a tax basis method  rather than the  historical  book basis method.
This  change  is  effective  starting  January  1,  2002.  Due to  this  change,
Oglethorpe anticipates that all future patronage source income will be offset by
the patronage exclusion.  Accordingly,  it is expected that substantially all of
Oglethorpe's  temporary  differences  will be  patronage  sourced and subject to
offset.  Therefore,  as of December 31, 2001, Oglethorpe reversed $63,485,000 of
net  deferred  income tax  liabilities  and has  recognized  this  reversal as a
deferred income tax credit of $63,485,000.

     Oglethorpe accounts for its income taxes pursuant to SFAS No. 109. SFAS No.
109 requires the  recognition  of deferred  tax assets and  liabilities  for the
expected  future  tax  consequences  of events  that have been  included  in the
financial statements or tax returns.

     A detail of the provision for income taxes in 2002,  2001 and 2000 is shown
as follows:

================================================================================
                                              (dollars in thousands)

                                        2002          2001            2000
================================================================================
Current
     Federal                          $    -        $      -        $   (283)
     State                                 -               -               -
- --------------------------------------------------------------------------------
                                           -               -            (283)
- --------------------------------------------------------------------------------
Deferred
     Federal                               -         (63,485)            283
     State                                 -               -               -
- --------------------------------------------------------------------------------
                                           -         (63,485)            283
- --------------------------------------------------------------------------------
Income taxes charged
     to operations                    $    -        $(63,485)       $      -
================================================================================

     The  difference  between the  statutory  federal  income tax rate on income
before income taxes and Oglethorpe's  effective income tax rate is summarized as
follows:

================================================================================
                                           2002             2001          2000
================================================================================
Statutory federal income tax rate          35.0%             35.0%        35.0%
Patronage exclusion                       (35.6%)          (376.0%)      (35.8%)
Other                                       0.6%              0.0%         0.8%
- --------------------------------------------------------------------------------
Effective income tax rate                   0.0%           (341.0%)        0.0%
================================================================================

                                       65


     The components of the net deferred tax  liabilities as of December 31, 2002
and 2001 were as follows:

================================================================================
                                                         (dollars in thousands)
                                                           2002          2001
===============================================================================
Deferred tax assets
   Net operating losses                                 $ 477,975     $ 482,058
   Member loss carryforwards                                    -         7,310
   Tax credits (alternative minimum tax
     and other)                                            58,811       196,452
- -------------------------------------------------------------------------------
                                                          536,786       685,820
   Less: Valuation allowance                             (536,786)     (678,510)
- -------------------------------------------------------------------------------
                                                                -         7,310
- -------------------------------------------------------------------------------
Deferred tax liabilities
Depreciation                                                    -        (7,310)
- -------------------------------------------------------------------------------
                                                                -        (7,310)
- -------------------------------------------------------------------------------
Net deferred tax liabilities                            $       -     $       -
===============================================================================

     As of December  31, 2002,  Oglethorpe  has federal tax net  operating  loss
carryforwards  (NOLs),  alternative minimum tax credits (AMT) and unused general
business credits (consisting primarily of investment tax credits) as follows:

=================================================================
                                    (dollars in thousands)
=================================================================
                           Alternative
                             Minimum
Expiration Date                Tax       Tax Credits       NOLs
                             Credits

2003                        $       -    $      652   $   253,665
2004                                -        55,663       114,285
2005                                -           189       213,080
2006                                -             -       209,009
2007                                -             -        86,779
2008                                -             -        94,927
2009                                -             -        96,394
2010                                -             -        77,970
2018                                -             -        61,533
2019                                -             -        10,516
2020                                -             -         4,362
2021                                -             -         6,207
None                            2,307             -             -
- -----------------------------------------------------------------
                            $   2,307    $   56,504   $ 1,228,727
=================================================================

     The NOL  expiration  dates start in the year 2003 and end in the year 2021.
Due to the change to the tax basis method for allocating  patronage and as shown
by the above valuation allowance,  it is not likely that the deferred tax assets
related to tax credits and NOLs will be  realized.  The change in the  valuation
allowance  from 2001 to 2002 was the result of the  reduction  in  deferred  tax
assets due to the expiration of tax credits and net operating  losses. It is not
likely that the AMT credit will be utilized.

4.  Capital leases:

     In 1985,  Oglethorpe sold and subsequently leased back from four purchasers
its 60%  undivided  ownership  interest in Scherer Unit No. 2. The gain from the
sale is being amortized over the 36-year term of the leases.

     In 2000,  Oglethorpe  entered into a power purchase and sale agreement with
Doyle I, LLC (Doyle  Agreement)  to purchase  all of the output from a five-unit
generation  facility (Plant Doyle) for a period of 15 years.  Oglethorpe has the
option to purchase  Plant Doyle at the end of the 15 year term for  $10,000,000,
which is considered a bargain purchase price.

     The minimum  lease  payments  under the capital  leases  together  with the
present value of the net minimum  lease  payments as of December 31, 2002 are as
follows:

================================================================================
Year Ending December 31,                           (dollars in thousands)
================================================================================
                                            Schererer       Plant
                                            Unit No. 2      Doyle        Total
- --------------------------------------------------------------------------------
2003                                       $  31,875    $  12,447     $ 44,322
2004                                          31,863       12,447       44,310
2005                                          31,863       12,447       44,310
2006                                          31,817       12,447       44,264
2007                                          31,871       12,447       44,318
2008-2021                                    313,975      105,424      419,399
- --------------------------------------------------------------------------------

Total minimum lease
   payments                                  473,264      167,659      640,923

   Less: Amount representing
     interest                               (212,476)     (52,727)    (265,203)
- --------------------------------------------------------------------------------
   Present value of net
     minimum lease payments                  260,788      114,932      375,720
   Less: Current portion                     (11,338)      (5,706)     (17,044)
- --------------------------------------------------------------------------------
   Long-term balance                       $ 249,450    $ 109,226     $358,676
================================================================================

     The interest rate on the Scherer No. 2 lease obligation is 6.97%. For Plant
Doyle,  the lease  payments vary to the extent the interest rate on the lessor's
debt varies from 6.00%. At December 31, 2002, the weighted average interest rate
on the Plant Doyle lease obligation was 6.61%.
     The  Scherer  No. 2 lease and the  Doyle  Agreement  meet the  definitional
criteria to be reported as capital leases.  For rate-making  purposes,  however,
Oglethorpe  treats  these  capital  leases  as  operating  leases.  Accordingly,
Oglethorpe includes the actual lease payments in its cost of service. The excess
of the lease  payments  over the  aggregate of the  amortization  on the capital
lease asset and the interest on the capital lease  obligation is recognized as a
regulatory asset on the balance sheet pursuant to SFAS No. 71.

                                       66


5.  Long-term debt:

     Long-term  debt consists of mortgage  notes payable to the United States of
America  acting through the Federal  Financing Bank (FFB) and the RUS,  mortgage
notes  and  unsecured  notes  issued  in  conjunction  with the  sale by  public
authorities  of  PCBs  and  mortgage  notes  payable  to  CoBank.   Oglethorpe's
headquarters facility is pledged as collateral for the CoBank headquarters note;
substantially  all of the owned tangible and certain of the intangible assets of
Oglethorpe  are  pledged as  collateral  for the FFB and RUS  notes,  the CoBank
mortgage  notes and the mortgage  notes issued in  conjunction  with the sale of
PCBs.

     In  connection  with a  corporate  restructuring  effective  April 1, 1997,
16.86%  of the then  outstanding  secured  PCBs  were  assumed  by GTC.  Because
Oglethorpe  was not legally  released from its  obligation to pay this debt, the
entire  debt is shown in the  Statement  of  Capitalization  as a  liability  of
Oglethorpe with an offsetting  amount reflecting the portion assumed by GTC. The
net obligation is reflected on Oglethorpe's balance sheet.

     In  connection  with  a  corporate   restructuring,   Oglethorpe   defeased
$92,130,000 in principal amount of Series 1992 tax-exempt PCBs.  Initially these
bonds  were  defeased  with the  proceeds  from the  issuance  of  approximately
$92,000,000 in commercial  paper which was deposited into an escrow account.  In
March and April 1998, Oglethorpe  refi-nanced the commercial paper issuance with
two medium-term  loans of $46,065,000 each, one from CoBank and one from CFC. In
October 2002,  Oglethorpe issued $91,990,000 of tax-exempt PCBs, the proceeds of
which were used to pre-pay the two  medium-term  loans.  On January 1, 2003 (the
first  optional  call date of the  issue),  the  remaining  funds in the  escrow
account  were used to fully  redeem  the  outstanding  Series  1992  PCBs.

     In December  2002,  Oglethorpe  completed a current  refunding  transaction
whereby  $30,075,000  of  PCBs  were  issued.  The  proceeds  were  used to make
principal payments due January 1, 2003.

     GTC  agreed  with  Oglethorpe  not  to  participate  in  this   $30,075,000
refinancing to the extent of their assumed  obligation in the PCBs.  Pursuant to
this  agreement,  Oglethorpe  will  provide a discount  to GTC of  approximately
$1,522,000 on the  $5,072,000  of principal  payments due from GTC in connection
with such refinancings. This $1,522,000 loss will be reported, together with the
unamortized  transaction  costs,  as a deferred  charge on the balance sheet and
will be amortized over four years.

     The annual interest requirement for 2003 is estimated to be $202,000,000.

     Maturities  for the long-term  debt and  amortization  of the capital lease
obligations through 2007 are as follows:

================================================================================
                                            (dollars in thousands)

                               2003       2004      2005       2006       2007
================================================================================
FFB and RUS                 $ 96,804   $101,754   $109,047   $116,023   $123,371
CoBank                           558        580        603        630        661
PCBs(1)                       25,835     27,855     28,146     30,000     34,501
Capital leases(2)             17,044     16,445     17,905     19,429     21,081
- --------------------------------------------------------------------------------
Total                       $140,241   $146,634   $155,701   $166,082   $179,614
================================================================================
(1) Does not contain portion assumed by GTC
(2) Represents principal portion of obligations under capital leases

     The weighted  average interest rate for 2002 for long-term debt and capital
leases and notes payable was 5.33%.

     Oglethorpe has a $50,000,000  committed short-term line of credit with CFC.
No balance was outstanding on this line of credit at either December 31, 2002 or
2001.

     Oglethorpe  has a  commercial  paper  program  under  which  it  may  issue
commercial paper not to exceed a $320,000,000  balance  outstanding at any time.
The  commercial  paper  may be used for  working  capital  requirements  and for
general  corporate  purposes.  Oglethorpe's  commercial  paper is backed 100% by
committed  lines of  credit.  By its  terms,  the  amount of the lines of credit
supporting the commercial paper program reduce to $290,000,000 on the earlier of
$350,000,000  in loan  funds  being  received  from RUS under the Talbot EMC and
Chattahoochee EMC loan commitments or June 30, 2003.

     Oglethorpe is providing loans to Talbot EMC and  Chattahoochee EMC to fund,
on an interim basis, approximately fifty percent of the construction cost of the
six combustion  turbines and the combined cycle facility.  Oglethorpe is funding
these loans under its  commercial  paper  program,  and at  December  31,  2002,
$297,776,000 of commercial paper was outstanding for this purpose. The loans are
included in Notes  receivable on  Oglethorpe's  balance  sheet.  Four of the six
combustion  turbines were placed  in-service in summer 2002,  with the other two
expected to be in-service by the summer of 2003. The combined cycle facility was
placed in service on February 15, 2003.

     The expected combined cost of constructing the six combustion  turbines and
the combined cycle facility totals approximately $600,000,000.  Two bridge loans
have also been secured to fund the remaining portion of the cost of constructing
these facilities.
                                       67


CFC is  providing a $141  million  bridge loan to Talbot EMC,  and Pitney  Bowes
Credit Corporation is providing a $160 million bridge loan to Chattahoochee EMC.
Oglethorpe's  loans to Talbot EMC and  Chattahoochee EMC are subordinated to the
CFC and Pitney Bowes loans, respectively. Oglethorpe is providing a guarantee of
the $160 million bridge loan to Chattahoochee EMC.
     In 2000, Oglethorpe submitted loan applications to RUS to provide permanent
financing  for  these  two  facilities.  The loan  applications  were  initially
submitted  on  behalf  of either  Oglethorpe  or  related  entities  that  might
ultimately  own these  facilities.  During the process of  evaluating  the terms
proposed by RUS for providing loans to Talbot EMC and Chattahoochee  EMC, it was
determined that the terms of the financing would be more favorable if Oglethorpe
owned the  facilities  and obtained the RUS  financing.  In September  2002, RUS
issued two RUS-guaranteed  loan commitments  totaling $589 million to Oglethorpe
for these generating facilities. The proceeds from these RUS loans will first be
used to repay  the  bridge  loans and then to  retire  Oglethorpe's  outstanding
commercial  paper.  Concurrently  with  the  funding  of these  loans,  which is
expected to occur in the second quarter of 2003, Oglethorpe will acquire the two
generating  facilities  from  Talbot  EMC and  Chattahoochee  EMC.  Oglethorpe's
acquisition  of  the  facilities  is  conditioned  upon  implementation  of  new
arrangements among Oglethorpe and the Members.
     The acquisition of these generating  facilities will increase  Oglethorpe's
assets and  liabilities  by  approximately  $600  million.  The new debt will be
secured  under  Oglethorpe's  Mortgage  Indenture.   Since  Oglethorpe's  margin
requirement  is based on a ratio applied to interest  charges  incurred for debt
secured  under the  Mortgage  Indenture,  the increase in debt will result in an
increase in the margin  requirement  of less than  $3,000,000 in the first year.
The  increase  in  assets  and  debt  will  decrease   Oglethorpe's   equity  to
capitalization  ratio and  equity  to asset  ratio by  approximately  3% and 2%,
respectively.

6.  Electric plant and related agreements:

     Oglethorpe and GPC have entered into agreements  providing for the purchase
and subsequent joint operation of certain of GPC's electric generating plants. A
summary of Oglethorpe's plant investments and related  accumulated  depreciation
as of December 31, 2002 is as follows:

============================================================================
                                                  (dollars in thousands)
                                                                 Accumulated
     Plant                                      Investment       Depreciation
============================================================================
In-service
     Owned property
         Vogtle Units No. 1 & No. 2
             (Nuclear - 30% ownership)           $ 2,721,256     $ 1,042,409
         Hatch Units No. 1 & No. 2
             (Nuclear - 30% ownership)               543,619         273,786
         Wansley Units No. 1 & No. 2
             (Fossil - 30% ownership)                174,999          99,332
         Scherer Unit No. 1
             (Fossil - 60% ownership)                436,566         245,156
         Rocky Mountain Units No. 1,
             No. 2 & No. 3
             (Hydro - 74.6% ownership)               556,784          83,861
         Wansley (Combustion Turbine -
             30% ownership)                            3,629           1,872
         Generation step-up substations               62,978          29,462
         Other                                        95,497          47,269
Property under capital lease
         Plant Doyle (Combustion Turbine -
             100% leasehold)                         126,990          18,199
         Scherer Unit No. 2
             (Fossil - 60% leasehold)                308,015         142,604
- ----------------------------------------------------------------------------
Total in-service                                 $ 5,030,333     $ 1,983,950
============================================================================
Construction work in progress
     Generation improvements                        $ 67,652
     Other                                             1,630
- ----------------------------------------------------------------------------
Total construction work in progress                 $ 69,282
============================================================================

     Oglethorpe,   as  of  December  31,  2002,   estimates  property  additions
(excluding   capitalized   interest  and  nuclear  fuel)  to  be   approximately
$77,000,000 in 2003,  $30,000,000 in 2004 and $30,000,000 in 2005, primarily for
replacements and additions to generation facilities.
     Oglethorpe's  proportionate  share of direct expenses of joint operation of
the above plants is included in the  corresponding  operating  expense  captions
(e.g.,  fuel,  production or  depreciation)  on the  accompanying  statements of
revenues and expenses.

                                       68


7.  Employee benefit plans:

     Oglethorpe has a money purchase pension plan which became effective January
1, 1999. Under this plan, Oglethorpe contributes 5%, subject to IRS limitations,
of each  employee's  annual  compensation.  In  addition,  older  employees  who
participated  in the  now-terminated  defined  benefit  pension  plan receive an
additional 1% to 2% of compensation. Oglethorpe's contributions to the plan were
approximately $513,000 in 2002 and $498,000 in 2001 and $444,000 in 2000.
     Oglethorpe  has a  contributory  401(k)  plan  covering  substantially  all
employees. The employee may contribute, subject to IRS limitations, up to 60% of
their  annual  compensation.  Oglethorpe,  at  its  discretion,  may  match  the
employee's  contribution  and has  done so each  year of the  plan's  existence.
Oglethorpe's  current policy is to match the employee's  contribution as long as
there is sufficient  margin to do so. The match,  which is  calculated  each pay
period,  currently can be equal to as much as  three-quarters of the first 6% of
the  employee's  compensation,  depending  on  the  amount  and  timing  of  the
employee's   contribution.   Oglethorpe's   contributions   to  the  plan   were
approximately $621,000 in 2002, $463,000 in 2001 and $261,000 in 2000.

8. Nuclear insurance:

     GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member
of Nuclear Electric  Insurance,  Ltd.  (NEIL),  a mutual insurer  established to
provide property damage  insurance  coverage in an amount up to $500,000,000 for
members'  nuclear  generating  facilities.  In  the  event  that  losses  exceed
accumulated  reserve funds,  the members are subject to retroactive  assessments
(in  proportion to their  premiums).  The portion of the current  maximum annual
assessment  for GPC that  would be  payable by  Oglethorpe,  based on  ownership
share, is limited to approximately $6,890,000 for each nuclear incident.
     GPC,  on  behalf of all the  co-owners  of Plants  Hatch  and  Vogtle,  has
coverage  under NEIL II,  which  provides  insurance  to cover  decontamination,
debris removal and premature  decommissioning  as well as excess property damage
to nuclear generating facilities for an additional  $2,250,000,000 for losses in
excess of the  $500,000,000  primary coverage  described  above.  Under the NEIL
policies,  members are subject to retroactive assessments in proportion to their
premiums if losses exceed the  accumulated  funds available to the insurer under
the policy.  The portion of the current  maximum annual  assessment for GPC that
would be  payable  by  Oglethorpe,  based on  ownership  share,  is  limited  to
approximately $8,413,000.
     For all on-site property damage insurance  policies for commercial  nuclear
power  plants,  the NRC requires  that the proceeds of such  policies  issued or
annually renewed on or after April 2, 1991 shall be dedicated first for the sole
purpose of placing the reactor in a safe and stable condition after an accident.
Any   remaining   proceeds   are  next  to  be  applied   toward  the  costs  of
decontamination  and  debris  removal  operations  ordered  by the NRC,  and any
further  remaining  proceeds are to be paid either to the company or to its bond
trustees  as  may  be  appropriate  under  the  policies  and  applicable  trust
indentures.
     The Price-Anderson  Act, as amended in 1988, limits public liability claims
that could arise from a single nuclear incident to  $9,500,000,000  which amount
is to be  covered by  private  insurance  and a  mandatory  program of  deferred
premiums that could be assessed  against all owners of nuclear  power  reactors.
Such  private  insurance  provided by American  Nuclear  Insurers  (ANI) (in the
amount of $300,000,000 for each plant,  the maximum amount currently  available)
is  carried  by GPC for the  benefit of all the  co-owners  of Plants  Hatch and
Vogtle.  Agreements  of indemnity  have been entered into by and between each of
the  co-owners  and the NRC. In the event of a nuclear  incident  involving  any
commercial  nuclear facility in the country  involving total public liability in
excess of $200,000,000,  a licensee of a nuclear power plant could be assessed a
deferred  premium of up to  $88,095,000  per incident for each licensed  reactor
operated by it, but not more than  $10,000,000  per  reactor per  incident to be
paid in a  calendar  year.  On the  basis of its  sell-back  adjusted  ownership
interest in four  nuclear  reactors,  Oglethorpe  could be assessed a maximum of
$105,714,000 per incident, but not more than $12,000,000 in any one year.
     All retrospective assessments, whether generated for liability or property,
may be subject to applicable state premium taxes.
     Following  the  terrorist  attacks  of  September  2001,  both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their  insurance.  Both companies,  however,  revised their policy
terms on a prospective basis to include an industry  aggregate for all terrorist
acts. The NEIL  aggregate,  which applies to all claims  stemming from terrorism
within a 12 month  duration,  is $3.24  billion  plus any amounts  that would be
available through  reinsurance or indemnity from an outside source.  The ANI cap
is a $300,000,000 shared industry aggregate.

                                       69


9.  Commitments:
a. Power purchase and sale agreements

     Oglethorpe is utilizing  power marketer  arrangements to reduce the cost of
power to the Members. Oglethorpe has a power marketer agreement with LG&E Energy
Marketing Inc. ("LEM"),  for approximately 50% of the load requirements of 37 of
the Members and an  additional  power  marketer  agreement  with Morgan  Stanley
Capital Group Inc.  ("Morgan  Stanley"),  effective May 1, 1997, with respect to
50% of the 39 Members' then forecasted load  requirements.  The LEM agreement is
based  on the  actual  requirements  of the  participating  Members  during  the
contract term,  whereas the Morgan Stanley  agreement  represents a fixed supply
obligation.  Generally,  these arrangements  benefit the Members by limiting the
risk of unit  availability and by providing future power needs at a fixed price.
Most of Oglethorpe's  generating  facilities and power purchase arrangements are
available  for  use  by LEM  and  Morgan  Stanley.  Oglethorpe  continues  to be
responsible  for all of the costs of its system  resources but receives  revenue
from LEM and Morgan  Stanley  for the use of the  resources.  After  taking into
account the  Oglethorpe  resources  made available to LEM and Morgan Stanley for
their use, Oglethorpe estimates that about 30% of its power supply capability in
2003 will be provided by these contracts.
     The Morgan  Stanley  agreement has a term  extending to March 31, 2005, but
the purchases for certain Members decline to zero prior to that date.
     The LEM  agreement  has a term  extending  through  2011.  With one  year's
notice,  Oglethorpe  has the right to terminate the LEM agreement as of December
31,  2001 or any  December 31 after that.  With 18 months'  notice,  LEM has the
right to  terminate  the  agreement  as of December  31, 2004 or any December 31
after that.  Pursuant to this  provision,  LEM has given notice to terminate the
agreement as of December 31, 2004.
     In February 2001, LEM and its  affiliates  initiated a binding  arbitration
process  to  resolve   certain  issues  relating  to  the   interpretation   and
administration of the LEM agreement and a similar agreement with Oglethorpe that
expired by its terms in 1999.  In April 2002,  Oglethorpe  and LEM settled  this
arbitration.  As part  of the  settlement,  Oglethorpe  paid  LEM  approximately
$48,500,000.  Oglethorpe recorded a reserve of $36,000,000 in 2001 and increased
the reserve by an additional $12,500,000 in 2002.
     In addition,  Oglethorpe has entered into various  long-term power purchase
agreements.  As of December 31, 2002,  Oglethorpe's minimum purchase commitments
under these agreements, without regard to capacity reductions or adjustments for
changes in costs, for the next five years and thereafter are as follows:

================================================================================
Year Ending December 31,                                  (dollars in thousands)
================================================================================
     2003                                                       $ 46,239
     2004                                                         46,620
     2005                                                         46,967
     2006                                                         31,998
     2007                                                         27,014
     Thereafter                                                  327,839
================================================================================

     Oglethorpe's   power   purchases   from  these   agreements   amounted   to
approximately  $100,836,000 in 2002,  $130,110,000  in 2001 and  $149,617,000 in
2000.
     Oglethorpe has entered into an agreement with Alabama Electric  Cooperative
to sell 100 MW of capacity for the period June 1998 through December 2005.

b. Operating leases

     In December 1999,  Oglethorpe sold existing coal rail cars and subsequently
entered into rental  agreements with various terms and expiration  dates for the
existing  and for  additional  new coal rail  cars.  As of  December  31,  2002,
Oglethorpe's  estimated  minimum rental  commitments for these operating  leases
over the next five years and thereafter are as follows:

================================================================================
Year Ending December 31,                                  (dollars in thousands)
================================================================================
     2003                                                      $ 2,877
     2004                                                        2,877
     2005                                                        2,877
     2006                                                        2,877
     2007                                                        3,126
     Thereafter                                                 35,108
================================================================================

                                       70


10. Environmental matters:
a. General

     As is typical  for  electric  utilities,  Oglethorpe  is subject to various
federal,  state and local air and water quality  requirements which, among other
things,  regulate emissions of pollutants,  such as particulate  matter,  sulfur
dioxide and nitrogen  oxides into the air and  discharges  of other  pollutants,
including heat, into waters of the United States.  Oglethorpe is also subject to
federal, state and local waste disposal requirements that regulate the manner of
transportation, storage and disposal of various types of waste.
     In general, environmental requirements are becoming increasingly stringent.
New requirements may  substantially  increase the cost of electric  service,  by
requiring  changes in the design or operation of existing  facilities or changes
or delays in the location, design,  construction or operation of new facilities.
Failure to comply with these  requirements  could  result in the  imposition  of
civil and  criminal  penalties as well as the  complete  shutdown of  individual
generating units not in compliance.  Oglethorpe cannot provide assurance that it
will always be in compliance with current and future regulations.

b. New source review

     In November 1999, the United States  Justice  Department,  on behalf of the
Environmental  Protection  Agency (EPA),  filed lawsuits against GPC and some of
its affiliates,  as well as other utilities.  The lawsuits allege  violations of
the new source review provisions and the new source performance standards of the
Clean Air Act at, among other facilities,  Scherer Unit Nos. 3 and 4. Oglethorpe
is not currently named in the lawsuits and Oglethorpe does not have an ownership
interest in the named units of Plant  Scherer.  However,  Oglethorpe can give no
assurance that units in which  Oglethorpe has an ownership  interest will not be
affected by this or a related  lawsuit in the  future.  The  resolution  of this
matter is highly uncertain at this time, as is any  responsibility of Oglethorpe
for a share of any penalties and capital costs required to remedy any violations
at facilities co-owned by Oglethorpe.

c. Clean air act

     On  December   30,   2002,   the  Sierra   Club,   Physicians   for  Social
Responsibility,  Georgia Forest Watch and one  individual  filed suit in Federal
Court in Georgia against GPC, alleging  violations of the Clean Air Act at Plant
Wansley.  The complaint  alleges  violations of opacity  limits at both the coal
fired units, in which Oglethorpe is a co-owner,  and other violations at several
of the combined cycle units where neither  Oglethorpe nor  Chattahoochee EMC has
an ownership interest.

Oglethorpe expects to acquire the combined cycle facility owned by Chattahoochee
EMC in the second  quarter of 2003.  This civil action  requests  injunctive and
declaratory relief, civil penalties,  a supplemental  environmental  project and
attorneys' fees. While Oglethorpe  believes that Plant Wansley has complied with
applicable laws and regulations,  resolution of this matter is uncertain at this
time, as is any  responsibility  of  Oglethorpe  for a share of any penalties or
other costs that might be assessed against GPC.
     On January 16, 2003, the Sierra Club appealed an unsuccessful  challenge to
an air operating  permit for the combined cycle facility owned by  Chattahoochee
EMC to the United States Court of Appeals for the Eleventh  Circuit.  Oglethorpe
has  intervened  in the  appeal.  The  petitioner  seeks to have the air  permit
invalidated  and remanded back to EPA and the Georgia  Environmental  Protection
Division.  Although  Oglethorpe believes that a favorable outcome in this appeal
is likely,  an unfavorable  ruling could  temporarily  affect the ability of the
facility to continue to operate.

11. Quarterly financial data (unaudited):

     Summarized quarterly financial information for 2002 and 2001 is as follows:

================================================================================
                                           (dollars in thousands)
                              First         Second        Third       Fourth
                             Quarter        Quarter      Quarter      Quarter
================================================================================
2002
     Operating revenues     $ 287,878      $ 279,527    $ 325,706    $ 270,210
     Operating margin          55,606         58,153       57,069       37,624
     Net margin                 9,269          9,409        7,371       (8,509)
2001
     Operating revenues     $ 306,607      $ 279,911    $ 319,580    $ 233,191
     Operating margin          66,765         48,934       45,316       53,717
     Net margin                15,283         (1,211)      (4,031)       8,376
================================================================================

     The negative net margin for the fourth quarter of 2002  primarily  resulted
from  charges  associated  with the early  retirement  of Plant  Tallassee.  The
negative  net margin for the second and third  quarters of 2001 is the result of
reductions to revenue requirements of $17,252,000 and $18,270,000, respectively,
approved by Oglethorpe's Board of Directors.

                                       71


REPORT OF MANAGEMENT

     The management of Oglethorpe Power Corporation has prepared this report and
is  responsible  for the financial  statements  and related  information.  These
statements  were  prepared in  accordance  with  generally  accepted  accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on best estimates and judgments of management.  Financial  information
throughout this annual report is consistent with the financial statements.

     Oglethorpe  maintains a system of internal  accounting  controls to provide
reasonable  assurance that assets are safeguarded and that the books and records
reflect  only  authorized  transactions.  Limitations  exist  in any  system  of
internal  control based upon the recognition  that the cost of the system should
not  exceed  its  benefits.  Oglethorpe  believes  that its  system of  internal
accounting  control,  together with the internal  auditing  function,  maintains
appropriate cost/benefit relations.

     Oglethorpe's  system of internal  controls is evaluated on an ongoing basis
by a qualified  internal  audit  staff.  The  Corporation's  independent  public
accountants  (PricewaterhouseCoopers  LLP) also consider certain elements of the
internal control system in order to determine their auditing  procedures for the
purpose of expressing an opinion on the financial statements.

     PricewaterhouseCoopers  LLP also  provides an objective  assessment  of how
well  management  meets  its  responsibility   for  fair  financial   reporting.
Management   believes  that  its  policies  and  procedures  provide  reasonable
assurance  that  Oglethorpe's  operations  are conducted with a high standard of
business  ethics.  In management's  opinion,  the financial  statements  present
fairly, in all material respects, the financial position, results of operations,
and cash flows of Oglethorpe.

Thomas A. Smith
President and Chief Executive Officer


REPORT OF INDEPENDENT ACCOUNTANTS


     To the Board of Directors of Oglethorpe Power Corporation:
     In  our  opinion,   the  accompanying  balance  sheets  and  statements  of
capitalization  and the related  statements of revenues and expenses,  patronage
capital  and of  cash  flows  present  fairly,  in all  material  respects,  the
financial  position of  Oglethorpe  Power  Corporation  at December 31, 2002 and
2001, and the results of its operations and its cash flows for each of the three
years in the period  ended  December  31,  2002 in  conformity  with  accounting
principles  generally accepted in the United States of America.  These financial
statements   are  the   responsibility   of  the   Company's   management;   our
responsibility  is to express an opinion on these financial  statements based on
our audits.  We conducted  our audits of these  statements  in  accordance  with
auditing  standards  generally  accepted in the United  States of America  which
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,  assessing the  accounting  principles
used and  significant  estimates made by management,  and evaluating the overall
financial  statement  presentation.   We  believe  that  our  audits  provide  a
reasonable basis for our opinion.


PricewaterhouseCoopers LLP
Atlanta, Georgia
March 14, 2003

                                       72


ITEM 9.  CHANGES  IN  AND  DISAGREEMENTS  WITH  ACCOUNTANTS  ON  ACCOUNTING  AND
          FINANCIAL DISCLOSURE

     None.


                                    PART III


ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     Oglethorpe has a ten-member board of directors  consisting of six directors
elected from the Members (the "Member  Directors") and four independent  outside
directors (the "Outside Directors").  Each Member Director must be a director or
general manager of an Oglethorpe  Member.  Five of the six Member Directors must
be located in each of five  geographical  regions of the State of  Georgia.  The
sixth Member Director is elected  statewide.  None of the four Outside Directors
may be a  director,  officer or employee  of GTC,  GSOC or any  Member.  All ten
directors  are  nominated by  representatives  from each Member  whose  weighted
nomination  is based on the number of retail  customers  served by each  Member.
After  nomination,  the directors are elected by a majority vote of each Member,
voting on a one-Member, one-vote basis.

     The Bylaws  provide for  staggered  three-year  terms of the  directors  by
dividing the number of directors into three groups.  The terms of  approximately
one-third of the directors expire each year.

     Oglethorpe  is managed and operated  under the direction of a President and
Chief Executive Officer, who is appointed by the Board of Directors.  The Senior
Officers and Directors of Oglethorpe are as follows:





Name                      Age  Position
- ----                      ---  --------

Thomas A. Smith.........   48  President and Chief Executive Officer
Michael W. Price........   42  Chief Operating Officer
W. Clayton Robbins......   56  Senior Vice President, Administration and Risk
                               Management
Elizabeth B. Higgins....   34  Vice President, Planning, Rates & Analysis
Benny W. Denham.........   72  Chairman of the Board, Member Director, Southwest
                               Region
Larry N. Chadwick.......   62  Member Director, Northwest Region
Marshall S. Millwood....   53  Member Director, Northeast Region
J. Sam L. Rabun.........   71  Member Director, Central Region and Vice Chairman
Robert E. Rentfrow......   48  Member Director, Southeast Region
H.B. Wiley, Jr..........   58  Member Director Statewide
Ashley C. Brown.........   57  Outside Director
Wm. Ronald Duffey.......   61  Outside Director
John S. Ranson..........   73  Outside Director
Jeffrey D. Tranen.......   56  Outside Director



     Thomas A. Smith is the President and Chief Executive  Officer of Oglethorpe
and has served in that capacity since  September  1999. He previously  served as
Senior Vice President and Chief  Financial  Officer of Oglethorpe from September
1998 to August 1999,  Senior  Financial  Officer from 1997 to August 1998,  Vice
President,  Finance from 1986 to 1990,  Manager of Finance from 1983 to 1986 and
Manager,  Financial Services from 1979 to 1983. From 1990 to 1997, Mr. Smith was

                                       73


Senior Vice  President of the Rural Utility  Banking  Group of CoBank,  where he
managed the bank's eastern division,  rural utilities.  Mr. Smith is a Certified
Public   Accountant,   has  a   Master   of   Science   degree   in   Industrial
Management-Finance from the Georgia Institute of Technology, a Master of Science
degree in Analytical  Chemistry  from Purdue  University  and a Bachelor of Arts
degree in  Mathematics  and  Chemistry  from  Catawba  College.  Mr.  Smith is a
Director of GSOC, ACES Power  Marketing,  the Georgia  Chamber of Commerce,  and
En-Touch  Systems,  Inc. in Houston,  Texas.  Mr.  Smith is also a member of the
Advisory Board of Mid-South Telecommunications, Inc. in Houston, Texas.

     Michael  W. Price is the Chief  Operating  Officer  of  Oglethorpe  and has
served in that office since February 1, 2000. Mr. Price served GSOC from January
1999 to January 2000, first as Senior Vice President and then as Chief Operating
Officer.  He served as Vice President of System Planning and Construction of GTC
from May 1997 to December 1998. He served as a manager of system control of GSOC
from January to May 1997. From 1986 to 1997, Mr. Price served  Oglethorpe in the
areas of control room operations, system planning, construction and engineering,
and energy management systems. Prior to joining Oglethorpe,  he was a field test
engineer  with the TVA from 1983 to 1986.  Mr.  Price has a Bachelor  of Science
degree in Electrical Engineering from Auburn University.

     W. Clayton  Robbins is the Senior Vice President,  Administration  and Risk
Management of Oglethorpe  and has served in that office since October 2002.  Mr.
Robbins  served  as Senior  Vice  President,  Finance  and  Administration  from
November 1999 to October 2002.  Mr.  Robbins served as Senior Vice President and
General  Manager of  Intellisource,  Inc. from  February 1997 to November  1999.
Prior to that,  Mr.  Robbins held several  positions at  Oglethorpe  since 1986,
including Senior Vice President,  Support Services from December 1991 to January
1997 and Vice  President,  Market  Research and Analysis  from  December 1989 to
December  1991.  Before coming to  Oglethorpe,  Mr.  Robbins spent 18 years with
Stearns-Catalytic World Corporation,  a major engineering and construction firm,
including 13 years in  management  positions  responsible  for human  resources,
information systems, contracts,  insurance, accounting and project controls. Mr.
Robbins  has a  Bachelor  of Arts  degree in  Business  Administration  from the
University of North Carolina in Charlotte.

     Elizabeth B. Higgins is the Vice President,  Planning,  Rates & Analysis of
Oglethorpe  and has served in this office since July 2000. Ms. Higgins served as
the Vice  President  and Assistant to the Chief  Executive  Officer from October
1999 to July 2000 and served in other  capacities for Oglethorpe from April 1997
to September  1999.  Prior to that,  Ms.  Higgins  served as Project  Manager at
Southern  Engineering  from October 1995 to April 1997, as Senior  Consultant at
Deloitte & Touche, LLP from April 1995 to October 1995, and as Senior Consultant
at  Energy  Management  Associates  from  June  1991 to  April  1995.  In  these
positions,  Ms. Higgins was responsible for competitive  bidding analyses,  rate
designs,  integrated  resource planning studies,  operational/dispatch  studies,
bulk power market analysis,  merger analyses and litigation support. Ms. Higgins
has a Bachelor of Industrial  Engineering  degree from the Georgia  Institute of
Technology.

     Benny W.  Denham is  Chairman  of the Board and  Member  Director  from the
Southwest  Region.  He has served on the Board of Directors of Oglethorpe  since
December  1988.  His present term will expire in March 2004. Mr. Denham has been
co-owner of Denham Farms in Turner  County,  Georgia  since 1980. He serves as a
Board member and past  Chairman of the Turner  County  Chamber of Commerce.  Mr.
Denham is the Chairman of the Board of Directors of Community  National  Bank of
Ashburn,  Georgia, and a Director of Georgia Electric Membership Corporation and
Irwin EMC.

     Larry N. Chadwick is the Member Director from the Northwest  Region. He has
been the owner of Chadwick's  Hardware in Woodstock,  Georgia since 1983. He has
served on the Board of Directors of Oglethorpe since July 1989. His present term
will expire in March 2005. Mr.  Chadwick is an engineer,  with experience in the
design of hydrogen gas plants. He is Chairman of the Board of Cobb EMC.

                                       74


     Marshall S. Millwood is the Member Director from the Northeast  Region.  He
became a member of the Board of Directors in March 2003 and his term will expire
in March 2006.  He has been the owner and  operator of Marjomil  Inc., a poultry
and cattle farm in Forsyth  County,  Georgia,  since  1998.  He is a Director of
Sawnee EMC.

     J.  Sam L.  Rabun  is the  Vice-Chairman  of the  Board  and is the  Member
Director from the Central Region. He is also a member of the Audit Committee. He
has been the owner and operator of a farm in  Jefferson  County,  Georgia  since
1979. He is also a 50% owner of R&R Livestock  Farms,  Inc. He has served on the
Board of Directors of Oglethorpe  since March 1993. His present term will expire
in March 2004.  Mr. Rabun served as the  President of the Board of Jefferson EMC
from 1993 to 1996,  was  employed  as General  Manager  from 1974 to 1979 and as
Office Manager and Accountant from 1970 to 1974. Mr. Rabun is  Vice-Chairman  of
the Board of the Georgia Energy Cooperative.

     Robert E. Rentfrow is the Member  Director from the Southeast  Region.  Mr.
Rentfrow  became a Member of the Board of Directors of  Oglethorpe in June 2002.
Mr. Rentfrow is a member of the Board's Audit Committee.  Mr. Rentfrow's term on
the Board of Directors of Oglethorpe  will expire in 2005. Mr. Rentfrow has been
the  President  and Chief  Executive  Officer of Satilla Rural EMC since January
1996 and has been  associated  with EMCs in Georgia  for the past 17 years.  Mr.
Rentfrow serves as Director on the Governor's Workforce Investment Board and the
Regional  Advisory  Council.  Mr.  Rentfrow also serves as Chairman of the Bacon
County  Industrial  Building  Authority and is a member of the Waycross  College
Board of Trustees.  Mr. Rentfrow is a graduate of Southern  Technical  Institute
and Georgia Southern College.

     H.B.  Wiley,  Jr. is the Member  Director  elected  statewide.  He became a
member of the Board of Directors in March 2003 and his term will expire in March
2006.  Mr. Wiley  previously  served as a member of the Board of Directors  from
July 1994 until  March  1997.  Mr.  Wiley has been an  associate  broker in real
estate  since 1994.  Prior to that he owned and  operated a dairy farm in Oconee
County,  Georgia  from 1973 to 1994.  During that time he served on the board of
Atlanta  Dairies  Cooperative  and Georgia Milk Producers  Board.  He has been a
director  of Walton EMC since June 1993,  and has served as its  Chairman of the
Board  since June 2000.  Mr.  Wiley has  Bachelor  of  Science  degree  from the
University of Georgia.

     Ashley  C.  Brown is an  Outside  Director.  He has  served on the Board of
Directors  of  Oglethorpe  since  March  1997.  He is the  Chairman of the Audit
Committee.  His present  term will expire in March 2005.  He has been  Executive
Director of the Harvard Electricity Policy Group at Harvard University's John F.
Kennedy School of Government since 1993. In addition,  he has been Of Counsel to
the law firm of LeBoeuf, Lamb, Greene and MacRae since May 1997. From April 1983
through April 1993,  Mr. Brown served as  Commissioner  of the Public  Utilities
Commission of Ohio.  Prior to his  appointment  to the Ohio  Commission,  he was
Coordinator  and Counsel of the Montgomery  County,  Ohio,  Fair Housing Center.
From 1979 to 1981, he was Managing  Attorney for the Legal Aid Society of Dayton
(Ohio),  Inc.  From 1977 to 1979,  he was  Legal  Advisor  of the  Miami  Valley
Regional  Planning  Commission  in Dayton,  Ohio.  In  addition,  Mr.  Brown has
extensive  teaching  experience  in  public  schools  and  universities  and has
published widely in the field of utility regulation.  Mr. Brown has a law degree
from the  University  of Dayton  School of Law, a Master of Arts degree from the
University of  Cincinnati,  and a Bachelor of Science  degree from Bowling Green
State University.

     Wm.  Ronald  Duffey is an Outside  Director.  He has served on the Board of
Directors of Oglethorpe since March 1997. He is a member of the Audit Committee.
His term will  expire in March  2004.  Mr.  Duffey  is the  President  and Chief
Executive  Officer and a director of Peachtree  National Bank in Peachtree City,
Georgia,  a wholly owned  subsidiary  of Synovus  Financial  Corp.  Prior to his
employment in 1985 with Peachtree  National Bank, Mr. Duffey served as Executive
Vice  President and Member of the Board of Directors for First  National Bank in
Newnan,  Georgia.  He holds a Bachelor of Business  Administration  from Georgia
State College with a concentration in finance and has completed  banking courses
at the Banking School of the South, the American Bankers  Association  School of
Bank  Investments,   and  The  Stonier  Graduate  School  of  Banking,   Rutgers
University. Mr. Duffey is a Director of Fayette Community Hospital.

     John S.  Ranson  is an  Outside  Director.  He has  served  on the Board of
Directors of Oglethorpe since March 1997. His term will expire in March 2005. He
is also a member of the  Compensation  Committee.  He has been the  President of
Ranson Municipal  Consultants,  L.L.C., a financial advisor in Wichita,  Kansas,
since 1994.  From 1990 to 1994,  Mr. Ranson was Chairman of Ranson Capital Corp.
an  investment  banking  firm.  Mr.  Ranson has been in the  investment  banking
business  since  1953.  His public  finance  clients  have  included  the Kansas
Turnpike Authority, the Kansas Municipal Energy Agency, the Kansas Municipal Gas
Agency,  and the Kansas City  (Kansas)  Board of Public  Utilities.  Mr.  Ranson
received his Bachelor of Science in Business  Administration from the University
of Kansas  (Lawrence,  Kansas)  and  attended  the Navy Supply  Corps  School in
Bayonne, New Jersey.

                                       75


     Jeffrey  D.  Tranen is an Outside  Director.  He has served on the Board of
Directors of Oglethorpe  since March 2000. His present term will expire in March
2003.  Since May 2000,  he has served as Senior Vice  President  of Lexecon,  an
economic,  regulatory and business  strategy  consulting firm. Prior to that, he
served as President and Chief Operating  Officer of Sithe Northeast,  a merchant
generation  company from 1999 to 2000.  Mr.  Tranen  served as the President and
Chief Executive Officer of the California  Independent System Operator from 1997
to 1999.  From 1970 to 1997, Mr. Tranen worked in several  positions for the New
England  Electric  System,  most  recently as Senior Vice  President  of the New
England Electric  System.  He is currently a member of the Board of Directors of
Doble  Engineering  Co.  Mr.  Tranen has a  Bachelor  of  Science in  Electrical
Engineering  and  a  Master  of  Science  in  Electrical  Engineering  from  the
Massachusetts Institute of Technology.

                                       76


ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

     The  following  table sets  forth,  for  Oglethorpe's  President  and Chief
Executive Officer and for the three other executive  officers,  all compensation
paid or accrued for services  rendered in all capacities  during the years ended
December 31, 2002, 2001 and 2000.


                                                                        Annual Compensation            All Other
                                                                        -------------------            ---------
Name and Principal Position                                 Year            Salary         Bonus    Compensation(1)
- ---------------------------                                 ----            ------         -----    ---------------
                                                                                                    
Thomas A. Smith......................................       2002          $320,000      $115,349          $193,736 (2)
President and Chief Executive Officer                       2001           292,500        87,320            90,529
                                                            2000           275,000        82,800            14,005

Michael W. Price.....................................       2002           196,267        70,530            19,346
Chief Operating Officer                                     2001           182,008        54,464            26,527
                                                            2000           157,667        50,912            23,583

W. Clayton Robbins...................................       2002           176,483        55,068            17,473
Senior Vice President, Administration and                   2001           169,417        44,160            17,640
Risk Management                                             2000           163,000        42,476            11,335

Elizabeth B. Higgins.................................       2002           148,434        46,381            16,165
Vice President, Planning, Rates and Analysis                2001           143,333        26,825            15,401
                                                            2000           126,125        24,975            11,846
- --------------
<FN>
(1)  Figures for 2002  consist of  contributions  made by  Oglethorpe  under the
     401(k)  Retirement  Savings Plan on behalf of Mr.  Smith,  Mr.  Price,  Mr.
     Robbins and Ms. Higgins of $8,250, $6,812, $5,264 and $7,076, respectively;
     contributions  under  Oglethorpe's Money Purchase Pension Plan on behalf of
     Mr. Smith,  Mr. Price,  Mr.  Robbins and Ms.  Higgins of $10,000,  $12,123,
     $10,648 and $8,763, respectively;  and insurance premiums paid on term life
     insurance on behalf of Mr. Smith, Mr. Price, Mr. Robbins and Ms. Higgins of
     $486, $412, $1,562 and $327, respectively.

(2)  Includes  a  contribution   under   Oglethorpe's   Executive   Supplemental
     Retirement  Plan of $75,000 and a bonus of $100,000 paid in connection with
     entering into a new employment agreement.
</FN>


Compensation of Directors

     Oglethorpe pays its Outside Directors a fee of $5,500 per Board meeting for
four  meetings in a year; a fee of $1,000 per Board meeting will be paid for the
remaining other Board meetings in a year. Outside Directors are also paid $1,000

                                       77


per day for  attending  committee  meetings,  annual  meetings of the Members or
other official business of Oglethorpe. Member Directors are paid a fee of $1,000
per Board  meeting and $600 per day for  attending  committee  meetings,  annual
meetings of the Members or other official  business of Oglethorpe.  In addition,
Oglethorpe  reimburses  all Directors  for  out-of-pocket  expenses  incurred in
attending a meeting.  All Directors are paid $50 per day when  participating  in
meetings by conference call. The Chairman of the Board is paid an additional 20%
of his  Director's  fee per Board meeting for time involved in preparing for the
meetings.

     Beginning in 2001,  Mr. Tranen was given a special  assignment by the Board
of  Directors  in  his  capacity  as a  Director  of  Oglethorpe  to  work  with
Oglethorpe's  staff and  consultants  on an  evaluation  of matters  relating to
member scheduling issues, system operations,  and pool operations.  During 2002,
Mr. Tranen was paid approximately $14,700 for fees and expenses relating to this
assignment.

Employment Contracts

     Oglethorpe  entered  into an  Employment  Agreement  with  Thomas A. Smith,
Oglethorpe's  President and Chief Executive  Officer,  effective March 15, 2002.
The agreement  extends until  December 31, 2004,  and  automatically  renews for
successive  one-year  periods unless either party gives notice of termination 24
months  prior  to the  expiration  of the  agreement  or  any  extension  of the
agreement.  The agreement has automatically renewed until December 31, 2005. Mr.
Smith's  minimum base salary is $325,000 per year,  and is annually  adjusted by
the Board of Directors of  Oglethorpe.  Mr. Smith was paid a retention  bonus of
$50,000 in  January  2003 and is  entitled  to  bonuses  totaling  $50,000 if he
remains employed by Oglethorpe through 2003 and 2004. In addition, Mr. Smith has
opportunities for variable pay for accomplishing goals set by Oglethorpe's Board
of Directors each year.

     Upon the  occurrence  of any of the  following  events,  Mr.  Smith will be
entitled to a lump-sum severance payment: (1) Oglethorpe  terminates Mr. Smith's
employment  without  cause;  (2) Mr. Smith resigns within 180 days of a material
reduction  or  alteration  of his title or  responsibilities  or a change in the
location of Mr. Smith's  principal  office by more than 50 miles; (3) Oglethorpe
is sold or  Oglethorpe  sells  essentially  all of its  assets or control of its
assets,  and the sale results in a  termination  of Mr.  Smith's  employment  as
President and Chief Executive  Officer of Oglethorpe or a material  reduction of
his title or responsibilities; or (4) an event of default under Oglethorpe's RUS
loan  contract  occurs  and is  continuing  and  RUS  requests  that  Oglethorpe
terminate Mr. Smith.  The severance  payment will equal Mr.  Smith's base salary
through the rest of the term of the agreement  (with a minimum of one year's pay
and a maximum  of two  years'  pay) plus the cost of  providing  all  health and
dental  insurance  for  the  longer  of one  year or the  remaining  term of the
agreement. If Mr. Smith resigns for any reason other than those described above,
he will be  entitled to a severance  payment  equal to six months'  salary if he
resigns before December 31, 2003.

     Oglethorpe  has also entered  into  Employment  Agreements  with Michael W.
Price, W. Clayton Robbins and Elizabeth B. Higgins, Oglethorpe's Chief Operating
Officer,  Senior Vice President of  Administration  and Risk Management and Vice
President  of  Planning,  Rates  and  Analysis,   respectively.  Each  agreement
automatically  renews for  successive  one-year  periods ending each December 31
unless  either  party  gives  notice  of  termination  13  months  prior  to the
expiration of any extension of the  Agreement.  Minimum annual base salaries are
$172,000 for Mr. Price,  $164,000 for Mr. Robbins and $165,000 for Ms.  Higgins.
Ms. Higgins  entered into an amendment to her  employment  agreement on February
19, 2003. The amendment  provided for an immediate  bonus of $30,000 and bonuses
totaling $50,000 if she remains employed by Oglethorpe through June 30, 2003 and
January 1, 2004.  Salaries  are  annually  adjusted by the Board of Directors of
Oglethorpe.  Each executive has opportunities for variable pay for accomplishing
goals set by Oglethorpe's Board of Directors each year.

                                       78


     Under each  Employment  Agreement,  the  executive  will be  entitled  to a
lump-sum severance payment if Oglethorpe  terminates the executive without cause
or if the  executive  resigns  after (1) a demotion or a material  reduction  or
alteration of the executive's title or responsibilities,  (2) a reduction of the
executive's  base  salary or (3) a change  in the  location  of the  executive's
principal  office by more than 50 miles.  The  severance  payment will equal the
executive's base salary for one year, plus the equivalent of six months' medical
allowance.

Compensation Committee Interlocks and Insider Participation

     J. Calvin  Earwood,  John S. Ranson and Mac F. Oglesby served as members of
the Oglethorpe  Power  Corporation  Compensation  Committee in 2002. Mr. Earwood
served as an  executive  officer of  Oglethorpe  from 1984 until  March 2003 and
served as the Chairman of the Board from 1989 until March 2003.

ITEM 12.  SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     Not applicable.

ITEM 13.  CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     Robert E. Rentfrow is a Director of Oglethorpe  and the President and Chief
Executive  Officer  of  Satilla  Rural  EMC.  Satilla  Rural  EMC is a Member of
Oglethorpe  and has a Wholesale  Power Contract with  Oglethrope.  Satilla Rural
EMC's payments to Oglethorpe  under the Wholesale  Power Contract  accounted for
approximately  3% of Oglethorpe's  total revenues and 48% of Satilla Rural EMC's
total revenues in 2002.

ITEM 14.  CONTROLS AND PROCEDURES

     Within 90 days prior to the filing date of this report,  Oglethorpe carried
out an  evaluation,  under the  supervision  and with the  participation  of its
management,  including  its  President  and  Chief  Executive  Officer  and Vice
President,  Finance  and  Treasurer,  of the  effectiveness  of the  design  and
operation  of its  disclosure  controls  and  procedures  (as  defined  in Rules
13a-14(c) and 15d-14(c) under the Securities  Exchange Act of 1934, as amended).
Based on this evaluation, the President and Chief Executive Officer and the Vice
President, Finance and Treasurer concluded that Oglethorpe's disclosure controls
and procedures are effective to ensure that information required to be disclosed
by  Oglethorpe  in the  reports  that  Oglethorpe  files or  submits  under  the
Securities Exchange Act is recorded,  processed,  summarized and reported within
the  time  periods  required  by the  Securities  Exchange  Act  and  the  rules
thereunder.

     No significant  changes  occurred in Oglethorpe's  internal  controls or in
other factors that could  significantly  affect its internal  controls since the
date of its evaluation. Oglethorpe has not found any significant deficiencies or
material weaknesses in these controls which require any corrective actions since
the date of Oglethorpe's evaluation.

                                       79


                                    PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

                                                                            Page
                                                                            ----
(a) List of Documents Filed as a Part of This Report.

    (1)  Financial Statements (Included under "Item 8. Financial Statements
         and Supplementary Data")
         Statements of Revenues and Expenses, For the Years Ended
         December 31, 2002, 2001 and 2000................................... 53
         Balance Sheets, As of December 31, 2002 and 2001................... 54
         Statements of Capitalization, As of December 31, 2002 and 2001..... 56
         Statements of Cash Flows, For the Years Ended
           December 31, 2002, 2001 and 2000................................. 57
         Statements of Patronage Capital and Membership Fees
           And Accumulated Other Comprehensive Margin For the Years Ended
           For the Years Ended December 31, 2002, 2001 and 2000............. 58
         Notes to Financial Statements...................................... 59
         Report of Management............................................... 72
         Report of Independent Accountants.................................. 72

    (2)  Financial Statement Schedules

         None applicable.

    (3)  Exhibits

     Exhibits  marked with an asterisk (*) are hereby  incorporated by reference
to exhibits  previously  filed by the  Registrant  as indicated  in  parentheses
following the description of the exhibit.

Number                                                            Description

*2.1 --   Second Amended and Restated  Restructuring  Agreement,  dated February
          24, 1997, by and among Oglethorpe,  Georgia  Transmission  Corporation
          (An Electric  Membership  Corporation)  and Georgia System  Operations
          Corporation.  (Filed as Exhibit 2.1 to the Registrant's  Form 10-K for
          the fiscal year ended December 31, 1996, File No. 33-7591.)

*2.2 --   Member  Agreement,  dated  August 1,  1996,  by and among  Oglethorpe,
          Georgia Transmission Corporation (An Electric Membership Corporation),
          Georgia System  Operations  Corporation and the Members of Oglethorpe.
          (Filed as  Exhibit  2.2 to the  Registrant's  Form 10-K for the fiscal
          year ended December 31, 1996, File No. 33-7591.)

*3.1(a)-- Restated Articles of Incorporation of Oglethorpe, dated as of July 26,
          1988.  (Filed as  Exhibit  3.1 to the  Registrant's  Form 10-K for the
          fiscal year ended December 31, 1988, File No. 33-7591.)

*3.1(b)-- Amendment  to Articles of  Incorporation  of  Oglethorpe,  dated as of
          March 11, 1997.  (Filed as Exhibit  3(i)(b) to the  Registrant's  Form
          10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)

                                       80


*3.2 --   Bylaws of  Oglethorpe,  as amended on  November  14,  2001.  (Filed as
          Exhibit  3.2 to the  Registrant's  Form 10-K for the fiscal year ended
          December 31, 2001, File No. 33-7591.)

*4.1 --   Form of Serial Facility Bond Due June 30, 2011 (included in Collateral
          Trust Indenture filed as Exhibit 4.2.)

*4.2 --   Collateral Trust Indenture,  dated as of December 1, 1997, between OPC
          Scherer 1997 Funding  Corporation  A,  Oglethorpe  and SunTrust  Bank,
          Atlanta,  as Trustee.  (Filed as Exhibit 4.2 to the Registrant's  Form
          S-4 Registration Statement, File No. 333-42759.)

*4.3 --   Nonrecourse  Promissory Lessor Note No. 2, with a Schedule identifying
          three other  substantially  identical  Nonrecourse  Promissory  Lessor
          Notes  and any  material  differences.  (Filed as  Exhibit  4.3 to the
          Registrant's Form S-4 Registration Statement, File No. 333-42759.)

*4.4 --   Amended  and  Restated  Indenture  of Trust,  Deed to Secure  Debt and
          Security  Agreement No. 2, dated December 1, 1997,  between Wilmington
          Trust Company and  NationsBank,  N.A.  collectively  as Owner Trustee,
          under  Trust  Agreement  No. 2,  dated  December  30,  1985,  with DFO
          Partnership, as assignee of Ford Motor Credit Company, and The Bank of
          New York Trust Company of Florida,  N.A. as Indenture Trustee,  with a
          Schedule  identifying three other substantially  identical Amended and
          Restated  Indentures  of  Trust,  Deeds to  Secure  Debt and  Security
          Agreements and any material differences.  (Filed as Exhibit 4.4 to the
          Registrant's Form S-4 Registration Statement, File No. 333-42759.)

*4.5(a)-- Lease  Agreement  No. 2 dated  December 30, 1985,  between  Wilmington
          Trust  Company  and  William J. Wade,  as Owner  Trustees  under Trust
          Agreement  No. 2, dated  December  30,  1985,  with Ford Motor  Credit
          Company,  Lessor, and Oglethorpe,  Lessee, with a Schedule identifying
          three  other  substantially  identical  Lease  Agreements.  (Filed  as
          Exhibit 4.5(b) to the Registrant's  Form S-1  Registration  Statement,
          File No. 33-7591.)

* 4.5(b)--First  Supplement  to Lease  Agreement No. 2 (included as Exhibit B to
          the Supplemental Participation Agreement No. 2 listed as 10.1.1(b)).

*4.5(c) --First  Supplement to Lease Agreement No. 1, dated as of June 30, 1987,
          between The Citizens and Southern National Bank as Owner Trustee under
          Trust  Agreement  No.  1 with IBM  Credit  Financing  Corporation,  as
          Lessor,  and  Oglethorpe,  as Lessee.  (Filed as Exhibit 4.5(c) to the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1987,
          File No. 33-7591.)

*4.5(d) --Second  Supplement to Lease  Agreement No. 2, dated as of December 17,
          1997, between NationsBank, N.A., acting through its agent, The Bank of
          New York, as an Owner  Trustee under the Trust  Agreement No. 2, dated
          December 30, 1985,  among DFO  Partnership,  as assignee of Ford Motor
          Credit Company, as the Owner Participant, and the Original Trustee, as
          Lessor, and Oglethorpe,  as Lessee, with a Schedule  identifying three
          other  substantially  identical Second Supplements to Lease Agreements
          and  any  material  differences.  (Filed  as  Exhibit  4.5(d)  to  the
          Registrant's Form S-4 Registration Statement, File No. 333-42759.)

*4.6  --  Amended and  Consolidated  Loan  Contract,  dated as of March 1, 1997,
          between  Oglethorpe  and the United  States of America,  together with
          four notes executed and delivered pursuant thereto.  (Filed as Exhibit
          4.7 to the  Registrant's  Form 10-K for the fiscal year ended December
          31, 1996, File No. 33-7591.)

*4.7.1(a)-Indenture,  dated as of March 1, 1997,  made by Oglethorpe to SunTrust
          Bank, Atlanta, as trustee. (Filed as Exhibit 4.8.1 to the Registrant's
          Form 10-K for the  fiscal  year  ended  December  31,  1996,  File No.
          33-7591.)

                                       81


*4.7.1(b)-First  Supplemental  Indenture,  dated as of October 1, 1997,  made by
          Oglethorpe  to SunTrust  Bank,  Atlanta,  as trustee,  relating to the
          Series  1997B  (Burke)  Note.   (Filed  as  Exhibit  4.8.1(b)  to  the
          Registrant's  Form 10-Q for the quarterly  period ended  September 30,
          1997, File No. 33-7591.)

*4.7.1(c)-Second  Supplemental  Indenture,  dated as of January 1, 1998, made by
          Oglethorpe to SunTrust Bank, as trustee,  relating to the Series 1997C
          (Burke) Note. (Filed as Exhibit 4.7.1(c) to the Registrant's Form 10-K
          for the fiscal year ended December 31, 1997, File No. 33-7591.)

*4.7.1(d)-Third  Supplemental  Indenture,  dated as of January 1, 1998,  made by
          Oglethorpe to SunTrust Bank, as trustee,  relating to the Series 1997A
          (Monroe) Note.  (Filed as Exhibit  4.7.1(d) to the  Registrant's  Form
          10-K for the fiscal year December 31, 1997, File No. 33-7591.)

*4.7.1(e)-Fourth  Supplemental  Indenture,  dated as of March 1,  1998,  made by
          Oglethorpe  to SunTrust  Bank,  Atlanta,  as trustee,  relating to the
          Series  1998A  (Burke)  and 1998B  (Burke)  Notes.  (Filed as  Exhibit
          4.7.1(e)  to the  Registrant's  Form 10-K for the  fiscal  year  ended
          December 31, 1998, File No. 33-7591.)

*4.7.1(f)-Fifth  Supplemental  Indenture,  dated as of April  1,  1998,  made by
          Oglethorpe  to SunTrust  Bank,  Atlanta,  as trustee,  relating to the
          Series 1998 CFC Note.  (Filed as Exhibit  4.7.1(f) to the Registrant's
          Form 10-K for the  fiscal  year  ended  December  31,  1998,  File No.
          33-7591.)

*4.7.1(g)-Sixth  Supplemental  Indenture,  dated as of January 1, 1999,  made by
          Oglethorpe  to SunTrust  Bank,  Atlanta,  as trustee,  relating to the
          Series  1998C  (Burke)  Note.   (Filed  as  Exhibit  4.7.1(g)  to  the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1998,
          File No. 33-7591.)

*4.7.1(h)-Seventh Supplemental  Indenture,  dated as of January 1, 1999, made by
          Oglethorpe  to SunTrust  Bank,  Atlanta,  as trustee,  relating to the
          Series  1998A  (Monroe)  Note.  (Filed  as  Exhibit  4.7.1(h)  to  the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1998,
          File No. 33-7591.)

*4.7.1(i)-Eighth Supplemental  Indenture,  dated as of November 1, 1999, made by
          Oglethorpe  to SunTrust  Bank,  Atlanta,  as trustee,  relating to the
          Series  1999B  (Burke)  Note.   (Filed  as  Exhibit  4.7.1(i)  to  the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1999,
          File No. 33-7591.)

*4.7.1(j)-Ninth  Supplemental  Indenture,  dated as of November 1, 1999, made by
          Oglethorpe  to SunTrust  Bank,  Atlanta,  as trustee,  relating to the
          Series  1999B  (Monroe)  Note.  (Filed  as  Exhibit  4.7.1(j)  to  the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1999,
          File No. 33-7591.)

*4.7.1(k)-Tenth  Supplemental  Indenture,  dated as of December 1, 1999, made by
          Oglethorpe  to SunTrust  Bank,  Atlanta,  as trustee,  relating to the
          Series  1999  Lease   Notes.   (Filed  as  Exhibit   4.7.1(k)  to  the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1999,
          File No. 33-7591.)

*4.7.1(l)-Eleventh Supplemental Indenture,  dated as of January 1, 2000, made by
          Oglethorpe to SunTrust  Bank as trustee,  relating to the Series 1999A
          (Burke) Note. (Filed as Exhibit 4.7.1(l) to the Registrant's Form 10-K
          for the fiscal year ended December 31, 1999, File No. 33-7591.)

*4.7.1(m)-Twelfth Supplemental  Indenture,  dated as of January 1, 2000, made by
          Oglethorpe to SunTrust  Bank as trustee,  relating to the Series 1999A
          (Monroe) Note.  (Filed as Exhibit  4.7.1(m) to the  Registrant's  Form
          10-K for the fiscal year ended December 31, 1999, File No. 33-7591.)

                                       82


*4.7.1(n)-Thirteenth Supplemental  Indenture,  dated as of January 1, 2001, made
          by  Oglethorpe to SunTrust  Bank,  as trustee,  relating to the Series
          2000 (Burke) Note. (Filed as Exhibit 4.7.1(n) to the Registrant's Form
          10-K for the fiscal year ended December 31, 2000, File No. 33-7591.)

*4.7.1(o)-Fourteenth Supplemental  Indenture,  dated as of January 1, 2001, made
          by  Oglethorpe to SunTrust  Bank,  as trustee,  relating to the Series
          2000 (Monroe) Note.  (Filed as 4.7.1(o) to the Registrant's  Form 10-K
          for the fiscal year ended December 31, 2000, File No. 33-7591.)

*4.7.1(p)-Fifteenth Supplemental Indenture, dated as of January 1, 2002, made by
          Oglethorpe to SunTrust  Bank, as trustee,  relating to the Series 2001
          (Burke) Note. (Filed as Exhibit 4.7.1(p) to the Registrant's Form 10-K
          for the fiscal year ended December 31, 2001, File No. 33-7591.)

*4.7.1(q)-Sixteenth Supplemental Indenture, dated as of January 1, 2002, made by
          Oglethorpe to SunTrust  Bank, as trustee,  relating to the Series 2001
          (Monroe) Note.  (Filed as Exhibit  4.7.1(q) to the  Registrant's  Form
          10-K for the fiscal year ended December 31, 2001, File No. 33-7591.)

4.7.1(r)--Seventeenth Supplemental Indenture,  dated as of October 1, 2002, made
          by  Oglethorpe to SunTrust  Bank,  as trustee,  relating to the Series
          2002A (Burke) Note.

4.7.1(s)--Eighteenth Supplemental  Indenture,  dated as of October 1, 2002, made
          by  Oglethorpe to SunTrust  Bank,  as trustee,  relating to the Series
          2002B (Burke) Note.

4.7.1(t)--Nineteenth Supplemental  Indenture,  dated as of January 1, 2003, made
          by  Oglethorpe to SunTrust  Bank,  as trustee,  relating to the Series
          2002C (Burke) Note.

4.7.1(u)--Twentieth Supplemental Indenture, dated as of January 1, 2003, made by
          Oglethorpe to SunTrust  Bank, as trustee,  relating to the Series 2002
          (Monroe) Note.

4.7.1(v)--Twenty-First Supplemental Indenture, dated as of January 1, 2003, made
          by  Oglethorpe to SunTrust  Bank,  as trustee,  relating to the Series
          2002 (Appling) Note.

*4.7.2 -- Security  Agreement,  dated as of March 1, 1997, made by Oglethorpe to
          SunTrust  Bank,  Atlanta,  as trustee.  (Filed as Exhibit 4.8.2 to the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1996,
          File No. 33-7591.)

4.8.1(1)--Loan  Agreement,  dated as of  October 1,  1992,  between  Development
          Authority  of Monroe  County and  Oglethorpe  relating to  Development
          Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe
          Power  Corporation  Scherer  Project),  Series  1992A,  and five other
          substantially identical loan agreements.


4.8.2(1)--Note, dated October 1, 1992, from Oglethorpe to Trust Company Bank, as
          trustee acting pursuant to a Trust  Indenture,  dated as of October 1,
          1992, between Development Authority of Monroe County and Trust Company
          Bank, and five other substantially identical notes.

4.8.3(1)--Trust  Indenture,  dated as of October 1,  1992,  between  Development
          Authority of Monroe County and Trust Company Bank,  Trustee,  relating
          to Development  Authority of Monroe County  Pollution  Control Revenue
          Bonds (Oglethorpe Power  Corporation  Scherer Project),  Series 1992A,
          and five other substantially identical trust indentures.

                                       83


4.9.1(1)--Loan  Agreement,  dated as of  December 1, 1992,  between  Development
          Authority  of Burke  County and  Oglethorpe  relating  to  Development
          Authority of Burke County  Adjustable Tender Pollution Control Revenue
          Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and
          one other substantially identical loan agreement.

4.9.2(1)--Note,  dated December 1, 1992,  from Oglethorpe to Trust Company Bank,
          as trustee acting pursuant to a Trust Indenture,  dated as of December
          1,  1992,  between  Development  Authority  of Burke  County and Trust
          Company Bank, and one other substantially identical note.

4.9.3(1)--Trust  Indenture,  dated as of  December  1,  1992,  from  Development
          Authority of Burke County to Trust Company Bank, as trustee,  relating
          to Development  Authority of Burke County  Adjustable Tender Pollution
          Control Revenue Bonds (Oglethorpe  Power Corporation  Vogtle Project),
          Series 1993A, and one other substantially identical trust indenture.

4.9.4(1)--Interest  Rate Swap  Agreement,  dated as of December 1, 1992,  by and
          between  Oglethorpe  and AIG  Financial  Products  Corp.  relating  to
          Development  Authority of Burke  County  Adjustable  Tender  Pollution
          Control Revenue Bonds (Oglethorpe  Power Corporation  Vogtle Project),
          Series 1993A, and one other substantially identical agreement.

4.9.5(1)--Liquidity  Guaranty  Agreement,  dated as of December 1, 1992,  by and
          between  Oglethorpe  and AIG  Financial  Products  Corp.  relating  to
          Development  Authority of Burke  County  Adjustable  Tender  Pollution
          Control Revenue Bonds (Oglethorpe  Power Corporation  Vogtle Project),
          Series 1993A, and one other substantially identical agreement.

4.9.6(1)--Standby Bond Purchase Agreement, dated as of December 1, 1998, between
          Oglethorpe  and  Bayerische  Landesbank   Girozentrale,   relating  to
          Development  Authority of Burke  County  Adjustable  Tender  Pollution
          Control Revenue Bonds (Oglethorpe  Power Corporation  Vogtle Project),
          Series 1993A.

4.9.7(1)--Standby  Bond  Purchase  Agreement,  dated as of  November  30,  1994,
          between Oglethorpe and Credit Local de France,  Acting through its New
          York  Agency,  relating  to  Development  Authority  of  Burke  County
          Adjustable  Tender Pollution  Control Revenue Bonds  (Oglethorpe Power
          Corporation Vogtle Project), Series 1994A.

4.10.1(1)-Loan  Agreement,  dated as of  October 1,  1996,  between  Development
          Authority  of Burke  County and  Oglethorpe  relating  to  Development
          Authority of Burke County Pollution  Control Revenue Bonds (Oglethorpe
          Power  Corporation  Vogtle  Project),   Series  1996,  and  one  other
          substantially identical loan agreements.

4.10.2(1)-Note,  dated  October 1,  1996,  from  Oglethorpe  to  SunTrust  Bank,
          Atlanta,  as trustee  pursuant to an Indenture  of Trust,  dated as of
          October 1, 1996,  between  Development  Authority  of Burke County and
          SunTrust Bank, Atlanta, and one other substantially identical note.

4.10.3(1)-Indenture of Trust, dated as of October 1, 1996,  between  Development
          Authority  of Burke  County and SunTrust  Bank,  Atlanta,  as trustee,
          relating to Development  Authority of Burke County  Pollution  Control
          Revenue Bonds (Oglethorpe Power  Corporation  Vogtle Project),  Series
          1996, and one other substantially identical indenture.

4.11.1(1)-Loan  Agreement,  dated as of  December 1, 1997,  between  Development
          Authority  of Burke  County and  Oglethorpe  relating  to  Development
          Authority of Burke County Pollution  Control Revenue Bonds (Oglethorpe
          Power  Corporation  Vogtle  Project)  Series  1997C,  and three  other
          substantially identical loan agreements.

                                       84


4.11.2(1)-Note,  dated  January 14,  1998,  from  Oglethorpe  to SunTrust  Bank,
          Atlanta,  as trustee  pursuant to an Indenture  of Trust,  dated as of
          December 1, 1997,  between  Development  Authority of Burke County and
          SunTrust Bank, Atlanta, and three other substantially identical notes.

4.11.3(1)-Indenture of Trust, dated as of December 1, 1997, between  Development
          Authority  of Burke  County and SunTrust  Bank,  Atlanta,  as trustee,
          relating to Development  Authority of Burke County  Pollution  Control
          Revenue Bonds (Oglethorpe Power  Corporation  Vogtle Project),  Series
          1997C, and three other substantially identical indentures.

4.12.1(1)-Loan  Agreement,  dated  as of  March  1,  1998,  between  Development
          Authority  of Burke  County and  Oglethorpe  relating  to  Development
          Authority of Burke County Pollution  Control Revenue Bonds (Oglethorpe
          Power  Corporation  Vogtle  Project),  Series  1998A,  and  one  other
          substantially identical loan agreement.

4.12.2(1)-Note, dated March 17, 1998, from Oglethorpe to SunTrust Bank, Atlanta,
          as trustee pursuant to a Trust  Indenture,  dated as of March 1, 1998,
          between  Development  Authority  of Burke  County and  SunTrust  Bank,
          Atlanta, and one other substantially identical note.

4.12.3(1)-Trust  Indenture,  dated  as of  March 1,  1998,  between  Development
          Authority  of Burke  County and SunTrust  Bank,  Atlanta,  as trustee,
          relating to Development  Authority of Burke County  Pollution  Control
          Revenue Bonds (Oglethorpe Power  Corporation  Vogtle Project),  Series
          1998A, and one other substantially identical indenture.

4.12.4(1)-Standby  Bond  Purchase  Agreement,  dated  March  17,  1998,  between
          Oglethorpe and Cooperatieve Centrale  Raiffeisen-Boerenleenbank  B.A.,
          "Rabobank Nederland",  acting through its New York Branch, relating to
          Development  Authority of Burke County Pollution Control Revenue Bonds
          (Oglethorpe Power Corporation  Vogtle Project),  Series 1998A, and one
          other substantially identical agreement.

*4.13.1-- Indemnity  Agreement,  dated  as of  March  1,  1997,  by and  between
          Oglethorpe   and  Georgia   Transmission   Corporation   (An  Electric
          Membership Corporation).  (Filed as Exhibit 4.13.1 to the Registrant's
          Form 10-K for the  fiscal  year  ended  December  31,  1996,  File No.
          33-7591.)

*4.13.2-- Indemnification  Agreement,  dated as of March 11, 1997, by Oglethorpe
          and  Georgia   Transmission   Corporation   (An  Electric   Membership
          Corporation)  for the benefit of the United States of America.  (Filed
          as Exhibit  4.13.2 to the  Registrant's  Form 10-K for the fiscal year
          ended December 31, 1996, File No. 33-7591.)

4.14.1(1)-Master Loan Agreement,  dated as of March 1, 1997,  between Oglethorpe
          and CoBank, ACB, MLA No. 0459.

4.14.2(1)-Consolidating   Supplement,   dated  as  of  March  1,  1997,  between
          Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T1.

4.14.3(1)-Promissory Note, dated March 1, 1997, in the original principal amount
          of $7,102,740.26, from Oglethorpe to CoBank, ACB, relating to Loan No.
          ML0459T1.

4.14.4(1)-Consolidating   Supplement,   dated  as  of  March  1,  1997,  between
          Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T2.

4.14.5(1)-Promissory Note, dated March 1, 1997, in the original principal amount
          of $1,856,475.12,  made by Oglethorpe to CoBank, ACB, relating to Loan
          No. ML0459T2.

*4.15.1-- Loan Agreement,  Loan No.  T-830404,  between  Oglethorpe and Columbia
          Bank for  Cooperatives,  dated as of April 29, 1983. (Filed as Exhibit
          4.18.1 to the Registrant's Form S-1 Registration  Statement,  File No.
          33-7591.)

                                       85


*4.15.2-- Promissory Note, Loan No. T-830404-1, in the original principal amount
          of  $9,935,000,  from  Oglethorpe to Columbia  Bank for  Cooperatives,
          dated  as  of  April  29,  1983.  (Filed  as  Exhibit  4.18.2  to  the
          Registrant's Form S-1 Registration Statement, File No. 33-7591.)

*4.15.3-- Security Deed and Security  Agreement,  dated April 29, 1983,  between
          Oglethorpe  and  Columbia  Bank for  Cooperatives.  (Filed as  Exhibit
          4.18.3 to the Registrant's Form S-1 Registration  Statement,  File No.
          33-7591, filed on October 9, 1986.)

*4.16 --  Exchange and Registration  Rights Agreement,  dated December 17, 1997,
          by and among Oglethorpe,  OPC Scherer 1997 Funding  Corporation A, and
          Goldman,  Sachs & Co. as representative  of the purchasers  identified
          therein.   (Filed  as  Exhibit  4.15  to  the  Registrant's  Form  S-4
          Registration Statement, File No. 333-42759.)

*10.1.1(a)Participation  Agreement No. 2 among Oglethorpe as Lessee,  Wilmington
          Trust Company as Owner Trustee,  The First National Bank of Atlanta as
          Indenture Trustee,  Columbia Bank for Cooperatives as Loan Participant
          and Ford Motor Credit Company as Owner Participant, dated December 30,
          1985,  together with a Schedule  identifying three other substantially
          identical Participation Agreements. (Filed as Exhibit 10.1.1(b) to the
          Registrant's Form S-1 Registration Statement, File No. 33-7591.)

*10.1.1(b)Supplemental   Participation   Agreement  No.  2.  (Filed  as  Exhibit
          10.1.1(a) to the Registrant's  Form S-1 Registration  Statement,  File
          No. 33-7591.)

*10.1.1(c)Supplemental Participation Agreement No. 1, dated as of June 30, 1987,
          among Oglethorpe as Lessee, IBM Credit Financing  Corporation as Owner
          Participant,  Wilmington  Trust  Company and The Citizens and Southern
          National Bank as Owner Trustee, The First National Bank of Atlanta, as
          Indenture  Trustee,  and  Columbia  Bank  for  Cooperatives,  as  Loan
          Participant. (Filed as Exhibit 10.1.1(c) to the Registrant's Form 10-K
          for the fiscal year ended December 31, 1987, File No. 33-7591.)

*10.1.1(d)Second  Supplemental  Participation  Agreement  No.  2,  dated  as  of
          December 17, 1997,  among Oglethorpe as Lessee,  DFO  Partnership,  as
          assignee  of  Ford  Motor  Credit  Company,   as  Owner   Participant,
          Wilmington Trust Company and NationsBank,  N.A. as Owner Trustee,  The
          Bank of New York Trust Company of Florida,  N.A. as Indenture Trustee,
          CoBank, ACB as Loan Participant,  OPC Scherer Funding Corporation,  as
          Original Funding Corporation,  OPC Scherer 1997 Funding Corporation A,
          as Funding  Corporation,  and  SunTrust  Bank,  Atlanta,  as  Original
          Collateral Trust Trustee and Collateral Trust Trustee, with a Schedule
          identifying   three   substantially   identical  Second   Supplemental
          Participation  Agreements  and any  material  differences.  (Filed  as
          Exhibit  10.1.1(d) to Registrant's  Form S-4  Registration  Statement,
          File No. 333-4275.)

                                       86


*10.1.2-- General  Warranty  Deed and Bill of Sale  No.  2  between  Oglethorpe,
          Grantor,  and  Wilmington  Trust Company and William J. Wade, as Owner
          Trustees under Trust  Agreement No. 2, dated  December 30, 1985,  with
          Ford  Motor  Credit  Company,   Grantee,   together  with  a  Schedule
          identifying three  substantially  identical General Warranty Deeds and
          Bills of Sale.  (Filed as Exhibit 10.1.2 to the Registrant's  Form S-1
          Registration Statement, File No. 33-7591.)

*10.1.3(a)Supporting  Assets  Lease No. 2,  dated  December  30,  1985,  between
          Oglethorpe,  Lessor, and Wilmington Trust Company and William J. Wade,
          as Owner  Trustees,  under Trust  Agreement No. 2, dated  December 30,
          1985, with Ford Motor Credit Company, Lessee, together with a Schedule
          identifying three  substantially  identical  Supporting Assets Leases.
          (Filed as Exhibit  10.1.3 to the  Registrant's  Form S-1  Registration
          Statement, File No. 33-7591.)

*10.1.3(b)First Amendment to Supporting Assets Lease No. 2, dated as of November
          19, 1987,  together with a Schedule  identifying  three  substantially
          identical  First  Amendments to Supporting  Assets  Leases.  (Filed as
          Exhibit  10.1.3(a) to the  Registrant's  Form 10-K for the fiscal year
          ended December 31, 1987, File No. 33-7591.)

*10.1.3(c)Second Amendment to Supporting Assets Lease No. 2, dated as of October
          3, 1989,  together  with a Schedule  identifying  three  substantially
          identical  Second  Amendments to Supporting  Assets Leases.  (Filed as
          Exhibit  10.1.3(c)  to the  Registrant's  Form 10-Q for the  quarterly
          period ended March 31, 1998, File No. 33-7591.)

*10.1.4(a)Supporting  Assets  Sublease No. 2, dated  December 30, 1985,  between
          Wilmington  Trust Company and William J. Wade, as Owner Trustees under
          Trust  Agreement No. 2 dated December 30, 1985, with Ford Motor Credit
          Company,  Sublessor,  and  Oglethorpe,   Sublessee,  together  with  a
          Schedule  identifying three substantially  identical Supporting Assets
          Subleases.  (Filed  as  Exhibit  10.1.4 to the  Registrant's  Form S-1
          Registration Statement, File No. 33-7591.)

*10.1.4(b)First  Amendment  to  Supporting  Assets  Sublease  No. 2, dated as of
          November  19,  1987,  together  with  a  Schedule   identifying  three
          substantially   identical  First   Amendments  to  Supporting   Assets
          Subleases.  (Filed as Exhibit  10.1.4(a) to the Registrant's Form 10-K
          for the fiscal year ended December 31, 1987, File No. 33-7591.)

*10.1.4(c)Second  Amendment  to  Supporting  Assets  Sublease No. 2, dated as of
          October  3,  1989,   together  with  a  Schedule   identifying   three
          substantially   identical  Second   Amendments  to  Supporting  Assets
          Subleases.  (Filed as Exhibit  10.1.4(c) to the Registrant's Form 10-Q
          for the quarterly period ended March 31, 1998, File No. 33-7591.)

*10.1.5(a)Tax Indemnification  Agreement No. 2, dated December 30, 1985, between
          Ford Motor Credit Company, Owner Participant, and Oglethorpe,  Lessee,
          together with a Schedule identifying three substantially identical Tax
          Indemnification   Agreements.   (Filed  as   Exhibit   10.1.5  to  the
          Registrant's Form S-1 Registration Statement, File No. 33-7591.)

*10.1.5(b)Amendment  No. 1 to the Tax  Indemnification  Agreement  No. 2,  dated
          December 17, 1997, between DFO Partnership,  as assignee of Ford Motor
          Credit Company, as Owner Participant,  and Oglethorpe, as Lessee, with
          a Schedule identifying three substantially  identical Amendments No. 1
          to the Tax  Indemnification  Agreements and any material  differences.
          (Filed as Exhibit  10.1.5(b) to the Registrant's Form S-4 Registration
          Statement, File No. 333-42759.)

                                       87


*10.1.6-- Assignment of Interest in Ownership  Agreement and Operating Agreement
          No. 2, dated  December 30, 1985,  between  Oglethorpe,  Assignor,  and
          Wilmington  Trust Company and William J. Wade, as Owner Trustees under
          Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
          Company,   Assignee,   together   with  Schedule   identifying   three
          substantially identical Assignments of Interest in Ownership Agreement
          and Operating Agreement.  (Filed as Exhibit 10.1.6 to the Registrant's
          Form S-1 Registration Statement, File No. 33-7591.)

*10.1.7-- Consent, Amendment and Assumption No. 2 dated December 30, 1985, among
          Georgia Power Company and Oglethorpe and Municipal  Electric Authority
          of Georgia  and City of Dalton,  Georgia  and Gulf Power  Company  and
          Wilmington  Trust Company and William J. Wade, as Owner Trustees under
          Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
          Company,  together  with a Schedule  identifying  three  substantially
          identical  Consents,  Amendments  and  Assumptions.  (Filed as Exhibit
          10.1.9 to the Registrant's Form S-1 Registration  Statement,  File No.
          33-7591.)

*10.1.7(a)Amendment  to Consent,  Amendment  and  Assumption  No. 2, dated as of
          August 16, 1993, among  Oglethorpe,  Georgia Power Company,  Municipal
          Electric  Authority of Georgia,  City of Dalton,  Georgia,  Gulf Power
          Company,  Jacksonville  Electric  Authority,  Florida  Power  &  Light
          Company and Wilmington Trust Company and NationsBank of Georgia, N.A.,
          as Owner  Trustees  under Trust  Agreement  No. 2, dated  December 30,
          1985,  with  Ford  Motor  Credit  Company,  together  with a  Schedule
          identifying  three  substantially  identical  Amendments  to Consents,
          Amendments  and  Assumptions.  (Filed  as  Exhibit  10.1.9(a)  to  the
          Registrant's  Form 10-Q for the quarterly  period ended  September 30,
          1993, File No. 33-7591.)

*10.2.1-- Section 168 Agreement and Election dated as of April 7, 1982,  between
          Continental  Telephone  Corporation and Oglethorpe.  (Filed as Exhibit
          10.2 to the  Registrant's  Form S-1 Registration  Statement,  File No.
          33-7591.)

*10.2.2-- Section 168 Agreement and Election dated as of April 9, 1982,  between
          Rollins,   Inc.  and  Oglethorpe.   (Filed  as  Exhibit  10.4  to  the
          Registrant's Form S-1 Registration Statement, File No. 33-7591.)

*10.3.1(a)Plant  Robert  W.  Scherer  Units  Numbers  One and Two  Purchase  and
          Ownership   Participation   Agreement  among  Georgia  Power  Company,
          Oglethorpe,  Municipal  Electric  Authority  of  Georgia  and  City of
          Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit 10.6.1 to
          the Registrant's Form S-1 Registration Statement, File No. 33-7591.)

*10.3.1(b)Amendment  to  Plant  Robert  W.  Scherer  Units  Numbers  One and Two
          Purchase and  Ownership  Participation  Agreement  among Georgia Power
          Company, Oglethorpe,  Municipal Electric Authority of Georgia and City
          of Dalton,  Georgia,  dated as of December 30, 1985. (Filed as Exhibit
          10.1.8 to the Registrant's Form S-1 Registration  Statement,  File No.
          33-7591.)

*10.3.1(c)Amendment  Number Two to the Plant Robert W. Scherer Units Numbers One
          and Two Purchase and Ownership  Participation  Agreement among Georgia
          Power Company, Oglethorpe, Municipal Electric Authority of Georgia and
          City of Dalton,  Georgia,  dated as of July 1, 1986. (Filed as Exhibit
          10.6.1(a)  to the  Registrant's  Form 10-K for the  fiscal  year ended
          December 31, 1987, File No. 33-7591.)

                                       88


*10.3.1(d)Amendment  Number Three to the Plant Robert W. Scherer  Units  Numbers
          One and Two  Purchase  and  Ownership  Participation  Agreement  among
          Georgia Power Company,  Oglethorpe,  Municipal  Electric  Authority of
          Georgia  and City of  Dalton,  Georgia,  dated as of August  1,  1988.
          (Filed as  Exhibit  10.6.1(b)  to the  Registrant's  Form 10-Q for the
          quarterly period ended September 30, 1993, File No. 33-7591.)

*10.3.1(e)Amendment  Number Four to the Plant Robert W. Scherer Units Number One
          and Two Purchase and Ownership  Participation  Agreement among Georgia
          Power Company, Oglethorpe, Municipal Electric Authority of Georgia and
          City of Dalton,  Georgia,  dated as of December  31,  1990.  (Filed as
          Exhibit  10.6.1(c)  to the  Registrant's  Form 10-Q for the  quarterly
          period ended September 30, 1993, File No. 33-7591.)

*10.3.2(a)Plant Robert W. Scherer Units Numbers One and Two Operating  Agreement
          among Georgia Power Company, Oglethorpe,  Municipal Electric Authority
          of Georgia  and City of  Dalton,  Georgia,  dated as of May 15,  1980.
          (Filed as Exhibit  10.6.2 to the  Registrant's  Form S-1  Registration
          Statement, File No. 33-7591.)

*10.3.2(b)Amendment  to  Plant  Robert  W.  Scherer  Units  Numbers  One and Two
          Operating Agreement among Georgia Power Company, Oglethorpe, Municipal
          Electric Authority of Georgia and City of Dalton, Georgia, dated as of
          December 30, 1985.  (Filed as Exhibit 10.1.7 to the Registrant's  Form
          S-1 Registration Statement, File No. 33-7591.)

*10.3.2(c)Amendment  Number Two to the Plant Robert W. Scherer Units Numbers One
          and Two Operating  Agreement among Georgia Power Company,  Oglethorpe,
          Municipal Electric  Authority of Georgia and City of Dalton,  Georgia,
          dated as of December  31,  1990.  (Filed as Exhibit  10.6.2(a)  to the
          Registrant's  Form 10-Q for the quarterly  period ended  September 30,
          1993, File No. 33-7591.)

*10.3.3-- Plant Scherer  Managing Board  Agreement  among Georgia Power Company,
          Oglethorpe,  Municipal Electric Authority of Georgia,  City of Dalton,
          Georgia,  Gulf  Power  Company,  Florida  Power  & Light  Company  and
          Jacksonville Electric Authority, dated as of December 31, 1990. (Filed
          as  Exhibit  10.6.3 to the  Registrant's  Form 10-Q for the  quarterly
          period ended September 30, 1993, File No. 33-7591.)

*10.4.1(a)Alvin  W.  Vogtle  Nuclear  Units  Numbers  One and Two  Purchase  and
          Ownership   Participation   Agreement  among  Georgia  Power  Company,
          Oglethorpe,  Municipal  Electric  Authority  of  Georgia  and  City of
          Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit 10.7.1
          to  the  Registrant's  Form  S-1  Registration  Statement,   File  No.
          33-7591.)

*10.4.1(b)Amendment  Number One,  dated January 18, 1977, to the Alvin W. Vogtle
          Nuclear Units Numbers One and Two Purchase and Ownership Participation
          Agreement among Georgia Power Company, Oglethorpe,  Municipal Electric
          Authority  of Georgia and City of Dalton,  Georgia.  (Filed as Exhibit
          10.7.3  to the  Registrant's  Form  10-K  for the  fiscal  year  ended
          December 31, 1986, File No. 33-7591.)

*10.4.1(c)Amendment  Number Two, dated February 24, 1977, to the Alvin W. Vogtle
          Nuclear Units Numbers One and Two Purchase and Ownership Participation
          Agreement among Georgia Power Company, Oglethorpe,  Municipal Electric
          Authority  of Georgia and City of Dalton,  Georgia.  (Filed as Exhibit
          10.7.4  to the  Registrant's  Form  10-K  for the  fiscal  year  ended
          December 31, 1986, File No. 33-7591.)

                                       89


*10.4.2-- Alvin W. Vogtle Nuclear Units Numbers One and Two Operating  Agreement
          among Georgia Power Company, Oglethorpe,  Municipal Electric Authority
          of Georgia and City of Dalton,  Georgia,  dated as of August 27, 1976.
          (Filed as Exhibit  10.7.2 to the  Registrant's  Form S-1  Registration
          Statement, File No. 33-7591.)

*10.5.1-- Plant Hal  Wansley  Purchase  and  Ownership  Participation  Agreement
          between  Georgia Power Company and  Oglethorpe,  dated as of March 26,
          1976.   (Filed  as  Exhibit  10.8.1  to  the  Registrant's   Form  S-1
          Registration Statement, File No. 33-7591.)

*10.5.2(a)Plant Hal Wansley  Operating  Agreement  between Georgia Power Company
          and Oglethorpe,  dated as of March 26, 1976.  (Filed as Exhibit 10.8.2
          to  the  Registrant's  Form  S-1  Registration  Statement,   File  No.
          33-7591.)

*10.5.2(b)Amendment,  dated as of January  15,  1995,  to the Plant Hal  Wansley
          Operating  Agreements by and among Georgia Power Company,  Oglethorpe,
          Municipal Electric  Authority of Georgia and City of Dalton,  Georgia.
          (Filed as  Exhibit  10.5.2(a)  to the  Registrant's  Form 10-Q for the
          quarterly period ended September 30, 1996, File No. 33-7591.)

*10.5.3 --Plant Hal Wansley  Combustion  Turbine Agreement between Georgia Power
          Company and  Oglethorpe,  dated as of August 2, 1982 and Amendment No.
          1, dated October 20, 1982. (Filed as Exhibit 10.18 to the Registrant's
          Form S-1 Registration Statement, File No. 33-7591.)

*10.6.1 --Edwin I. Hatch  Nuclear  Plant  Purchase and  Ownership  Participation
          Agreement  between Georgia Power Company and  Oglethorpe,  dated as of
          January 6, 1975. (Filed as Exhibit 10.9.1 to the Registrant's Form S-1
          Registration Statement, File No. 33-7591.)

*10.6.2-- Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia Power
          Company and Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit
          10.9.2 to the Registrant's Form S-1 Registration  Statement,  File No.
          33-7591.)

*10.7.1-- Rocky  Mountain  Pumped  Storage   Hydroelectric   Project   Ownership
          Participation Agreement, dated as of November 18, 1988, by and between
          Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.1 to the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1988,
          File No. 33-7591.)

*10.7.2-- Rocky  Mountain  Pumped  Storage   Hydroelectric   Project   Operating
          Agreement,  dated as of November 18, 1988,  by and between  Oglethorpe
          and  Georgia  Power  Company.   (Filed  as  Exhibit   10.22.2  to  the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1988,
          File No. 33-7591.)

*10.8.1-- Amended and Restated  Wholesale Power Contract,  dated as of August 1,
          1996, between Oglethorpe and Altamaha Electric Membership  Corporation
          and all schedules  thereto,  together with a Schedule  identifying  37
          other  substantially  identical  Amended and Restated  Wholesale Power
          Contracts,  and an  additional  Amended and Restated  Wholesale  Power
          Contract that is not substantially identical. (Filed as Exhibit 10.8.1
          to the  Registrant's  Form 10-K for the fiscal year ended December 31,
          1996, File No. 33-7591.)

*10.8.2-- Amended and  Restated  Supplemental  Agreement,  dated as of August 1,
          1996,  by  and  between   Oglethorpe,   Altamaha  Electric  Membership
          Corporation and the United States of America, together with a Schedule
          identifying  38 other  substantially  identical  Amended and  Restated
          Supplemental Agreements.  (Filed as Exhibit 10.8.2 to the Registrant's
          Form 10-K for the  fiscal  year  ended  December  31,  1996,  File No.
          33-7591.)

                                       90


*10.8.3-- Supplemental  Agreement  to the Amended and Restated  Wholesale  Power
          Contract,  dated as of  January 1, 1997,  by and among  Georgia  Power
          Company,  Oglethorpe  and Altamaha  Electric  Membership  Corporation,
          together with a Schedule identifying 38 other substantially  identical
          Supplemental Agreements.  (Filed as Exhibit 10.8.3 to the Registrant's
          Form 10-K for the  fiscal  year  ended  December  31,  1996,  File No.
          33-7591.)

*10.8.4-- Supplemental  Agreement  to the Amended and Restated  Wholesale  Power
          Contract,  dated as of March 1, 1997,  by and between  Oglethorpe  and
          Altamaha  Electric  Membership  Corporation,  together with a Schedule
          identifying 36 other substantially identical Supplemental  Agreements,
          and an additional  Supplemental  Agreement  that is not  substantially
          identical.  (Filed as Exhibit 10.8.4 to the Registrant's Form 10-K for
          the fiscal year ended December 31, 1996, File No. 33-7591.)

*10.8.5-- Supplemental  Agreement  to the Amended and Restated  Wholesale  Power
          Contract,  dated as of March 1, 1997,  by and between  Oglethorpe  and
          Coweta-Fayette  Electric  Membership  Corporation,   together  with  a
          Schedule  identifying  1 other  substantially  identical  Supplemental
          Agreement.  (Filed as Exhibit 10.8.5 to the Registrant's Form 10-K for
          the fiscal year ended December 31, 1996, File No. 33-7591.)

*10.8.6-- Supplemental  Agreement  to the Amended and Restated  Wholesale  Power
          Contract,  dated  as of May 1,  1997  by and  between  Oglethorpe  and
          Altamaha  Electric  Membership  Corporation,  together with a Schedule
          identifying 38 other substantially identical Supplemental  Agreements.
          (Filed  as  Exhibit  10.8.6  to the  Registrant's  Form  10-Q  for the
          quarterly period ended June 30, 1997, File No. 33-7591.)

*10.9(a)--Joint  Committee  Agreement  among Georgia Power Company,  Oglethorpe,
          Municipal  Electric  Authority  of  Georgia  and the  City of  Dalton,
          Georgia,  dated as of August 27, 1976.  (Filed as Exhibit  10.14(b) to
          the Registrant's Form S-1 Registration Statement, File No. 33-7591.)

*10.9(b)--First  Amendment to Joint  Committee  Agreement  among  Georgia  Power
          Company,  Oglethorpe,  Municipal Electric Authority of Georgia and the
          City of Dalton,  Georgia, dated as of June 19, 1978. (Filed as Exhibit
          10.14(a) to the Registrant's Form S-1 Registration Statement, File No.
          33-7591.)

*10.10--  Letter  of  Commitment   (Firm  Power  Sale)  Under  Service  Schedule
          J--Negotiated    Interchange    Service   between   Alabama   Electric
          Cooperative,  Inc. and  Oglethorpe,  dated March 31,  1994.  (Filed as
          Exhibit 10.11(b) to the  Registrant's  Form 10-Q for the quarter ended
          June 30, 1994, File No. 33-7591.)

*10.11.1--Assignment of Power System Agreement and Settlement  Agreement,  dated
          January  8,  1975,  by  Georgia  Electric  Membership  Corporation  to
          Oglethorpe.  (Filed as Exhibit  10.20.1 to the  Registrant's  Form S-1
          Registration Statement, File No. 33-7591.)

*10.11.2--Power System  Agreement,  dated April 24, 1974, by and between Georgia
          Electric Membership  Corporation and Georgia Power Company.  (Filed as
          Exhibit 10.20.2 to the Registrant's  Form S-1 Registration  Statement,
          File No. 33-7591.)

                                       91


*10.11.3--Settlement  Agreement,  dated April 24, 1974,  by and between  Georgia
          Power Company,  Georgia Municipal  Association,  Inc., City of Dalton,
          Georgia  Electric  Membership   Corporation  and  Crisp  County  Power
          Commission.  (Filed as Exhibit  10.20.3 to the  Registrant's  Form S-1
          Registration Statement, File No. 33-7591.)

*10.12--  Long-Term Firm Power Purchase  Agreement  between Big Rivers  Electric
          Corporation and Oglethorpe,  dated as of December 17, 1990.  (Filed as
          Exhibit  10.24.3 to the  Registrant's  Form 10-K for the  fiscal  year
          ended December 31, 1990, File No. 33-7591.)

*10.13--  Revised and Restated Coordination Services Agreement between and among
          Georgia  Power  Company,  Oglethorpe  and  Georgia  System  Operations
          Corporation,  dated as of September 10, 1997.  (Filed as Exhibit 10.14
          to the  Registrant's  Form 10-K for the fiscal year ended December 31,
          1997, File No. 33-7591.)

*10.14 -- ITSA,  Power  Sale  and  Coordination   Umbrella   Agreement   between
          Oglethorpe and Georgia Power  Company,  dated as of November 12, 1990.
          (Filed as Exhibit 10.28 to the Registrant's Form 8-K, filed January 4,
          1991, File No. 33-7591.)

*10.15 -- Amended and Restated  Nuclear  Managing Board  Agreement among Georgia
          Power  Company,  Oglethorpe  Power  Corporation,   Municipal  Electric
          Authority of Georgia and City of Dalton,  Georgia  dated as of July 1,
          1993.  (Filed  as  Exhibit  10.36  to the  Registrant's  10-Q  for the
          quarterly period ended September 30, 1993, File No. 33-7591.)

*10.16 -- Supplemental  Agreement by and among Oglethorpe,  Tri-County  Electric
          Membership Corporation and Georgia Power Company, dated as of November
          12, 1990, together with a Schedule  identifying 38 other substantially
          identical  Supplemental  Agreements.  (Filed as  Exhibit  10.30 to the
          Registrant's Form 8-K, filed January 4, 1991, File No. 33-7591.)

*10.17 -- Unit Capacity and Energy  Purchase  Agreement  between  Oglethorpe and
          Entergy Power  Incorporated,  dated as of October 11, 1990.  (Filed as
          Exhibit 10.31 to the Registrant's  Form 10-K for the fiscal year ended
          December 31, 1990, File No. 33-7591.)

*10.18 -- Power  Purchase  Agreement  between  Oglethorpe  and  Hartwell  Energy
          Limited  Partnership,  dated as of June 12,  1992.  (Filed as  Exhibit
          10.35 to the Registrant's Form 10-K for the fiscal year ended December
          31, 1992, File No. 33-7591).

*10.19(2)-Power Purchase and Sale  Agreement  among LG&E Power  Marketing  Inc.,
          LG&E Energy  Corp.  and  Oglethorpe,  dated as of November  19,  1996.
          (Filed as Exhibit 10.30 to the  Registrant's  Form 10-K for the fiscal
          year ended December 31, 1996, File No. 33-7591.)

*10.20(2)-Power Purchase and Sale  Agreement  among LG&E Power  Marketing  Inc.,
          LG&E Power Inc. and Oglethorpe, dated as of January 1, 1997. (Filed as
          Exhibit 10.31 to the Registrant's  Form 10-K for the fiscal year ended
          December 31, 1996, File No. 33-7591.)

*10.21.1--Participation  Agreement  (P1),  dated as of December 30, 1996,  among
          Oglethorpe,  Rocky Mountain Leasing Corporation,  Fleet National Bank,
          as Owner Trustee,  SunTrust Bank,  Atlanta,  as Co-Trustee,  the Owner
          Participant named therein and Utrecht-America  Finance Co., as Lender,
          together  with  a  Schedule   identifying  five  other   substantially
          identical Participation  Agreements.  (Filed as Exhibit 10.32.1 to the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1996,
          File No. 33-7591.)

                                       92


*10.21.2--Rocky  Mountain Head Lease  Agreement  (P1),  dated as of December 30,
          1996,  between Oglethorpe and SunTrust Bank,  Atlanta,  as Co-Trustee,
          together  with  a  Schedule   identifying  five  other   substantially
          identical  Rocky  Mountain  Head Lease  Agreements.  (Filed as Exhibit
          10.32.2  to the  Registrant's  Form  10-K for the  fiscal  year  ended
          December 31, 1996, File No. 33-7591.)

*10.21.3--Ground Lease  Agreement (P1),  dated as of December 30, 1996,  between
          Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee,  together with a
          Schedule  identifying five other substantially  identical Ground Lease
          Agreements.  (Filed as Exhibit 10.32.3 to the  Registrant's  Form 10-K
          for the fiscal year ended December 31, 1996, File No. 33-7591.)

*10.21.4--Rocky Mountain  Agreements  Assignment and Assumption  Agreement (P1),
          dated as of December 30, 1996,  between  Oglethorpe and SunTrust Bank,
          Atlanta,  as  Co-Trustee,  together with a Schedule  identifying  five
          other substantially identical Rocky Mountain Agreements Assignment and
          Assumption  Agreements.  (Filed as Exhibit 10.32.4 to the Registrant's
          Form 10-K for the  fiscal  year  ended  December  31,  1996,  File No.
          33-7591.)

*10.21.5--Facility Lease Agreement (P1), dated as of December 30, 1996,  between
          SunTrust  Bank,  Atlanta,  as Co-Trustee  and Rocky  Mountain  Leasing
          Corporation,   together  with  a  Schedule   identifying   five  other
          substantially  identical Facility Lease Agreements.  (Filed as Exhibit
          10.32.5  to the  Registrant's  Form  10-K for the  fiscal  year  ended
          December 31, 1996, File No. 33-7591.)

*10.21.6--Ground Sublease Agreement (P1), dated as of December 30, 1996, between
          SunTrust  Bank,  Atlanta,  as Co-Trustee  and Rocky  Mountain  Leasing
          Corporation,   together  with  a  Schedule   identifying   five  other
          substantially identical Ground Sublease Agreements.  (Filed as Exhibit
          10.32.6  to the  Registrant's  Form  10-K for the  fiscal  year  ended
          December 31, 1996, File No. 33-7591.)

*10.21.7--Rocky Mountain Agreements Re-assignment and Assumption Agreement (P1),
          dated as of December 30, 1996,  between  SunTrust  Bank,  Atlanta,  as
          Co-Trustee and Rocky  Mountain  Leasing  Corporation,  together with a
          Schedule identifying five other substantially identical Rocky Mountain
          Agreements Re-assignment and Assumption Agreements.  (Filed as Exhibit
          10.32.7  to the  Registrant's  Form  10-K for the  fiscal  year  ended
          December 31, 1996, File No. 33-7591.)

*10.21.8--Facility  Sublease  Agreement  (P1),  dated as of December  30,  1996,
          between  Oglethorpe and Rocky Mountain Leasing  Corporation,  together
          with  a  Schedule  identifying  five  other  substantially   identical
          Facility  Sublease  Agreements.  (Filed  as  Exhibit  10.32.8  to  the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1996,
          File No. 33-7591.)

*10.21.9--Ground  Sub-sublease  Agreement  (P1),  dated as of December 30, 1996,
          between Rocky Mountain  Leasing  Corporation and Oglethorpe,  together
          with a Schedule identifying five other substantially  identical Ground
          Sub-sublease Agreements. (Filed as Exhibit 10.32.9 to the Registrant's
          Form 10-K for the  fiscal  year  ended  December  31,  1996,  File No.
          33-7591.)

                                       93


*10.21.10-Rocky  Mountain   Agreements   Second   Re-assignment  and  Assumption
          Agreement (P1), dated as of December 30, 1996,  between Rocky Mountain
          Leasing   Corporation  and   Oglethorpe,   together  with  a  Schedule
          identifying   five  other   substantially   identical  Rocky  Mountain
          Agreements Second Re-assignment and Assumption  Agreements.  (Filed as
          Exhibit  10.32.10  to the  Registrant's  Form 10-K for the fiscal year
          ended December 31, 1996, File No. 33-7591.)

*10.21.11-Payment  Undertaking  Agreement  (P1),  dated as of December 30, 1996,
          between Rocky Mountain Leasing  Corporation and Cooperatieve  Centrale
          Raiffeisen-Boerenleenbank B.A., New York Branch, as the Bank, together
          with a Schedule identifying five other substantially identical Payment
          Undertaking Agreements. (Filed as Exhibit 10.32.11 to the Registrant's
          Form 10-K for the  fiscal  year  ended  December  31,  1996,  File No.
          33-7591.)

*10.21.12-Payment  Undertaking  Pledge  Agreement (P1), dated as of December 30,
          1996, between Rocky Mountain Leasing Corporation, Fleet National Bank,
          as Owner Trustee, and SunTrust Bank, Atlanta, as Co-Trustee,  together
          with a Schedule identifying five other substantially identical Payment
          Undertaking  Pledge  Agreements.  (Filed as  Exhibit  10.32.12  to the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1996,
          File No. 33-7591.)

*10.21.13-Equity Funding Agreement (P1), dated as of December 30, 1996,  between
          Rocky Mountain Leasing Corporation, AIG Match Funding Corp., the Owner
          Participant named therein,  Fleet National Bank, as Owner Trustee, and
          SunTrust  Bank,  Atlanta,  as  Co-Trustee,  together  with a  Schedule
          identifying   five  other   substantially   identical  Equity  Funding
          Agreements.  (Filed as Exhibit 10.32.13 to the Registrant's  Form 10-K
          for the fiscal year ended December 31, 1996, File No. 33-7591.)

*10.21.14-Equity Funding Pledge  Agreement (P1),  dated as of December 30, 1996,
          between Rocky Mountain Leasing Corporation and SunTrust Bank, Atlanta,
          as  Co-Trustee,  together  with  a  Schedule  identifying  five  other
          substantially  identical Equity Funding Pledge  Agreements.  (Filed as
          Exhibit  10.32.14  to the  Registrant's  Form 10-K for the fiscal year
          ended December 31, 1996, File No. 33-7591.)

*10.21.15-Deed to Secure Debt,  Assignment of Surety Bond and Security Agreement
          (P1),  dated as of December 30, 1996,  between Rocky Mountain  Leasing
          Corporation,  SunTrust Bank, Atlanta,  as Co-Trustee,  together with a
          Schedule  identifying five other  substantially  identical  Collateral
          Assignment,  Assignment of Surety Bond and Security Agreements. (Filed
          as Exhibit 10.32.15 to the Registrant's  Form 10-K for the fiscal year
          ended December 31, 1996, File No. 33-7591.)

*10.21.16-Subordinated Deed to Secure Debt and Security Agreement (P1), dated as
          of December 30, 1996, among  Oglethorpe,  AMBAC Indemnity  Corporation
          and SunTrust Bank,  Atlanta,  as Co-Trustee,  together with a Schedule
          identifying five other  substantially  identical  Subordinated Deed to
          Secure Debt and Security Agreements. (Filed as Exhibit 10.32.16 to the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1996,
          File No. 33-7591.)

*10.21.17-Tax  Indemnification  Agreement  (P1),  dated as of December 30, 1996,
          between  Oglethorpe and the Owner Participant named therein,  together
          with a Schedule  identifying  five other  substantially  identical Tax
          Indemnification   Agreements.   (Filed  as  Exhibit  10.32.17  to  the
          Registrant's  Form 10-K for the fiscal year ended  December  31, 1996,
          File No. 33-7591.)

                                       94


*10.21.18-     Consent No. 1, dated as of December 30, 1996, among Georgia Power
               Company,  Oglethorpe,  SunTrust Bank, Atlanta, as Co-Trustee, and
               Fleet National  Bank, as Owner Trustee,  together with a Schedule
               identifying five other substantially  identical Consents.  (Filed
               as Exhibit 10.32.18 to the Registrant's  Form 10-K for the fiscal
               year ended December 31, 1996, File No. 33-7591.)

*10.21.19(a)-- OPC  Intercreditor  and  Security  Agreement  No. 1,  dated as of
               December 30,  1996,  among the United  States of America,  acting
               through  the  Administrator  of  the  Rural  Utilities   Service,
               SunTrust  Bank,  Atlanta,   Oglethorpe,  Rocky  Mountain  Leasing
               Corporation,   SunTrust  Bank,  Atlanta,  as  Co-Trustee,   Fleet
               National Bank, as Owner Trustee,  Utrecht-America Finance Co., as
               Lender and AMBAC Indemnity Corporation,  together with a Schedule
               identifying five other substantially  identical Intercreditor and
               Security   Agreements.   (Filed  as  Exhibit   10.32.19   to  the
               Registrant's  Form 10-K for the fiscal  year ended  December  31,
               1996, File No. 33-7591.)

*10.21.19(b)-- Supplement  to OPC  Intercreditor  and Security  Agreement No. 1,
               dated as of March 1, 1997,  among the United  States of  America,
               acting through the Administrator of the Rural Utilities  Service,
               SunTrust  Bank,  Atlanta,   Oglethorpe,  Rocky  Mountain  Leasing
               Corporation,   SunTrust  Bank,  Atlanta,  as  Co-Trustee,   Fleet
               National Bank, as Owner Trustee,  Utrecht-America Finance Co., as
               Lender and AMBAC Indemnity Corporation,  together with a Schedule
               identifying five other substantially identical Supplements to OPC
               Intercreditor   and  Security   Agreements.   (Filed  as  Exhibit
               10.32.19(b) to the Registrant's Form S-4 Registration  Statement,
               File No. 333-42759.)

*10.22.1--     Member Transmission Service Agreement, dated as of March 1, 1997,
               by and between  Oglethorpe and Georgia  Transmission  Corporation
               (An Electric Membership  Corporation).  (Filed as Exhibit 10.33.1
               to the Registrant's  Form 10-K for the fiscal year ended December
               31, 1996, File No. 33-7591.)

*10.22.2--     Generation Services Agreement,  dated as of March 1, 1997, by and
               between  Oglethorpe  and Georgia System  Operations  Corporation.
               (Filed as Exhibit 10.33.2 to the  Registrant's  Form 10-K for the
               fiscal year ended December 31, 1996, File No. 33-7591.)

*10.22.3--     Operation Services  Agreement,  dated as of March 1, 1997, by and
               between  Oglethorpe  and Georgia System  Operations  Corporation.
               (Filed as Exhibit 10.33.3 to the  Registrant's  Form 10-K for the
               fiscal year ended December 31, 1996, File No. 33-7591.)

*10.23(2)--    Power Purchase and Sale Agreement  between Morgan Stanley Capital
               Group Inc. and Oglethorpe,  dated as of April 7, 1997.  (Filed as
               Exhibit  10.34 to the  Registrant's  Form 10-Q for the  quarterly
               period ended March 31, 1997, File No. 33-7591.)

*10.24 --      Long Term Transaction Service Agreement Under Southern Companies'
               Federal Energy Regulatory Commission Electric Tariff Volume No. 4
               Market-Based  Rate  Tariff,  between  Georgia  Power  Company and
               Oglethorpe,  dated as of  February  26,  1999.  (Filed as Exhibit
               10.27 to the  Registrant's  Form  10-Q for the  quarterly  period
               ended March 31, 1999, File No. 33-7591.)

*10.25(3)--    Employment  Agreement,  dated  as  of  March  15,  2002,  between
               Oglethorpe  and Thomas A. Smith.  (Filed as Exhibit  10.25 to the
               Registrant's  Form 10-K for the fiscal  year ended  December  31,
               2001, File No. 33-7591.)

                                       95


*10.26(3)--    Employment Agreement, dated July 25, 2000, between Oglethorpe and
               Michael W.  Price.  (Filed as Exhibit  10.26 to the  Registrant's
               Form 10-K for the fiscal year ended  December 31, 2001,  File No.
               33-7591.)

*10.27(3)--    Employment  Agreement,  dated August 7, 2000,  between Oglethorpe
               and  W.  Clayton   Robbins.   (Filed  as  Exhibit  10.28  to  the
               Registrant's  Form 10-Q for the  quarterly  period ended June 30,
               2000, File No. 33-7591.)

*10.28.1(3)--  Employment  Agreement,  dated August 7, 2000,  between Oglethorpe
               and   Elizabeth   Higgins.   (Filed  as  Exhibit   10.29  to  the
               Registrant's  Form 10-Q for the  quarterly  period ended June 30,
               2000, File No. 33-7591.)

*10.28.2(3)--  Amendment to  Employment  Agreement,  dated May 8, 2001,  between
               Oglethorpe and Elizabeth Higgins.  (Filed as Exhibit 10.30 to the
               Registrant's  Form 10-Q for the  quarterly  period ended June 30,
               2001, File No. 33-7591.)

10.28.3(3) --  Second  Amendment to  Employment  Agreement,  dated  February 19,
               2003, between Oglethorpe and Elizabeth Higgins.

*10.29(3) --   Oglethorpe Power Corporation  Executive  Supplemental  Retirement
               Plan,  dated  March  15,  2002.  (Filed as  Exhibit  10.29 to the
               Registrant's  Form 10-Q for the quarterly  period ended March 31,
               2002, File No. 33-7591.)

*10.30(3) --   Participation  Agreement  for the  Oglethorpe  Power  Corporation
               Executive  Supplemental  Retirement  Plan,  dated as of March 15,
               2002, between  Oglethorpe and Thomas A. Smith.  (Filed as Exhibit
               10.30 to the  Registrant's  Form  10-Q for the  quarterly  period
               ended March 31, 2002, File No. 33-7591.)

21.1 --        Rocky Mountain Leasing Corporation, a Delaware corporation.

99.1 --        Certification  Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to
               Section 906 of the Sarbanes-Oxley Act of 2002, by Thomas A. Smith
               (Principal Executive Officer).

99.2 --        Certification  Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to
               Section 906 of the Sarbanes-Oxley Act of 2002, by Anne F. Appleby
               (Principal Financial Officer).

- -----------
(1)  Pursuant to 17 C.F.R.  229.601(b)(4)(iii),  this  document(s)  is not filed
     herewith;  however the registrant  hereby agrees that such document(s) will
     be provided to the Commission upon request.
(2)  Certain  portions of this  document have been omitted as  confidential  and
     filed separately with the Commission.
(3)  Indicates a management contract or compensatory arrangement required  to be
     filed as an  exhibit to this Report.

(b)  Reports on Form 8-K.

          Oglethorpe  filed no reports  on Form 8-K during the fourth quarter of
          2002.


                                       96


                                   SIGNATURES

     Pursuant  to the  requirements  of  Section  13 or 15(d) of the  Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the  undersigned,  thereunto duly  authorized,  on the 27th day of
March, 2003.


                                            OGLETHORPE POWER CORPORATION
                                            (AN ELECTRIC MEMBERSHIP CORPORATION)


                                        By:        /s/ THOMAS A. SMITH
                                           -------------------------------------
                                                       THOMAS A. SMITH
                                           President and Chief Executive Officer

     Pursuant to the  requirements of the Securities  Exchange Act of 1934, this
report  has  been  signed  below  by the  following  persons  on  behalf  of the
registrant and in the capacities and on the dates indicated.




                Signature                                    Title                                 Date
                ---------                                    -----                                 ----

                                                                                        
/s/          THOMAS A. SMITH              President and Chief Executive Officer               March 27, 2003
- ------------------------------------
             THOMAS A. SMITH              (Principal Executive Officer)

/s/          ANNE F. APPLEBY              Vice President, Finance and Treasurer               March 27, 2003
- ------------------------------------
             ANNE F. APPLEBY              (Principal Financial Officer)

/s/            MARK CHESLA                Controller                                          March 27, 2003
- ------------------------------------
               MARK CHESLA

/s/          ASHLEY C. BROWN              Director                                            March 27, 2003
- ------------------------------------
             ASHLEY C. BROWN

/s/         LARRY N. CHADWICK             Director                                            March 27, 2003
- ------------------------------------
            LARRY N. CHADWICK

/s/          BENNY W. DENHAM              Director                                            March 27, 2003
- ------------------------------------
             BENNY W. DENHAM

/s/         WM. RONALD DUFFEY             Director                                            March 27, 2003
- ------------------------------------
            WM. RONALD DUFFEY


                                       97


/s/          J. SAM L. RABUN              Director                                            March 27, 2003
- ------------------------------------
             J. SAM L. RABUN

/s/          JOHN S. RANSON               Director                                            March 27, 2003
- ------------------------------------
             JOHN S. RANSON

/s/        ROBERT E. RENTFROW             Director                                            March 27, 2003
- ------------------------------------
           ROBERT E. RENTFROW

/s/         JEFFREY D. TRANEN             Director                                            March 27, 2003
- ------------------------------------
            JEFFREY D. TRANEN

                                       98




                                 CERTIFICATIONS

I, Thomas A. Smith, certify that:

     1. I have  reviewed  this annual  report on Form 10-K of  Oglethorpe  Power
Corporation (An Electric Membership Corporation);

     2. Based on my  knowledge,  this annual  report does not contain any untrue
statement of a material fact or omit to state a material fact  necessary to make
the statements made, in light of the  circumstances  under which such statements
were made,  not  misleading  with  respect to the period  covered by this annual
report;

     3. Based on my knowledge,  the financial  statements,  and other  financial
information  included  in this annual  report,  fairly  present in all  material
respects the financial  condition,  results of operations  and cash flows of the
registrant as of, and for, the periods presented in this annual report;

     4. The  registrant's  other  certifying  officers and I are responsible for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

     (a)  designed  such  disclosure  controls  and  procedures  to ensure  that
material  information  relating to the  registrant,  including its  consolidated
subsidiaries, is made known to us by others within those entities,  particularly
during the period in which this annual report is being prepared;

     (b) evaluated the effectiveness of the registrant's disclosure controls and
procedures  as of a date  within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and

     (c) presented in this annual report our conclusions about the effectiveness
of the  disclosure  controls and  procedures  based on our  evaluation as of the
Evaluation Date;

     5. The registrant's other certifying  officers and I have disclosed,  based
on our most  recent  evaluation,  to the  registrant's  auditors  and the  audit
committee  of  registrant's  board  of  directors  (or  persons  performing  the
equivalent function):

     (a) all  significant  deficiencies  in the design or  operation of internal
controls  which  could  adversely  affect  the  registrant's  ability to record,
process,  summarize  and  report  financial  data  and have  identified  for the
registrant's auditors any material weaknesses in internal controls; and

     (b) any fraud,  whether or not material,  that involves management or other
employees who have a significant role in the registrant's internal controls; and

     6. The registrant's other certifying  officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: March 27, 2003

/s/ Thomas A. Smith
- --------------------------
Thomas A. Smith
President and Chief Executive Officer
  (Principal Executive Officer)

                                       99


I, Anne F. Appleby, certify that:

     1. I have  reviewed  this annual  report on Form 10-K of  Oglethorpe  Power
Corporation (An Electric Membership Corporation);

     2. Based on my  knowledge,  this annual  report does not contain any untrue
statement of a material fact or omit to state a material fact  necessary to make
the statements made, in light of the  circumstances  under which such statements
were made,  not  misleading  with  respect to the period  covered by this annual
report;

     3. Based on my knowledge,  the financial  statements,  and other  financial
information  included  in this annual  report,  fairly  present in all  material
respects the financial  condition,  results of operations  and cash flows of the
registrant as of, and for, the periods presented in this annual report;

     4. The  registrant's  other  certifying  officers and I are responsible for
establishing and maintaining  disclosure  controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

     (a)  designed  such  disclosure  controls  and  procedures  to ensure  that
material  information  relating to the  registrant,  including its  consolidated
subsidiaries, is made known to us by others within those entities,  particularly
during the period in which this annual report is being prepared;

     (b) evaluated the effectiveness of the registrant's disclosure controls and
procedures  as of a date  within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and

     (c) presented in this annual report our conclusions about the effectiveness
of the  disclosure  controls and  procedures  based on our  evaluation as of the
Evaluation Date;

     5. The registrant's other certifying  officers and I have disclosed,  based
on our most  recent  evaluation,  to the  registrant's  auditors  and the  audit
committee  of  registrant's  board  of  directors  (or  persons  performing  the
equivalent function):

     (a) all  significant  deficiencies  in the design or  operation of internal
controls  which  could  adversely  affect  the  registrant's  ability to record,
process,  summarize  and  report  financial  data  and have  identified  for the
registrant's auditors any material weaknesses in internal controls; and

     (b) any fraud,  whether or not material,  that involves management or other
employees who have a significant role in the registrant's internal controls; and

     6. The registrant's other certifying  officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

Date: March 27, 2003

/s/ Anne F. Appleby
- ---------------------------
Anne F. Appleby
Vice President, Finance and Treasurer
     (Principal Financial Officer)

                                      100


     SUPPLEMENTAL  INFORMATION  TO BE FURNISHED  WITH REPORTS FILED  PURSUANT TO
SECTION 15(d) OF THE ACT BY  REGISTRANTS  WHICH HAVE NOT  REGISTERED  SECURITIES
PURSUANT TO SECTION 12 OF THE ACT.

     The  registrant  is a  membership  corporation  and  has no  authorized  or
outstanding  equity  securities.  Proxies are not solicited  from the holders of
Oglethorpe's  public bonds.  No annual report or proxy material has been sent to
such bondholders.













                                      101