SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.D. C. 20549

-------------------------------------

FORM 10-K
(MARK ONE)
/ /
X(Mark One)

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

For the fiscal year ended December 31, 19931996

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

For the Transition Period From ___________ to _____________

Commission File No. 33-7591

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OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION)-------------

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

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

POST OFFICE BOXPost Office Box 1349
2100 EAST EXCHANGE PLACEEast Exchange Place
Tucker, Georgia 30085-1349
TUCKER, GEORGIA (Zip Code)
(Address of principal executive offices) (Zip Code)

Registrant's telephone number, including area code: (404)(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 ofto such
filing requirements for the past 90 days. YES__X__ NO______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 ][_]

State the aggregate market value of the voting stock held by
nonaffiliates of the registrant. 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
19931996 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS

Item Page
- ---- ----

PART I

1 Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Oglethorpe Power Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
The Members of Oglethorpe. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
The Power Supply System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Co-owners of the Plants and the Plant and Transmission Agreements. . . . . . . . . . . . 19
2 Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
3 Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24
4 Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . . . . . . . . 24

PART II

5 Market for Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . 25
6 Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
7 Management's Discussion and Analysis of Financial Condition and Results of Operations. . . 26
8 Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . 32
9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . 49

PART III

10 Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . . 49
11 Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61
12 Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . . 63
13 Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . . 63

PART IV

14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . . . 64
Table of Contents

Item Page
- ---- ----
PART I

1 Business ............................................................ 1
Oglethorpe Power Corporation....................................... 1
The Members of Oglethorpe.......................................... 8
Member Requirements and Power Supply Resources..................... 12
Other Information.................................................. 16

2 Properties........................................................... 17
Generating Facilities.............................................. 17
Co-Owners of the Plants and the Plant Agreements................... 20
Environmental and Other Regulations................................ 24
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
8 Financial Statements and Supplementary Data.......................... 42
9 Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................. 62

PART III

10 Directors and Executive Officers of the Registrant................... 62
11 Executive Compensation............................................... 65
12 Security Ownership of Certain Beneficial Owners and Management....... 68
13 Certain Relationships and Related Transactions....................... 68

PART IV

14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K..... 69

SELECTED DEFINITIONS

When used herein the following terms will have the meanings indicated below:

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

ADSCR Annual Debt Service Coverage Ratio
BPSA Block Power Sale Agreement
CFC National Rural Utilities Cooperative Finance Corporation
CoBank CoBank, ACB, formerly known as the National Bank for
Cooperatives
Commission Securities and Exchange Commission
CSA Coordination Services Agreement
Dalton City of Dalton, Georgia
DSC Debt Service Coverage Ratio
EPI Entergy Power, Inc.
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
ITS Integrated Transmission System
ITSA Revised and Restated Integrated Transmission System
Agreement
kWh Kilowatt-hours
LPM LG&E Power Marketing Inc.
Members The 39 retail distribution cooperatives that are members
of Oglethorpe
MEAG Municipal Electric Authority of Georgia
MFI Margins for Interest
Morgan Stanley Morgan Stanley Capital Group
MW Megawatts
MWh Megawatt-hours
NRC Nuclear Regulatory Commission
Oglethorpe Oglethorpe Power Corporation (An Electric Membership
Corporation)
PCBs Pollution Control Revenue Bonds
PCR Percentage Capacity Responsibility
PURPA Public Utility Regulatory Policies Act
RUS Rural Utilities Service Coverage Ratio
AFUDC Allowance for Debt and Equity Funds Used During Construction
BPSA Block Power Sale Agreement
CFC National Rural Utilities Cooperative Finance Corporation
CoBank National Bank for Cooperatives
Commission Securities and Exchange Commission
CSA Coordination Services Agreement
Dalton City of Dalton, Georgia
DOE United States Department of Energy
DSC Debt Service Coverage Ratio
EPA United States Environmental Protection Agency
EPI Entergy Power, Inc.
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FFB Federal Financing Bank
G&T Generation and Transmission Cooperative
GEMC Georgia Electric Membership Corporation
GPC Georgia Power Company
GPSC Georgia Public Service Commission
ITS Integrated Transmission System
ITSA Revised and Restated Integrated Transmission System Agreement
kWh Kilowatt-hours
Members The 39 retail distribution cooperatives that are members of Oglethorpe
MEAG Municipal Electric Authority of Georgia
MW Megawatts
MWh Megawatt-hours
NRC Nuclear Regulatory Commission
Oglethorpe Oglethorpe Power Corporation
PURPA Public Utility Regulatory Policies Act
REA Rural Electrification Administration
SEPA Southeastern Power Administration
SONOPCO Southern Nuclear Operating Company
TIER Times Interest Earned Ratio
TVA Tennessee Valley Authority

PART I

Item 1. BUSINESS

OGLETHORPE POWER CORPORATION

GENERALGeneral

Oglethorpe Power Corporation (An Electric Membership Generation &
Transmission Corporation)
("Oglethorpe") is ana Georgia electric generation and
transmission cooperative ("G&T")membership corporation incorporated in 1974
in the State of Georgia.
It isand headquartered in metropolitan Atlanta. Oglethorpe is entirely owned by its
39 retail electric distribution cooperative members (the "Members"), who, in
turn, are entirely owned by their retail consumers. Oglethorpe is the largest
G&Telectric cooperative in the United States in terms of operating revenues,
assets, kilowatt-hour ("kWh") sales and, through the Members, consumers served.
It is one of the ten largest electric utilities in the United States in terms of
land area served. As
of February 28, 1994, Oglethorpe had 505has 146 full-time and 4318 part-time employees.employees, after
reflecting the effect of a corporate restructuring and a business alliance
transaction. (See "Corporate Restructuring" and "Relationship with
Intellisource" herein.)

As with cooperatives generally, Oglethorpe operates on a not-for-profit
basis. Oglethorpe's principal business is providing wholesale electric servicepower to
the Members. The Members are local consumer-owned distribution cooperatives
providing retail electric service on a not-for-profit basis. In general, the
membership of the distribution cooperative Members consists of residential,
commercial and industrial consumers within specific geographic areas. As of
December 31, 1993, theThe
Members servedserve approximately 11.2 million electric consumers (meters) representing
a total population of approximately 2.32.6 million people.

Each Member purchases capacity and energy from Oglethorpe pursuant to a
long-term, "all-requirements" wholesale power contract betweenCorporate Restructuring

Oglethorpe and the Member (eachMembers completed a "Wholesale Power Contract"corporate restructuring (the
"Corporate Restructuring") on March 11, 1997 (the "Closing") pursuant to terms
and collectivelyconditions set forth in the "Wholesale
Power Contracts"Second Amended and Restated Restructuring
Agreement, dated February 24, 1997, by and among Oglethorpe, Georgia
Transmission Corporation (An Electric Membership Corporation) ("GTC") and
Georgia System Operations Corporation ("GSOC"). Pursuant to the Corporate
Restructuring, Oglethorpe suppliesdivided itself into three specialized operating
companies to respond to increasing competition and regulatory changes in the
capacityelectric industry. As part of the Corporate Restructuring, the transmission
business is now owned and operated by GTC, a newly formed Georgia electric
membership corporation, and the system operations business is now owned and
operated by GSOC, a newly formed Georgia nonprofit corporation. Oglethorpe
continues to own and operate its power supply business.

On October 1, 1996, Oglethorpe transferred to GSOC its system
operations assets, consisting of its system control center and related energy
control and revenue metering systems equipment. The purchase price totaled
approximately $9.4 million and was paid by GSOC's assumption of Oglethorpe's
obligations under an existing note held by the Rural Utilities Service ("RUS"),
by delivery of a purchase money note payable to Oglethorpe and by the assumption
of certain other liabilities of Oglethorpe. Since October 1, 1996, Oglethorpe
had been the sole member of GSOC. The Members and GTC became members of GSOC at
the Closing. GSOC now operates the system control center and provides system
operations services to the Members, Oglethorpe and GTC.

At the Closing, Oglethorpe transferred to GTC its transmission business
and assets. The purchase price for the transmission business was based on an
appraisal of the fair market value of such business, as determined by an
independent appraiser, and was approximately $708 million. The purchase price
was paid primarily by GTC's assumption of a portion (approximately 16.86%) of
Oglethorpe's long-term secured debt in an amount equal to approximately $686
million. Approximately $541 million of this debt (payable to RUS, the Federal
Financing Bank ("FFB") and CoBank, ACB ("CoBank")) became the sole obligation of
GTC, and Oglethorpe was released from all liability with regard to this debt.
The remaining debt assumed by GTC in connection with the Corporate

Restructuring, approximately $145 million, relates to Oglethorpe's pollution
control revenue bonds ("PCBs"). While GTC assumed and agreed to pay this $145
million of debt, Oglethorpe is not legally released from its obligation to pay
for this debt. The remainder of the purchase price was paid by GTC from cash
obtained through a borrowing from National Rural Utilities Cooperative Finance
Corporation ("CFC") and the assumption of approximately $1 million of other
Oglethorpe liabilities. Oglethorpe also made a special patronage capital
distribution of approximately $49 million to the Members which was used by the
Members to establish equity in and to provide initial working capital to GTC.
Oglethorpe and the 39 Members are members of GTC. GTC now provides transmission
services to the Members and Oglethorpe. GTC has succeeded to all of Oglethorpe's
rights and obligations with respect to the Integrated Transmission System
("ITS"). (See "Relationship with GTC" herein for further discussion of the ITS.)

Oglethorpe continues to operate its power supply business. Oglethorpe
retained all of its owned and leased generation assets and has total assets of
approximately $4.7 billion and total long-term debt of approximately $3.9
billion. Oglethorpe also continues to administer its power purchase contracts
and provide marketing support functions to the Members.

Contemporaneously with the Corporate Restructuring, Oglethorpe replaced
its Consolidated Mortgage and Security Agreement, dated as of September 1, 1994
(the "RUS Mortgage"), by and among Oglethorpe, as mortgagor, the United States
of America, acting through the Administrator of the RUS, CoBank, Credit Suisse
First Boston, acting by and through its New York Branch ("Credit Suisse"), and
SunTrust Bank, Atlanta ("SunTrust"), as trustee under certain pollution control
bond indentures identified in the RUS Mortgage, with an Indenture, dated as of
March 1, 1997, from Oglethorpe to SunTrust, as trustee (the "Master Indenture").
As did the RUS Mortgage, the Master Indenture provides for a lien on
substantially all of the owned tangible and certain intangible property of
Oglethorpe. (See "Electric Rates" herein and "General--Rates and Financial
Coverage Requirements" in Item 7 for further discussion of the revenue
requirements of the Master Indenture.)

New Wholesale Power Contracts

In connection with the Closing, Oglethorpe and each of the Members
from a combination of ownedentered into an Amended and leased generating plants and from
power purchased under long-term contracts with other power suppliers,
principally Georgia Power Company ("GPC"), a wholly owned subsidiary of The
Southern Company.

MEMBER CONTRACTS

EachRestated Wholesale Power Contract, will remain in effectdated August 1,
1996 (collectively, the "New Wholesale Power Contracts") which extends through
the year 2025
and thereafter until terminated by three years' written notice byDecember 31, 2025. The New Wholesale Power Contracts permit each Member to take
future incremental power requirements either from Oglethorpe or other sources.
Under the respective Member. EachNew Wholesale Power Contract provides that, exceptContracts, a Member is unconditionally obligated
on an express "take-or-pay" basis for power purchased froma fixed allocation of Oglethorpe's costs
for its existing resources, as well as the Southeasterncosts with respect to any future
resources in which such Member elects to participate. The New Wholesale Power
Administration ("SEPA"), Oglethorpe
shall sell and deliver to the Member, and the Member shall purchase and receive
from Oglethorpe, all electric capacity and energyContracts specifically provide that the Member requires for
the operation ofmust 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 systemreasonable best efforts to
the extentoperate, maintain and manage its resources in accordance with prudent utility
practices. The New Wholesale Power Contracts provide that Oglethorpe has capacitywill be
responsible for power supply planning, resource procurement and energy and facilities available. In 1993, the aggregate SEPA allocation to the
Members was 542 megawatts ("MW") plus associated energy, representing
approximately 13% of total Member peak demand and approximately 6% of total
Member energy requirements. Because the amountsales of
capacity and energy available
from SEPAfor a Member unless the Member notifies Oglethorpe that it
does not want Oglethorpe to provide these services.

Each Member's cost responsibility is allocated in the New Wholesale
Power Contracts by assigning each Member an agreed-upon fixed percentage
capacity responsibility ("PCR"). PCRs have been assigned for all of Oglethorpe's
existing resources. PCRs for any future resource will be assigned only to
Members choosing to participate in that resource. The New Wholesale Power
Contracts provide that each Member will be jointly and

severally responsible for all costs and expenses of all existing resources, as
well as for any future resources (whether or not expectedsuch Member has elected to
increaseparticipate in an amountsuch 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 of a defaulting Member 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.

The New Wholesale Power Contracts contain covenants by the Member (i)
to establish, maintain and collect rates and charges for the service of its
electric system, and (ii) to conduct its business in a manner that will produce
revenues and receipts at least sufficient to serveenable the Member to pay to
Oglethorpe, when due, all amounts payable by the Member under the New Wholesale
Power Contracts and to pay any and all other amounts payable from, or which
might constitute a material portioncharge or a lien upon, the revenues and receipts derived from
its electric system, including all operation and maintenance expenses and the
principal and interest on all indebtedness related to the Member's electric
system.

In connection with the implementation of long-term power marketer
arrangements with LG&E Power Marketing Inc. ("LPM"), Oglethorpe and each Member
entered into supplemental agreements to the New Wholesale Power Contracts which
relate to certain provisions of the projected growth inNew Wholesale Power Contracts and apply
during the Members' requirements, such
growth is expected to be served primarily through Oglethorpe's resources. (See
"Member Demand and Energy Requirements--DISPERSED GENERATION" and "THE MEMBERS
OF OGLETHORPE--Contracts with SEPA" herein.)

Eachterm of the power marketer arrangements. The supplemental agreements
clarify the application of the New Wholesale Power Contract providesrate schedule to the
power marketer agreements. The 75% requirement described above has been met with
respect to the LPM agreements. The supplemental agreements assure that withoutall costs
incurred by Oglethorpe under the approval of bothLPM agreement are recoverable under the New
Wholesale Power Contracts. As the expected additional power marketer
arrangements are finalized, additional supplemental agreements to the New
Wholesale Power Contracts will be entered into by Oglethorpe and the Rural Electrification Administration ("REA"), no Member may
reorganize, consolidate or merge, or sell, lease or transfer all orMembers.

See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES" for a substantial partdescription
of its assets (or make any agreement therefor), so long as
Oglethorpe has notes outstanding to REA and the FFB, without first paying such
portion of any such outstanding notes as may be determined by Oglethorpe with
the prior written consent of REA and otherwise complying with such reasonable
terms as Oglethorpe and REA may require.

MEMBER DEMAND AND ENERGY REQUIREMENTS

The following table shows the aggregate peakMembers' demand and energy requirements of the Members for the years 1991 through 1993 and also shows the amounts of
such requirements supplied by Oglethorpe and SEPA. For the years 1991 through
1993, demand and energy requirements increased at an average annual compound
growth rate of 8.1% and 7.3%, respectively.

DEMAND (MW) ENERGY REQUIREMENTS (MWh)
-------------------------------------- -----------------------------------------
TOTAL TOTAL
REQUIRE- SUPPLIED BY SUPPLIED BY REQUIRE- SUPPLIED BY SUPPLIED BY
MENTS(1) OGLETHORPE(2) SEPA(3) MENTS OGLETHORPE(2) SEPA(3)
-------- ------------- ----------- -------- ------------- -----------

1991 . . . . . . . . . 3,664 3,122 542 15,029,976 14,022,213 1,007,763
1992 . . . . . . . . . 3,865 3,323 542 15,562,495 14,466,943 1,095,552
1993 . . . . . . . . . 4,283 3,736 542 17,313,313 16,253,283 1,060,030

- -------------------------
(1) System peak demand of the Members measured at the Members' delivery points
(net of system losses).

(2) Includes purchased power. (See "THE POWER SUPPLY SYSTEM--Power Sales to
and Purchases from GPC--POWER PURCHASE ARRANGEMENTS" and "--Other Power
Purchases".)

(3) Supplied by SEPA through existing contracts with the Members. (See "THE
MEMBERS OF OGLETHORPE--Contracts with SEPA".)

Prior to 1993, no Member accounted for 10% or more of Oglethorpe's total
revenues. In 1993, however, Cobb EMC accounted for approximately 10% of
Oglethorpe's total revenues.

SEASONAL VARIATIONS

Although the demand for energy by the Members is influenced by seasonal
weather conditions, Oglethorpe's rate structure is designed to cause capacity
revenues, which include margins, to remain relatively level throughout the year.
Energy revenues, which do not include margins, track energy costs as they are
incurred. Although energy charges, which are based on variable costs, fluctuate
from month to month, capacity charges, which are based on annual peak demands,
do not fluctuate based on a Member's usage during a given year. Historically,
Oglethorpe's peak demand occurs during the months of June through September.

CONSERVATION AND LOAD MANAGEMENT

Oglethorpe and the Members have implemented various demand management
programs. The program goal, developed in conjunction with Oglethorpe's
integrated resource planning process, is to modify demand patterns so that
current resources are used efficiently and the need for additional generating
resources is delayed. The programs that have been implemented include an energy
efficient home program (the "Good Cents Home" program), remote-controlled
switching of air conditioners, water heaters and irrigation pumps, residential
energy audits and public appeals to encourage consumers to use less energy
during periods of peak demand. The demand management programs have reduced, and
are expected to continue to reduce, the growth of peak demand and have resulted
in an increase in off-peak sales. (See "THE POWER SUPPLY SYSTEM--Future Power
Resources--OTHER FUTURE RESOURCES".)

DISPERSED GENERATION

Oglethorpe and the Members have been discussing the desire of a number of
the Members to make greater use of dispersed generation units. If permitted by
REA, such units would be used to maintain reliability of electric service during
emergencies on a Member's distribution system, to serve specific customer needs
and otherwise to be available to Oglethorpe to serve the demands of Members on
its system. The installation and use of dispersed generation units by any Member
would be governed by policies and procedures, consistent with the Wholesale
Power Contract, designed to

ensure system reliability and prevent any material adverse effect on
Oglethorpe's revenues or on any other Member'srelated power costs.

ELECTRIC RATESsupply
resources.

Electric Rates

Each Member is required to pay Oglethorpe for capacity and energy
furnished under its New 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
such rates will be sufficient, but only sufficient, with its revenues from all
other sources to pay operating and maintenance costs, the cost of purchased
power, the cost of transmission services, and principal and interest on all
indebtedness (including capital lease obligations) of Oglethorpe, all costs
associated with decommissioning or otherwise retiring any generating facility,
and to provide for the establishment and maintenance of reasonable reserves.
Rates are also required to be established so as to enable Oglethorpe to comply
with all financial requirements
(including coverage ratios) under the Consolidated MortgageMaster Indenture. (See "General--Rates
and Security
Agreement dated as of September 1, 1993 (the "REA Mortgage") among Oglethorpe,
as mortgagor, and the United States of America acting through the Administrator
of REA, the National Bank for Cooperatives ("CoBank"), Credit Suisse, acting by
and through its New York Branch ("Credit Suisse"), and Trust Company Bank
("Trust Company"), as trustee under certain pollution control bond indentures
identified in the REA Mortgage. (See "General--RATES AND FINANCIAL COVERAGE
REQUIREMENTS"Financial Coverage Requirements" in Item 7.)

Oglethorpe's current monthly rate for electric service for capacity and
energy delivered to each Member includes energy charges that recover fuel and
variable operation and maintenance costs, adjusted semiannually to assure full
recovery of such costs, and capacity charges. The rate also includes a provision
to reflect the amortization of the deferred margins accumulated from 1985
through 1993, which amounts will be fully amortized by the end of 1995. (See
Note 1 of Notes to Financial Statements in Item 8.) Oglethorpe's rate policy
provides for a number of separate rates for certain qualified consumer loads,
which are designed to have a favorable impact on the Members' competitiveness
for certain new industrial and commercial loads. (See "THE MEMBERS OF
OGLETHORPE--Service Area and Competition".)

Oglethorpe's rates, as established by its Board of Directors, are subject
to review and approval by REA. Oglethorpe ishad been required under the REAprior RUS Mortgage to implement
rates designed to maintain a Times Interest Earned Ratio ("TIER") of not less
than 1.05, a Debt Service Coverage Ratio ("DSC") of not less than 1.0 and an
Annual Debt Service Coverage Ratio ("ADSCR") of not less than 1.25. Oglethorpe
has always met or exceeded the TIER, DSC and ADSCR requirements of the REARUS
Mortgage. Oglethorpe's policy for 1996 was to set rates to meet a TIER of 1.07.
Under the Master Indenture, Oglethorpe is required to establish and collect
rates which are reasonably expected, together with other revenues of Oglethorpe,
to yield a Margins for Interest ("MFI") for each fiscal year equal to at least
1.10 times total interest charges during such fiscal year on all indebtedness
secured under the Master Indenture (or by a lien equal or prior to the lien of
the Master Indenture), excluding indebtedness assumed by GTC. MFI is determined
by adding (i) Oglethorpe's net margins (after certain defined adjustments), (ii)
interest charges on indebtedness secured under the Master Indenture (or by lien
equal to

or prior to the lien of the Master Indenture), excluding indebtedness assumed by
GTC, and (iii) any amount included in net margins for accruals for federal or
state income taxes. The definition of MFI 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 or if Oglethorpe has made a payment with respect to such losses or
expenditures. (See "General--RATES AND FINANCIAL COVERAGE REQUIREMENTS""General--Rates and Financial Coverage Requirements" in Item
7.)

TheUnder the formulary rate established by Oglethorpe in the new rate
schedule to the New Wholesale Power Contracts, provide that nothe rates charged by Oglethorpe
are developed using a rate revision shallmethodology under which all categories of costs are
specifically separated as components of the formula to determine Oglethorpe's
revenue requirements. The rate schedule formula implements the assignment of
responsibility for fixed costs (i.e., the PCR). The monthly charges for capacity
and other non-energy charges are based on a rate formula using Oglethorpe's
annual budget. Such capacity and other non-energy charges may be effective unless approvedadjusted by REA, but suchthe
Board of Directors, if necessary, during the year through an adjustment to the
annual budget. Energy charges reflect the passthrough of actual energy costs.
However, under the supplemental agreements for the LPM agreements, each Member
pays a fixed rate for energy, plus certain adjustments, while LPM pays all
energy costs, within an agreed upon range of costs. The new rate schedule
formula also includes a prior period adjustment ("PPA") mechanism. The PPA
serves to facilitate the achievement of the minimum 1.10 MFI ratio, and it
provides for the retention of margins within a range from a 1.10 MFI ratio to a
1.20 MFI ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum
1.10 MFI ratio would be accrued as of December 31 of the applicable year and
collected during the period April through December of the following year.
Amounts, if any, earned by Oglethorpe in excess of a 1.20 MFI ratio would be
charged against revenues as of December 31 of the applicable year and refunded
during the period April through December of the following year. The new rate
schedule formula is intended to permit 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 MFI ratio.

Under the terms of Oglethorpe's prior RUS Mortgage, all rate revisions
by Oglethorpe were subject to the approval of RUS. Under the Master Indenture
and related loan contract with RUS, however, adjustments to Oglethorpe's rates
to reflect changes in Oglethorpe's budgets are not subject to RUS approval,
except for reductions in rates in a fiscal year following a fiscal year in which
Oglethorpe has failed to meet the minimum 1.10 MFI ratio set forth in the Master
Indenture. Any change to the underlying rate formula would be subject to RUS
approval. Rate revisions are not subject to the approval of any other Federalfederal or
state agency or authority, including the Georgia Public Service Commission (the
"GPSC").

To date, REA has not reduced or
delayed the effectiveness of any rate increase proposed by Oglethorpe.

For information regarding future rates, see "General--Rates and
Financial Coverage Requirements" and "Results of Operations--
OPERATING REVENUES--SALES TO MEMBERS"Operations--Factors Affecting
Future Financial Performance" in Item 7.

CERTAIN FACTORS AFFECTING THE UTILITY INDUSTRY IN GENERALRelationship with GTC

GTC purchased and is operating the transmission system as described in
"Corporate Restructuring" herein. Oglethorpe and all 39 Members are members of
GTC. GTC is providing transmission services to the Members for delivery of the
Members' power purchases from Oglethorpe, Southeastern Power Administration
("SEPA") and any other power suppliers. GTC also provides transmission services
to Oglethorpe and third parties. Oglethorpe has entered into a transmission
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 Project, a pumped storage hydroelectric facility ("Rocky
Mountain").

In connection with the Corporate Restructuring, GTC and the Members
entered into transmission agreements (the "Transmission Agreements") under which
GTC provides transmission service to the Members pursuant to a transmission
tariff. The electric utility industryTransmission Agreements have a minimum term of network service for
current load until December 31, 2025. After an initial ten-year term, load
growth above 1995 requirements may, with notice to GTC, be served by others. The
Transmission 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 Transmission Agreements, Members have the right to
design, construct and own new distribution substations.

The Transmission Agreements provide that the Members are responsible,
on a joint and several basis, for all of GTC's obligations relating to its
transmission business. The Transmission Agreements contain an express covenant
of the Members to set and collect retail rates sufficient to allow the Members
to meet their respective obligations under the Transmission Agreements. The rate
formula set forth in the transmission tariff is becoming increasingly competitiveintended to recover all costs
and expenses paid or incurred by GTC. The rate expressly includes in the
description of costs to be recovered all principal and interest on indebtedness
of GTC (including any indebtedness of Oglethorpe assumed by GTC). The rate
further expressly provides for GTC to earn sufficient margins to satisfy the
requirements of its new indenture, which is substantially similar to
Oglethorpe's Master Indenture.

The GTC transmission tariff and associated Transmission Agreements have
been developed to implement the Corporate Restructuring and to be consistent
with federal transmission policy as a
resultexpressed in Order 888 of deregulation, competing energy suppliers, technologies, and other
factors. The Energy Policy Act of 1992 (the "Energy Policy Act") amended the Federal Energy
Regulatory Commission ("FERC"). FERC's Order 888 mandates open access of
essentially all transmission systems in order to promote competition in the bulk
power markets and provides that non-regulated utilities (such as GTC) must
provide access to their transmission systems on reciprocal terms and conditions
in order to obtain transmission from FERC-regulated utilities. The transmission
tariff and Transmission Agreements have been designed to facilitate the
operation of GTC in the new regulatory environment and provide for GTC to serve
on a nondiscriminatory basis both member and non-member customers on terms
intended to meet FERC's reciprocity requirement.

Prior to the Closing, Oglethorpe, together with Georgia Power ActCompany
("GPC"), the Municipal Electric Authority of Georgia ("MEAG") and the Public Utility Holding Company ActCity of
Dalton ("Dalton"), owned transmission facilities which together form the ITS.
GTC succeeded to allow for
increased competition among wholesale electricity suppliersOglethorpe's rights in the ITS at the Closing, and increasedGTC now owns
approximately 2,267 miles of transmission line and 426 substations of various
voltages. Through agreements, common access to the combined facilities that
compose the ITS enables the owners to use their combined resources to make
deliveries to or for their respective consumers, to provide transmission servicesservice
to third parties and to make off-system purchases and sales.

GTC's rights and obligations with respect to the ITS are governed by
such suppliers. A number of other significant
factors have affected the operations of electric utilities. They includeRevised and Restated Integrated Transmission System Agreement (the "ITSA"),
which was assigned to GTC in connection with the availability and cost of fuelCorporate Restructuring. The
ITSA provides for the generationtransmission and distribution of electric energy fluctuating
ratesin the
State of load growth, complianceGeorgia, other than in certain counties, and for bulk power
transactions, through use of the ITS. The ITS 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. The ITS consists of all transmission facilities, including land,
owned by the parties on the date the ITSA became effective and those thereafter
acquired, which are located in the State of Georgia other than in the excluded
counties and which are used or usable to transmit power of a certain minimum
voltage and to transform power of a certain minimum voltage and a certain
minimum capacity (the "Transmission Facilities"). GPC has entered into
agreements with environmentalMEAG and Dalton that are substantially similar to the ITSA, and
GPC may enter into such agreements with other governmental
regulations, licensingentities. The ITSA will remain in
effect through December 31, 2012 and, other delays affectingif not then terminated by five years'
prior written notice by either party, will continue until so terminated.

The ITSA is administered by a committee (the "Joint Committee")
composed of GTC, GPC, MEAG and Dalton. Each year, the construction,Joint Committee determines
a four-year plan of additions to the Transmission Facilities that will reflect
the current and anticipated future transmission requirements of the parties.
Each ITS participant is generally required to maintain an original cost
investment in the Transmission Facilities in proportion to their respective Peak
Loads (as defined in the ITSA).

GTC and GPC are parties to a Transmission Facilities Operation and
Maintenance Contract (the "Transmission Operation Contract"), under which GPC
provides System Operator Services (as defined in the

Transmission Operation Contract) for GTC. In addition, GPC is required to
provide such supervision, operation and maintenance supplies, spare parts,
equipment and labor for the operation, maintenance and construction as may be
specified by GTC. GPC is also required to perform certain emergency work under
the Transmission Operation Contract. GTC is permitted, upon notice to GPC, to
perform, or contract with others for the performance of, certain services
performed by GPC. Absent termination or amendment of the Transmission Operation
Contract, however, GPC will continue to perform System Operator Services for
GTC. The term of the Transmission Operation Contract will continue from year to
year unless terminated by either party upon four years' notice. GTC is required
to pay its proportionate share of the cost for the services provided by GPC.

Relationship with GSOC

From October 1, 1996 until the Closing, Oglethorpe was the sole member
of newGSOC. The Members and existing facilities,GTC became members of GSOC upon the Closing. GSOC now
operates the system control center and provides system operations services to
the Members, Oglethorpe and GTC. GTC has contracted with GSOC to provide certain
transmission system operation services including reliability monitoring,
switching operations, and the effects of conservation, energy
management and other governmental regulations on the use of electric energy. All
of these factors present an increasing challenge to companies in the electric
utility industry, including Oglethorpe and the Members, to reduce costs and
improve thereal-time management of resources. (See "THE POWER SUPPLY SYSTEM--General",
"--Future Power Resources" and "--Environmental and Other Regulations".)

RELATIONSHIP WITHthe transmission system.

Relationship with GPC

Oglethorpe's relationship with GPC is a significant factor in several
aspects of Oglethorpe's business. GPC is one of Oglethorpe's principal suppliersuppliers
of purchased power, and Oglethorpe is one of GPC's largest customers. In 1993,
Oglethorpe derived 15% of its total revenues from sales to GPC, making GPC
Oglethorpe's largest customer. Substantially allAll of
Oglethorpe's co-owned generating facilities, were purchased at various stages of construction from GPC and were
constructed andexcept Rocky Mountain, are now operated
by GPC. Oglethorpe is the constructionGPC on behalf of itself as a co-owner and operatingas agent for the Rocky Mountain Project, a pumped storage hydroelectric
facility ("Rocky Mountain"), in which it acquired an interest from GPC.
Oglethorpe purchases coordination services fromother co-owners.
GPC to schedule its power
resources and its off-system purchases and sales. Oglethorpe, through the Members, is one of GPC's principalare competitors in the State of Georgia
for electric service to new customers that have a choice of supplier under the
Georgia Territorial Electric Service Act (the "Territorial Act"). Likewise, GPC
is the principal competitor of the Members for such customers. Oglethorpe and
GPC also own transmission facilities that are part of the Integrated
Transmission System (the "ITS"). GPC provides system operator services and
performs most of the required maintenance of Oglethorpe's transmission
facilities. GPC and Oglethorpe are parties to an agreement that makes allowance
for the joint planning of future generation and transmission facilities. For further
information regarding the various relationships and agreements with GPC, see
"THE MEMBERS OF OGLETHORPE--Service Area and Competition", "THE"MEMBER REQUIREMENTS
AND POWER SUPPLY SYSTEM--General", "--Fuel Supply", "--Power Sales toRESOURCES--Power Purchase and Sale Arrangements--Power
Purchases from GPC", "--Future Power Resources--ROCKY MOUNTAIN", "-Transmission and Other"--Other Power System Arrangements" herein, and "GENERATING
FACILITIES--Fuel Supply", "CO-OWNERS OF THE PLANTS AND THE PLANT
AND
TRANSMISSION AGREEMENTS--Co-Owners of the Plants--GEORGIA POWER COMPANY"Plants--Georgia Power Company", and "--The Plant
Agreements", "--Agreements Relating to the Integrated Transmission
System", and "--The Joint Committee Agreement".

RELATIONSHIP WITH REA

Federal in Item 2.

Relationship with RUS

Historically, federal loan programs administered by REARUS have provided
the principal source of financing for electric cooperatives. Direct loans from REALoans guaranteed by
RUS and made by FFB have been a major source of funding for the Members, while loans guaranteed by REA and made
by the Federal Financing Bank ("FFB") have been a major source of funding for
Oglethorpe. Through provisions of the REA Mortgage, REA exercises substantial
control and supervision over Oglethorpe in such areas as accounting, issuing
secured indebtedness, rates and charges for the sale of power, construction and
acquisition of facilities, and the purchase and sale of power. In
recent years, there have been legislative, administrative and budgetary
initiatives intended to reduce or, in some cases, eliminate federal funding for
electric cooperatives. However, Oglethorpe does not have any new generation
facilities under construction, and management does not anticipate the need for
construction of any new capacity well into the future. (See "MEMBER REQUIREMENTS
AND POWER SUPPLY RESOURCES--Power Purchase and Sale Arrangements--Power Marketer
Arrangements" for a discussion of the long-term power marketer arrangements.) In
addition, the REA loan and guarantee programs have
been characterized byMaster Indenture improves Oglethorpe's ability to borrow funds in
the imposition of increasingly problematic terms and
conditions and extended delays in access to necessary funding.

The President's budget for fiscal year 1995 proposes to set the level of
funding for the 100% guarantee program at $275 million, which if sustained at
that level in future years would not likely provide adequate funding for the
transmission and power supply needs of REA borrowers. Congress historically has
increased Administration-proposed lending levels to those necessary to meet
borrower demand. Notwithstanding historical practices, however, the future cost,
availability and magnitude of REA-guaranteed loans cannot be predicted.public capital markets. See "THE MEMBERS OF OGLETHORPE-Members'OGLETHORPE--Members'
Relationship with REA"RUS" for a discussion of the impact of changes in the budget proposalRUS
lending program on the directMembers.

Through provisions of the prior RUS Mortgage, RUS exercised substantial
control and supervision over Oglethorpe in such areas as accounting, the
issuance of secured indebtedness, rates and charges for the sale of power,
construction and acquisition of facilities, and the purchase and sale of power.
Under the Master Indenture

and the new loan program.

REA continues to re-evaluate its regulatorycontact entered into with RUS in connection therewith, RUS has
significantly reduced these controls.

Relationship with Intellisource

In conjunction with the Corporate Restructuring and lending relationship with
its borrowers through what it has described as a comprehensive rule-making
project.part of its
continuing efforts to reduce costs, effective February 1, 1997, Oglethorpe
implemented a business alliance with Intellisource, Inc., a national provider of
outsourcing services. Pursuant to an agreement with Intellisource, approximately
150 support services division employees in the areas of accounting, auditing,
communications, human resources, facility management, purchasing,
telecommunications and information technology became employees of the
Intellisource organization. Oglethorpe, GTC and GSOC are key customers of
Intellisource and are being served on-site by the managers and employees of
Oglethorpe's former support services division.

Certain Factors Affecting the Utility Industry in General

The electric utility industry in the United States is undergoing
fundamental change and is becoming increasingly competitive. This change is
promoted by the Energy Policy Act of 1992 (the "Energy Policy Act"), recently
adopted and proposed policies from FERC regarding transmission access and
pricing, increased consolidation and mergers of electric utilities, the
proliferation of self-generators and independent power producers, surplus
generation in certain regional markets and other factors. The Energy Policy Act
and FERC policies allow for increased competition among wholesale electric
suppliers and increased access to transmission services by such suppliers. The
new competitive environment is subject to rapidly evolving regulatory policy at
both the federal and state levels, which is based on a shift to a market-driven
environment from a regulated one. Significant legislative developments at the
federal level and in various state legislative bodies, and regulatory
developments at FERC and in state commissions are expected to continue to
clarify the policy and regulatory framework for increased competition. The GPSC
staff has scheduled a series of workshops, the stated purpose of the projectwhich is to
solicit views from the various parties impacted by electric industry
restructuring and to discuss potential resolutions to these issues. At the
conclusion of the workshops, the GPSC staff anticipates presenting a report to
the GPSC that will identify electric industry restructuring issues, potential
resolutions and the views of the parties who participated in the workshop. (See
"THE MEMBERS OF OGLETHORPE--Service Area and Competition".)

A number of other significant factors have affected the operations of
electric utilities. They include the cost of fuel for the generation of electric
energy, recovery of the cost of existing facilities, fluctuating rates of load
growth, the effects of conservation and energy management on the use of electric
energy and compliance with environmental and other governmental regulations.

All of the factors mentioned above present an increasing challenge to
companies in the electric utility industry, including Oglethorpe and the
Members, to reduce costs, improve the credit-worthinessmanagement of loans made or guaranteed by REA. In additionresources and respond to adopting new rules regulating
policiesthe
changing environment. (See "Corporate Restructuring" herein and procedures for insured"MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES--General", "--Power Purchase and guaranteed loansSale
Arrangements--Other Power Purchases", and lien
accommodations, REA has published a proposed rule describing a new form of
wholesale power contract and has,"ENVIRONMENTAL AND OTHER REGULATIONS"
in an advance notice of proposed rule-making,
requested suggestions for revisions to its standard form of mortgage. Many of
these rule-makings have taken many months or years to complete and the outcome

of these various rule-making initiatives, whether others may be forthcoming,
whether any of such rule-making initiatives may achieve the objectives stated by
REA, or the extent to which such initiatives may affect Oglethorpe or the
Members cannot be predicted.

The Clinton Administration has proposed that the Department of Agriculture,
which includes REA, be reorganized to improve its efficiency. Legislation has
been introduced that would authorize the Secretary of Agriculture to implement
this reorganization. Under the proposed reorganization, the electric and
telephone programs of REA would be included in a new Rural Utilities Service.
The rural development functions of REA would be included in a Rural Business and
Cooperative Development Service. Both agencies would report to an Under
Secretary for Rural Economic and Community Development. Oglethorpe's management
does not believe that the reorganization, if implemented as proposed, will have
a significant adverse effect on it or the Members.

5Item 2.)

THE MEMBERS OF OGLETHORPE

SERVICE AREA AND COMPETITIONService Area and Competition

The Members are identified in Item 10(a) of this Reportlisted below and include 39 of the 42 electric
distribution cooperatives in the State of Georgia.

As of
December 31, 1993, theAltamaha EMC Habersham EMC Planters EMC
Amicalola EMC Hart EMC Rayle EMC
Canoochee EMC Irwin EMC Satilla Rural EMC
Carroll EMC Jackson EMC Sawnee EMC
Central Georgia EMC Jefferson EMC Slash Pine EMC
Coastal EMC Lamar EMC Snapping Shoals EMC
Cobb EMC Little Ocmulgee EMC Sumter EMC
Colquitt EMC Middle Georgia EMC Three Notch EMC
Coweta-Fayette EMC Mitchell EMC Tri-County EMC
Excelsior EMC Ocmulgee EMC Troup EMC
Flint EMC Oconee EMC Upson County EMC
Grady EMC Okefenoke Rural EMC Walton EMC
GreyStone Power Corporation Pataula EMC Washington EMC

The Members servedserve approximately 11.2 million electric consumers (meters)
representing a total population of approximately 2.32.6 million people. The Members
serve a region covering approximately 40,000 square miles, which is
approximately 70% of the land area of Georgia served by the owners of the ITS,
encompassing 150 of the State's 159 counties. Sales by the Members in 19931996
amounted to approximately 16.219.6 million megawatt-hours ("MWh"), with 74%72% to
residential consumers, 24%26% to commercial and industrial consumers and 2% to
other consumers. No single consumer of any Member constituted more than 1% of
the Members' aggregate sales in 1993. 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 19911994 through 19931996 of 4.5%5% in number of consumers, 6.9%9% in MWh
sales and 8.9%7% in electric revenues.

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.
TheWith limited exceptions, the Members have the exclusive right to provide retail
electric service in their respective assigned territories, which are predominately
outside of the municipal limits.limits existing at the time the Territorial Act was
enacted in 1973. The chief 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 not reassign territory or transfer service except in
limited circumstances provided by the Territorial Act. 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: (i) upon a determination by the GPSC, 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) upon a finding by GPSC, 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
premises and the electric utility is unwilling or unable to comply with an order
from GPSC regarding such service.

The GPSC may reassign territory only if it
determines that an assignee electric supplier has breached the tenets of public
convenience and necessity.

The territorial assignments underAs discussed above, the Territorial Act are also subject to
an exception that permitsallows the owner of any new
facility located outside of
existing municipal limits and having a connected demand 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 industrialcommercial and commercialindustrial loads. The number of

commercial and industrial loads served by the Members continues to increase
annually. Retail competition in the electric utility industry has increasedhistorically
been rare. While the competition for 900-kilowatt loads represents only limited
competition in recent years.

COOPERATIVE STRUCTUREGeorgia, this competition has given Oglethorpe and the Members
the opportunity to develop resources and strategies to operate in an
increasingly competitive market.

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
New Wholesale Power Contracts provide that a Member may not dissolve, liquidate
or otherwise wind up its affairs without Oglethorpe's approval. The Member may
not 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 of its assets to any person, whether in a
single transaction or series of transactions, unless either (i) the transaction
is approved by Oglethorpe or (ii) other specified conditions are satisfied
including, but not limited to, an assumption agreement by the transferee,
satisfactory to Oglethorpe, containing an assumption by the transferee of the
performance and observance of every covenant and condition of the Member under
the New Wholesale Power Contract, and certifications of accountants as to
certain specified financial requirements of the transferee (taking into account
the transfer).

Cooperative Structure

The Members 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 REA. TheseRUS or loan documents with other lenders. The RUS mortgages
generally prohibit such distributions unless, after any such distribution, the
Member's total equity will equal at least 40% of its total assets, except that
distributions may be made of up to 25% of the margins and patronage capital
received by the Member in the preceding year. As a general matter, the Members
that borrow from RUS distribute accumulated patronage capital from time to time
subject to their respective financial policies and in conformity with their
respective REARUS mortgages. (See "Members' Relationship with RUS" herein.)

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 New 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--MemberCORPORATION--New 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 New Wholesale Power Contracts. Revenues of the Members that borrow
from RUS are, however, pledged under thetheir respective REA mortgagesRUS mortgages.

Rate Regulation of the Members.

RATE REGULATION OF MEMBERSMembers

Through provisions in the loan documents securing loans to the Members,
REARUS exercises control and supervision over the Members that borrow from it in
such areas as: (i) accounting; (ii) borrowings; (iii) rates and charges for the
sale of power; (iv) construction and acquisition of facilities; and (v) the
purchase and sale of power. The individual REARUS mortgages of the Members require
them to design rates with a view to maintaining an average TIER of not less than
1.50 and an average DSC of not less than 1.25 for the two highest out of every
three successive years.

Although the setting of the rates of the Members is not subject to
approval ofby any Federal or state agency or authority other than REA,RUS, the
Territorial Act prohibits the Members from unreasonable discrimination in the

9
setting of rates, charges, service rules or regulations.

CONTRACTS WITHregulations and requires the Members
to obtain GPSC approval of long-term borrowings.

Snapping Shoals EMC, Mitchell EMC, Troup EMC, Walton EMC and Cobb EMC
have prepaid their RUS indebtedness and are no longer RUS borrowers. Each of
these Members now have financial and other requirements under loan documents
with their new lenders. Other Members may also pursue this option. To the extent
that these five Members and others that in the future prepay their RUS
indebtedness engage in wholesale sales or transmission in interstate commerce,
they will be subject to regulation by FERC under the Federal Power Act.

Members' Relationship with RUS

Historically, federal loan programs providing direct loans from RUS to
electric cooperatives have been a major source of funding for the Members. In
recent years, there have been legislative, administrative and budgetary
initiatives intended to reduce or, in some cases, eliminate federal funding for
electric cooperatives. In addition, the RUS loan and guarantee programs have
been characterized by the imposition of increasingly problematic terms and
conditions and extended delays in access to necessary funding. RUS has adopted a
new standard form of mortgage and has published a proposed rule describing a new
standard form of loan contract for distribution borrowers.

Recent changes and proposals for further changes have made the direct
loan program administered by RUS more costly. The Rural Electrification Loan
Restructuring Act of 1993 eliminated the long-standing 2% loan program and
substituted a new program, the interest rates for which 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 a 5% loan program. The future cost,
availability and amount of RUS direct and guaranteed loans which may be
available to the Members cannot be predicted.

Five Members have prepaid their RUS indebtedness and are no longer RUS
borrowers. Other Members may also pursue this option. (See "Rate Regulation of
Members" herein.)

Members' Relationship with GTC and GSOC

For information about the Members' relationship with GTC and GSOC, see
"OGLETHORPE POWER Corporation--Relationship with GTC" and "--Relationship with
GSOC".

Contracts with SEPA

In addition to energy received from Oglethorpe under the New Wholesale
Power Contracts, the Members purchase hydroelectric power under contracts with
SEPA. In 1993,1996, the aggregate SEPA allocation to the Members was 542 MWmegawatts
("MW") plus associated energy, representing approximately 13%11% of total Member
peak demand and approximately 6%5% of total Member energy requirements. New
20-year contracts between each of the Members and SEPA have recently been
executed. The provisions of the new contracts are essentially the same as the
existing contracts with a few exceptions. The Members must schedule their energy
allocation, and each has designated Oglethorpe to perform this function. In a
separate agreement, Oglethorpe will schedule, through GSOC, the Members' SEPA
power deliveries. Further, the Members 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.
SEPA and Oglethorpe have entered into new transmission arrangements under which
Oglethorpe would deliver the Members' SEPA purchases. GTC, as assignee of this
agreement, will

deliver the SEPA power under its network tariff and contract with each Member.
The new contracts are subject to RUS approval. The amount of capacity and energy
available from SEPA is not expected to increase in an amount sufficient to serve
a material portion of the projected growth in the Members' requirements. (See
"OGLETHORPE POWER CORPORATION-MemberCorporation--New Wholesale Power Contracts" and "-Member"MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES--Member Demand and Energy Requirements"
and the table thereunder.)

In September 1993, SEPA issued a NoticeDuring 1996, legislative proposals were made that would have resulted
in the privatization of Intent to revise itsseveral of the federal power marketing policyadministrations,
in particular SEPA. Ultimately, no proposal for the Georgia-Alabama-South Carolina systemprivatization of projects, from which
the Members purchase SEPA power. This policy will govern the renewal of SEPA's
contracts with the Members, which are subject to renewal on May 31, 1994.
Although Oglethorpepower
marketing administrations was passed by Congress. The President's Budget for
fiscal year 1998 does not anticipate that such revised policy will resultinclude any proposals to privatize the federal power
marketing administrations. The ultimate outcome of this issue in a significant change, the final marketing policy and its effect on the Members'
allocations of capacity and energyCongress cannot
be predicted with certainty.

MEMBERS' RELATIONSHIP WITH REA

Federal loan programs providing direct loans from REA to electric
cooperatives have been a major source of funding for the Members. On November 1,
1993, the President signed into law the Rural Electrification Loan Restructuring
Act of 1993, which contains significant revisions to the REA loan program
utilized by the Members. The Members previously relied on the 5% insured loan
program, under which the REA Administrator could require that up to 30% of a
borrower's capital needs be obtained from private sources. The 1993 Act provides
for loans to be made at an interest rate equal to that being paid on municipal
bonds with comparable maturities. Certain borrowers with either (i) low
consumer density or (ii) higher than average rates and consumers having lower
than average incomes will have borrowing rates capped at 7%. The 1993 Act
continues to make 5% loans available for hardship cases. Loans will also be
available to fund demand-side management and conservation programs. Although the
1993 Act will reduce the Government's cost associated with the REA loan program,
there is no guarantee that further changes in the cost and availability of the
REA lending program will not be made, since the level of funding will remain
subject to the Congressional budget and appropriation processes. The President's
budget proposal for the fiscal year 1995 includes a proposal to replace most of
the "municipal bond rate" program with higher-cost loans made at the cost to the
United States Department of the Treasury. The outcome of this budget proposal
and the future cost, availability and amount of REA direct and guaranteed loans
cannot be predicted.

For further information regarding the REA program, see "OGLETHORPE POWER
CORPORATION-Relationship with REA".

711

THIRD-PARTY INTEREST IN MEMBER SYSTEMS

From time to time, utilities may be approached by other utilities or other
parties interested in purchasing their systems. Some of Oglethorpe's Members
have been approached in the past by third parties indicating an interest in
purchasing their systems. The Wholesale Power Contract between Oglethorpe and
each Member provides that no Member may reorganize, consolidate or merge, or
sell, lease or transfer all or a substantial portion of its assets (or make any
agreement therefor), so long as Oglethorpe has notes outstanding to REA and the
FFB, without first paying such portion of any such outstanding notes as may be
determined by Oglethorpe with the prior written consent of REA and otherwise
complying with such reasonable terms and conditions as Oglethorpe and REA may
require. The enforceability of the REA form of wholesale power contract has been
consistently upheld by the courts in several jurisdictions. In addition, REA has
recently stated its policy that it will not encourage or facilitate the buyout
of borrowers by third parties and that it will expect cooperative distribution
utilities to retire a proportionate share of the associated G&T indebtedness and
to pay other appropriate costs and expenses of the G&T as a condition of a
buyout.

Oglethorpe's management is unable to predict what transactions, if any,
might result from the past third-party interest or whether any other proposals
will be made to the Members. Oglethorpe has received an opinion of its counsel
that each of the Wholesale Power Contracts is a valid, binding and enforceable
obligation of each respective Member. Based on this opinion and other factors,
Oglethorpe's management believes that no sale or transfer of Member assets would
have a material adverse effect upon its financial condition or results of
operations.

THEREQUIREMENTS AND POWER SUPPLY SYSTEM

GENERALRESOURCES

General

Oglethorpe supplies the current capacity and energy requirements of the
Members from a combination of owned and leased generating plants and from power
purchased under long-term contracts with other power suppliers.suppliers and power
marketers. Oglethorpe owns or leases 3,335.0 MW of nameplate capacity,
consisting of 1,500.6 MW of coal-fired capacity, 1,185 MW of nuclear-fueled
capacity, 632.5 MW of pumped storage hydroelectric capacity, 14.8 MW of
oil-fired combustion turbine capacity and 2.1 MW of conventional hydroelectric
capacity. (SEE "GENERATING FACILITIES--General" and "--Plant Performance" in
Item 2 for a description of Oglethorpe's generating facilities.) These resources
are generally scheduled and dispatched so as to minimize the operating cost of
Oglethorpe's system. In addition,However, Oglethorpe purchases and sells capacity and energy in the
bulkhas entered into long-term arrangements
with power marketmarketers to make the best use ofbetter utilize its resources and thus minimizeto reduce the cost of
capacity and energy delivered to the Members, in part by giving certain dispatch
rights to the power marketers. (See "Power Purchase and Sale Arrangements--Power
Marketer Arrangements" herein.)

Member Demand and Energy Requirements

The following table shows the aggregate peak demand and energy
requirements of the Members for the years 1994 through 1996 and also shows the
amounts of such requirements supplied by Oglethorpe and SEPA. For the years 1994
through 1996, demand and energy requirements increased at an average annual
compound growth rate of 13.2% and 9.7%, respectively.

Demand (MW) Energy Requirements (MWh)
--------------------------------------- --------------------------------------------
Total Total
Require- Supplied by Supplied by Require- Supplied by Supplied by
ments(1) Oglethorpe(2) SEPA(3) ments Oglethorpe(2) SEPA(3)
-------- ------------- ------- ----- ------------- -------

1994 3,938 3,396 542 17,278,812 16,285,127 993,685
1995 4,850 4,308 542 19,403,703 18,442,153 961,550
1996 5,045 4,503 542 20,793,864 19,807,101 986,763

- ----------

(1) System peak demand of the Members measured at the Members' delivery points
(net of system losses). The significant increase in peak demand in 1995
was due in large part to a milder than normal summer in 1994.

(2) Includes purchased power. (See "Power Purchase and Sale
Arrangements--Power Purchases from GPC" and "--Other Power Purchases"
herein.)

(3) Supplied by SEPA through existing contracts with the Members. (See "THE
MEMBERS OF OGLETHORPE--Contracts with SEPA".)

In 1996, Cobb EMC and Jackson EMC accounted for approximately 12.5% and
11.2% of Oglethorpe's total revenues, respectively.

Seasonal Variations

The demand for energy by the Members is influenced by seasonal weather
conditions. Historically, Oglethorpe's peak demand occurs during the months of
June through September. (See "OGLETHORPE POWER Corporation--Electric Rates".)
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, the capacity
revenues are billed and recognized in equal monthly amounts.

Demand Management

Oglethorpe and the Members have implemented various demand management
programs. The program goal, developed in conjunction with Oglethorpe's
integrated resource planning process, has been to modify demand patterns so that
current resources are used efficiently and the need for additional generating
resources is delayed. The programs that have been implemented include an energy
efficient home program (the "Good Cents Home" program), remote-controlled
switching of air conditioners, water heaters and irrigation pumps, residential
energy audits and public appeals to encourage consumers to use less energy
during periods of peak demand. The demand management programs have reduced the
growth of peak demand and have also resulted in an increase in off-peak sales.
(See "Power Purchase and Sale Arrangements--Other Power Purchases" herein.)

Power Purchase and Sale Arrangements

Power Marketer Arrangements

As a means of reducing the cost of power provided to the Members,
Oglethorpe utilized short-term power marketer arrangements during 1996 with two
different power marketers. Under both of the arrangements, the power marketer
was required to provide to Oglethorpe at a favorable fixed rate all of the
energy needed to meet the Members' requirements, and Oglethorpe was required to
provide upon request to the power marketers at cost (subject to certain
limitations) all energy available from Oglethorpe's total power resources. Under
these arrangements, Oglethorpe continued to operate the power supply system and
continued to dispatch the generating resources to ensure system reliability.

Oglethorpe is now utilizing power marketer arrangements on a long-term
basis to reduce the cost of power. It has entered into power marketer agreements
with LPM for 50% of the load requirements of the Members, and is working to
finalize an agreement with Morgan Stanley Capital Group ("Morgan Stanley") for
the remaining 50% of the Members' load requirements.

Effective January 1, 1997, Oglethorpe entered into power marketer
agreements with LPM for 50% of the load requirements of the Members. Under the
agreements, LPM is obligated to deliver, and Oglethorpe is obligated to take,
50% of the load requirements of the participating Members less the load
requirements for certain customer choice loads (900 kilowatt or greater), plus
50% of the delivery obligations under Oglethorpe's existing firm power
off-system sale contracts. For customer choice loads of three megawatts or less,
LPM is obligated to deliver, if Oglethorpe requests, 50% of the associated load
requirements. Oglethorpe has the option of purchasing the energy requirements
for customer choice loads from another supplier. Oglethorpe is obligated to sell
and LPM is obligated to buy 50% of the output of each participating Member's PCR
share of the "must run" units (primarily nuclear units). Oglethorpe is also
obligated to make available the same share of all other resources, which LPM may
schedule. LPM does not have the right to the output of upgrades to these
resources. LPM must pay Oglethorpe the cost of fuel associated with the energy
taken. There is a price adjustment if the plant performance does not meet
specified levels of availability and output. Oglethorpe must pay LPM a
contractually specified price for each MWh purchased.

Oglethorpe has contracted with GTC to provide available transmission
services to deliver to the border of the ITS any energy sold to LPM. Each Member
will use its Transmission Agreement for delivery of energy purchased from LPM
and others.

Effective with the Corporate Restructuring and the execution of
supplemental agreements to the New Wholesale Power Contracts, the LPM agreement
relating to 37 of the 39 Members has a term extending to 2011. With one years'
notice, Oglethorpe has the right to terminate the LPM agreement for any year
beginning with 2002. With one years' notice, LPM has the right to terminate the
LPM agreement for any year beginning with 2005. The LPM agreement relating to
the other two Members has a term extending through the end of 1999. The

supplemental agreements are the vehicle through which Oglethorpe and the Members
assure that the Members receive the benefits of and support the obligations for
the new power marketer arrangements under the New Wholesale Power Contracts.

LPM is an indirect wholly owned subsidiary of LG&E Energy Corp., a
Kentucky corporation, which is a diversified energy services holding company.
LG&E Energy Corp. 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 Securities and Exchange Commission (the
"Commission"). Copies of this material can be obtained at prescribed rates from
the Commission's Public Reference Section at 450 Fifth Street, N.W., Room 1024,
Washington, D.C. 20549. Certain securities of LG&E Energy Corp. are listed on
the New York Stock Exchange, and reports and other information concerning LG&E
Energy Corp. can be inspected at the office of such Exchange.

Oglethorpe is now working to finalize power marketer arrangements with
Morgan Stanley that would supply the remaining 50% of the Members' load
requirements. The agreement is expected to allow each Member to have Oglethorpe
elect a term from three to eight years. Each Member is currently deciding
whether to have Oglethorpe obtain its remaining load requirements from Morgan
Stanley. The proposed agreement would obligate Oglethorpe to purchase fixed
quantities of energy, averaging 50% of the Members' forecasted requirements
during the term of the agreement. Initially, Oglethorpe would manage the system
through purchases or sales to balance this fixed requirement against the actual
requirements. Oglethorpe would have considerably more discretion in the
management of the power supply system under the proposed Morgan Stanley contract
than under the LPM contract. In order to complete the implementation of the
Morgan Stanley power marketer arrangements, Oglethorpe and each participating
Member will enter into supplemental agreements to the New Wholesale Power
Contract to conform the provisions of the New Wholesale Power Contracts to the
terms of the power marketing arrangements. Any Member that elects not to
participate in the Morgan Stanley agreement would have other options available,
including having Oglethorpe manage this portion of the Member's load
requirements and, beginning as early as January 1, 1998, contract with other
power marketers.

In the interim, Oglethorpe is supplying this portion of the Members'
requirements from its own resources and by off-system purchase and sales. In the
event Oglethorpe does not enter into power marketer agreements for the remainder
of its load, it can continue to operate effectively in this manner

Oglethorpe will continue to plan for each Member's requirements beyond
the term of the respective power marketer agreements, including decisions
regarding early termination.

Power Purchases from GPC

Oglethorpe currently purchases 1,000 MW of capacity and associated
energy from GPC on a take-or-pay basis under the Block Power Sale Agreement
("BPSA"), which extends through December 31, 2003. The capacity purchases under
the BPSA are from five Component Blocks (as defined in the BPSA), composed of
three Component Blocks of 250 MW each (coal-fired units) and two Component
Blocks of 125 MW each (combustion turbine units). The capacity in one or more
Component Blocks may, however, be less than the MW stated above, as the result
of scheduled retirement of units or retirements due to force majeure events. All
units in the combustion turbine Component Blocks are scheduled to be retired by
2003. Although Oglethorpe may not increase its capacity purchases under the
BPSA, it may reduce or extend its purchases of one or more Component Blocks upon
proper notice to GPC. Oglethorpe has given notice of its intent to reduce its
purchases by two 250 MW Component Blocks (coal-fired units) effective September
1, 1997 and September 1, 1998. Also, pursuant to its long-term power marketer
agreements with LPM, Oglethorpe has committed to continue reducing its purchases
from GPC as permitted under the BPSA and thus will no longer purchase any energy
under the BPSA effective September 1, 2001. (See "Power Marketer Arrangements"
herein for a discussion of the LPM agreement.)

Other Power Purchases

Oglethorpe purchases 100 MW of capacity from each of Entergy Power,
Inc. ("EPI") and Big Rivers Electric Corporation ("Big Rivers"), under
agreements extending through June and July 2002, respectively. The availability
of capacity under the EPI contract is dependent on the availability of two
specific generating units available to EPI. The Tennessee Valley Authority
("TVA") provides the transmission service to deliver the power from the Big
Rivers electric system to the ITS. TVA and Southern Company Services, as agent
for Alabama Power Company and Mississippi Power Company, provide the
transmission service necessary to deliver the power from EPI to the ITS. (See
Note 9 of Notes to Financial Statements in Item 8.)

Oglethorpe also has a contract through 2019 to purchase approximately
300 MW of capacity with Hartwell Energy Limited Partnership ("Hartwell"), a
partnership owned 50% by Destec Energy, Inc. and 50% by American National Power,
Inc., a subsidiary of National Power, PLC. Oglethorpe intends to use the units
for peaking capacity but has the right to dispatch the units fully.

In addition to the purchases from GPC, Big Rivers and EPI, 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 FERC, Oglethorpe has 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 has historically
provided the Members with the necessary services to fulfill these sale
obligations. Purchases by Oglethorpe from such qualifying facilities provided
0.2% of Oglethorpe's energy requirements for the Members in 1996. As a result of
the Corporate Restructuring, the Member may make such purchases in the future.

Oglethorpe has contracted with Florida Power Corporation to purchase 50
MW of peaking capacity during the summer of 1997 and 275 MW of peaking capacity
during the summer of 1998.

Under the New Wholesale Power Contracts, Oglethorpe will provide joint
planning services for all participating Members. A Member may elect not to have
Oglethorpe provide joint planning, procurement or bulk power marketing. Although
the long-term power marketer arrangements may provide substantially all of the
Members' requirements for the contract term, Oglethorpe will continue to supply
these planning services for requirements beyond the contract term as well as for
evaluation of contract options.

Long-Term Power Sales

Oglethorpe has an agreement to sell 100 MW of base capacity to Alabama
Electric Cooperative beginning June 1, 1998, and extending through December 31,
2005.

Other Power System Arrangements

Oglethorpe has interchange, transmission and/or short-term capacity and
energy purchase or sale agreements with over 20 utilities 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. The
development of and access to a statewide transmission network and the
interconnections with other utilities are key elements in Oglethorpe's ability
to make off-system sales and purchases through its contract with GTC and to
compete in an increasingly competitive market.

OTHER INFORMATION

Information with respect to fuel supply for Oglethorpe's plants is set
forth under the caption "GENERATING FACILITIES--Fuel Supply" included in Item 2
and is incorporated herein by reference. Information with respect to
environmental and other regulations affecting Oglethorpe and its plants is set
forth under the caption "ENVIRONMENTAL AND OTHER REGULATIONS" included in Item 2
and is incorporated herein by reference.

Item 2. PROPERTIES

GENERATING FACILITIES

General

The following table sets forth certain information with respect to the
generating facilities in which Oglethorpe currently has ownership or leasehold
interests, all of which are in commercial operation except for Rocky Mountain,
which is under construction.operation. The Edwin I. Hatch Plant
("Plant Hatch"), the Hal B. Wansley Plant ("Plant Wansley"), the Alvin W. Vogtle
Plant ("Plant Vogtle") and the Robert W. Scherer Units No. 1 and No. 2 ("Scherer
Units No. 1 and No. 2") are co-owned by Oglethorpe, GPC, the Municipal Electric Authority of Georgia
("MEAG")MEAG and the City of Dalton ("Dalton").Dalton. GPC is
the operating agent for each of these plants, except Rocky Mountain.co-owned plants. Rocky Mountain is
co-owned by Oglethorpe and GPC, and Oglethorpe is the construction and operating agent.
Oglethorpe is the sole owner of the Tallassee Project at the Walter W. Harrison
Dam ("Tallassee"). (See "CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION
AGREEMENTS--The
Plant Agreements".)

OGLETHORPE'S
SHARE OF NAME- COMMERCIAL LICENSE
PERCENTAGE PLATE CAPACITY OPERATION EXPIRATION
TYPE OF FUEL INTEREST(1)Oglethorpe's
Share of Name- Commercial License
Percentage Plate Capacity Operation Expiration
Type of Fuel Interest(1) (MW) DATE DATEDate Date
------------ ----------- -------------- ---------- -------------- ---- ----
FACILITIES IN SERVICE:

FACILITIES IN SERVICE:
Plant Hatch (near Baxley)
Unit No. 1 Nuclear 30 243.0 1975 2014
Unit No. 2 Nuclear 30 246.0 1979 2018
Plant Vogtle (near Waynesboro)
Unit No. 1 Nuclear 30 348.0 1987 2027
Unit No. 2 Nuclear 30 348.0 1989 2029
Plant Wansley (near Carrollton)
Unit No. 1 Coal 30 259.5 1976 N/A(3)A(2)
Unit No. 2 Coal 30 259.5 1978 N/A(3)A(2)
Combustion Turbine Oil 30 14.8 1980 N/A(3)A(2)
Plant Scherer (near Forsyth)
Unit No. 1 Coal 60 490.8 1982 N/A(3)A(2)
Unit No. 2 Coal 60 490.8 1984 N/A(3)A(2)
Tallassee (near Athens) Hydro 100 2.1 1986 2023
-------
Total in Service 2,702.5
-------

FACILITIES UNDER CONSTRUCTION:
Rocky Mountain Pumped Storage
(near Rome) Hydro 75(2) 635.974.61 632.5 1995 2027
----------------
Total Ownership 3,338.4
-------

- -------------------------3,335.0
=========

- ----------

(1) Oglethorpe has an ownership interest in all of the facilities except
Scherer Unit No. 2. The 60% interest in Scherer Unit No. 2 is leased under
leases that expire in 2013, subject to options to renew for a total of 8.5
years.

(2) Represents Oglethorpe's estimated ownership interest upon completion.
Oglethorpe's ultimate ownership interest is proportional to its investment
in the project relative to GPC's investment. (See "Future Power
Resources--ROCKY MOUNTAIN" herein.)

(3) Coal-fired units and combustion turbines do not operate under operating
licenses similar to those granted to nuclear units by the Nuclear
Regulatory Commission and to hydroelectric plants by the Federal Energy
Regulatory Commission.

Upon completion of Rocky Mountain, Oglethorpe will own or lease 1,500.6 MW
of coal-fired capacity, 1,185 MW of nuclear-fueled capacity, an estimated 635.9
MW of pumped storage hydroelectric capacity, 14.8 MW of oil-fired combustion
turbine capacity and 2.1 MW of hydroelectric capacity.

Oglethorpe and the other co-owners of the above plants also own
transmission facilities which together formexcept
Scherer Unit No. 2. The 60% interest in Scherer Unit No. 2 is leased under
leases that expire in 2013, subject to options to renew for a total of 8.5
years.

(2) Coal-fired units and combustion turbines do not operate under operating
licenses similar to those granted to nuclear units by the ITS. Through agreements, common
access to the combined facilities that compose the ITS enables the owners to use
their combined resources to make deliveries to their respective consumers, to
provide transmission service to third partiesNuclear
Regulatory Commission and to make off-system purchases
and sales. (See "Transmission and Other Power System Arrangements" herein and
"CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--Agreements
Relating to Integrated Transmission System".)

PLANT PERFORMANCEhydroelectric plants by FERC.

Plant Performance

The following table sets forth certain operating performance
information of each of the major generating facilities in which Oglethorpe
currently has ownership or leasehold interests, except for Rocky Mountain which is not yet in
commercial operation:interests:

EQUIVALENT AVAILABILITY(1) CAPACITY FACTOR(2)
-------------------------- --------------------
UNIT 1993 1992 1991 1993 1992 1991Equivalent Availability (1) Capacity Factor (2)
------------------------------ -------------------------
Unit 1996 1995 1994 1996 1995 1994
- ---- ---- ---- ---- ---- ---- ----

Plant Hatch
Unit No. 1 . . . . . . . 76% 95% 73% 77% 95% 72%1................... 83% 98% 84% 83% 100% 85%
Unit No. 2 . . . . . . .2................... 97 75 70 7478 99 75 70 7479
Plant Vogtle
Unit No. 1 . . . . . . . 85 96 781................... 80 98 86 96 7880 98 86
Unit No. 2 . . . . . . . 87 80 92 87 80 922................... 88 89 91 89 90 91
Plant Wansley
Unit No. 1 . . . . . . .1................... 88 90 92 84 71 76 6458 56 62
Unit No. 2 . . . . . . . 90 92 94 73 77 732................... 91 89 88 62 56 58
Plant Scherer
Unit No. 1 . . . . . . . 881................... 92 95 98 36 17 2597 74 73 64
Unit No. 2 . . . . . . .2................... 84 97 85 72 85 60
Rocky Mountain (3)
Unit No. 1................... 94 83 N/A 15 16 N/A
Unit No. 2................... 95 100 100 37 2992 N/A 13 15 N/A
Unit No. 3................... 95 92 N/A 10 16
- -------------------------N/A

- ---------------------

(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 Commercial Operation Dates: Unit 1 - July 24, 1995; Unit 2
- June 19, 1995; Unit 3 - June 1, 1995. This information was calculated
beginning from the commercial operation date for each unit. As a pumped
storage plant, Rocky Mountain primarily operates in peaking service.

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.

Although Plant Scherer is designed for base load operation, it has
primarily operated in peaking service due to the historically higher cost of its
fuel supply (low-sulfur coal under long-term contracts) relative to the cost of
Oglethorpe's other resources. Thus, the capacity factors for Scherer Units No. 1
and No. 2 have been lower than those typical of base loaded units. With the
planned acquisition of lower cost low-sulfur coal and expected increases in
Member sales, Oglethorpe's management anticipates higher utilization of Scherer
Units No. 1 and No. 2 in the future.

FUEL SUPPLYFuel Supply

Coal for Plant Wansley is purchased under long-term contracts, which are
estimated to be sufficient to provide the majority of the coal requirements of
Plant Wansley through 1997, with the remainder being provided through spot
market transactions. To comply with the requirements of the Clean Air Act, as
amended (the "Clean Air Act"), Plant Wansley is being modified to burn
low-sulfur coal. As of February 28, 1994,1997, there was a 20-day38-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 spot market transactions. As of February
28, 1994,1997, the coal stockpile at Plant Scherer contained a 29-day37-day

supply based on nameplate rating. Further,During 1994, Plant Scherer is beingwas converted to
burn both sub-bituminous and bituminous coals, and a separate stockpile of
sub-bituminous coal is beingwas built in addition to the stockpile of bituminous coal.

The coal supply at PlantsPlant Scherer and Wansley is lower than normal due to
(i) higher than expected use of Plant Scherer during the summer of 1993 and the
winter of 1994 because of abnormal temperatures, (ii) transportation
interruptions resulting from severe weather conditions, and (iii) deferred
deliveries because of higher replacement prices due to the United Mine Workers
of America strike. The supply is planned to be replenished as needed and as
competitively priced coal becomes available.

The Scherer ownership and operating agreements were
amended effective
Octoberin 1993 and 1996, respectively, to 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 elected to dispatch separately in November 1993. Pursuant to the amendments, GPC is expectedOglethorpe
implemented separate dispatch of Plant Scherer in 1994. Oglethorpe expects to
implement separate dispatch at Plant Wansley by May 1,
1994.early to mid-summer 1997.
Oglethorpe intends to continuecontinues to use GPC as its agent for fuel procurement.

In anticipationTo take advantage of these changes at Plants Scherer and Wansley,
Oglethorpe formed a wholly owned subsidiary to acquire rail cars designed for
hauling coal from the western coal mining regions. The subsidiary, Black Diamond
Energy, Inc., has acquired 115
cars, and Oglethorpe anticipates the acquisition of approximately 350 additional
cars during the next three years for both Plants Scherer and Wansley.purchased or leased 299 rail cars. Oglethorpe has entered into
an initial 15-year lease with the subsidiary which obligates Oglethorpe to pay
all of the ownership and operating expenses of the subsidiary relating to the
leased rail cars during the lease term. The co-owners are
currently negotiating a similar amendment to the Plant Wansley operating
agreement.

For information relating to the impact that the Clean Air Act will have
on Oglethorpe, see "Environmental and Other Regulations" herein."ENVIRONMENTAL AND OTHER REGULATIONS--Clean Air Act".

GPC, as operating agent, has the responsibility to procure nuclear fuel
for PlantPlants Hatch and Plant Vogtle. GPC has contracted with Southern Nuclear Operating
Company ("SONOPCO") to provide nuclear services, 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.

Plants Hatch and Vogtle currently have on-site spent fuel storage
capacity. Based on normal operations and retention of all spent fuel in the
reactor, it is anticipated that existing on-site pool capacity would not be
sufficient in 2003 and 2009,2008, respectively, to accept the number of spent fuel
assemblies that would normally be removed from the reactor during a refueling.
Contracts with the Department of Energy ("DOE") have been executed to provide
for the permanent disposal of spent nuclear fuel produced at PlantPlants Hatch and Plant
Vogtle. The services to be provided by DOE are scheduled to begin in 1998. However,1998;
however, the actual yearDOE has stated that these servicespermanent nuclear waste storage facilities will
beginnot be available by that date, and it is uncertain.uncertain when they will be available.
If DOE does not begin receiving the spent fuel from Plant Hatch in 2003 or from
Plant Vogtle in 2009,2008, alternative methods of spent fuel storage will be needed.
One option available
is expansion of spent fuelActivities for adding dry cast storage capacity at the plant sites.Plant Hatch by as early as
1999 are in progress. (See "Environmental and
Other Regulations" herein"ENVIRONMENTAL AND OTHER REGULATIONS--Nuclear
Regulation" for a discussion of the Nuclear Waste Policy Act and Note 1 of Notes
to Financial Statements in Item 8 regarding nuclear fuel cost.)

PROPOSED CHANGES TO NUCLEAR PLANT OPERATING ARRANGEMENTS

In September 1992, GPC filed applications with the Nuclear Regulatory
Commission (the "NRC") to add SONOPCO to the operating license of each unit of
Plants Hatch and Vogtle and designate SONOPCO as the operator. The application
is currently pending before the Atomic Safety and Licensing Board. SONOPCO, a
subsidiary of The Southern Company specializing in nuclear services, currently
provides certain operating, maintenance, and other services to GPC in accordance
with the Amended and Restated Nuclear Managing Board Agreement (the "Amended and
Restated NMBA") and the agreements referenced in the Amended and Restated NMBA.
The co-owners have agreed to a Nuclear Operating Agreement between GPC and
SONOPCO, which will be entered into in the event the NRC approves the
application. (See "CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION
AGREEMENTS--The Plant Agreements--HATCH, WANSLEY, VOGTLE AND SCHERER".)

POWER SALES TO AND PURCHASES FROM GPC

A significant portion of Oglethorpe's sales are made to GPC and a
significant portion of Oglethorpe's purchased power is obtained from GPC. The
following table sets forth a summary of Oglethorpe's electric purchases from and
sales to GPC and all other utilities as a group:

MWh
------------------------------
1993 1992
---------- ----------

Sources of Energy:
- -----------------
Owned or Leased Generation . . . . . . . . 14,575,920 13,805,683
Purchased -- GPC . . . . . . . . . . . . . 5,198,356 4,669,282
-- Others. . . . . . . . . . . . 2,422,459 1,563,980
---------- ----------
Total Sources. . . . . . . . . . . 22,196,735 20,038,945
---------- ----------
---------- ----------
Distribution of Energy:
- ----------------------
Members. . . . . . . . . . . . . . . . . . 16,253,283 14,466,943
Non-Members -- GPC . . . . . . . . . . . . 3,432,542 4,621,675
-- Others. . . . . . . . . . . 1,617,684 272,314
Transmission Losses. . . . . . . . . . . . 893,226 678,013
---------- ----------
Total Distribution . . . . . . . . 22,196,735 20,038,945
---------- ----------
---------- ----------

The sales to GPC are made under the GPC Sell-back (as herein defined) and
the Coordination Services Agreement (the "CSA"). The purchases from GPC are made
under the Block Power Sale Agreement (the "BPSA") and the CSA.

GPC SELL-BACK

Pursuant to the contractual arrangements with GPC, Oglethorpe has an
obligation to sell to GPC, and GPC has an obligation to buy from Oglethorpe,
commencing with the commercial operation of each co-owned unit (other than Rocky
Mountain) and extending for various periods, a declining percentage of
Oglethorpe's entitlement to the capacity and energy of such unit (the "GPC
Sell-back"). The GPC Sell-back has expired in accordance with its terms for
Plants Wansley, Hatch and Scherer Units No. 1 and No. 2 and continues to decline
for Plant Vogtle. The GPC Sell-back will expire for Unit No. 1 of Plant Vogtle
at the end of May 1994 and for Unit No. 2 of Plant Vogtle at the end of May
1995. For 1993, the GPC Sell-back represented 6% of total energy sales by
Oglethorpe. Capacity and energy revenues from the GPC Sell-back represented 10%
of Oglethorpe's total revenues in 1993.

As GPC's entitlement to capacity and energy under the GPC Sell-back has
decreased and continues to decrease, Oglethorpe's increased entitlement to the
output of each unit has been and will continue to be used to serve its

own requirements. The increased costs thereof will be recovered through Member
rates and through off-system sales transactions. The historical ability of
Oglethorpe to sell power from new units to GPC under the GPC Sell-back while at
the same time purchasing power from GPC under lower-cost arrangements has
enabled Oglethorpe to moderate the effects of the higher costs associated with
new generating units on Oglethorpe's costs of service, and therefore on the
rates charged the Members. (See "Other Power Purchases" herein, and "CO-OWNERS
OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--The Plant Agreements--
HATCH, WANSLEY, VOGTLE AND SCHERER" and Note 1 of Notes to Financial Statements
in Item 8.)

The following table sets forth the contractual schedule for the fractional
portion of capacity and energy retained by GPC for the units for which GPC is
currently making GPC Sell-back payments:

CONTRACT YEAR ENDED MAY 31,
---------------------------
OPERATING UNIT 1994 1995 1996
-------------- ---- ---- ----

Vogtle Unit No. 1. . . . . . . . 4/30 -- --
Vogtle Unit No. 2. . . . . . . . 8/30 4/30 --

POWER PURCHASE ARRANGEMENTS

Oglethorpe purchases 1,250 MW of capacity and associated energy from GPC on
a take-or-pay basis under the BPSA. The contract expires December 31, 2001. The
BPSA, along with the Revised and Restated Integrated Transmission System
Agreements (the "ITSA") and the CSA, were entered into in 1990 and made
effective in 1991 as part of a comprehensive restructuring of the way Oglethorpe
plans for and meets the Members' power requirements. These agreements have
improved Oglethorpe's ability to buy and sell power and transmission services in
the bulk power markets.

The capacity purchases under the BPSA are from six Component Blocks (as
defined in the BPSA), composed of four Component Blocks of 250 MW each
(coal-fired units) and two Component Blocks of 125 MW each (combustion turbine
units). Although Oglethorpe may not increase its purchases under the BPSA, it
may reduce its purchases by eliminating one or more Component Blocks upon
written notice to GPC. Oglethorpe may reduce up to 250 MW with two years'
notice, above 250 to 500 MW with four years' notice, and more than 500 MW with
seven years' notice. Oglethorpe is entitled to extend the purchase of one or
more Component Blocks one additional year at a time under the same notice
conditions. The capacity in one or more Component Blocks may, however, be less
than 250 MW, as the result of scheduled retirement of units or retirements due
to force majeure events. All units in the combustion turbine Component Blocks
are scheduled to be retired by 2003.

Under the CSA, Oglethorpe schedules and directs GPC to dispatch and
coordinate power from all of Oglethorpe's generation and purchased power
resources through December 31, 1999. The CSA requires Oglethorpe to give GPC one
hour's notice in order to schedule any off-system transactions, which will limit
Oglethorpe's ability to compete with GPC for short-term energy transactions
requiring less than one hour's notice. Oglethorpe may elect to establish its
own control area and terminate regulation services under the CSA upon one year's
notice to GPC. Upon such termination, the parties will, if necessary, negotiate
new service schedules and applicable rates. In order to optimize its use of
coordination services, Oglethorpe is currently installing the equipment that
would be necessary to operate its own control area.

For a further discussion of the new power supply arrangements, see "Other
Power Purchases", "Future Power Resources", and "Transmission and Other Power
System Arrangements" herein, and "CO-OWNERS OF THE PLANTS AND THE PLANT AND
TRANSMISSION AGREEMENTS--The Plant Agreements--HATCH, WANSLEY, VOGTLE AND
SCHERER".

OTHER POWER PURCHASES

Oglethorpe has entered into power purchase contracts with Entergy Power,
Inc. ("EPI") and Big Rivers Electric Corporation ("Big Rivers"), each for the
purchase of 100 MW, extending through June and July 2002, respectively. The EPI
contract is subject to the approval of REA. The availability of capacity under
the EPI contract is dependent on the availability of two specific generating
units available to EPI. The Tennessee Valley Authority ("TVA") provides the
transmission service to deliver the power from the Big Rivers electric system to
the ITS. TVA and Southern Company Services, as agent for Alabama Power Company
and Mississippi Power Company, provide the transmission service necessary to
deliver the power from EPI to the ITS. (See "Transmission and Other Power System
Arrangements" herein and Note 10 of the Financial Statements in Item 8.)

In addition to the purchases from GPC, Big Rivers and EPI, 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
will make 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 provides the Members with the necessary services to fulfill these
sale obligations. Purchases by Oglethorpe from such qualifying facilities
provided 0.4% of Oglethorpe's energy requirements for the Members in 1993.

FUTURE POWER RESOURCES

Oglethorpe uses an integrated resources planning process to study regularly
the need for and feasibility of adding additional generation facilities. This
planning process also considers demand-side management options that could be
implemented by the Members as well as off-system sales of capacity and energy to
optimize the use of Oglethorpe's resources. Oglethorpe's current resources (both
owned or leased generation and purchased power) consist predominately of
resources that can be best used in base-load operation. As a result, all of
Oglethorpe's currently planned resource additions are for peaking capacity. To
further optimize the use of its resources, Oglethorpe is seeking to sell certain
amounts of base capacity and associated energy and to replace it with the
acquisition of peaking capacity when necessary (see "Future Long-Term Power
Sales" herein).

ROCKY MOUNTAIN

Rocky Mountain, which is currently under construction by Oglethorpe, is a
pumped storage hydroelectric facility with no conventional hydroelectric
capability. The facility is designed to consist of three units with a combined
nameplate rating of 847.8 MW at maximum head and a FERC-licensed capacity of 760
MW at minimum head. Under optimal operations, the maximum output of the plant
will decline steadily over a period of approximately eight hours as the upper
reservoir is emptied.

In 1988, Oglethorpe acquired from GPC an undivided ownership interest in
Rocky Mountain. Under the Rocky Mountain ownership arrangement, Oglethorpe, as
agent, is responsible for the design, construction and operation of Rocky
Mountain.

The license issued by FERC for Rocky Mountain expires in 2027. Among other
conditions, the license requires that construction be completed by June 1, 1996.
As of February 28, 1994, Rocky Mountain was approximately 92% complete. Rocky
Mountain is currently scheduled to begin commercial operation in early 1995.
Construction at Rocky Mountain is currently on schedule and under budget.

Under the Ownership Participation Agreement (as hereinafter defined), GPC
has not been required to expend any funds for construction of Rocky Mountain
since December 15, 1988, and is not required to make any additional
contributions. Oglethorpe is required to finance and complete Rocky Mountain.
(See "Liquidity and Capital Resources" in Item 7.) Each party's undivided
interest in Rocky Mountain is equal to the proportion that its respective
investment bears to the total investment in Rocky Mountain (excluding each
party's cost of funds and ad valorem taxes). (See "CO-OWNERS OF THE PLANTS AND
THE PLANT AND TRANSMISSION AGREEMENTS--The Plant

Agreements--ROCKY MOUNTAIN".) As of December 31, 1993, Oglethorpe's ownership
interest in Rocky Mountain was approximately 70%. Based on current arrangements,
Oglethorpe's ultimate ownership interest in Rocky Mountain is estimated to be
approximately 75%, with GPC owning the remaining 25%.

Oglethorpe, GPC and certain third parties have had preliminary discussions
regarding alternatives by which Oglethorpe may acquire the output of GPC's
remaining interest in Rocky Mountain. Options being discussed include a
long-term lease or power purchase arrangement with a third party which would
purchase GPC's interest or a purchase of such interest directly by Oglethorpe.
The nameplate rating of GPC's ultimate ownership interest is estimated to be
approximately 212 MW, and if any such transaction is consummated, such output
would satisfy a portion of Oglethorpe's long-term capacity needs. The outcome of
these discussions cannot be determined at this time.

HARTWELL PURCHASE

In 1992, Oglethorpe entered into a contract for the purchase of
approximately 300 MW of capacity with Hartwell Energy Limited Partnership
("Hartwell"), a partnership owned 50% by Destec Energy, Inc. and 50% by American
National Power, Inc., a subsidiary of National Power, PLC. The contract has a
term of 25 years, commencing upon commercial operation, which by contract is
scheduled to be no later than June 1994. Under the contract, Hartwell is
constructing two 150 MW gas-fired turbine generating units on a site near
Hartwell, Georgia. Oglethorpe intends to use the units for peaking capacity but
has the right to dispatch the units fully. If Hartwell misses any of a specified
list of project milestones, Oglethorpe may terminate the contract and, if it so
chooses, purchase the project at fair market value. Hartwell has provided an
irrevocable letter of credit payable to Oglethorpe in the amount of $10,360,000,
which can be drawn upon if the project is not in service by the scheduled date
or as liquidated damages in case of a default by Hartwell. Hartwell has advised
Oglethorpe that it expects to begin deliveries of power to Oglethorpe prior to
June 1994.

OTHER FUTURE RESOURCES

In its current integrated resource plan, Oglethorpe has identified a
potential need for additional peaking capacity in the late 1990s. In November
1993, Oglethorpe issued a Request for Proposals for the purchase of up to 600 MW
of long-term peaking capacity to be available by June 1, 1999. Proposals were
due March 29, 1994. Oglethorpe has reserved the right to reject any and all
bids, and should it do so, Oglethorpe may construct that capacity itself.
Oglethorpe has also agreed to purchase from Florida Power Corporation 50 MW of
peaking capacity during the summer of 1997 and 275 MW of peaking capacity during
the summer of 1998. This purchase is subject to regulatory approval.

TRANSMISSION AND OTHER POWER SYSTEM ARRANGEMENTS

As of February 28, 1994, Oglethorpe owned approximately 2,186 miles of
transmission line and 404 substations of various voltages. Oglethorpe provides
power and energy to the Members through the ITS consisting of transmission
system facilities owned by Oglethorpe, GPC, MEAG and Dalton. As a result of its
participation in the ITS, Oglethorpe is entitled to use any of the transmission
facilities included in the system, regardless of ownership. Oglethorpe's rights
and obligations with respect to the system are governed by the ITSA. (See "Power
Sales to and Purchases from GPC--POWER PURCHASE ARRANGEMENTS" herein and
"CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--Agreements
Relating to Integrated Transmission System".)

In addition to the interconnections available to Oglethorpe through the
ITS, Oglethorpe has interconnection, interchange, transmission and/or short-term
capacity and energy purchase or sale agreements with Alabama Electric
Cooperative, Cajun Electric Power Cooperative, Big Rivers, Seminole Electric
Cooperative, Entergy Services (as agent for the Entergy operating companies),
TVA, Florida Power Corporation, Jacksonville Electric Authority, Tampa Electric
Company, Louisville Gas & Electric Company, Florida Power & Light Company, SEPA,
South Carolina Electric & Gas (subject to approval by FERC), South Carolina
Public Service Authority, Arkansas Electric Cooperative Corporation and East
Kentucky Power Cooperative. The agreements provide variously for the purchase
and/or sale of capacity and energy and/or for transmission service.
Implementation of such contracts and other off-system transactions are
accomplished by the CSA (see "Power Sales to and Purchases from GPC--POWER
PURCHASE ARRANGEMENTS" herein).

In addition, Oglethorpe has sold to GPC a portion of its entitlement to the
interface capability between the ITS and the Florida electric system through May
1994. Oglethorpe has purchased from GPC sufficient entitlement to the interface
between the Integrated Transmission System and TVA to implement the purchases
from Big Rivers and EPI. Oglethorpe regularly buys and sells power in the
short-term bulk power market.

FUTURE LONG-TERM POWER SALES

Oglethorpe has signed a Letter of Intent with Alabama Electric Cooperative
for the sale of 100 MW of base capacity beginning June 1, 1998, and extending
through December 31, 2005. This arrangement is subject to the approval of a
definitive agreement by the Boards of Directors of each party. The agreement
would also be subject to approval by REA. No assurances can be given that such
definitive agreement will be consummated. Oglethorpe has also submitted bids to
various formal and informal solicitations for capacity sales. Whether any such
bid will be successful is uncertain.

ENVIRONMENTAL AND OTHER REGULATIONS

GENERAL

As is typical in the utility industry, Oglethorpe is subject to Federal,
State and local air and water quality requirements which, among other things,
regulate emissions of particulates, sulfur dioxide and nitrogen oxide into the
air and discharges of pollutants, including heat, into waters of the United
States. Oglethorpe is also subject to Federal, State and local waste disposal
requirements which regulate the manner of transportation, storage and disposal
of solid and other waste. In general, environmental requirements are becoming
increasingly stringent, and further or new requirements may substantially
increase the cost of electric service by requiring changes in the design or
operation of existing facilities as well as changes or delays in the location,
design, construction or operation of new facilities. Failure to comply with such
requirements could result in the imposition of civil and criminal penalties as
well as the complete shutdown of individual generating units not in compliance.
There is no assurance that the units in operation or under construction will
always remain subject to the regulations currently in effect or will always be
in compliance with future regulations.

Compliance with environmental standards or deadlines will continue to be
reflected in Oglethorpe's capital and operating costs. Oglethorpe's direct
capital costs to achieve compliance with air and water quality control
facilities were approximately $6.5 million in 1993 and are expected to be
approximately $3.1 million in 1994, $4.1 million in 1995 and $8.6 million in
1996.

CLEAN AIR ACT

The Clean Air Act seeks to improve the ambient air quality throughout the
United States by the year 2000 and beyond. The acid rain provisions of Title IV
require the reduction of sulfur dioxide and nitrogen oxide emissions from
affected units, including coal-fired electric power facilities. The sulfur
dioxide reductions required by Title IV will be achieved in two phases. Phase I
addresses specific generating units named in the Clean Air Act. Both units of
Plant Wansley are "affected units" under Phase I. Scherer Units No. 1 and No. 2
are not "affected units" under Phase I but are affected units under Phase II. In
Phase II, the total U.S. emissions of sulfur dioxide will be capped at 8.9
million tons by the year 2000, using a "tradeable allowance" plan. Final Phase
II sulfur dioxide allocations have been published by Environmental Protection
Agency ("EPA") regulations. Compliance with the Clean Air Act will require
expenditures for monitoring, annual permit fees, and in some instances may
involve increased operating or maintenance expenses or capital expenditures for
pollution control and continuous monitoring equipment.

Capital improvements, of which Oglethorpe's share is approximately $6.4
million, are in progress at Plant Wansley. Scheduled to be completed in 1994,
these improvements are designed to bring the plant into compliance with
anticipated requirements for both Phase I and Phase II. Approximately $500,000
in capital improvements, to be completed in 1994, will be made at Plant Scherer.
The estimated cost of additional improvements at Plant Wansley and Plant Scherer
are

dependent upon the chosen compliance plan and may be affected by future plan
amendments and future regulation. In addition, the final capital cost of
improvements and any effect on operating costs will be determined by the
compliance plan as finally implemented and any applicable regulatory changes.

Title I of the Clean Air Act requires the State of Georgia to conduct
specific studies and establish new rules regulating sources of nitrogen oxide
and volatile organic compounds. The new rules must be promulgated by November
1994, with attainment demonstrated by November 1999. Metropolitan Atlanta is
classified as a "serious non-attainment area" with regard to the ozone ambient
air quality standards. Plant Wansley is near although not in this non-attainment
area. The results of these studies and new rules could require nitrogen oxide
controls more stringent than those required for Title IV compliance. The Clean
Air Act also requires that several studies be conducted regarding the health
effects of power plant emissions of certain hazardous air pollutants. The
studies will be used in making decisions on whether additional controls of these
pollutants are necessary. The effect of any of these potential regulatory
changes under Title I, including new rules under the amended provisions, cannot
now be predicted.

The Clean Air Act requires the EPA to review all National Ambient Air
Quality Standards ("NAAQS") periodically, revising such standards as necessary.
EPA continues to evaluate the need for a new short-term standard for sulfur
oxides (measured as sulfur dioxide). Preliminary results from an EPA study
indicate that a new short-term NAAQS for sulfur dioxide might require numerous
power plants to install emission controls, perhaps in addition to any required
under Title IV of the Clean Air Act. These controls could result in substantial
costs to Oglethorpe. EPA is also evaluating the need to revise the NAAQS for
nitrogen dioxide and will be updating the criteria document used in its recent
decision not to revise the NAAQS for ozone. EPA is not currently formally
revising the particulate matter NAAQS but is gathering information which may be
used in a revision. The impact of any change in the ozone, sulfur dioxide,
nitrogen dioxide or particulate matter NAAQS cannot now be determined because
the effect of any change would depend in part on the final ambient standards.

Compliance with requirements under 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 "Power Sales to and Purchases from GPC--POWER PURCHASE
ARRANGEMENTS" herein.)

CLEAN WATER ACT

Oglethorpe is subject to provisions of the Clean Water Act, as amended. As
a result of the 1987 Amendments to the Clean Water Act, the State of Georgia has
amended its State Water Quality Standards to make them more stringent. These
amendments will cause an increase in Oglethorpe's cost to comply. These costs
include capital expenditures for improvements at Plant Scherer to comply with
Georgia's new clean water regulations covering waste water discharge.
Oglethorpe's share of these improvements, completed in early 1994, was
approximately $2 million.

Congress is considering reauthorizing the Clean Water Act. If that occurs,
Oglethorpe's operations could be affected. However, the full impact of any
reauthorization cannot now be determined and will depend on the specific changes
to the statute, as well as to any implementing state or federal regulations that
might be promulgated.

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 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. (See "Proposed Changes to Nuclear Plant Operating
Arrangements" herein.)

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
nuclear fuel. Such Act requires the owner of nuclear facilities to enter into
disposal contracts with 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. (See "Fuel Supply" herein.)

For information concerning nuclear insurance, see Note 9 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

Oglethorpe is subject to other environmental statutes including, but not
limited to, the Toxic Substances Control Act, the Resource Conservation &
Recovery Act, the Endangered Species Act, the Comprehensive Environmental
Response, Compensation and Liability Act, and 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 operations. Changes to any of these laws
could affect many areas of Oglethorpe's operations. Furthermore, compliance with
new environmental legislation could have a significant impact on Oglethorpe.
Such impacts cannot be fully determined at this time, however, and would depend
in part on any such legislation and the development of implementing regulations.

The scientific community, regulatory agencies and the electric utility
industry are examining the issues of global warming and the possible health
effects of electric and magnetic fields. While no definitive scientific
conclusions have been reached regarding these issues, 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.

ENERGY POLICY ACT

The Energy Policy Act creates a new class of utilities called Exempt
Wholesale Generators ("EWGs"), which are exempt from certain restrictions
otherwise imposed by the Public Utility Holding Company Act. The effect of this
exemption is to facilitate the development of independent third-party generators
potentially available to satisfy utilities' needs for increased power supplies.
(See "Future Power Resources--OTHER FUTURE RESOURCES" herein.) Unlike purchases
from qualifying facilities under PURPA (see "Other Power Purchases" herein),
however, utilities have no statutory obligation to purchase power from EWGs.
Furthermore, EWGs are precluded from making direct sales to retail electricity
customers.

The Energy Policy Act also broadens the authority of FERC to require a
utility to transmit power to or on behalf of other participants in the electric
utility industry, including EWGs and qualifying facilities, but FERC is
precluded from requiring a utility to transmit power from another entity
directly to a retail customer.

1819

CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS

CO-OWNERS OF THE PLANTSCo-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, and Oglethorpe owns or leases,
undivided interests in the amounts shown in the following table (which excludes
the Plant Wansley combustion turbine). GPC is the construction and operating agent for each of
these plants, except for Rocky Mountain for which Oglethorpe is the construction and operating
agent. (See "The Plant Agreements" herein.)

NUCLEAR COAL-FIRED PUMPED STORAGE
------------------------------ --------------------------------Nuclear Coal-Fired Pumped Storage
----------------------------- ---------------------------------- --------------
PLANT PLANT PLANT SCHERER UNITS ROCKY
HATCH VOGTLE WANSLEY NO.Plant Plant Plant Scherer Units Rocky
Hatch Vogtle Wansley No. 1 & NO.No. 2 MOUNTAIN(3) TOTAL
------------- ------------- ------------- --------------- ---------------Mountain Total
----------- -------------- -------------- ---------------- -------------- -----
% MW(1) % MW(1) % MW(1) % MW(1) % MW(1) MW(1)
---- ----- ---- ----- ---- ----- ---- ----- --------- ----- ----- ----- ----- ----- -----

Oglethorpe . . .Oglethorpe. 30.0 489 30.0 696 30.0 519 60.0(2) 982 75(4) 636 3,322
GPC. . . . . . .74.61 633 3,319
GPC........ 50.1 817 45.7 1,060 53.5 926 8.4 137 25(4) 212 3,152
MEAG . . . . . .25.39 215 3,155
MEAG....... 17.7 288 22.7 527 15.1 261 30.2 494 -- -- 1,570
Dalton . . . . .Dalton..... 2.2 36 1.6 37 1.4 24 1.4 23 -- -- 120
----- ----- ----- ----- ----- ----- ----- ----- --- --- -----
Total. . . . . .--------------------- ------- ------- ------- ------- ------- ------ ------ ------
Total...... 100.0 1,630 100.0 2,320 100.0 1,730 100.0 1,636 100100.00 848 8,164
----- ----- ----- ----- ----- ----- ----- ----- --- --- -----
----- ----- ----- ----- ----- ----- ----- ----- --- --- -----

- -------------------------
(1) Based on nameplate ratings.

(2) Oglethorpe leases its interest in Scherer Unit No. 2 pursuant to long-term
net leases.

(3) Rocky Mountain is currently under construction and scheduled to be in
commercial operation in early 1995.

(4) Represents Oglethorpe's and GPC's estimated ownership interests upon
completion. (See "The Plant Agreements--ROCKY MOUNTAIN" herein.)===== ===== ===== ===== ===== ===== ===== ===== ====== === =====

GEORGIA POWER COMPANY- ----------

(1) Based on nameplate ratings.

(2) Oglethorpe leases its interest in Scherer Unit No. 2 pursuant to long-term
net leases.

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 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 three municipalities. GPC is the largest supplier of
electric energy in the State of Georgia. (See "OGLETHORPE POWER
CORPORATION--
RelationshipCORPORATION--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 Securities and Exchange Commission (the "Commission").Commission. Copies of this material can be
obtained at prescribed rates from the Commission's Public Reference Section at
450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549. Certain securities of
GPC are listed on the New York Stock Exchange, and reports and other information
concerning GPC can be inspected at the office of such Exchange.

MUNICIPAL ELECTRIC AUTHORITY OF GEORGIAMunicipal 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 (who also markets under the name of MEAG
Power) has entered into power sales contracts with each of 4748 cities and one
county in the State of Georgia. Such political subdivisions, located in 39 of
the State's 159 counties, collectively serve approximately 268,000270,000 electric
customers.

1920

CITY OF DALTON, GEORGIACity 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.

THE PLANT AGREEMENTS

HATCH, WANSLEY, VOGTLE AND SCHERERThe 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, and Vogtle and Scherer, respectively. The
Operating Agreements and Ownership Agreements relating to Plants Hatch and
Wansley are two-party agreements between Oglethorpe and GPC. The other Operating
Agreements and Ownership Agreements are agreements among Oglethorpe, GPC, MEAG
and Dalton. The parties to each Ownership Agreement and each Operating Agreement
are referred to as "Participants" with respect to each such agreement.

In 1985, in four separate transactions, Oglethorpe sold its entire 60%
undivided ownership interest in Scherer Unit No. 2 to four separate owner trusts
established by four different institutional investors. (See Note 4 of Notes to
Financial Statements in Item 8.) 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. (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. 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 subject to, in the case of
Scherer Units No. 1 and No. 2, certain limited rights of the Participants to
disapprove capital budgets proposed by GPC and to substitute alternative capital
budgets.budgets and in the case of Plants Hatch and Vogtle, the right of any co-owner to
disapprove large discretionary capital improvements.

Each Operating Agreement gives GPC, as agent, sole authority and
responsibility for the management, control, maintenance, operation, scheduling
and dispatching of the plant to which it relates. However, as provided in the
recent amendments to the Plant Scherer Ownership and Operating Agreements, Oglethorpe
has elected to dispatchis separately dispatching its ownership share of Scherer Units No. 1 and No. 2.
Similar amendments to the Plant Wansley Operating Agreement have recently been
entered into and Oglethorpe expects to begin dispatching separately its
ownership share in Plant Wansley in 1997. (See "THE POWER SUPPLY SYSTEM--Fuel"GENERATING FACILITIES--Fuel
Supply".) In 1990, the co-owners of Plants Hatch and Vogtle entered into the
NMBANuclear Managing Board Agreement which amended the Plant Hatch and Plant Vogtle
Ownership and Operating agreements, primarily with respect to GPC's reporting
requirements, but did not alter GPC's role as agent with respect to the nuclear
plants. In 1993, the co-owners entered into the Amended and Restated NMBANuclear
Managing Board Agreement (the "Amended and Restated NMBA") which provides for a
managing board (the "Nuclear Managing Board") to coordinate the implementation
and administration of the Plant Hatch and Plant Vogtle Ownership and Operating
Agreements and provides for increased rights for the co-owners regarding certain
decisions and allowed GPC to contract with a

third party for the operation of the nuclear units. In connection with the
recent 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 (the "Plant Scherer 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,
subject to its obligation to sell capacity and energy to GPC as described below.
Except as otherwise provided, each party 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, once Oglethorpe begins separate dispatch there, each party will be
responsible for its fuel costs and for variable Operating Costs in proportion to
the net energy output for its ownership interest, while responsibility for fixed
Operating Costs will continue to be equal to the percentage undivided ownership
interest which is owned or leased in such unit. GPC is required to furnish
budgets for Operating Costs, fuel plans and scheduled maintenance plans subject
to, in the case of Scherer Units No. 1 and No. 2, certain limited rights of the
Participants to disapprove such budgets proposed by GPC and to substitute
alternative budgets. (See "THE POWER SUPPLY SYSTEM--Proposed Changes to Nuclear
Plant Operating Arrangements".)

During the first seven years of Commercial Operation (as defined in the
Operating Agreement for Plant Vogtle) of Plant Vogtle, GPC is entitled to a
declining percentage of Oglethorpe's capacity and energy for all or a portion of
each contract year ending May 31. (See "THE POWER SUPPLY SYSTEM--Power Sales to
and Purchases from GPC--GPC SELL-BACK" and Note 1 of the Financial Statements
in Item 8.) Regardless of the amount of capacity available, GPC is obligated to
pay Oglethorpe monthly for the capacity of each unit to which it is entitled,
if any, an amount derived by a formula set forth in the Operating Agreement
based upon an average of GPC's annual fixed costs and Oglethorpe's annual fixed
costs with respect to each unit. In addition, GPC is responsible for the same
percentage of Oglethorpe's share of the Operating Costs and fuel-related costs
incurred.

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.

TERMS.

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. 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, 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 MOUNTAINProposed Changes to Nuclear Plant Operating Arrangements

In September 1992, GPC filed applications with the Nuclear Regulatory
Commission (the "NRC") to add SONOPCO to the operating license of each unit of
Plants Hatch and Vogtle and designate SONOPCO as the operator. The application
has been recently approved by the Atomic Safety and Licensing Board and became
effective in late March. SONOPCO, a subsidiary of The Southern Company
specializing in nuclear services, currently provides certain operating,
maintenance, and other services to GPC in accordance with the Amended and
Restated NMBA and the agreements referenced in the Amended and Restated NMBA.
The co-owners had previously agreed to a Nuclear Operating Agreement between GPC
and SONOPCO, which became operative on the effective date of the license
amendment.

Rocky Mountain

Oglethorpe's rights and obligations with respect to Rocky Mountain are
contained in several contracts between Oglethorpe and GPC, the co-owners of
Rocky Mountain. Pursuant to Rocky Mountain Pumped Storage Hydroelectric
Ownership Participation Agreement, by and between Oglethorpe and GPC (the
"Ownership Participation Agreement"), on December 15, 1988, Oglethorpe initially acquired a 3%
undivided interest in Rocky Mountain together with a futurewhich interest in
the remaining 97% undivided interest.increased as Oglethorpe
expended funds to complete construction of Rocky Mountain. The final ownership
percentages for Rocky Mountain are Oglethorpe 74.61% and GPC 25.39%. In
connection with this

acquisition, Oglethorpe and GPC also entered into the Rocky Mountain Pumped
Storage Hydroelectric Project Operating Agreement (the "Rocky Mountain Operating
Agreement").

Under the Ownership Participation Agreement, Oglethorpe has responsibility
for financing and completing the construction of Rocky Mountain. As Oglethorpe
expends funds for construction, GPC's ownership interest decreases and
Oglethorpe's ownership interest increases. At all times, each party's undivided
interest in the project is equal to the proportion that its respective
investment bears to the total investment in the project (excluding each party's
cost of funds and ad valorem taxes). Except as described below in respect of the
exercise by GPC of its option to retain a minimum ownership interest, GPC is not
required to expend any funds for construction. GPC's prior investment is
determined in "as-spent" dollars, while Oglethorpe's investment is discounted to
constant 1987 dollars (computed using a semi-annual Handy-Whitman Index).

The Ownership Participation 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 Ownership Participation Agreement provides that Oglethorpe must
use its reasonable best efforts in accordance with Prudent Utility Practices (as
defined therein) to have Rocky Mountain in commercial operation by June 1, 1996. The Rocky Mountain Operating Agreement gives Oglethorpe, as agent,
sole authority and responsibility for the management, control, maintenance and
operation of Rocky Mountain. 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 Ownership Participation Agreement.
GPC
will schedule and dispatch Rocky Mountain on a continuous economic dispatch
basis, on behalf of itself and Oglethorpe and will notify Oglethorpe in advance
of estimated operating levels, until such time as Oglethorpe may electGPC have each elected to schedule separately itstheir respective
ownership interest.interests. The Rocky Mountain Operating Agreement will terminate in
2035.

Oglethorpe completed, in two separate closings on December 31, 1996 and
January 3, 1997, lease transactions for its 74.61% undivided ownership interest
in Rocky Mountain. Under the terms of these transactions, Oglethorpe leased the
facility to three institutional investors for a term of 71 years, who in turn
leased it back to Oglethorpe for a term of 30 years. The transactions are
characterized as a sale and lease-back for income tax purposes, but not for
financial reporting purposes. Oglethorpe will continue to control and operate
the plant during the lease-back term, and it fully intends to repurchase tax
ownership and to retain all other rights of ownership with respect to the plant
at the end of the lease-back period. As a result of these transactions,
Oglethorpe received net proceeds of approximately $96 million which is being
recorded as a deferred credit and will be recognized in income over the term of
the lease-back. Approximately $91 million of the proceeds will be used for the
early retirement of FFB debt, with the remaining $5 million being used to pay
alternative minimum taxes on the fortieth anniversarytransactions. The combination of the Completion
Adjustment Date (as defined therein).

AGREEMENTS RELATING TO THE INTEGRATED TRANSMISSION SYSTEMdebt
prepayment and the amortized gain will result in an estimated $11 million in
annual savings. In connection with these transactions, Oglethorpe is obligated
to maintain liquidity from various sources of approximately $50 million.

ENVIRONMENTAL AND OTHER REGULATIONS

General

As is typical in the utility industry, Oglethorpe is subject to
Federal, State and GPC have enteredlocal air and water quality requirements which, among other
things, regulate emissions of pollutants, such as particulate matter ("PM"),
sulfur oxides and nitrogen oxides ("NOx") into the ITSAair and discharges of other
pollutants, including heat, into waters of the United States. Oglethorpe is also
subject to provide forFederal, State and local waste disposal requirements which regulate
the transmissionmanner of transportation, storage and distributiondisposal of solid and other waste. In
general, environmental requirements are becoming increasingly stringent, and
further or new requirements may substantially increase the cost of electric
energyservice by requiring changes in the design or operation of existing facilities
as well as 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. There is no assurance that the
units in operation will always remain subject to the regulations currently in
effect or will always be in compliance with future regulations.

Compliance with environmental standards or deadlines will continue to
be reflected in Oglethorpe's capital and operating costs. Oglethorpe's direct
capital costs to achieve compliance with environmental requirements are expected
to be an aggregate of approximately $250,000 for 1997, 1998 and 1999.

Clean Air Act

The Clean Air Act seeks to improve air quality throughout the United
States. The acid rain provisions of the Clean Air Act require the reduction of
sulfur dioxide ("SO2") and NOx emissions from affected units, including
coal-fired electric power facilities. The SO2 reductions required by the Clean
Air Act will be achieved in two phases. Phase I addresses specific generating
units named in the Clean Air Act. Both units of Plant Wansley are "affected
units" under Phase I. Scherer Units No. 1 and No. 2 are not "affected units"
under Phase I but are "affected units" under Phase II. Beginning in 1995, Phase
I affected units became subject to the SO2 emission allowance trading program.
Emission allowances are issued by the U.S. Environmental Protection Agency
("EPA"), based on statutory allocations in Phase I and on fossil fuel
consumption for affected units from 1985 through 1987 for Phase II. An
allowance, which gives the holder the authority to emit one ton of SO2 during a
calendar year, is transferable and can be bought, sold or banked for use in the
years following its issuance. Oglethorpe expects to comply with Phase I
requirements through the use of its allowances coupled with switching to lower
sulfur coal, a compliance strategy that has required some equipment upgrades at
Plant Wansley and may result in unused allowances that can be banked for future
use or sold.

For Phase II, which begins in the year 2000, when total U.S. emissions
of SO2 will be capped at 8.9 million tons, Oglethorpe could use a variety of
options for SO2 compliance, including use of emission allowances (allocated,
banked or purchased, if needed), fuel-switching or installation of flue gas
desulfurization equipment. Achieving compliance with Phase II has already
resulted in some equipment upgrades at Scherer Units No. 1 and No. 2.

Although some NOx regulations implementing the requirements of the
Clean Air Act have been finalized for some time, others have recently been
promulgated and there remains the possibility that further regulation of NOx
emissions from utility sources could be imposed. EPA recently issued a final
rule lowering the NOx emission standard for boiler types such as those found at
Scherer Units No. 1 and No. 2. These rules have been challenged, however, and
whether the new NOx emission standards will ultimately be imposed at Plant
Scherer Units No. 1 and

No. 2 is not known. Depending on the form those NOx rules take after the
associated litigation has ended, additional expenditures for pollution control
equipment may be incurred.

In general, compliance with the Clean Air Act will continue to require
expenditures for monitoring and permitting, and in some instances may involve
increased operating or maintenance expenses. Capital expenditures of Oglethorpe
through 1996 for pollution control equipment needed to comply with the Clean Air
Act at Plant Wansley have been approximately $7,200,000 and at Scherer Units No.
1 and No. 2 have been approximately $720,000. Although the estimated cost of any
additional improvements at Plant Wansley and Scherer Units No. 1 and No. 2
remains dependent upon the chosen compliance plan and may be affected by future
plan amendments and/or future regulation, Oglethorpe has budgeted approximately
$250,000 in capital expenditures for Clean Air Act and related projects over the
next three years. In addition, the final capital cost of improvements and any
effect on operating costs will be determined by the compliance plan as finally
implemented and any applicable regulatory changes.

Metropolitan Atlanta is classified as a "serious nonattainment area"
with regard to the ozone ambient air quality standards. The Clean Air Act, under
which these standards are promulgated, requires the State of Georgia other
than in certain counties,to conduct
specific studies and for bulk power transactions, through useestablish new rules regulating sources of NOx and volatile
organic compounds ("VOC"), to achieve attainment of the ITS. The ITS, together with transmission system facilities acquired or
constructedstandards by MEAG and Dalton under agreements with GPC referred to below, was
established in order to obtain the benefits of a coordinated development of the
parties' transmission facilities1999 and to
make it unnecessarymaintain compliance thereafter. These studies could result in new rules for
any party to
construct duplicative facilities. The ITS consists of all transmission
facilities, including land, owned by the parties on the date the ITSA became
effective and those thereafter acquired, which are locatedpower plants in the State, of
Georgiaincluding Plants Wansley and Scherer. Further, along
with 36 other thanstates in the excluded countieseastern half of the U.S., Georgia, as a member of
the Ozone Transport Assessment Group ("OTAG"), is performing extensive
photochemical grid modeling in an effort to reach a consensus among its member
states as to the strategies needed to reduce ozone and its precursors (including
NOx). Large, stationary sources of NOx have been a focus for OTAG. Originally,
each OTAG state was to have new emission reduction strategies in place by late
spring or early summer of 1997. However, EPA has stated its intention to specify
the overall amount of NOx and VOC emission reductions that must be achieved by
each OTAG state.

Plant Wansley is near the non-attainment area while Plant Scherer is
located further away. The results of these studies and new rules could require
NOx controls more stringent than those now required under the acid rain
provisions of the Clean Air Act for compliance. Portions of Subchapter I of the
Clean Air Act also require that several studies be conducted regarding the
health effects of power plant emissions of certain hazardous air pollutants. The
studies will be used in making decisions on whether additional controls of these
pollutants are necessary. The effect of any of these potential regulatory
changes under the Clean Air Act, including new rules under the amended
provisions, can not now be predicted.

The Clean Air Act also requires EPA to review all National Ambient Air
Quality Standards ("NAAQS") periodically, revising such standards as necessary.
Last year, EPA decided not to impose a new short-term standard for sulfur oxides
(measured as SO2). That decision has been appealed, however, so that it is still
possible that a new SO2 standard could be promulgated. If a new short-term NAAQS
for SO2 were imposed, it might require new emission controls at Plants Wansley
and Scherer, which could result in substantial costs to Oglethorpe.

EPA has also proposed to revise the NAAQS for both ozone and PM. Either
of these proposals, if finalized, could have a substantial effect on the types
of controls that might be needed at Plants Wansley or Scherer for compliance.
However, the final impacts (and any associated expenditures) at either plant can
not now be predicted with any certainty. In fact, the impact of any change in
these NAAQS can not now be determined, because the effect of any change would
depend in part on the final ambient standards developed.

Although Oglethorpe's management is currently unable to determine the
overall effect that compliance with requirements under the Clean Air Act will
have on its operations, it does not believe that any required increases in
capital or operating expenses would have a material effect on its results of
operations or its financial condition. Compliance with the requirements under
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 from GPC" in Item 1.)

Clean Water Act

For some time now, Congress has been considering reauthorization of the
Clean Water Act. If that occurs, Oglethorpe's operations could be affected.
However, the full impact of any reauthorization cannot now be determined and
will depend on the specific changes to the statute, as well as to any
implementing state or federal regulations that might be promulgated.

At the state level, EPA is under Federal court order to begin
development of Total Maximum Daily Loads ("TMDLs") for all of Georgia's stream
segments that do not yet meet established water quality standards. The order
calls for a strict schedule for the development of such TMDLs, beginning in the
summer of 1997. Oglethorpe cannot now predict what impact, if any, such
development will have on the operations of Plants Wansley, Scherer, Hatch or
Vogtle, because the effect will depend on the final TMDLs to be developed and
EPA's (and the state's) approach for revising National Pollutant Discharge
Elimination System permits to achieve the desired TMDLs and ultimately achieve
the required water quality standards.

Georgia Hazardous Site Response Act ("GHSRA")

GHSRA requires the compilation and listing of an inventory of all known
or suspected sites where "regulated substances" have been disposed of or
released in quantities deemed reportable by the state. In developing this list,
which includes hundreds of sites, one site co-owned by Oglethorpe was listed.
The site is located at Plant Wansley and consists of an ash pond. As the
operating agent of the plant, GPC will conduct the required remedial
investigation in late 1997 or early 1998, to determine if any clean-up
activities are usedrequired. At this time, it is uncertain whether any remediation
will be required and what the timing of any required remediation might be. If
remediation is required, Oglethorpe could incur up to an estimated $800,000 in
clean-up costs and $6 million in capital costs, associated with the
redevelopment of the ash pond. Additional sites may require investigation and
remediation expenses, a portion or usableall of which Oglethorpe may be liable for. At
this time, Oglethorpe does not believe that any capital or operating costs
associated with GHSRA clean-ups would have a material effect on its results of
operations or its financial condition.

Nuclear Regulation

Oglethorpe is subject to transmit powerthe provisions of the Atomic Energy Act of
1954, as amended (the "Atomic Energy Act"), which vests jurisdiction in the 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 certain minimum voltage and to transform power of a certain
minimum voltage and a certain minimum capacity (the "Transmission Facilities").
GPC has entered into agreements with MEAG and Dalton that are substantially
similar to the ITSA, and GPC may enter into such agreements with other entities.
The ITSA will remain in effect through December 31, 2012 and, if not then
terminated by five years' prior written notice by either party, will continue
until so terminated.

The ITSA is administered by a Joint Committee established by a Joint
Committee Agreement, summarized below. Each year, the Joint Committee determines
a four-year plan of additions to the Transmission Facilities that will reflect
the current and anticipated future transmission requirements of the parties.
Oglethorpe and GPC are each required to maintain an original cost investment in
the Transmission Facilities in proportion to their respective Peak Loads (as
defined in the ITSA).

Oglethorpe and GPC are parties to a Transmission Facilities Operation and
Maintenance Contract (the "Transmission Operation Contract"), under which GPC
provides System Operator Services (as defined in the Transmission Operation
Contract) for Oglethorpe. In addition, GPC is required to provide such
supervision, operation and maintenance supplies, spare parts, equipment and
labor for the operation, maintenance and construction as may be specified by
Oglethorpe. GPC is also required to perform certain emergency workfacility licensed under the Transmission Operation Contract. Oglethorpe is permitted, upon notice to GPC, to
perform, or contract with others for the performance of, certain services
performed by GPC. Absent termination or amendment of the Transmission Operation
Contract, however, GPC will continue to perform System Operator Services for
Oglethorpe. The term of the Transmission Operation Contract will continue from
year to year unless terminated by either party upon four years' notice.
Oglethorpe is required to pay its proportionate share of the cost for the
services provided by GPC.

THE JOINT COMMITTEE AGREEMENT

Oglethorpe, GPC, MEAG and Dalton are parties to a Joint Committee
Agreement. In the past, the Joint Committee coordinated the implementation and
administration of the various Ownership Agreements and Operating

Agreements, the various integrated transmission system agreements, and the
various integrated transmission system operation and maintenance agreements
among the parties. However, the Nuclear Managing Board has assumed such
responsibilities forAtomic
Energy Act. Plants Hatch and Vogtle the Plant Scherer Managing Board
has assumed such responsibilities for Plant Scherer and, if agreedare being operated under licenses issued by
the co-owners, an operating committee would also assume such responsibilities forNRC. 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. (See
"CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--The Plant
Wansley. (See "TheAgreements--Proposed Changes to Nuclear Plant Agreements--HATCH, WANSLEY, VOGTLE AND SCHERER"
herein.Operating Arrangements".)

The Joint Committee Agreement also makes allowancePursuant to the Nuclear Waste Policy Act of 1982, as amended, the
Federal government has the regulatory responsibility for the joint
planningfinal disposition
of futurecommercially produced high-level radioactive waste materials, including

spent nuclear fuel. Such Act requires the owner of nuclear facilities to enter
into disposal contracts with 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. (See "GENERATING
FACILITIES--Fuel Supply".)

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

In 1993, EPA issued a ruling confirming the non-hazardous status of
coal ash. That ruling may apply, however, only to situations where those wastes
are not co-managed, i.e. not mixed with other wastes. Pursuant to court order,
EPA has until 1998 to classify co-managed utility wastes as either hazardous or
non-hazardous. If the wastes are classified as hazardous, substantial additional
costs for the management of such wastes might be required, although the full
impact would depend on the subsequent development of requirements pertaining to
these wastes.

Oglethorpe is subject to other environmental statutes including, but
not limited to, the Toxic Substances Control Act ("TSCA"), the Resource
Conservation & Recovery Act ("RCRA"), the Endangered Species Act ("ESA"), the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
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 operations.
Changes to any of these laws, however, could affect many areas of Oglethorpe's
operations. Congress is considering amending the ESA and reauthorizing CERCLA,
TSCA and perhaps RCRA. 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
health effects of electromagnetic fields. While no definitive scientific
conclusions have been reached regarding these issues, 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 alleging damages from electromagnetic fields.

Energy Policy Act

The Energy Policy Act allows for increased competition among wholesale
electric suppliers and increased access to transmission and generation facilities.

ITEM 2. PROPERTIES

Information with respectservices by such
suppliers. It created a new class of utilities called Exempt Wholesale
Generators ("EWGs"), which are exempt from certain restrictions otherwise
imposed by the Public Utility Holding Company Act. The effect of this exemption
is to Oglethorpe's properties is set forthfacilitate the development of independent third-party generators
potentially available to satisfy utilities' needs for increased power supplies.
Unlike purchases from qualifying facilities under the
caption "THEPURPA (see "MEMBER
REQUIREMENTS AND POWER SUPPLY SYSTEM" includedRESOURCES--Power Purchase and Sales
Arrangements--Other Power Purchases" in Item 1), utilities have no statutory
obligation to purchase power from EWGs. Furthermore, EWGs are precluded from
making direct sales to retail electricity customers.

The Energy Policy Act also broadened the authority of FERC to require a
utility to transmit power to or on behalf of other participants in the electric
utility industry, including EWGs and qualifying facilities, but FERC is
precluded from requiring a utility to transmit power from another entity
directly to a retail customer. In 1996,

FERC issued two final rules (Orders 888 and 889) and a notice of proposed
rulemaking regarding capacity reservation tariffs that would make significant
changes in the form of transmission services performed by public utilities
subject to FERC's jurisdiction. See "OGLETHORPE POWER CORPORATION--Relationship
with GTC" in Item 1 and is incorporated herein
by reference.

ITEMfor information regarding GTC's transmission tariff.

Item 3. LEGAL PROCEEDINGS

Oglethorpe is a party to various actions and proceedings incident 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.

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

Not applicable.

2429

PART II

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

Not Applicable.applicable.

ITEM 6. SELECTED FINANCIAL DATA

- -----------------------------------------------------------------------------

(dollars in thousands)

1996 1995 1994 1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------------------------------------------------
- -

OPERATING REVENUES:Operating revenues:
Sales to Members . . . . . . . . . . . . . . . ...................... $ 1,023,094 $ 1,030,797 $ 930,875 $ 899,720 $ 816,000
$ 763,657 $ 710,607 $ 631,966
Sales to non-Members . . . . . . . . . . . . . .................. 78,343 118,764 125,207 200,940 268,763
300,293 390,535 367,183
----------- ----------- ----------- ----------- ----------------------- ------------ ------------ ------------ ------------
Total operating revenues . . . . . . . . . . . .............. 1,101,437 1,149,561 1,056,082 1,100,660 1,084,763
1,063,950 1,101,142 999,149
----------- ----------- ----------- ----------- -----------
OPERATING EXPENSES:------------ ------------ ------------ ------------ ------------
Operating expenses:
Fuel . . . . . . . . . . . . . . . . . . . . . .................................. 206,524 219,062 203,444 176,342 167,288
165,168 209,971 180,698
Production . . . . . . . . . . . . . . . . . . ............................... 129,178 133,858 132,723 129,972 115,915
130,041 125,506 97,266
Purchased power. . . . . . . . . . . . . . . . .power ......................... 229,089 264,844 227,477 271,970 230,510
229,898 213,311 202,778
Depreciation and
amortization. . . . . . . . . .amortization ............................ 163,130 139,024 131,056 128,060 126,047
135,152 134,021 123,614
Taxes. . . . . . . . . . . . . . . . . . . . . .Taxes ................................... 30,262 27,561 24,741 25,148 19,634 42,422 41,798 31,541
Other operating expenses . . . . . . . . . . . ................. 60,505 56,535 49,234 44,876 50,578
49,373 41,755 33,301
----------- ----------- ----------- ----------- ----------------------- ------------ ------------ ------------ ------------
Total operating expenses . . . . . . . . . . . ................. 818,688 840,884 768,675 776,368 709,972
752,054 766,362 669,198
----------- ----------- ----------- ----------- -----------

OPERATING MARGIN. . . . . . . . . . . . . . . . .------------ ------------ ------------ ------------ ------------
Operating margin ........................ 282,749 308,677 287,407 324,292 374,791
311,896 334,780 329,951
OTHER INCOME, NET . . . . . . . . . . . . . . . .Other income, net ....................... 65,334 33,710 40,795 38,741 45,928
113,441 94,471 70,297
NET INTEREST CHARGES. . . . . . . . . . . . . . .Net interest charges .................... (326,331) (320,129) (305,120) (350,652) (393,247)
(396,892) (400,712) (379,820)
----------- ----------- ----------- ----------- -----------
MARGIN BEFORE CUMULATIVE EFFECT
OF CHANGE IN ACCOUNTING
PRINCIPLE. . . . . . . . . . . . . . . . . . . .Margin before cumulative effect of change
in accounting principle ............. 21,752 22,258 23,082 12,381 27,472
28,445 28,539 20,428
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING FOR INCOME TAXES. . . . . . . . . . .Cumulative effect of change in accounting
for income taxes .................... -- -- -- 13,340 - - - -
----------- ----------- ----------- ----------- -----------
NET MARGIN. . . . . . . . . . . . . . . . . . . .--
------------ ------------ ------------ ------------ ------------
Net margin .............................. $ 21,752 $ 22,258 $ 23,082 $ 25,721 $ 27,472
$ 28,445 $ 28,539 $ 20,428
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

ELECTRIC PLANT, NET:============ ============ ============ ============ ============
Electric plant, net:
In service . . . . . . . . . . . . . . . . . . ............................ $ 4,345,200 $ 4,436,009 $ 3,980,439 $ 4,054,956 $ 4,122,411
$ 4,196,966 $ 4,268,440 $ 4,275,770
Construction work in progress. . . . . . . . . .progress ........... 31,181 35,753 538,789 450,965 322,628
178,980 102,045 103,729
----------- ----------- ----------- ----------- ----------------------- ------------ ------------ ------------ ------------
$ 4,376,381 $ 4,471,762 $ 4,519,228 $ 4,505,921 $ 4,445,039
============ ============ ============ ============ ============
Total assets ............................ $ 4,375,9465,362,175 $ 4,370,4855,438,496 $ 4,379,499
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

TOTAL ASSETS. . . . . . . . . . . . . . . . . . .5,346,330 $ 5,323,890 $ 5,359,597
$ 5,246,435 $ 5,200,762 $ 5,288,673
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

CAPITALIZATION:============ ============ ============ ============ ============
Capitalization:
Long-term debt . . . . . . . . . . . . . . . . ........................ $ 4,052,470 $ 4,207,320 $ 4,128,080 $ 4,058,251 $ 4,095,796
$ 4,093,218 $ 4,094,246 $ 4,112,892
Obligation under capital leases. . . . . . . . .leases ......... 293,682 296,478 303,749 303,458 302,061
300,833 299,783 298,929Other obligations .................... 41,685 -- -- -- --
Patronage capital and membership fees. . . . . .fees 356,229 338,891 309,496 289,982 264,261
236,789 217,895 194,233
----------- ----------- ----------- ----------- ----------------------- ------------ ------------ ------------ ------------
$ 4,744,066 $ 4,842,689 $ 4,741,325 $ 4,651,691 $ 4,662,118
============ ============ ============ ============ ============
Property additions ...................... $ 4,630,84093,704 $ 4,611,924138,921 $ 4,606,054
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

PROPERTY ADDITIONS. . . . . . . . . . . . . . . .206,345 $ 235,285 $ 232,283
$ 225,021 $ 200,257 $ 226,709
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

ENERGY SUPPLY (MEGAWATT-HOURS)============ ============ ============ ============ ============
Energy supply (megawatt-hours):
Generated. . . . . . . . . . . . . . . . . . . .Generated ............................ 17,866,143 18,402,839 16,924,038 14,575,920 13,805,683
12,686,323 13,387,572 12,079,706
Purchased. . . . . . . . . . . . . . . . . . . .Purchased ............................... 6,606,931 5,738,634 4,381,087 7,620,815 6,233,262
6,915,758 6,198,434 5,664,919
----------- ----------- ----------- ----------- ----------------------- ------------ ------------ ------------ ------------
Available for sale . . . . . . . . . . . . . . ....................... 24,473,074 24,141,473 21,305,125 22,196,735 20,038,945
19,602,081 19,586,006 17,744,625
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

MEMBER REVENUE PER============ ============ ============ ============ ============
Member revenue per kWh SOLD . . . . . . . . . . . 5.47 cents 5.55 cents 5.36 cents 5.01 cents 4.84 cents

CERTAIN PRIOR YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH CURRENT YEAR
PRESENTATION.sold ............. 5.11(cent) 5.53(cent) 5.65(cent) 5.47(cent) 5.55(cent)
============ ============ ============ ============ ============

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

GENERAL

MARGINS AND PATRONAGE CAPITALCorporate Restructuring

Oglethorpe and the Members completed a corporate restructuring (the
Corporate Restructuring) on March 11, 1997 (the Closing) pursuant to terms and
conditions set forth in the Second Amended and Restated Restructuring Agreement
(the Restructuring Agreement). Pursuant to the Corporate Restructuring,
Oglethorpe divided itself into three specialized operating companies to respond
to increasing competition and regulatory changes in the electric industry. As
part of the Corporate Restructuring, the transmission business is now owned and
operated by a newly formed Georgia electric membership corporation, Georgia
Transmission Corporation (An Electric Membership Corporation) (GTC), and the
system operations business is now owned and operated by a newly formed Georgia
nonprofit corporation, Georgia System Operations Corporation (GSOC). Oglethorpe
continues to own and operate the power supply business.

On October 1, 1996, Oglethorpe transferred to GSOC its system operations
assets, consisting of its system control center and related energy control and
revenue metering systems equipment. The purchase price of these assets totaled
approximately $9.4 million and was funded by GSOC's assumption of Oglethorpe's
obligations under an existing note held by the Rural Utilities Service (RUS), by
delivery of a purchase money note payable to Oglethorpe and by the assumption of
certain other liabilities of Oglethorpe. Since October 1, 1996, Oglethorpe has
been the sole member of GSOC. The Members and GTC became members of GSOC on the
Closing. GSOC will operate the system control center and provide system
operations services to the Members, Oglethorpe and GTC.

At the Closing, Oglethorpe transferred its transmission business and assets
to GTC. The purchase price for the transmission business was based on an
appraisal of the fair market value of such business, as determined by an
independent appraiser, and was approximately $708 million. The purchase price
was paid primarily by GTC's assumption of a portion (approximately 16.86%) of
Oglethorpe's long-term secured debt in an amount equal to approximately $686
million. Approximately $541 million of this debt (payable to RUS, Federal
Financing Bank (FFB) and CoBank, ACB (CoBank)) became the sole obligation of
GTC, and Oglethorpe was released from all liability with regard to this
indebtedness. The remaining debt assumed by GTC in connection with the Corporate
Restructuring, approximately $145 million, relates to Oglethorpe's pollution
control revenue bonds (PCBs). While GTC assumed and agreed to pay this $145
million of debt, Oglethorpe is not legally released from its liability for this
debt. The remainder of the purchase price was paid by GTC from cash obtained
through a borrowing from National Rural Utilities Cooperative Finance
Corporation (CFC) and the assumption of approximately $1 million of other
Oglethorpe liabilities. Oglethorpe also made a special patronage capital
distribution of approximately $49 million to the Members which was used by the
Members to establish equity in and to provide initial working capital to GTC.
Oglethorpe and the 39 Members are members of GTC. GTC now owns and operates the
transmission system and provides transmission services to the Members and
Oglethorpe. GTC has succeeded to all of Oglethorpe's rights and obligations with
respect to the Integrated Transmission System (ITS).

Oglethorpe continues to operate the power supply business. Oglethorpe
retained all of its owned and leased generation assets and has total assets of
approximately $4.7 billion and total long-term debt of approximately $3.9
billion. Oglethorpe also continues to administer its power purchase contracts
and provide marketing support functions to the Members.

In connection with the Corporate Restructuring, Oglethorpe, GTC, GSOC and
the Members entered into a Member Agreement (Member Agreement) which specifies
the form of the new wholesale power contracts (New Wholesale Power Contracts),
transmission agreements (Transmission Agreements) and system operations
contracts to be signed by the Members. The New Wholesale Power Contracts provide
that the Members are responsible, on a joint and several basis, for all of
Oglethorpe's obligations relating to its existing generation business. The
Transmission Agreements provide that the Members are responsible, on a joint and
several basis, for all of GTC's obligations with respect to its transmission
business.

Pursuant to the Member Agreement, in connection with the Closing, Oglethorpe
and each of the Members entered into New Wholesale Power Contracts which extend
through December 31, 2025. Under the New Wholesale Power Contracts, each Member
is assigned an agreed-upon fixed percentage capacity responsibility (PCR) for
all of Oglethorpe's existing resources. PCR responsibility for any future
resource will be assigned only to Members choosing to participate in that
resource. The New Wholesale Power Contracts permit each Member to take future
incremental power requirements either from Oglethorpe or other sources. Under
the New Wholesale Power Contracts, a Member is unconditionally obligated on an
express "take-or-pay" basis for a fixed allocation of Oglethorpe's costs for its

existing resources, as well as the costs with respect to any future resources in
which such Member elects to participate. The New Wholesale Power Contracts
specifically provide that the Member must make payments whether or not power is
delivered and whether or not a plant has been sold. Oglethorpe is obligated to
use its reasonable best efforts to operate, maintain and manage its resources in
accordance with prudent utility practices. The New Wholesale Power Contracts
provide that Oglethorpe will be responsible for power supply planning, resource
procurement and sales of capacity and energy for a Member unless the Member
notifies Oglethorpe that it does not want Oglethorpe to provide these services.

The New Wholesale Power Contracts provide that each Member will be jointly
and severally responsible for all costs and expenses of all existing resources
and any future resources (whether or not such Member has elected to participate
in such future resource) that have been 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 of a defaulting Member 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.

In connection with the implementation of new power marketer arrangements
with LG&E Power Marketing Inc. ("LPM"), Oglethorpe and each Member have entered
into supplemental agreements to the New Wholesale Power Contracts which relate
to certain provisions of the New Wholesale Power Contracts and apply during the
term of the power marketer arrangements. The supplemental agreements clarify the
application of the New Wholesale Power Contract rate schedule to the power
marketer agreements. The 75% requirement described above has been met with
respect to the LPM agreements. The supplemental agreement assures that all costs
incurred by Oglethorpe under the LPM agreement are recoverable under the New
Wholesale Power Contracts. As the expected additional power marketer
arrangements are finalized, additional supplemental agreements to the New
Wholesale Power Contracts will be entered into by Oglethorpe and the Members.
See "Results of Operations-Factors Affecting Future Financial Performance" for a
description of the power supply arrangements.

The rate set forth in the New Wholesale Power Contracts is intended to
recover all costs and expenses paid or incurred by Oglethorpe. The rate
expressly includes in the description of costs to be recovered all principal and
interest on indebtedness of Oglethorpe and all costs associated with
decommissioning or otherwise retiring any generating facility. The rate further
expressly provides for Oglethorpe to earn sufficient margins to satisfy the
requirements of the Master Indenture (defined below). The New Wholesale Power
Contracts contain covenants by the Member (i) to establish, maintain and collect
rates and charges for the service of its electric system and (ii) to conduct its
business in a manner that will produce revenues and receipts at least sufficient
to enable the Member to pay to Oglethorpe, when due, all amounts payable by the
Member under the New Wholesale Power Contracts and to pay any and all other
amounts payable from, or which might constitute a charge and a lien upon, the
revenues and receipts derived from its 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.

The New Wholesale Power Contracts provide that a Member will not dissolve,
liquidate or otherwise wind up its affairs without Oglethorpe's approval. The
Member will not 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 of its assets to any person,
whether in a single transaction or series of transactions, unless either (i) the
transaction is approved by Oglethorpe or (ii) other specified conditions are
satisfied including, but not limited to, an assumption agreement by the
transferee, satisfactory to Oglethorpe, containing an assumption by the
transferee of the performance and observance of every covenant and condition of
the Member under the New Wholesale Power Contract, and certifications of
accountants as to certain specified financial requirements of the transferee
(taking into account the transfer).

Effective with the Corporate Restructuring, Oglethorpe amended its Bylaws to
implement a new governance structure with an 11-member board of directors
consisting of six directors elected from the Members, four independent outside
directors and Oglethorpe's President and Chief Executive Officer. This smaller
board replaced Oglethorpe's former 39-member board comprised of directors
nominated from and by each Member. The new directors will be nominated by
representatives from each Member on a weighted-voting method, based on the
number of retail customers served by such Member. However, each director will
continue to be elected by a vote of the Member representatives on a one-Member,
one-vote basis. Except for two of the four outside directors, all of
Oglethorpe's new directors have been elected and began their terms at the
Closing. The remaining two outside directors are expected to be elected on March
27, 1997.

Contemporaneously with the Corporate Restructuring, Oglethorpe replaced its
existing Consolidated Mortgage and Security Agreement, dated as of September 1,
1994, by and among Oglethorpe, as Mortgagor, the United States of

America, acting through the Administrator of the RUS and certain other
mortgagees (the RUS Mortgage) with the Indenture, dated as of March 1, 1997,
from Oglethorpe to SunTrust Bank, Atlanta, as trustee, (the Master Indenture)
providing for a lien on substantially all of the owned tangible and certain
intangible property of Oglethorpe. See "Rates and Financial Coverage
Requirements" below for a further description of the Master Indenture.

In conjunction with the Corporate Restructuring and as a part of its
continuing efforts to reduce costs, effective February 1, 1997, Oglethorpe
implemented a business alliance with Intellisource, Inc., a national provider of
outsourcing services. Pursuant to an agreement with Intellisource, approximately
150 support services division employees in the areas of accounting, auditing,
communications, human resources, facility management, purchasing,
telecommunications and information technology became employees of the
Intellisource organization. Oglethorpe, GTC and GSOC are key customers of
Intellisource and are being served on-site by the managers and employees of
Oglethorpe's former support services division.

Margins and Patronage Capital

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 in Oglethorpe's statements of revenues and expenses and patronage
capital as net margin. Retained net margins are designated on Oglethorpe's
balance sheets as patronage capital, which is allocated to each of its 39 retail
electric distribution cooperatives (Members)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 of $356 million in patronage capital as of December 31, 1993, had a
balance of $290 million in patronage capital.1996.

Oglethorpe's equity ratio (patronage capital and membership fees divided by
total capitalization) increased from 7.0% at December 31, 1995 to 7.5% at
December 31, 1996.

Patronage capital constitutes the principal equity of Oglethorpe. As a
means of accumulating additional equity,Under
Oglethorpe's Board of Directors amended
in 1992 the patronage capital retirement policy, for returning margins are to be returned to
the Members to extend the retirement schedule from 13 years to 30 years after the year in which the margins were generated.are earned. Pursuant to
such policy, no patronage capital would be retired until 2010, at which time the
1979 patronage capital would be returned. Any distributions of patronage capital
are subject to the discretion of the Board of Directors and approval byDirectors. See "Corporate
Restructuring" above regarding a special patronage capital distribution made in
connection with the Rural Electrification
Administration (REA).

Oglethorpe's equity ratio (patronageCorporate Restructuring.

Now that the Master Indenture has been substituted for the prior RUS
Mortgage, distributions of patronage capital and membership fees divided by
total capitalization) increased from 5.7% at December 31, 1992 to 6.2% at
December 31, 1993.

RATES AND FINANCIAL COVERAGE REQUIREMENTS

Oglethorpe's policy is to design its rates to generate sufficient revenues
to recover its Member cost of service and produce net margins at such levels as
Oglethorpe's Board of Directors determines to be consistent with sound financial
practice. Rate revisions by Oglethorpe are no longer subject to the
approval of RUS, but are subject to certain restrictions set forth in the REAMaster
Indenture. Under the Master Indenture, Oglethorpe is prohibited from making any
distribution of patronage capital to the Members if, at the time thereof or
after giving effect thereto, (i) an event of default exists under the Master
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 of 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 Financial Coverage Requirements

Pursuant to date, the REA has not reduced or delayed the effectiveness of any rate
increase proposed by Oglethorpe.New Wholesale Power Contract, Oglethorpe has entered into a wholesale power
contract with each of its Membersis required to
design capacity and energy rates that requires rates to be designedgenerate sufficient revenues to recover
all costs as described in such contracts. Oglethorpe's rates include an energy
charge that is set annuallycontracts, to establish and adjusted at mid-yearmaintain reasonable
margins and to recover actual fuel and
variable operations and maintenance costs.meet its financial coverage requirements. Oglethorpe reviews its
capacity rates at least annually to ensure that its fixed costs are being
adequately recovered and, if necessary, adjusts its rates to meet its net margin
goals. Oglethorpe's energy rate is established to recover actual fuel and
variable operations and maintenance costs. Under the terms of Oglethorpe's prior
RUS Mortgage, rate revisions by Oglethorpe utilizeswere subject to the approval of RUS.
Under the Master Indenture, Oglethorpe's rates are not subject to RUS approval
except in limited circumstances.

The capacity rate applied by Oglethorpe in 1994 utilized a proportional
allocation of fixed costs based on the previous year's billing demand for each
Member. Consequently, the 1994 rate produced capacity revenues which were
virtually unaffected by current year factors. In 1995, Oglethorpe implemented
two additional capacity rate options in an effort to provide greater flexibility
to the Members. These options allocated fixed costs using billing determinants
of the current year. These rates produced differing monthly amounts of capacity
revenues throughout the year and introduced some variability and uncertainty as
to the level of revenues and margins to be received. Due to extreme weather
conditions and other factors, the 1995 rates options produced $2.5 million of
revenues in excess of budgeted amounts. Such excess amounts were returned to the
Members in 1996.

Under a capacity rate mechanism effective throughout 1996, each Member was
responsible for

an assigned share of fixed costs based on an agreed-upon allocation. Under this
approach, capacity costs were collected in equal monthly amounts. This interim
rate mechanism has now been extended through March 31, 1997. A new rate schedule
will become effective under the New Wholesale Power Contracts on April 1, 1997.
This new rate schedule implements on a long-term basis the assignment 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. 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 are based on actual energy costs. However, under the supplemental
agreements for the LPM agreements, each Member pays a fixed rate for energy,
plus certain adjustments, while LPM pays all energy costs, within certain risk
bands. The new rate schedule also includes a prior period adjustment (PPA)
mechanism. The PPA serves to facilitate the achievement of the minimum 1.10 MFI
ratio, and it provides for the retention of margins within a range from a 1.10
MFI ratio to a 1.20 MFI ratio. Amounts, if any, by which Oglethorpe fails to
achieve a minimum 1.10 MFI ratio would be accrued as of December 31 of the
applicable year and collected during the period April through December of the
following year. Amounts, if any, earned by Oglethorpe in excess of a 1.20 MFI
ratio would be charged against revenues as of December 31 of the applicable year
and refunded during the period April through December of the following year.

Under the prior RUS Mortgage, Oglethorpe utilized a Times Interest Earned
Ratio (TIER) as the basis for establishing its annual net margin goal. TIER is
determined by dividing the sum of Oglethorpe's net margin plus interest on
long-term debt (including interest charged to construction) by Oglethorpe's
interest on long-term debt (including interest charged to construction). The REARUS
Mortgage requiresrequired Oglethorpe to implement rates that are designed to maintain an
annual TIER of not less than 1.05. Oglethorpe's Board of Directors set an annual
net margin goal to be the amount required to produce a TIER of 1.07 in 1994
through 1996.

In addition to the TIER requirement under the REARUS Mortgage, Oglethorpe iswas
also required under the REARUS Mortgage to implement rates designed to maintain a
Debt Service Coverage Ratio (DSC) of not less than 1.0 and an Annual Debt
Service Coverage Ratio (ADSCR) of not less than 1.25. DSC is determined by
dividing the sum of Oglethorpe's net margin plus interest on long-term debt
(including interest charged to construction) plus depreciation and amortization
(excluding amortization of nuclear fuel and debt discount and expense) by
Oglethorpe's interest and principal payable on long-term debt (including
interest charged to construction). ADSCR is determined by dividing the sum of
Oglethorpe's net margin plus interest on long-term debt (excluding interest
charged to construction) plus depreciation and amortization (excluding
amortization of nuclear fuel and debt discount and expense) by Oglethorpe's
interest and principal payable on long-term debt secured under the REARUS Mortgage
(excluding interest charged to construction).

Oglethorpe has always met or exceeded the TIER, DSC and ADSCR requirements of
the REARUS Mortgage. TIER, DSC and ADSCR for the years 19911994 through 19931996 were as
follows:

- -----------------------------------------------------------------------------
1993 1992 1991
- -----------------------------------------------------------------------------

TIER 1.07 1.07 1.07
DSC 1.23 1.22 1.28
ADSCR 1.26 1.25 1.31
- -----------------------------------------------------------------------------
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
TIER 1.07 1.07 1.07
DSC 1.25 1.21 1.19
ADSCR 1.32 1.27 1.25
- --------------------------------------------------------------------------------

Under the Master Indenture, Oglethorpe is required to establish and collect
rates which are reasonably expected, together with other revenues of Oglethorpe,
to yield a Margins for Interest (MFI) for each fiscal year equal to at least
1.10 times total interest charges during such fiscal year on all indebtedness
secured under the Master Indenture (or by a lien equal or prior to the lien of
the Master Indenture), excluding indebtedness assumed by GTC. MFI is determined
by adding (i) Oglethorpe's net margins (after certain defined adjustments), (ii)
interest charges on indebtedness secured under the Master Indenture (or by lien
equal to or prior to the lien of the Master Indenture), and (iii) any amount
included in net margins for accruals for federal or state income taxes. The
definition of MFI 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 or if
Oglethorpe has made a payment with respect to such losses or expenditures.

The MFI ratio requirement went into effect upon the substitution of the
Master Indenture for the prior RUS Mortgage. For comparative purposes only, the
pro-forma MFI ratio for 1996 would have been 1.09.

Miscellaneous

Currently, Oglethorpe is subject to the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation". Oglethorpe has recorded regulatory assets and liabilities related
to its generation and transmission operations. In 1992, as partthe event that Oglethorpe is
no longer subject to the provisions of Statement No. 71, Oglethorpe would be
required to write off related regulatory assets and liabilities. In addition,
Oglethorpe would be required to determine any impairment of other assets,
including utility plant, and

write down the plant assets, if impaired, to their fair value. See Note 1 of
Notes to Financial Statements for additional information.

The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry regarding
the recognition, measurement and classification of decommissioning costs for
nuclear generating facilities in financial statements of electric utilities. In
response to these questions, the Financial Accounting Standards Board has issued
an Exposure Draft of a planproposed Statement on "Accounting for Certain Liabilities
Related to build additional equity, Oglethorpe's BoardClosure or Removal of Directors revised its annual net margin goal to beLong-Lived Assets". The proposed Statement
would require the amount required to
produce a TIER of 1.07 in each year through 1995, 1.08 in 1996, 1.09 in 1997 and
1.10 in 1998 and thereafter. Historically, by setting rates to meet the TIER
goals established by Oglethorpe's Board, the DSC and ADSCR requirementsrecognition of the REA Mortgage have always been met or exceeded. Based on Oglethorpe's currententire obligation for decommissioning at
its present value as a liability in the financial projections, however, rates based on these levelsstatements. Rate-regulated
utilities would also recognize an offsetting asset for differences in the timing
of TIER may not be
sufficient to meet the ADSCR requirementrecognition of the REA Mortgage. Incosts of decommissioning for financial reporting and
rate-making purposes. Oglethorpe's management does not believe that event,
rates sufficient to meet the ADSCR requirementsthis
proposed Statement would have an adverse effect on results of operations due to
be established.

HISTORICAL FACTORS AFFECTING FINANCIAL PERFORMANCEits current and future ability to recover decommissioning costs through rates.

Beginning in years 2014 through 2029, it is expected that Plant Hatch and
Vogtle units will begin the decommissioning process. The expected timing of
payments for decommissioning costs will extend for a period of 9 to 14 years.
Oglethorpe's management does not expect such payments to have an adverse impact
on liquidity or capital resources due to available amounts which have been set
aside in reserves for this purpose.

RESULTS OF OPERATIONS

Historical Factors Affecting Financial Performance

Over the past severalthree years, the most significant factor affecting
Oglethorpe's financial performance has been the mechanisms Oglethorpe has
utilized to moderate the financial impact of new generating plants. During this
period, Oglethorpe's Members have absorbed much ofinto rates
additional responsibility for the cost of its ownership interests in Plant
Vogtle and Scherer Units No. 1 and No. 2. 26

The mechanisms used byThese generating units were placed in commercial
operation in 1987 and 1989, respectively. Oglethorpe to mitigate the rate impact of absorbing
these costs have includedhas utilized both long-term
contractual arrangements with Georgia
Power Company (GPC)GPC and Board of Directors policies that have resulted in thea rate mechanism to allow for a gradual
absorption of costs over several years. In addition, Oglethorpe utilized this
rate mechanism to mitigate the impact of absorbing the costs of the Rocky
Mountain Pumped Storage Hydroelectric Project (Rocky Mountain) which was placed
in service during June and July 1995.

Contractual arrangements with GPC provideprovided that Oglethorpe sell to GPC and
GPC purchase from Oglethorpe a
declining percentage of Oglethorpe's entitlement to the capacity and energy of
certain co-owned generating plants during the initial seven to ten years of
operation of such units (GPC Sell-back). The GPC Sell-back will
expire for Plant Vogtle Unit No. 1 asAs of May 31, 1994, and for Plant Vogtle
Unit No. 2 as of May 31, 1995. The1995, the GPC Sell-back
has expired for Scherer Unit No. 1 expired
in May 1991 and for Scherer Unit No. 2, in May 1993. (See Note 1 of Notes to
Financial Statements.)all units. The historical ability of Oglethorpe to sell power
from new units to GPC under the GPC Sell-back has enabled Oglethorpe to moderate the
effects of the higher costs associated with new generating units on Oglethorpe's
cost of service and, therefore, on the rates charged to Members. Furthermore,
the GPC Sell-back has enabled Oglethorpe to obtain the generating capacity needed to
serve anticipated increases in Member loads while minimizing the risks and costs
of excess generating capacity.

Prior to the completion of the first unit of Plant Vogtle in 1987,
Oglethorpe's Board of Directors implemented policies that have resulted in the
gradual absorption of the costs of Plant Vogtle by the Members. In each of the
years 1985 through 1993,1995, Oglethorpe exceeded its net margin goal. The Board
adopted resolutions in each of these years requiring that these excess margins
be deferredretained and used to mitigate rate increases associated with Plant Vogtle.Vogtle
and, subsequently, with Rocky Mountain. In each year beginning with 1989, a
portion of these margins has beenwas returned to the Members through billing credits.
(See Note 1 of Notes to Financial Statements.) Furthermore, during 1986 and 1987, Oglethorpe's rates to its Members
included a one mill per kilowatt-hour (kWh) charge (Vogtle Surcharge). The
Vogtle Surcharge represented a pre-collection of charges prior to commercial
operation of Plant Vogtle the effect of which was to mitigate future rate
increases. In addition, two of the Members elected to increase the level of this
charge for their systems during this period.

As of December 31, 1993, Oglethorpe held a balance of approximately $48
million from deferred margins1996, all
amounts previously retained have been returned to the Members and the voluntary Vogtle Surcharges to two Members
which will be utilized for futurethis rate
mitigation. Oglethorpe's Board of
Directors and the two Members intend to utilize these amounts as offsets to
rates charged during 1994 and 1995. By the end of 1995, all costs associated
with Plant Vogtle will be included in Member rates.

RESULTS OF OPERATIONS

OPERATING REVENUESmechanism ended.

Operating Revenues

Oglethorpe's operating revenues are derived from sales of electric services
to the Members and non-Members. Revenues from Members are collected pursuant to
the
wholesale power contracts and are a function of the demand for power by the
Members' consumers and Oglethorpe's cost of service. Historically, most of
Oglethorpe's non-Member revenues have resulted from various plant operating
agreements with GPC as discussed below. However, in recent years, an increasing
amount of non-Member revenues has been derived by off-system sales to other
utilities and power marketers.

For the period 19911994 through 1993,1996, although total revenues have remained virtually unchanged,varied
slightly, the scheduled reduction of the GPC Sell-back has resulted in the
planned decrease of non-
Membernon-Member revenues from GPC of almost $130about $45 million. As
expected, the capacity and energy no longer being sold to GPC have been used by
Oglethorpe to meet increased Member requirements. In addition to increasing
sales to Members, Oglethorpe has increased revenues from energy salesachieved reductions in fixed and transmission sales to
other utilitiesoperating costs in
order to mitigate the need to recover from the Members costs which were
previously recovered through sales to GPC. SALES TO MEMBERS.The refinancing transactions
discussed under "Financial Condition-Refinancing Transactions" below have
resulted in a reduction in gross interest charges from $330 million in 1994 to
$308 million in 1996, or a 7% decrease in that fixed cost component of the
capacity rates.

As a means of further reducing the cost of power provided to the Members,
Oglethorpe utilized short-term power supply arrangements during 1996. The

initial agreement was with Enron Power Marketing, Inc. (EPMI) and was in place
January through August. From September through December 1996, another power
supply arrangement was utilized with Duke/Louis Dreyfus L.L.C. (DLD). Under both
of the agreements, the power marketer was required to provide to Oglethorpe at a
favorable fixed rate all the energy needed to meet the Members' requirements and
Oglethorpe was required to provide to the power marketer at cost, subject to
certain limitations, upon request, all energy available from Oglethorpe's total
power resources. Under both agreements, Oglethorpe continued to operate the
power supply system and continued to dispatch the generating resources to ensure
system reliability.

Sales to Members. Revenues from sales to Members increased 10.3%decreased by 0.7% in 19931996
compared to 1992,1995 and increased 6.9%10.7% in 19921995 compared to 1991.1994. These increaseschanges
reflect two factors: first, higher capacity rates, offset byboth cost-related and volume-related factors. The 1996 revenues
decreased compared to 1995 due to the fact that the pass-through of savings in
energy costs (see the discussion of savings in purchased power under "Operating
Expenses" herein) more than offset higher capacity revenue requirements and the
effect of increased amounts of energy sold. The increase in revenues between
1995 and 1994 was due to the fact that higher capacity revenue requirements and
additional amounts of energy sold more than offset savings in energy costs (see
the discussion of savings in fuel and purchased power costs under "OPERATING EXPENSES""Operating
Expenses" herein); and second, increased amounts of energy sold.
Concerning the first factor, as.

As non-Member revenues from GPC have declined, Oglethorpe hasOglethorpe's Member capacity
revenues have increased rates to Members to recoverreflect the recovery of the fixed costs which had
previously been recovered from GPC through the GPC Sell-back. Since December 28,
1990, Oglethorpe has placed into effect four rate changes, as set forth below:

- -----------------------------------------------------------------------------

EFFECTIVE DATE RATE CHANGE (1)
- -----------------------------------------------------------------------------

January 1, 1994 -4.5%
January 1, 1993 1.7%
December 27, 1991 8.8%
December 28, 1990 4.8%

(1) After credit for deferred margins. (See Note 1 of Notes to Financial
Statements.)
- -----------------------------------------------------------------------------

Oglethorpe was able(See the
discussion of this type of revenues under "Sales to implement a rate reduction for 1994 because the
anticipatednon-Members" herein.) Member
capacity revenues in 1996 and 1995 were also affected by additional revenues to be derived based on the increase in the
Members' 1993 peak demand more than offset the reduction in revenues from the
GPC Sell-back.

Oglethorpe's wholesale ratefixed costs
related to the Members sets forth the mannercommercial operation of Rocky Mountain beginning in whichJune 1995.

Member energy revenues per kilowatt-hour (kWh) declined 13.2% in 1996
compared to 1995 and declined 7.6% in 1995 compared to 1994. The decrease in
1996 resulted from savings of approximately $32 million in energy costs
are(compared to be recovered. Oglethorpe's rate provides that actualbudget) achieved under the power supply arrangements. In 1995, the
decrease reflected savings in fuel and production costs and lower average
purchased power costs. Actual energy costs beare passed through to the Members
such that energy revenues equal energy costs.

The following table summarizes the amounts of kilowatt-hourskWh sold to Members during each of
the past three years:

- -----------------------------------------------------------------------------
KILOWATT-HOURS
(in thousands)
- -----------------------------------------------------------------------------

1993 16,253,283
1992 14,466,943
1991 14,022,213
- -----------------------------------------------------------------------------

- --------------------------------------------------------------------------------
Kilowatt-hours
(in thousands)
- --------------------------------------------------------------------------------
1996 19,807,101
1995 18,442,153
1994 16,285,127
- --------------------------------------------------------------------------------

Member sales have been significantly affected by abnormal weather conditions
during two of the past three years. In 1995 prolonged hot weather boosted sales,
while in 1994 record-breaking rainfall amounts statewide moderated Member sales.
Member sales increased 7.4% in 1996 despite a summer in which temperatures were
lower than 1995, due to continued growth in the Member systems' service
territories.

The net impact of the above capacity and energy rate factors, combined with
the spreading of fixed capacity costs over an increasing number of kWh sold each
year, have resulted in the following decreasing trend in average Member revenues:

- -----------------------------------------------------------------------------
CENTS/KILOWATT-HOUR
- -----------------------------------------------------------------------------

1993 5.47 cents
1992 5.55
1991 5.36
- -----------------------------------------------------------------------------

Oglethorpe is reducing the needrevenue
requirements:

- --------------------------------------------------------------------------------
Cents per Kilowatt-hour
- --------------------------------------------------------------------------------
1996 5.11(cent)
1995 5.53
1994 5.65
- --------------------------------------------------------------------------------

Sales to recover from Members the additional
costs resulting from reductions to the GPC Sell-back by increasing revenues from
off-system sales and reducing fixed and operating costs.

In addition to the impact of reductions in GPC Sell-back revenues, future
Member rates will also be affected by such factors as fixed costs relating to
the Rocky Mountain Project, a pumped storage hydroelectric facility (Rocky
Mountain), the cost of adding to Oglethorpe's existing transmission system,
changes in fuel costs, environmental and other governmental regulations
applicable to Oglethorpe and its suppliers and the completion in 1995 of the
amortization of deferred margins. Oglethorpe's future rates will also be
affected by its ability to forecast accurately its future power resource needs
and by its ability to obtain and manage its power resources, including its
purchases and construction of generating capacity and its procurement of coal.

SALES TO NON-MEMBERS.non-Members. Sales of electric services to non-Members are primarily
made pursuant to three different types of contractual arrangements with GPC and
from off-system sales to other non-Member utilities.

The following table summarizes the amounts of non-Member revenues from these
sources for the past three years:

- -------------------------------------------------------------------------------
1993 1992 1991
(DOLLARS IN THOUSANDS)
- -------------------------------------------------------------------------------

Plant operating agreements $106,146 $171,686 $235,851
Power supply arrangements 44,904 61,602 45,662
Transmission agreements 13,549 29,586 17,203
Other utilities 36,341 5,889 1,577
------- ------- -------
Total $200,940 $268,763 $300,293
------- ------- -------
------- ------- -------
- -------------------------------------------------------------------------------

- --------------------------------------------------------------------------------
1996 1995 1994
(dollars in thousands)
- --------------------------------------------------------------------------------
GPC-plant operating agreements $ -- $ 10,096 $ 45,392
GPC-power supply arrangements 13,703 43,226 26,280
ITS transmission agreements 9,789 12,614 10,974
Sales to power marketers 15,895 -- --
Sales to other utilities 38,956 52,828 42,561
------- -------- --------
Total $78,343 $118,764 $125,207
======= ======== ========
- --------------------------------------------------------------------------------

Revenues from sales to non-Members declined in 19931996 compared to 1992,1995 and in
19921995 compared to 1991. These decreases1994. The first two types of non-Member revenues were primarily attributable to
scheduled reductions inderived
from contractual agreements with GPC. First, the elimination of the revenues
from the plant operating agreement revenues attributableagreements was due to the scheduled conclusion,
effective June 1, 1995, of the GPC Sell-back with respect to Plants Vogtle and Scherer.Plant Vogtle.

The second source of non-Member revenues is

power supply arrangements with GPC. These revenues are derived, for the most
part, from energy sales arising from dispatch situations whereby GPC causes
co-owned coal-fired generating resources to be operated when Oglethorpe's system
does not require all or part
of its contractual entitlement to the generation. These
revenues essentially represent reimbursement of costs to Oglethorpe because,
under the operating agreements, Oglethorpe is responsible for its share of fuel
costs any time a unit operates. The greater amountRevenues from sales of such revenuesthis type to GPC were
lower in 19921996 compared to 19931995 and 1991 was largely attributablewere higher in 1995 compared to GPC's operational decisions causing a higher
level1994. In
1996, the power marketers elected to retain more of generation atthe output from Plant
Wansley, whereas, in 1995, Oglethorpe retained less of its share of the output
from Plant Wansley units because the added cost associated with emission
allowances made those units less attractive than certain purchased resources.
The 1994 revenues reflect the fact that Oglethorpe retained much of its share of
the output from the Plant Scherer and Plant Wansley units because the lower
average fuel costs made those units more attractive than certain purchased
resources. Emission allowances for Plant Wansley were not required in 1992.1994. See
the discussion under "Operating Expenses" herein of the lower average fuel costs
of the coal-fired generating units in 1996 and 1995. Pursuant to the amendments
to the Plant Scherer ownership and operating agreements, Oglethorpe elected to
separately dispatch its ownership interest in Plant Scherer beginning May 1,
1994. Thereafter, Plant Scherer ceased to be a source of this type of sales
transaction. Pursuant to similar amendments to the Plant Wansley operating
agreement, Oglethorpe expects to begin separately dispatching its ownership
interest in Plant Wansley this year.

The third source of non-Member revenues is primarily payments from GPC for
use of the Integrated Transmission System (ITS)ITS and related transmission interfaces. GPC compensates Oglethorpe
to the extent that Oglethorpe's percentage of investment in the ITS exceeds its
percentage use of the system. In such case, Oglethorpe is entitled to
income as compensation for the use of its investment by the other ITS participants. In addition, beginningThe
change in 1991, GPC purchased the right to use
the majorityrevenues for 1996 through 1994 resulted from normal variations of
Oglethorpe's shareinvestment percentages and its use of the interface capability betweensystem.

Under the ITSEPMI and the Florida electric system through May 1994.

The higher amount of transmission agreement revenues in 1992 compared to
1993 and 1991 was partially attributableDLD power supply agreements, sales to the receiptpower marketers
represented the net energy transmitted off-system on behalf of EPMI and DLD on a
daily basis from Oglethorpe's total resources. Such energy was sold to EPMI and
DLD at Oglethorpe's cost, subject to certain limitations. Sales to other
non-Member utilities were initiated by EPMI and DLD in 1996 while in 1995 and
1994 these sales were made by Oglethorpe directly with the non-Member utilities.
While Oglethorpe maintains the contractual relationship with these other
utilities and administers the transactions, all profits in 1992 of
a payment of $10.5 million from GPC as a result of adjustments of transmission
income for the years 1990 through 1992.

Other revenues from non-Members increased significantly in 1993 compared to
1992 and 1991. This increase reflects greater revenues from off-system energy
sales. Oglethorpe is continuing to seek to make off-system1996 on these sales
to non-Members.

OPERATING EXPENSESother utilities from Oglethorpe's total resources accrued to EPMI and DLD.
See "Factors Affecting Future Financial Performance" herein regarding
Oglethorpe's new long-term power supply arrangements.

Operating Expenses

Oglethorpe's operating expenses decreased 2.6% in 1996 compared to 1995 and
increased 9.4% in 19931995 compared to 1992 and
decreased 5.6%1994. The decrease in 1992operating expenses in
1996 compared to 1991.1995 was primarily attributable to energy cost savings achieved
under the short-term power supply arrangements offset somewhat by an increase in
depreciation and amortization. The increase in operating expenses in 19931995
compared to 19921994 was primarily attributable to higher productiona 13% increase in kWhs sold to
Members and non-Members. In addition, depreciation and amortization, sales, and
administrative and general expenses purchased power expenses and taxes other than income taxes.were also higher.

The decrease in operating expensestotal fuel costs in 19921996 as compared to 1991 was primarily due1995 resulted partly
from unplanned outages at Plant Scherer and Plant Wansley Unit No. 1 and partly
from the power marketer electing to declinesdispatch the fossil units less. These
factors resulted in production expenses, depreciation and amortization, taxes other than income
taxes and income taxes.

Generally, over the years 1991 through 1993, the Members have received the
benefit of declining average3.1% lower fossil generation in 1996 compared to 1995. The
increase in total fuel costs in 1995 versus 1994 resulted from 23% higher
generation at Plant Scherer. The continued use of Oglethorpe's generating resources
through the pass-throughlower-priced western coal
combined with a greater reliance on a favorable spot market for coal resulted in
a per unit fuel cost decrease for Plant Scherer of lower energy costs. The average fuel costs of
Oglethorpe's nuclear and fossil generating resources for the last three years
are as follows:

- -------------------------------------------------------------------------------
CENTS/KILOWATT-HOUR
-------------------
NUCLEAR FOSSIL
- -------------------------------------------------------------------------------

1991 .80 cents 2.08 cents
1992 .66 2.04
1993 .61 1.96
- -------------------------------------------------------------------------------

Much5% in 1995 from 1994 levels.
Because of the reductiondecline in average fuel costs was attributable to
Oglethorpe's nuclear units. Fuel savings were particularly significantcost per kWh at Plant Vogtle where average fuel costs declined by 29%Scherer, the usage of the
units increased significantly. Oglethorpe retained significantly less of its
output from Plant Wansley in 19931995 compared to 1991. The
decline was1994 primarily due to the lower cost of replacement fuel relative to the
cost of the initial core loading of fuel. These initial fuel supplies were
purchased well in advance of commercial operation of these units

and carried a significantly higher amount of capitalized interest than
subsequent fuel reloads. Additionally, as a result of
purchases of nuclear fuel
in the spot market, Oglethorpe'srelatively higher costs for nuclear fuel in the last three years
have been favorably impacted.

The lower amount of production expenses in 1992 compared to 1993Plant Scherer due to its emission allowance
requirement and 1991
was attributabledue to a reduced number of nuclear refueling outagescost reductions at Plant Scherer discussed above.

Purchased power cost decreased by 14% in 1992. Two
of Oglethorpe's nuclear units underwent planned outages in 1992, as1996 compared to three units1995 and increased
by 16% in both 19931995 compared to 1994. Lower purchased power costs were achieved in
1996 despite the fact that energy purchases increased 15% in 1996 from 1995
levels. The 1996 cost reduction was due to (1) energy cost savings of $32
million realized from the short-term power supply arrangements and 1991.

The increase in 1993(2)
reductions in purchased power expenses wascapacity costs due to (a) proceeds of $10.8
million from the resultsettlement of a 22%
increase in kWh purchases. This increase was, forlawsuit with GPC and (b) savings resulting from
the most part, necessitated by
the greater energy needselimination of a 250 MW Component Block (coal-fired units) of the MembersBlock
Power Sale Agreement (BPSA) effective September 1, 1996. In 1995, the 13% higher
kWh sales, including the increased Member sales and sales to GPC pursuant to
power supply arrangements (see "OPERATING REVENUES - SALES TO
MEMBERS"the discussion under "Operating Revenues" herein)

resulted in higher utilization of purchased power resources. Energy purchases
increased 31% in 1995 compared to 1994.

Purchased power expense for 1994 through 1996 reflect the cost of capacity
and by Oglethorpe's increased off-system energy sales (see
"OPERATING REVENUES - SALES TO NON-MEMBERS" herein).

The declinepurchases under various long-term power purchase agreements. These
long-term agreements have, in some cases, take-or-pay minimum energy
requirements. For 1994 through 1996, Oglethorpe utilized its energy from these
purchase power delivery expenses from 1991 through 1993 was due to
the lengthening of maintenance cycles, particularly on substation equipment, and
to delaysagreements in 1993 by GPC, Oglethorpe's primary transmission maintenance
contractor, in performing authorized work. Additionally, in 1991 Oglethorpe
incurred a transmission charge of $3.8 million resulting from a greater
percentage useexcess of the ITS comparedtake-or-pay requirements.
Oglethorpe's power purchases from these agreements amounted to its projected percentage of investment.
(This amount was subsequently returned to Oglethorpeapproximately
$196 million in 1992. See1996, $207 million in 1995 and $183 million in 1994. For a
discussion of transmission income adjustment in 1992 under "OPERATING REVENUES - SALES TO NON-
MEMBERS" herein.)the power purchase agreements, see Note 9 of Notes to Financial
Statements.

The increase in sales, administrative and general expense in 1992 compared
to 1991 was primarily attributable to increases in property insurance for
co-owned plants, expanded marketing programs, and the expenses associated with
one-time payments made to separated employees and to the utilization of
consultants in a workforce reduction undertaken in 1992.

Decreases in depreciation and amortization income taxes and taxes other
than income taxes also contributed to the decrease in total operating expenses
in 1992 compared to 1991. These lower expense categories also directly
contributed to the substantial amount of margins earned in excess of the 1992
TIER-based goal. (See the discussion below under "OTHER INCOME" concerning the
disposition of this excess.)

As a result of depreciation studies undertaken by GPC as operating agent in
the fall of 1991, Oglethorpe implemented lower depreciation rates for all
co-owned generating units. The lower rates are primarily1996 is partly due to a
plant life
extension program undertaken by GPC for the co-owned units.

Property taxes,full year of depreciation on Rocky Mountain which constitute the majoritybegan commercial operation in
June 1995 and due to $14 million of taxes other than income
taxes, decreased in 1992 as a resultBoard- approved accelerated amortization of
deferred charges of the favorable resolutiondiscontinued Pickens County pumped storage hydroelectric
project. All remaining unamortized charges related to this project were expensed
in 1996.

Sales, administrative and general expenses increased in 1995 as compared to
1994 primarily resulting from increased marketing efforts in support of Oglethorpe's
property tax appeal with the
State of Georgia for the years 1985 through 1988.
The negotiated settlement of this appeal resultedMembers.

Other Income/Expense

Interest income increased in a reduction of 1992
property tax expense1996 compared to 1995 and 1995 compared to
1994. In 1996, interest income was higher due to higher average investment
balances. In 1995, interest income increased partly due to higher short-term
interest rates and due to higher investment returns in the amountdecommissioning trust
fund.

In 1996, Oglethorpe utilized all remaining amounts available ($32 million)
under its deferred margin rate mechanism, and, as scheduled, this mechanism
ended. Likewise, deferred margins of approximately $7.5 million.

Income taxes were substantially lower in 1992 compared to 1991 due to
several factors, including lower interest income, less gain in 1992 than in 1991
from the sale of debt service reserve fund securities (see "OTHER INCOME" below)
and increased energy sales to GPC and other utilities. These sales to GPC were $16 million higherand $18 million were amortized
as credits against Member revenue requirements in 1992,1995 and sales1994, respectively,
to other utilities were $3 million higher.
(See "OPERATING REVENUES - SALES TO NON-MEMBERS" herein.) Oglethorpe deducts
both fixedmitigate the rate impact of increased capacity costs related to Plant Vogtle
and variable costs from the revenues from these energy sales which
generated tax losses resultingRocky Mountain. Also, in lower taxable income from non-Member sales.

OTHER INCOME

Interest income decreased in 19931995 and in 1992, as a result of lower average
interest rates on investments. In 1992 and 1991, Oglethorpe realized the capital
appreciation on securities invested for its debt service reserve funds by
selling investments bearing coupon yields which were higher than prevailing
market rates. The securities sold in 1991 had been held for a number of years
and their average rates were substantially higher than market rates at the time
of the sale. The 1992 gain captured only the capital appreciation resulting
from declining interest rates during the 12 months following the 1991 sale.

In 1993, 1992 and 1991,1994, Oglethorpe's Board of Directors
authorized the retention of approximately $5 million, $40$14 million and $12$9 million,
respectively, in excess of the 1.07 TIER margin requirement as deferred margins.
The remaining amounts will be available in 1994 and 1995 to mitigate rate
increases. Amortization of deferred margins
for 1993 was set by Oglethorpe's
Board of Directors at $4 million, significantly less thanunder the amounts utilized
in 1992 and 1991.mechanism. (See Note 1 of Notes to Financial Statements for a
discussion of deferred margins and amortization of deferred margins.) INTEREST CHARGESThe
decrease in amortization of deferred gains in 1996 and 1995 as compared to 1994
resulted from the completion of amortization in September 1994 of a gain on the
sale of Plant Scherer common facilities. (Also see Note 1 of Notes of Financial
Statements for a discussion of the sale.)

Interest Charges

Net interest charges declinedincreased in 19931996 compared to 1992,1995 and in 19921995 compared
to 1991.1994. The decrease in interest on long-term debt and capital leases
in 1993 wasincreases were due for the most part, to the refinancing efforts discussed under
"LIQUITY AND CAPITAL RESOURCES" herein. Allowancefact that the allowances for debt and
equity funds used during construction (AFUDC) increaseddecreased in 19931996 compared to 1995
and in 19921995 compared to 1994 as a result of increased construction activity atthe three units of Rocky Mountain.Mountain
becoming commercially operable in June and July 1995. The continued decrease in
gross interest on long-term debt and capital leases in 1996 and 1995 was due to
the refinancing efforts discussed under "Financial Condition(Refinancing
Transactions" below. The change in other interest expense in 19931995 compared to
1994 was primarily due to higher interest expenseinvestment returns in 1992
associatedthe decommissioning trust fund.
(See Note 1 of Notes to Financial Statements for explanation of Oglethorpe's
accounting for decommissioning gains and losses.)

Factors Affecting Future Financial Performance

Effective January 1, 1997, Oglethorpe entered into power supply agreements
with the settlementLPM for 50% of the property tax appeal and the federal income
tax case. Additionally, Oglethorpe paid a premium in 1992 in connection with
its repricing of Federal Financing Bank (FFB) advances at reduced rates. In
order to modify the FFB advances, Oglethorpe paid a premium equal to
approximately one year's interest on these repriced advances.

LIQUIDITY AND CAPITAL RESOURCES

In the past, Oglethorpe, like most other G&Ts, has obtained the majority of
its long-term financing from REA-guaranteed loans funded by the FFB. Oglethorpe
has

also obtained a substantial portion of its long-term financingload requirements from
tax-exempt pollution control bonds (PCBs).

In addition, Oglethorpe's operations have consistently provided a sizable
contribution to the financing of construction programs, such that internally
generated funds have provided interim funding or long-term capital for nuclear
fuel reloads, new generation, transmission and general plant facilities, and
replacements and additions to existing facilities.

Oglethorpe's investment in electric plant, net of depreciation, was
approximately $4.5 billion as of December 31, 1993. Expenditures for property
additions during 1993 amounted to approximately $235 million, of which $198
million was provided from operations. These expenditures were primarily for the
construction of Rocky Mountain and replacements and additions to generation and
transmission facilities.

As part of its ongoing capital planning, Oglethorpe forecasts expenditures
required for generation and transmission facilities and related capital
projects. Actual construction costs may vary from the estimates 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 Federal and other regulatory
approvals, construction delays, and cost of capital, equipment, material and
labor. The table below indicates Oglethorpe's estimated capital expenditures
through 1996, including AFUDC:

- -------------------------------------------------------------------------------
CAPITAL EXPENDITURES
(DOLLARS IN THOUSANDS)

Year Generation(1) Transmission Rocky Mtn.(2) General Total
- -------------------------------------------------------------------------------

1994 $ 84,982 $ 60,966 $118,055 $20,384(3) $284,387
1995 85,389 52,319 61,493 5,015 204,216
1996 90,231 53,285 882 3,239 147,637
-------- -------- -------- ------- --------
Total $260,602 $166,570 $180,430 $28,638 $636,240
-------- -------- -------- ------- --------
-------- -------- -------- ------- --------

(1) CONSISTS OF CAPITAL EXPENDITURES REQUIRED FOR REPLACEMENTS AND ADDITIONS
TO FACILITIES IN SERVICE, COMPLIANCE WITH ENVIRONMENTAL REGULATIONS, NUCLEAR
FUEL RELOADS AND THE PURCHASE OF RAILCARS.
(2) INCLUDES RELATED TRANSMISSION FACILITIES AND ADDITIONS, RENEWALS AND
REPLACEMENTS TO ROCKY MOUNTAIN AFTER ITS IN-SERVICE DATE.
(3) CONSISTS PRIMARILY OF DEVELOPMENT COSTS RELATED TO AN ENERGY CONTROL
SYSTEM.

- -------------------------------------------------------------------------------

Based on its current construction budget, Oglethorpe anticipates that it
will fund all capital expenditures through 1996, other than for Rocky Mountain,
from operations.

In 1988, Oglethorpe acquired from GPC an undivided ownership interest in
Rocky Mountain and assumed responsibility for its construction and operation.
As of December 31, 1993, Rocky Mountain was approximately 90% complete and
Oglethorpe's investment in the project was $414 million. Oglethorpe is
financing its share of Rocky Mountain from the proceeds of an REA-guaranteed
loan funded through the FFB. As of December 31, 1993, $248 million had been
advanced under this loan and $459 million remained available to be drawn as
permanent financing for Rocky Mountain. Oglethorpe intends to finance all
direct expenditures and capitalized interest associated with the construction of
Rocky Mountain through such FFB loan, and management believes the amounts
remaining to be drawn under such loan are more than adequate to complete the
project. The obligation to advance funds under this loan, however, is subject
to certain conditions, including the requirement that Oglethorpe maintain an
annual TIER of at least 1.0 and that the REA shall not have determined that
there has occurred any material adverse change in the assets, liabilities,
operations or financial condition of Oglethorpe or any circumstances involving
the nature or operation of the business of Oglethorpe. In management's opinion,
no such material adverse change has occurred. The current schedule anticipates
commercial operation in early 1995.

Oglethorpe has a commercial paper program under which it may issue
commercial paper notMembers. Under the agreements,
LPM is obligated to exceed $355 million outstanding at any one time. The
commercial paper may be used as a source of short-term fundsdeliver, and is not
designated for any specific purpose. Oglethorpe's commercial paper is backed
100% by a committed line of credit provided by a group of banks for which Trust
Company Bank acts as agent. Historically, Oglethorpe has not relied on
commercial paper for short-term funding due to the availability of internally
generated funds and has never utilized the backup line of credit. Oglethorpe
has also arranged one committed and two uncommitted lines of credit to provide
additional sources of short-term financing. As of December 31, 1993,
Oglethorpe's short-term credit facilities were as follows:

- --------------------------------------------------------------------------------
SHORT-TERM CREDIT FACILITIES AUTHORIZED
AMOUNT
- --------------------------------------------------------------------------------

Commercial Paper . . . . . . . . . . . . . . . . . . . . . $355,000,000
National Bank for Cooperatives (CoBank). . . . . . . . . . 70,000,000
National Rural Utilities Cooperative
Finance Corporation (CFC). . . . . . . . . . . . . . . . 50,000,000
Trust Company Bank (Committed) . . . . . . . . . . . . . . 30,000,000
- --------------------------------------------------------------------------------

The maximum amount that can be outstanding at any one time under the
commercial paper program and the lines of credit totals $425 million due to
certain restrictions contained in the CFC and Trust Company Bank line of credit
agreements. As of December 31, 1993, no commercial paper was outstanding and
there was no outstanding balance on any line of credit.

As part of a March 1993 PCB refinancing transaction involving two forward
interest rate swap agreements, Oglethorpe is obligated to maintain minimum
liquidity in an amount equal to 25%take, 50% of the
principal amountload requirements of the variable rate
refunding bonds issuedparticipating Members less the load requirements for
certain customer choice loads (900 kilowatt or to be issued in connection therewith. This minimum
liquidity requirement currently equals $81 million and will decrease
proportionately as such variable rate refunding bonds are retired. The minimum
liquidity must consist of (a) any combination of (i) amounts available under
committed lines of credit and commercial paper programs to pay termination
payments, if any, due upon early terminationgreater), plus 50% of the
forward interest rate swap
transactions, (ii) cash, (iii) United States government securities,delivery obligations under Oglethorpe's existing firm power off-system sale
contracts. For customer choice loads of three megawatts or less, LPM is
obligated to deliver if Oglethorpe requests 50% of the associated load
requirements. Oglethorpe is obligated to sell and (iv)
accounts receivable due within 30 days, less (b) monetary

obligations due within 30 days. AsLPM is obligated to buy, 50%
of December 31, 1993,the output of each participating Member's PCR share of the "must run" units
(primarily nuclear units). Oglethorpe had
approximately $467 millionis also obligated to make available the
same share of such liquidity available to meet this requirement.

Oglethorpe's scheduled maturities of long-term debt overall other resources, which LPM may schedule. LPM does not have the
next five
years total $425 million. Of this amount, $299 million, or seventy percent,
relatesright to the repaymentoutput of REAupgrades to these resources. LPM must pay Oglethorpe the
cost of fuel associated with the energy taken. There is a price adjustment if
the plant performance does not meet specified levels of availability and FFB debt.

REFINANCING TRANSACTIONS

Over the past few years,output.
Oglethorpe must pay LPM a contractually specified price for each MWh purchased.
Oglethorpe has implementedthe option of purchasing the energy requirements for customer
choice loads from another supplier.

Oglethorpe will cause GTC to provide available transmission to deliver to
the border of the ITS any energy sold to LPM. Each Member will use its
Transmission Agreement for delivery of energy purchased from LPM and others.

2002. LPM has the right to terminate the contract for any year beginning with
2005. The LPM agreement relating to the other two Members has a term extending
through the end of 1999.

Oglethorpe is now working to finalize a power supply agreement with Morgan
Stanley Capital Group (Morgan Stanley) that would supply the remaining 50% of
the Members' load requirements. The contract is expected to have a term of up to
eight years. Each Member is currently deciding individually whether to have
Oglethorpe obtain its interest costs by refinancing or prepaying a sizableremaining load requirements from Morgan Stanley. Any
Member that elects not to participate in the Morgan Stanley agreement would have
other options available, including having Oglethorpe manage this portion of the
Member's load requirements. In the interim, Oglethorpe is supplying this portion
of its high-
interest PCBrequirements from its own resources and FFB debt. Several transactions were completedby off-system purchase and sales.
In the event Oglethorpe does not enter into power marketer agreements for the
remainder of its load, it can continue to operate effectively in 1993this manner.

In order to complete the implementation of power marketer arrangements,
Oglethorpe and early
1994, covering approximately $1.3 billion in existing PCB and FFB debt (See Note
5each Member will enter into supplemental agreements to the New
Wholesale Power Contracts to implement the terms of Notes to Financial Statements.)each power marketing
arrangement under the New Wholesale Power Contracts.

The net result of the 1993 transactions was
to reduce the average interest rate on total long-term debt from 8.18% at
December 31, 1992 to 7.94% at December 31, 1993. The average interest rate was
further reduced to 7.13% as a result of the transactions completed in early
1994.

In March 1993, Oglethorpe entered into two forward interest rate swap
agreements totaling $322 million to refinance $364 million of existing high-
interest PCBs. Through this forward swap transaction, Oglethorpe arranged
synthetic fixed rate financing at an average effective rate of 6.15% for $200
million of variable rate refunding bonds which were issued on November 30, 1993
and $122 million of variable rate refunding bonds to be issuedelectric utility industry in the fallUnited States is undergoing fundamental
change and is becoming increasingly competitive. This change is promoted by the
Energy Policy Act of 1994. Interest savings totaling $9.1 million1992 (the "Energy Policy Act"), recently adopted and
an additional $4.3 million will
occur duringproposed policies from FERC regarding transmission access and pricing, increased
consolidation and mergers of electric utilities, the first full year following each respective issuance.

In February 1994, Oglethorpe refunded $205 millionproliferation of
PCBs through an
issuance of $195 million of fixed rate refunding bonds. With an effective
interest rate of 4.8%, this transaction will generate net interest savings of
about $10.5 million duringself-generators and independent power producers, surplus generation in certain
regional markets and other factors. The Energy Policy Act and FERC policies
allow for increased competition among wholesale electric suppliers and increased
access to transmission services by such suppliers. The new competitive
environment is subject to rapidly evolving regulatory policy at both the first full year. Oglethorpe expectsfederal
and state levels which is based on a shift to achieve
additional interest savings through a $35 million current refunding of PCBsmarket-driven environment from a
regulated one. Significant legislative developments at the federal level and in
the fall of 1994.

In addition to these refinancings, Oglethorpe has also recently taken
certain actions to reduce the interest expense on its FFB debt. In January 1993,
Oglethorpe prepaid six FFB advances totaling $75 million with interest rates
exceeding 10%. These advances, which had becomevarious state legislative bodies, and regulatory developments at least 12 years old, were
prepaid with one year's interest premium. The net annual average savings in the
first full year are $6.9 million.

During 1993, Oglethorpe pursued refinancing all of its approximately $3
billion in outstanding REA and FFB debt (the REA Indebtedness) through the
issuance of bonds in the public market which would have resulted in Oglethorpe
exiting the REA program (the REA Refinancing). In January 1994, FFB advised
Oglethorpe that the Department of the Treasury would not take certain actions
requested to facilitate the REA Refinancing. Oglethorpe continues to believe
that an REA Refinancing is in its long-term best interest and will continue to
evaluate options to exit the REA program. If the REA Refinancing were to be
consummated, it would require, among other things, a substitution of the REA
Mortgage with a trust indenture which would secure all of Oglethorpe's first
lien indebtedness, regulation of Oglethorpe's rates by the Federal
Energy Regulatory Commission (FERC) and certain amendmentsin state commissions, are expected to
continue to clarify policy and the regulatory framework for increased
competition. All of these factors present an increasing challenge to Oglethorpe
and the Members to reduce costs, manage resources and respond to the wholesale power contracts
between Oglethorpe and each of its Members. Oglethorpe's management is unable to
give any assurance at this time that Oglethorpe will be able to effect the REA
Refinancing, or, if so, on what terms and conditions.

Although Oglethorpe continues to pursue the REA Refinancing, it has taken
advantage of an option currently available to reduce the interest expense on its
FFB debt. At the beginning of 1994, Oglethorpe had over $1 billion of advances
that had been outstanding for more than 12 years under notes to the FFB that
were eligible to be modified to reduce their interest rates. In two separate
transactions in early 1994, Oglethorpe modified certain FFB notes and thereby
reduced the interest rates on approximately $795 million of advances. In
connection with such note modification, a premium was paid in an amount equal to
one year's interest on the advances of approximately $64 million, which will be
expensed over the longest remaining life of the subject advances, which is 22
years. These transactions will generate net interest savings of $18.5 million in
the first full year. Oglethorpe may elect to reduce the interest rates on
approximately $250 million of additional FFB advances through this note
modification process. The timing of such election depends on the magnitude of
the interest rate savings that can be achieved.

Oglethorpe is also evaluating and may seek to reduce its interest expense
by refinancing certain of its other FFB notes upon payment of a premium as
permitted under the recently enacted Section 306C of the Rural Electrification
Act. Under 306C, an FFB borrower is able to refinance its outstanding
indebtedness at interest rates based on the then current Treasury rates upon
payment of a premium. Based on current interest rates and the premium that would
be due under Section 306C, Oglethorpe is evaluating refinancing a portion of its
FFB indebtedness and financing at least a portion of the premium. Oglethorpe's
management has not determined whether Oglethorpe will avail itself of such
refinancing option.

MISCELLANEOUSchanging
environment.

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.

FINANCIAL CONDITION

General

The implementationprincipal changes in Oglethorpe's financial condition in 1996 were
additions of recently released pronouncements$43 million to gross utility plant and a decrease in the cost of
capital achieved through the refinancing of $106 million of long-term debt. The
average interest rate on long-term debt decreased from 6.76% at December 31,
1995 to 6.56% at December 31, 1996.

In addition, Oglethorpe completed a long-term lease transaction on its share
of Rocky Mountain which produced approximately $96 million of net proceeds. (For
a further discussion of this transaction, see "Rocky Mountain Transactions"
below.)

Capital Requirements

As part of its ongoing capital planning, Oglethorpe forecasts expenditures
required for generation facilities and other capital projects. The table below
details these expenditures for 1997 through 1999. 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 federal and other regulatory approvals, construction delays,
and cost of capital, equipment, material and labor.

- --------------------------------------------------------------------------------
Capital Expenditures(1)
(dollars in thousands)
- --------------------------------------------------------------------------------
Generating Nuclear General
Year Plant(2) Fuel Plant AFUDC(3) Total

1997 $14,753 $ 44,271 $ 3,715 $1,882 $ 64,621
1998 14,142 33,148 3,827 1,804 52,921
1999 11,250 35,549 3,941 1,435 52,175
------- -------- ------- ------ --------
Total $40,145 $112,968 $11,483 $5,121 $169,717
======= ======== ======= ====== ========

(1) Not included in the above amounts are capital expenditures which became the
responsibility of GTC and GSOC as of the Closing of the Corporate Restructuring.
For the period 1997 through 1999, these expenditures total $135 million for GTC
and $1 million for GSOC.

(2) Consists of capital expenditures required for replacements and additions to
facilities in service and compliance with environmental regulations..

(3) Allowance for funds used during construction of generation and general plant
facilities.
- --------------------------------------------------------------------------------

Currently, Oglethorpe does not have any new generation facilities under
construction, and management does not anticipate the need for construction of
any new capacity well into the future. (See "Results of Operations-Factors
Affecting Future Financial Accounting Standards Board,Performance" for a discussion of the long-term power
supply arrangements.)

Oglethorpe's investment in electric plant, net of depreciation, was
approximately $4.4 billion as of December 31, 1996. Expenditures for property
additions during 1996 amounted to $94 million, of which

$91 million was provided from operations. These expenditures were primarily for
additions and replacements to generation and transmission facilities.

In addition to the funds needed for capital expenditures, approximately $271
million will be required over the next three years for sinking fund requirements
and maturities of long-term debt. Of this amount, $216 million, or 80%, relates
to the repayment of RUS and FFB debt. Excluded from these amounts is the amount
of debt assumed by GTC and GSOC as part of the Corporate Restructuring. (See
"General-Corporate Restructuring" and Note 5 of Notes to Financial Statements
for further discussion regarding long-term debt maturities.)

Liquidity and Sources of Capital

In the past, Oglethorpe, like most other G&Ts, 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
tax-exempt PCBs.

In addition, Oglethorpe's operations have consistently provided a sizable
contribution to the funding of capital requirements, such that internally
generated funds have provided interim funding or long-term capital for nuclear
fuel reloads, new generation, transmission and general plant facilities,
replacements and additions to existing facilities, and retirement of long-term
debt. Oglethorpe anticipates that it will meet its future capital requirements
through 1999 primarily with funds generated from operations and, if necessary,
with short-term borrowings.

To meet short term cash needs and liquidity requirements, Oglethorpe had, as
of December 31, 1996, (i) approximately $133 million in cash and temporary cash
investments, (ii) $91 million in other short term investments and (iii)
available credit facilities as follows:

- --------------------------------------------------------------------------------
Short-Term Credit Facilities Authorized Amount
- --------------------------------------------------------------------------------
Commercial Paper ..............................................$250,000,000
Committed lines of credit:

SunTrust Bank, Atlanta .......................................30,000,000
Uncommitted lines of credit:

National Rural Utilities Cooperative
Finance Corporation (CFC) ...............................50,000,000
- --------------------------------------------------------------------------------

Under its commercial paper program, Oglethorpe may issue commercial paper
not to exceed $250 million outstanding at any one time. The commercial paper is
backed 100% by committed lines of credit provided by a group of banks for which
SunTrust Bank, Atlanta acts as agent. Proceeds from the issuance of commercial
paper may be used for working capital requirements and for general corporate
purposes.

The maximum amount that can be outstanding at any one time under the
commercial paper program and the lines of credit totals $250 million due to
certain restrictions contained in the SunTrust Bank and CFC line of credit
agreements. As of December 31, 1996, no commercial paper was outstanding and
there was no outstanding balance on any line of credit. In March 1997,
Oglethorpe issued approximately $92 million of commercial paper to fund the
defeasance of certain PCBs in conjunction with the Corporate Restructuring. (See
"Refinancing Transactions" below for a further discussion of this defeasance.)

Refinancing Transactions

Over the past few years, Oglethorpe has implemented a program to reduce its
interest costs by refinancing or prepaying a sizable portion of its
high-interest rate PCB and FFB debt. Since the first transaction was completed
in June 1992, Oglethorpe has refinanced $1.1 billion in PCB debt and $1.2
billion in FFB debt and has prepaid another $105 million in FFB debt. Included
in these amounts are a January 1996 refinancing of $89 million of FFB debt and
an October 1996 refinancing of $16 million of PCB debt. (See Note 5 of Notes to
Financial Statements.) The net result of the 1996 transactions was to reduce the
average interest rate on total long-term debt from 6.76% at December 31, 1995 to
6.56% at December 31, 1996. The refinancings completed since the program began
resulted in total annual savings in 1996 of more than $90 million in gross
interest expense and $80 million in net interest expense (net of prepayment
penalties and transaction costs).

Oglethorpe's use of financial derivatives is for the purpose of mitigating
business risks and is not used for speculative purposes. Derivatives have been
used on a very limited basis, as discussed below, and at December 31, 1996, any
credit risk for derivatives outstanding was not material.

To refinance high-interest rate PCBs, Oglethorpe entered into 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 agreements 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.

Under the swap agreements, Oglethorpe is obligated to make periodic payments
to AIG-FP based on a notional principal amount equal to the aggregate prin-

cipal 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 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 affects 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%. For the
three years ended December 31, 1994, 1995 and 1996, Oglethorpe has made in
connection with both interest rate swap arrangements combined net swap payments
to AIG-FP of $6.0 million, $6.4 million and $8.2 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 Statement No. 115, "Accounting for Certain
Investmentswhether 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
Debt and Equity Securities" and Statement No. 112, "Employer's
Accounting for Postemployment Benefits", are not expected to have a material
effectratings on Oglethorpe's resultsPCBs, without credit enhancement, to a level that is
below investment grade. Oglethorpe estimates that its maximum aggregate
liability for termination payments under both swap arrangements had such
payments been due on December 31, 1996 would have been approximately $34
million. (For additional information about the swap arrangements, see Note 2 of
operations.Notes to Financial Statements.)

In connection with these interest rate swap agreements, Oglethorpe is
obligated to maintain minimum liquidity in an amount equal to 25% of the
principal amount of the variable rate refunding bonds outstanding. This minimum
liquidity requirement currently equals $81 million and will decrease
proportionately as such bonds are retired as a result of scheduled sinking fund
payments.

In connection with the Corporate Restructuring, Oglethorpe defeased
approximately $92 million in principal amount of Series 1992 PCBs. Initially
these bonds have been defeased through the issuance of commercial paper.
Oglethorpe may refinance the commercial paper issuance with medium-term notes at
some point in the future and expects to refinance the commercial paper or such
medium-term notes in late 2002 with PCBs.

Also, in connection with the Corporate Restructuring, Oglethorpe refinanced
approximately $217 million in principal amount of Series 1992A PCBs through the
issuance of refunding bonds having a nine-month maturity (the Series 1997A
bonds). Payment of principal and interest on the Series 1997A bonds are insured
by a municipal bond insurance policy issued by AMBAC Indemnity Corporation. In
connection with the AMBAC insurance, Oglethorpe is obligated to maintain
liquidity in an amount at least equal to the principal amount of the Series
1997A bonds outstanding plus interest accrued thereon. The maximum amount of
this liquidity requirement during the nine-month period equals approximately
$223 million. Oglethorpe currently expects to refinance the Series 1997A bonds
in the second half of 1997 with another series of PCBs.

Rocky Mountain Transactions

Oglethorpe completed, in two separate closings on December 31, 1996 and
January 3, 1997, lease transactions for its 74.61% undivided ownership interest
in Rocky Mountain. Under the terms of these transactions, Oglethorpe leased the
facility to three institutional investors for a term of 71 years, who in turn
leased it back to Oglethorpe for a term of 30 years. The transactions are
characterized as a sale and lease-back for income tax purposes, but not for
financial reporting purposes. Rocky Mountain is subject to the lien of the
Master Indenture. The leasehold interest transferred is subject and subordinate
to such lien. Oglethorpe will continue to control and operate the plant during
the lease-back term, and it fully intends to repurchase tax ownership and to
retain all other rights of ownership with respect to the plant at the end of the
lease-back period. As a result of these transactions, Oglethorpe received net
proceeds of approximately $96 million which is being recorded as a deferred
credit and will be recognized in income over the term of the lease-back.
Approximately $91 million of the proceeds will be used for the early retirement
of FFB debt, with the remaining $5 million being used to pay alternative minimum
taxes on the transactions. The combination of the debt prepayment and the
amortized gain will result in an estimated $11 million in annual savings. In
connection with these transactions, Oglethorpe is obligated to maintain
liquidity of approximately $50 million.

ITEMItem 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

OGLETHORPE POWER CORPORATION

INDEX TO FINANCIAL STATEMENTS

Page
----

Statements of Revenues and Expenses, For the Years Ended December 31, 1993,
1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Statements of Patronage Capital, For the Years Ended December 31, 1993,
1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Balance Sheets, As of December 31, 1993 and 1992 . . . . . . . . . . . . . . . . 34
Statements of Capitalization, As of December 31, 1993 and 1992 . . . . . . . . . 36
Statements of Cash Flows, For the Years Ended December 31, 1993,
1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Notes to Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . 38
Report of Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . .Index To Financial Statements
Page
----
Statements of Revenues and Expenses, For the Years Ended
December 31, 1996, 1995 and 1994...................................... 43
Statements of Patronage Capital, For the Years Ended
December 31, 1996, 1995 and 1994...................................... 43
Balance Sheets, As of December 31, 1996 and 1995......................... 44
Statements of Capitalization, As of December 31, 1996 and 1995........... 46
Statements of Cash Flows, For the Years Ended December 31, 1996,
1995 and 1994......................................................... 47
Notes to Financial Statements, including pro-forma financial
statements relating to the Corporate Restructuring.................... 48

32Report of Management..................................................... 60
Reports of Independent Public Accountants................................ 60

STATEMENTS OF REVENUES AND EXPENSES

- -------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBERFor the years ended December 31, 1993, 1992 AND 19911996, 1995 and 1994

(DOLLARS IN THOUSANDS)
1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
1996 1995 1994

OPERATING REVENUES (NOTEOperating revenues (Note 1):
Sales to Members . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 899,7201,023,094 $ 816,0001,030,797 $ 763,657930,875
Sales to non-Members . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 200,940 268,763 300,293
--------- --------- ---------
TOTAL OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,100,660 1,084,763 1,063,950
--------- --------- ---------

OPERATING EXPENSES:78,343 118,764 125,207
----------- ----------- -----------
Total operating revenues 1,101,437 1,149,561 1,056,082
----------- ----------- -----------

Operating expenses:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 176,342 167,288 165,168206,524 219,062 203,444
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 129,972 115,915 130,041129,178 133,858 132,723
Purchased power (Note 10). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 271,970 230,510 229,8989) 229,089 264,844 227,477
Power delivery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14,286 17,804 20,44318,216 17,520 16,965
Sales, administrative and general. . . . . . . . . . . . . . . . . . . . . . . . . 30,590 32,774 28,930general 42,289 39,015 32,269
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . . . 128,060 126,047 135,152amortization 163,130 139,024 131,056
Taxes other than income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . 23,328 15,668 22,827taxes 30,262 27,561 24,741
Income taxes (Note 1). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,820 3,966 19,595
--------- --------- ---------
TOTAL OPERATING EXPENSES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 776,368 709,972 752,054
--------- --------- ---------
OPERATING MARGIN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 324,292 374,791 311,896
--------- --------- ---------

OTHER INCOME (EXPENSE)3) -- -- --
----------- ----------- -----------
Total operating expenses 818,688 840,884 768,675
----------- ----------- -----------
Operating margin 282,749 308,677 287,407
----------- ----------- -----------

Other income (expense):

Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20,316 29,218 40,814
Gain on sale of debt service reserve fund securities . . . . . . . . . . . . . . . - 3,884 32,44923,485 18,031 10,518
Amortization of deferred gains (Notes 21 and 6) . . . . . . . . . . . . . . . . . . 12,532 12,486 12,4824) 2,341 2,341 9,985
Amortization of proceeds fromnet benefit of sale of income
tax benefits (Note 6) . . . . . . . . . . . . . . . . . . . . . . . . . 8,102 8,1021) 8,054 8,043 8,102
Amortization of deferred margins (Note 1) . . . . . . . . . . . . . . . . . . . . 4,138 35,973 31,00032,047 15,959 18,072
Deferred margins (Note 1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . (5,083) (40,464) (11,703)
Co-owner inventory settlement (Note 7) . . . . . . . . . . . . . . . . . . . . . . - (4,827) --- (14,282) (9,287)
Allowance for equity funds used during
construction (Note 1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,278 1,377 782238 1,715 2,907
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3,542) 179 (485)
--------- --------- ---------
TOTAL OTHER INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 38,741 45,928 113,441
--------- --------- ---------

INTEREST CHARGES:(831) 1,903 498
----------- ----------- -----------
Total other income 65,334 33,710 40,795
----------- ----------- -----------

Interest charges:

Interest on long-term debt and capital leases . . . . . . . . . . . . . . . . . . 367,439 392,454 398,999308,013 317,968 329,738
Other interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,539 17,049 7,35710,006 12,979 3,856
Allowance for debt funds used during construction (Note 1) . . . . . . . . . . . . (29,988) (20,255) (13,111)(2,576) (21,114) (36,113)
Amortization of debt discount and expense . . . . . . . . . . . . . . . . . . . . 4,662 3,999 3,647
--------- --------- ---------
NET INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 350,652 393,247 396,892
--------- --------- ---------
MARGIN BEFORE CUMULATIVE EFFECT
OF CHANGE IN ACCOUNTING PRINCIPLE . . . . . . . . . . . . . . . . . . . . . . . . 12,381 27,472 28,445
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
FOR INCOME TAXES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13,340 - -
--------- --------- ---------
NET MARGIN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10,888 10,296 7,639
----------- ----------- -----------
Net interest charges 326,331 320,129 305,120
----------- ----------- -----------
Net margin $ 25,72121,752 $ 27,47222,258 $ 28,445
--------- --------- ---------
--------- --------- ---------23,082
=========== =========== ===========

STATEMENTS OF PATRONAGE CAPITAL

- -------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBERFor the years ended December 31, 1993, 1992 AND 19911996, 1995 and 1994

PATRONAGE CAPITAL AND MEMBERSHIP FEES-BEGINNING
OF YEAR (NOTEPatronage capital and membership fees - beginning
of year (Note 1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 264,261338,891 $ 236,789 $ 217,895
NET MARGIN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,721 27,472 28,445
PATRONAGE CAPITAL RETIREMENTS DECLARED . . . . . . . . . . . . . . . . . . . . . . - - (9,551)
--------- --------- ---------
PATRONAGE CAPITAL AND MEMBERSHIP FEES-END OF YEAR. . . . . . . . . . . . . . . . . .309,496 $ 289,982
Net margin 21,752 22,258 23,082
Change in unrealized gain (loss) on available-for-sale
securities, net of income taxes (Note 2) (4,414) 7,137 (3,568)
----------- ----------- -----------
Patronage capital and membership fees-end of year $ 264,261356,229 $ 236,789
--------- --------- ---------
--------- --------- ---------

CERTAIN PRIOR YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH CURRENT YEAR
PRESENTATION.
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.338,891 $ 309,496
=========== =========== ===========

33The accompanying notes are an integral part of these financial statements.

BALANCE SHEETS

- -------------------------------------------------------------------------------
DECEMBERDecember 31, 1993 AND 19921996 and 1995

- ---------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
ASSETS 1993 1992
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
Assets 1996 1995

ELECTRIC PLANT (NOTESElectric plant (Notes 1, 2, 5 AND4 and 6):
In service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .service $ 5,047,7395,742,597 $ 4,980,2795,699,213
Less: Accumulated provision for depreciation. . . . . . . . . . . . . . . . . (1,110,296) (989,892)
------------ ------------
3,937,443 3,990,387depreciation (1,488,272) (1,362,431)
----------- -----------
4,254,325 4,336,782

Nuclear fuel, at amortized cost . . . . . . . . . . . . . . . . . . . . . . . 110,177 123,62786,722 94,013
Plant acquisition adjustments, at amortized cost. . . . . . . . . . . . . . . 7,336 8,397cost 4,153 5,214
Construction work in progress . . . . . . . . . . . . . . . . . . . . . . . . 450,965 322,628
------------ ------------
4,505,921 4,445,039
------------ ------------

INVESTMENTS AND FUNDS, AT COST:31,181 35,753
----------- -----------
4,376,381 4,471,762
----------- -----------

Investments and funds (Notes 1 and 2):
Bond, reserve and construction funds, (Note 4) . . . . . . . . . . . . . . . . 110,390 163,964at market 53,955 56,511
Decommissioning fund, (Note 1) . . . . . . . . . . . . . . . . . . . . . . . . 56,911 47,921at market 86,269 74,492
Investment in associated organizations, (Note 3) . . . . . . . . . . . . . . . 19,123 19,909
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 486 644
------------ ------------
186,910 232,438
------------ ------------

CURRENT ASSETS:at cost 15,379 15,853
Deposit on Rocky Mountain transactions, at cost 41,685 --
----------- -----------
197,288 146,856
----------- -----------

Current assets:
Cash and temporary cash investments, at cost (Note 1) . . . . . . . . . . . . 244,173 275,624132,783 201,151
Other short-term investments, at cost . . . . . . . . . . . . . . . . . . . . - 66,165market 91,499 79,165
Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82,274 75,146113,289 99,559
Inventories, at average cost (Note 7) . . . . . . . . . . . . . . . . . . . . 86,468 93,6401) 89,825 82,949
Prepayments and other current assets. . . . . . . . . . . . . . . . . . . . . 14,763 17,132
------------ ------------
427,678 527,707
------------ ------------
DEFERRED CHARGES:assets 14,625 14,325
----------- -----------
442,021 477,149
----------- -----------

Deferred charges:

Premium and loss on reacquired debt, being amortized (Note 5) . . . . . . . . 91,981 48,076201,007 200,794
Deferred amortization of Scherer leasehold (Note 2) . . . . . . . . . . . . . 71,559 61,8804) 90,717 87,134
Deferred debt expense, being amortized . . . . . . . . . . . . . . . . . . . . 21,527 24,735
Discontinued project, being amortized21,703 21,135
Other (Note 6). . . . . . . . . . . . . . . . 18,314 19,722
------------ ------------
203,381 154,413
------------ ------------1) 33,058 33,666
----------- -----------
346,485 342,729
----------- -----------
$ 5,323,8905,362,175 $ 5,359,597
------------ ------------
------------ ------------

CERTAIN PRIOR YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH CURRENT YEAR
PRESENTATION.5,438,496
=========== ===========

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE BALANCE SHEETS.

34The accompanying notes are an integral part of these balance sheets.

- ---------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
EQUITY AND LIABILITIES 1993 1992
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
Equity and Liabilities 1996 1995

CAPITALIZATION (SEE ACCOMPANYING STATEMENTS)Capitalization (see accompanying statements):
Patronage capital and membership fees (Note 1). . . . . . . . . . . . . . . . $ 289,982356,229 $ 264,261338,891
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,058,251 4,095,796debt 4,052,470 4,207,320
Obligation under capital leases (Note 2). . . . . . . . . . . . . . . . . . . 303,458 302,061
------------ ------------
4,651,691 4,662,118
------------ ------------

CURRENT LIABILITIES:4) 293,682 296,478
Obligation under Rocky Mountain transactions (Note 1) 41,685 --
---------- ----------
4,744,066 4,842,689
---------- ----------

Current liabilities:
Long-term debt and capital leases due within one year. . . . . . . . . . . . . . . . . . . . . . 78,644 133,136year 159,622 89,675
Deferred margins and Vogtle surcharge to be refunded within one year (Note 1). . . . . . . . . . . . . . . . . . . . . 26,777 5,738 -- 32,047
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62,186 64,535payable 42,891 48,855
Accrued interest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108,702 59,323interest 15,931 91,096
Accrued and withheld taxes. . . . . . . . . . . . . . . . . . . . . . . . . . 9,401 3,660
Energy cost billed in excess of actual (Note 1`). . . . . . . . . . . . . . . 11,456 29,318taxes 4,940 1,785
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . 40,234 22,456
------------ ------------
337,400 318,166
------------ ------------

DEFERRED CREDITS AND OTHER LIABILITIES:14,022 18,007
---------- ----------
237,406 281,465
---------- ----------

Deferred credits and other liabilities:
Gain on sale of plant, being amortized (Notes 2). . . . . . . . . . . . . . . 65,550 67,892
Gain on(Note 4) 58,527 60,868
Net benefit of sale of Scherer common facilities, being amortized (Note 6) . . . . . 7,644 17,835
Sale of income tax benefits, being amortized (Note 6) . . . . . . . . . . . . 66,838 74,9391) 42,049 50,194
Net benefit of Rocky Mountain transactions, being amortized (Note 1) 70,701 --
Accumulated deferred income taxes (Note 1). . . . . . . . . . . . . . . . . .3) 61,985 65,510 77,225
Deferred margins and Vogtle surcharge (Note 1). . . . . . . . . . . . . . . . 21,083 42,777
Decommissioning reserve (Note 1). . . . . . . . . . . . . . . . . . . . . . . 90,476 77,490 124,468 114,049
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,698 21,155
------------ ------------
334,799 379,313
------------ ------------

COMMITMENTS AND CONTINGENCIES (NOTES 2,6,9 AND 10)

$ 5,323,890 $ 5,359,597
------------ ------------
------------ ------------22,973 23,721
---------- ----------
380,703 314,342
---------- ----------
Commitments and Contingencies (Notes 4, 9 and 11)

$5,362,175 $5,438,496
========== ==========

3545

STATEMENTS OF CAPITALIZATION

- -------------------------------------------------------------------------------
DECEMBERDecember 31, 1993 AND 19921996 and 1995

- ----------------------------------------------------------------------------------------------------------
(dollars in thousands)
1993 1992
- ------------------------------------------------------------------------------------------------------------------------------1996 1995
LONG-TERM DEBT (NOTE
Long-term debt (Note 5):

Mortgage notes payable to the Federal Financing Bank (FFB) at
interest rates varying from 6.61%5.27% to 10.95%9.51% (average rate of
8.367%6.95% at December 31, 1993)1996) due in quarterly installments
. . . . . . . . . . . . . .through 2023 ............................................................. $ 3,040,7673,172,851 $ 3,111,1603,253,636

Mortgage notes payable to the Rural Electrification Administration (REA)Utilities Service (RUS) at
an interest rate of 5% due in monthly installments . . . . . . . . . . . . . . . . . . 23,927 24,365through 2021 .......... 22,475 22,983

Mortgage notes issued in conjunction with the sale by public authorities of
pollution control revenue bonds:
- Series 1978
Serial bonds, 6.00% to 6.40%, due serially through 1999 . . . . . . . . . . . . . . 5,440 6,180
Term bonds, 6.80%, due 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16,700 16,700

-o Series 1982
Serial bonds, 10.00% to 10.60%, due serially through 1997. . . . . . . . . . . . . . 23,195 27,740

- Series 1984
Serial bonds, 9.50% to 10.50%, due serially through 2000 . . . . . . . . . . . . . . 61,800 67,790
Term bonds, 7.00% to 10.63%, due 2004 to 2014. . . . . . . . . . . . . . . . . . . . 119,135 270,965

- Series 1984B
Serial bonds, 9.75% to 10.50%, due serially through 2000 . . . . . . . . . . . . . . 11,530 25,910
Term bonds, 10.50%, due 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 69,080

- Series 1985
Serial bonds, 8.50% to 9.50%, due serially through 2001. . . . . . . . . . . . . . . 29,290 31,770
Term bonds, 7.50% to 9.88%, due 2005 to 2017 . . . . . . . . . . . . . . . . . . . . 141,890 141,890

- Series 1992A
Adjustable tender bonds, 2.10% to 2.65%, due 2025 . . . . . . . . . . . . . . . . . 216,925 216,925
Serial bonds, 3.85% to 6.80%, due serially from 1994 through 2012. . . . . . . . . . 143,710 143,710

-1997 .......................... 6,675 6,675

o Series 1992
Term bonds, 7.50% to 8.00%, due 2003 to 2022 . . . . . . . . . . . . . . . . . . . .............................. 92,130 92,130

-oSeries 1992A
Adjustable tender bonds, 3.40% to 3.70%, due 2025 ........................ 216,925 216,925
Serial bonds, 5.35% to 6.80%, due serially from 1998 through 2012 ........ 124,690 129,760

o Series 1993
Serial bonds, 3.55% to 5.25%, due serially from 1997 through 2013 ........ 37,255 38,110

o Series 1993A
Adjustable tender bonds, 3.10%4.00%, due 2016 . . . . . . . . . . . . . . . . . . . . . .................................. 199,690 -

National Bank for Cooperatives (CoBank)199,690

o Series 1993B
Serial bonds, 3.75% to 5.05%, due serially from 1998 through 2008 ........ 126,935 136,745

o Series 1994
Serial bonds, 4.20% to 7.125%, due serially from 1997 through 2015 ....... 10,365 10,690
Term bonds, 7.15% due 2021 ............................................... 11,550 11,550

o Series 1994A
Adjustable tender bonds, 4.00%, due 2019 ................................. 122,740 122,740

o Series 1994B
Serial bonds, 5.45% to 6.45%, due serially from 1998 through 2005 ........ 11,140 12,475

Unsecured notes issued in conjunction with the sale by public authorities of
pollution control revenue bonds:
o Series 1995
Adjustable rate bonds, 3.70% to June 1996, due in 2015 ................... -- 21,670

o Series 1996
Adjustable rate bonds, 3.88% to April 1997, due in 2017 .................. 37,885 --

CoBank, ACB notes payable:
-o Headquarters note payable: $5.4 million fixed at 7.40%6.60% through April 1995,
$0.5 million fixed at 6.35%-7.35% to April 1995;1997,
due in quarterly installments through January 1, 2009 . . . . . . . . . . . . . . . . . . . . . . . . 5,938 6,328
-................... 4,672 5,159
o Transmission note payable: fixed at 7.40%6.50% through
April 1995;September 1997; due in bimonthly installments through November 1, 2018 . . . . . . . . . . . . . . . 2,296 2,310
-... 2,237 2,261
o Transmission note payable: fixed at 7.25%6.50% through April 1995;October 1997; due
in bimonthly installments through September 1, 2019 . . . . . . . . . . . . . . 8,751 8,798
----------...................... 8,556 8,637
----------- 4,143,114 4,263,751-----------
4,208,771 4,291,836

Less:Unamortized debt discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6,219) (34,819)
----------............................................. (766) (832)
----------- -----------
Total long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,136,895 4,228,932.................................................. 4,208,005 4,291,004

Less: AmountLong-term debt due within one year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (78,644) (133,136)
----------.................................... (155,535) (83,684)
----------- TOTAL LONG-TERM DEBT, EXCLUDING AMOUNT DUE WITHIN ONE YEAR . . . . . . . . . . . . . . . . . . 4,058,251 4,095,796

OBLIGATION UNDER CAPITAL LEASES (NOTE 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . 303,458 302,061

PATRONAGE CAPITAL AND MEMBERSHIP FEES (NOTE-----------
Total long-term debt, excluding amount due within one year .................... 4,052,470 4,207,320

Obligation under capital leases, long-term (Note 4) ........................... 293,682 296,478

Obligation under Rocky Mountain transactions, long-term (Note 1) . . . . . . . . . . . . . . . . . . . . . . . . 289,982 264,261
----------.............. 41,685 --

Patronage capital and membership fees (Note 1) ................................ 356,229 338,891
----------- TOTAL CAPITALIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .-----------
Total capitalization .......................................................... $ 4,651,6914,744,066 $ 4,662,118
---------- -----------
---------- -----------4,842,689
=========== ===========

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.

36The accompanying notes are an integral part of these financial statements.

STATEMENTS OF CASH FLOWS

- -------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBERFor the years ended December 31, 1993, 1992 AND 19911996, 1995 and 1994

(dollars in thousands)

(DOLLARS IN THOUSANDS)
1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------1996 1995 1994
Cash flows from operating activities:

CASH FLOWS FROM OPERATING ACTIVITIES:
Net margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .................................................... $ 25,72121,752 $ 27,47222,258 $ 28,445
-------- -------- --------23,082
--------- --------- ---------
Adjustments to reconcile net margin to net cash
provided by operating activities:
Cumulative effect of change in accounting for income taxes . . . . . . . . (13,340) - -
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . 180,221 188,285 203,770............................ 196,593 196,920 193,351
Net benefit of Rocky Mountain transactions ............... 70,701 -- --
Interest on decommissioning reserve ...................... 7,167 9,951 1,291
Amortization of deferred gains . . . . . . . . . . . . . . . . . . . . . . (12,532) (12,486) (12,482)........................... (2,341) (2,341) (9,985)
Deferred margins and amortization of deferred margins. . . . . . . . . . . 945 4,491 (19,297)margins .... (32,047) (1,677) (8,785)
Amortization of proceeds fromnet benefit of sale of income tax benefits. . . . . . . . .benefits (8,145) (8,043) (8,102) (8,102) (8,102)
Interest on decommissioning reserve . . . . . . . . . . . . . . . . . . . 7,356 5,443 5,850
Gain on sale of bond fund investments . . . . . . . . . . . . . . . . . . - (3,884) (32,449)
Allowance for equity funds used during construction. . . . . . . . . . . . (2,278) (1,377) (782)construction ...... (238) (1,715) (2,907)
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . 1,625 2,459 19,595.................................... (3,525) -- --
Option payment on power swap agreement ................... (3,750) -- --
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ..................................................... (13) (3,066) 1,118(13) (13)

Change in net current assets, excluding long-term
debt due within one year and deferred margins and
Vogtle surcharge to be refunded within one year:
Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7,128) 371 (3,956)............................................ (13,731) (10,686) (18,055)
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,172 (1,670) (6,865)............................................ (6,875) 12,127 (8,608)
Prepayments and other current assets . . . . . . . . . . . . . . . . . 2,369 (3,043) 109................... (299) 532 (94)
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,349) 1,106 19,109....................................... (5,964) (4,066) (10,569)
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . . 49,379 (1,238) (147)....................................... (75,165) (8,914) (8,692)
Accrued and withheld taxes . . . . . . . . . . . . . . . . . . . . . . 5,741 (14,505) (55)
Energy cost billed in excess of actual . . . . . . . . . . . . . . . . (17,862) 29,318 -............................. 3,155 219 (7,835)
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . 15,542 (7,532) (3,993)
-------- -------- --------.............................. (3,985) (169) (24,124)
--------- --------- ---------
Total adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 206,746 174,570 161,423
-------- -------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES . . . . . . . . . . . . . . . . . . . 232,467 202,042 189,868
-------- -------- --------

CASH FLOWS FROM INVESTING ACTIVITIES:............................................ 121,538 182,125 86,873
--------- --------- ---------
Net cash provided by operating activities ....................... 143,290 204,383 109,955
--------- --------- ---------

Cash flows from investing activities:
Property additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (235,285) (232,283) (225,021)
Net proceeds from........................................... (93,704) (138,921) (206,345)
Activity in decommissioning fund - Purchases ................. (327,233) (410,597) (297,492)
- Proceeds ........................ 316,542 399,077 293,990
Activity in bond, reserve and construction funds - Purchases . . . . . . . . . . . . 53,574 15,957 35,024(107,890) (27,762) (498,052)
- Proceeds ........... 109,230 39,566 540,712
Activity in other short-term investments - Purchases ......... (15,532) (76,180) --
Decrease in investment in associated organizations . . . . . . . . . . . . . . 786 1,213 824
Decrease (increase)........... 474 1,518 1,752
--------- --------- ---------
Net cash used in other short-term investments . . . . . . . . . . . . . 66,165 (66,165) -
Release of safe harbor lease indemnity fund . . . . . . . . . . . . . . . . - - 120,000
Increase in decommissioning fund . . . . . . . . . . . . . . . . . . . . . . . (8,990) (6,841) (7,259)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 158 (158) (486)
-------- -------- --------
NET CASH USED IN INVESTING ACTIVITIES . . . . . . . . . . . . . . . . . . . . . (123,592) (288,277) (76,918)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:investing activities ........................... (118,113) (213,299) (165,435)
--------- --------- ---------

Cash flows from financing activities:
Debt proceeds, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 232,675 579,938 51,157.......................................... 2,243 132,874 523,518
Debt payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (369,962) (554,029) (40,550)
Patronage capital retirements . . . . . . . . . . . . . . . . . . . . . . . . - (9,551) (4,877)............................................... (95,367) (108,481) (517,530)
Return of Vogtle surcharge . . . . . . . . . . . . . . . . . . . . . . . . . . (1,600) (5,085) (990).................................. -- (3,320) (2,031)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,439) (144) (203)
-------- -------- --------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES . . . . . . . . . . . . . . (140,326) 11,129 4,537
-------- -------- --------
NET INCREASE (DECREASE) IN CASH
AND TEMPORARY CASH INVESTMENTS . . . . . . . . . . . . . . . . . . . . . . . . (31,451) (75,106) 117,487

CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR . . . . . . . . . . . . 275,624 350,730 233,243
-------- -------- --------

CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR . . . . . . . . . . . . . . ........................................................ (421) (1,648) (2,008)
--------- --------- ---------
Net cash provided by (used in) financing activities ............. (93,545) 19,425 1,949
--------- --------- ---------
Net increase (decrease) in cash and temporary cash investments .. (68,368) 10,509 (53,531)

Cash and temporary cash investments at beginning of year ........ 201,151 190,642 244,173
--------- --------- ---------
Cash and temporary cash investments at end of year .............. $ 244,173132,783 $ 275,624201,151 $ 350,730
-------- -------- --------
-------- -------- --------

CASH PAID FOR:190,642
========= ========= =========

Cash paid for:
Interest (net of amounts capitalized) . . . . . . . . . . . . . . . . . . . ........................ $ 289,255383,440 $ 388,117308,797 $ 386,450304,882
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,658 43 -................................................ -- -- --

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.

37The accompanying notes are an integral part of these financial statements.

NOTES TO FINANCIAL STATEMENTS

- ----------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBERFor the years ended December 31, 1993, 1992 AND 19911996, 1995 and 1994

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

A. BASIS OF ACCOUNTINGSummary of significant accounting policies:

a. Business description

Oglethorpe Power Corporation (Oglethorpe) is an electric generation and
transmission (G&T) cooperative incorporated in 1974 and headquartered in
suburban Atlanta. Oglethorpe provides wholesale electric service, on a
not-for-profit basis, to 39 of Georgia's 42 Electric Membership Corporations
(EMCs). These 39 electric distribution cooperatives (Members) in turn distribute
energy on a retail basis to more than 2.6 million people across two-thirds of
the State. Oglethorpe is the nation's largest G&T in terms of operating
revenues, assets, kilowatt-hour sales and, through its Members, consumers
served.

Oglethorpe supplies energy to the Members from 3,335 megawatts (MW) of owned
or leased generating capacity and purchases the remainder from other power
suppliers. Oglethorpe also has access to over 16,000 miles of transmission line
through its ownership in the statewide Integrated Transmission System.

Oglethorpe and the Members completed on March 11, 1997, a corporate
restructuring. For a discussion of the corporate restructuring, see Note 11.

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 Electrification Administration (REA)Utilities Service (RUS).

B. ELECTRIC PLANTThe 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, 1996 and 1995 and the
reported amounts of revenues and expenses for each of the three years ending
December 31, 1996. 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 is the retained net margin
of Oglethorpe. As provided in the bylaws, 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.

Under Oglethorpe's patronage capital retirements policy, margins are to be
returned to the Members 30 years after the year in which the margins are earned.
Pursuant to such policy, no patronage capital would be returned to the Members
until 2010, at which time the 1979 patronage capital would be returned.

Since the RUS Mortgage was replaced with the Master Indenture in connection
with Oglethorpe's corporate restructuring, patronage distributions also will be
restricted by the terms of the Master Indenture.

d. Margin policy

Under Oglethorpe's prior RUS mortgage, Oglethorpe's margin policy was based
on the provision of a Times Interest Earned Ratio (TIER) established annually by
the Oglethorpe Board of Directors. Pursuant to this policy, the annual net
margin goal for 1996, 1995 and 1994 was the amount required to produce a TIER of
1.07. The RUS Mortgage was replaced with the Master Indenture in connection with
Oglethorpe's corporate restructuring. Under the Master Indenture, Oglethorpe is
required to produce a Margins for Interest (MFI) Ratio of 1.10.

The Oglethorpe Board of Directors adopted resolutions annually requiring that
Oglethorpe's net margins for the years 1985 through 1995 in excess of its annual
margin goals be deferred and used to mitigate rate increases associated with
Plant Vogtle and Rocky Mountain. In addition, during 1986 and 1987, Oglethorpe's
wholesale electric rate to its Members provided for a one mill per kilowatt-hour
charge (Vogtle Surcharge), also to be used to mitigate the effect of Plant
Vogtle on rates.

Pursuant to rate actions by Oglethorpe's Board of Directors, specified
amounts of deferred margins and Vogtle Surcharge were returned in 1989 through
1995 and all remaining amounts were returned in 1996. A summary of deferred
margins and Vogtle Surcharge as of December 31, 1996 and 1995 is as follows:

- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
- --------------------------------------------------------------------------------
Deferred margins
1985-92 $ 165,552 $ 165,552
1993 5,083 5,083
1994 9,287 9,287
1995 14,282 14,282
--------- ---------
194,204 194,204
Vogtle Surcharge
1986-87 36,613 36,613
--------- ---------
Subtotal 230,817 230,817

Less: Amounts returned in:
1989-93 (159,388) (159,388)
1994 (20,103) (20,103)
1995 (19,279) (19,279)
1996 (32,047) --
--------- ---------
-- 32,047

Less: Current portion -- (32,047)
--------- ---------
Long-term balance $ -- $ --
========= =========
- --------------------------------------------------------------------------------

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 12.5% and 11.2% in 1996, 11.3% and 10.4% in 1995, and 11.0% and
10.5% in 1994, 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 1996, 1995 and 1994 amounted to $49,298,000, $54,588,000 and
$55,229,000, respectively.

Contracts with the U.S. Department of Energy (DOE) have been executed to
provide for the permanent disposal of spent nuclear fuel for the life of Plant
Hatch and Plant Vogtle. The services to be provided by DOE were scheduled to
begin in 1998. However, the actual year that these services will begin is
uncertain. The Plant Hatch spent fuel storage is expected to be sufficient into
2003. The Plant Vogtle spent fuel storage is expected to be sufficient into
2008. Activities for adding dry cast storage capacity at Plant Hatch by as early
as 1999 are in progress.

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
decon-tamination 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
$14,900,000, which is being amortized to nuclear fuel expense over the next 11
years. Oglethorpe has also recorded an obligation to DOE which approximated
$11,800,000 at December 31, 1996.

g. Nuclear decommissioning

Oglethorpe's portion of the costs of decommissioning co-owned nuclear
facilities is estimated 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 1994 1994 1994 1994

Expected start date
of decommissioning 2014 2018 2027 2029

Decommissioning cost:
Discounted $ 92,000 $ 109,000 $ 82,000 $ 106,000
Undiscounted 157,000 207,000 198,000 271,000
- --------------------------------------------------------------------------------

The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above 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.

The annual provision for decommissioning for 1996, 1995 and 1994 was
$2,597,000, $4,156,000 and $5,948,000, respectively. In developing the amount of
the annual provision for 1996 and 1997, the escalation rate was assumed to be
2.72% and return on trust assets was assumed to be 8%. Oglethorpe accounts for
this provision for decommissioning as depreciation expense with an offsetting
credit to a decommissioning reserve. Oglethorpe's management is of the opinion
that any changes in cost estimates of decommissioning will be fully recovered in
future rates.

In compliance with a Nuclear Regulatory Commission (NRC) regulation,
Oglethorpe maintains an external trust fund to provide for a portion of the cost
of decommissioning its nuclear facilities. The NRC regulation requires funding
levels based on average expected cost to decommission only the radioactive
portions of a typical nuclear facility. Oglethorpe's decommissioning reserve
reflects its obligation to decommission both the radioactive and most of the
non-radioactive portions of its nuclear facilities.

Realized investment earnings from the external trust fund, while increasing
the fund and interest income, also are applied to the decommissioning reserve
and charged to interest expense. Interest income earned from the external trust
fund is offset by the recognition of interest expense such that there is no
effect on Oglethorpe's net margin.

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 1996,
1995 and 1994 were as follows:

- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Steam production 2.13% 2.13% 2.47%
Nuclear production 2.73% 2.78% 2.84%
Hydro production 2.00% 2.00% 2.00%
Other production 3.75% 3.75% 2.42%
Transmission 2.75% 2.75% 2.75%
Distribution 2.88% 2.88% 2.88%
General 2.00-20.00% 2.00-20.00% 2.00-20.00%
- --------------------------------------------------------------------------------

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. The plant acquisition adjustments represent the
excess of the cost of the plant to Oglethorpe over the original cost, less
accumulated depreciation at the time of acquisition, and are being amortized
over a ten-year period.

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.

C. OPERATING REVENUES

Salesj. Bond, reserve and construction funds:

Bond, reserve and construction funds for pollution control bonds are
maintained as required by Oglethorpe's bond agreements. Bond funds serve as
payment clearing accounts, reserve funds maintain amounts equal to Members consist primarily of electricity sales pursuant to
long-term wholesale power contracts which Oglethorpe maintains with each of
its 39 retail electric distribution cooperatives (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 endmaximum
annual debt service of each month.

For the year ended December 31, 1993, revenues from Cobb EMC, one of
Oglethorpe's Members, accountedbond issue and construction funds hold bond proceeds
for 10.3% of Oglethorpe's total revenues.
Prior to 1993, no individual Member accounted for 10% or more of Oglethorpe's
total revenues.

Sales to non-Members consist primarily of capacity and energy sales to
Georgia Power Company (GPC) under terms of sell-back agreements entered into
when Oglethorpe purchased interests in certain of GPC's generation
facilities. Pursuant to these agreements, GPC purchases from Oglethorpe a
declining fractional part of the capacity and energy during the first seven
to ten years of an applicable generating unit's commercial operation. The
portion of Oglethorpe's capacity and energy retained by GPC is shown as
follows:

- ----------------------------------------------------------------------------
Fractional Part of Capacity and Energy Retained by GPC during Contract Year
Ended May 31
- ----------------------------------------------------------------------------

Generating Unit 1994 1993 1992 1991
- ----------------------------------------------------------------------------

Plant Scherer,
Unit No. 1 -- -- -- 6/60

Plant Scherer,
Unit No. 2 -- 6/60 12/60 18/60

Plant Vogtle,
Unit No. 1 4/30 8/30 11/30 14/30

Plant Vogtle,
Unit No. 2 8/30 11/30 14/30 17/30
- ----------------------------------------------------------------------------

Pursuant to these sell-back agreements and to other contractual
arrangements with GPC, revenues from GPC accounted for approximately 15%,
24%, and 28% of Oglethorpe's total revenues in 1993, 1992, and 1991,
respectively.

D. DEPRECIATION

Depreciation is computed on additions when they are placed in service
using the composite straight-line method. Annual depreciation rates in effect
in 1993, 1992 and 1991 were as follows:

- ----------------------------------------------------------------------------
1993 1992 1991
- ----------------------------------------------------------------------------

Steam production 2.66% 2.66% 2.73%
Nuclear production 2.83% 2.74% 3.09%
Hydro production 2.00% 2.00% 2.00%
Other production 1.09% 1.09% 1.14%
Transmission 2.75% 2.75% 2.75%
Distribution 2.88% 2.88% 2.88%
General 2.00-17.00% 2.00-17.00% 2.00-17.00%
- ----------------------------------------------------------------------------

Oglethorpe's portion of the cost of decommissioning co-owned nuclear
facilities, based on current price levels and decommissioning promptly after
the unit is taken out of service, is estimated at approximately $71,000,000
for Hatch Unit No. 1, $93,000,000 for Hatch Unit No. 2, $79,000,000 for
Vogtle Unit No.1 and $99,000,000 for Vogtle Unit No. 2. The depreciation
rate for nuclear production includes a factor to provide for such expected
cost of decommissioning. Oglethorpe accounts for this provision for
decommissioning as depreciation expense with an offsetting credit to a
decommissioning reserve. Imputed interest calculated based on current
investment rates is applied to the decommissioning reserve balance and
charged to interest expense. The estimates for the expected cost of
decommissioning and the corresponding decommissioning factor in the
depreciation rate are adjusted periodically to reflect changing price levels
and technology.

In compliance with a Nuclear Regulatory Commission (NRC) regulation,
Oglethorpe maintains an external trust fund to provide for a portion of the
cost of decommissioning its nuclear facilities. The NRC regulation requires
funding levels based on average expected cost to decommission only the
radioactive portions of a typical nuclear facility. Investment earnings
generated from the external trust fund increase the decommissioning fund and
interest income.

E. 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 1993, 1992 and 1991 amounted to $49,647,000,
$55,804,000 and $62,349,000, respectively.

Contracts with the U.S. Department of Energy (DOE)which construction expenditures have not yet been executed to
provide for the permanent disposal of spent nuclear fuel for the life of
Plant Hatch and Plant Vogtle. The services to be provided by DOE are
scheduled to begin in 1998. However, the actual year that these services will
begin is uncertain. The Plant Hatch spent fuel storage is expected to be
sufficient into 2003. The Plant Vogtle spent fuel storage is expected to be
sufficient into 2009. If DOE does not begin receiving spent fuel from Plant
Hatch in 2003 or from Plant Vogtle in 2009, alternative spent fuel storage
will be needed.

The Energy Policy Act of 1992 requires that utilities with nuclear
plants be assessed, over the next 15 years, 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 is based on
its past purchases of nuclear fuel enrichment services from DOE. Based on its
ownership in Plants Hatch and Vogtle, Oglethorpe has recorded a nuclear fuel
asset of approximately $20,000,000, which is being amortized to nuclear fuel
expense over the 15-year assessment period. Oglethorpe has also recorded,
net of sell-back, an obligation to DOE which approximated $14,000,000 at
December 31, 1993.

F. 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 is the retained net
margin of Oglethorpe.made. As provided in the bylaws, 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.

The margin and patronage capital retirements policy adopted by the
Oglethorpe Board of Directors in 1992 extended from 13 years to 30 years the
period that each year's net margin will be retained by Oglethorpe. Pursuant
to the previous 13-year patronage capital retirement schedule, 1978 patronage
capital assignments were retired in 1992, and 1977 assignments in 1991. Under
the new 30-year retirement schedule, no patronage capital would be returned
to the Members until 2010, at which time the 1979 patronage capital would be
returned.

G. INCOME TAX ACCOUNTING

Oglethorpe is a not-for-profit membership corporation subject to
Federal, State of Georgia and State of Alabama income taxes. For years 1981
and prior, Oglethorpe claimed tax-exempt status under Section 501(c)(12) of
the Internal Revenue Code of 1954, as amended (the Code). In 1982, Oglethorpe
reported as a taxable entity as a result of income received by it from GPC
under the capacity and energy sell-back agreement applicable to Scherer Unit
No. 1. In connection with its 1985 tax return. Oglethorpe made an election
under Section 168(j)(4)(E)(ii) of the Code to remain taxable from 1985 until
at least 2005 without regard to the amount of its income from GPC or other
non-Members. As a taxable electric cooperative, Oglethorpe has annually
allocated its income and deductions between Member and non-Member activities.
Any Member taxable income has been offset with a patronage exclusion.

As of January 1, 1993, Oglethorpe prospectively adopted the provisions
of Statement of Financial Accounting Standards (SFAS) No. 109, "Accounting
for Income Taxes". In adopting SFAS No. 109, Oglethorpe recorded a
$13,340,000 reduction in accumulated deferred income taxes and an increase in
income from the cumulative effect of a change in accounting principle. 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. Deferred tax assets and liabilities are
determined based on the differences between the financial and tax bases using
enacted tax rates in effect for the year in which the differences are
expected to reverse.

A detail of the provision for income taxes in 1993, 1992 and 1991 is
shown as follows:

- ---------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993 1992 1991
- ---------------------------------------------------------------------------

Current
Federal $ -- $ -- $ --
State 195 1,507 --
--------- -------- --------
195 1,507 --
--------- -------- --------
Deferred
Federal 1,820 4,127 17,541
State (195) (1,668) 2,054
--------- -------- --------
1,625 2,459 19,595
--------- -------- --------
Income taxes charged
to operations $ 1,820 $ 3,966 $ 19,595
--------- -------- --------
--------- -------- --------
- ---------------------------------------------------------------------------

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

- ------------------------------------------------------------------------------
1993 1992 1991
- ------------------------------------------------------------------------------

Statutory federal income tax rate 35.0% 34.0% 34.0%
Patronage exclusion (35.1%) (21.6%) 4.3%
Other 0.1% 0.7% (1.8%)
Effect of increase in
statutory rate 12.8% 0.0% 0.0%
---- ---- ----
Effective income tax rate 12.8% 13.1% 36.5%
---- ---- ----
---- ---- ----
- ------------------------------------------------------------------------------

The components of the net deferred tax liabilities as of December 31,
1993
were as follows:

- -----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993
- -----------------------------------------------------------------------------

Deferred tax assets:
Net operating losses $ 471,069
Member loss carryforwards 363,140
Accounting for safe harbor leases 102,886
Tax credits 252,701
Patronage exclusions available 39,149
Accounting for asset dispositions 38,381
Accrued nuclear decommissioning
expense 29,324
Other 8,002
---------
1,304,652
Less: Valuation allowance (252,701)
---------
1,051,951
---------

Deferred tax liabilities:
Depreciation (1,068,396)
Accounting for debt
extinguishment (34,114)
Other (14,951)
---------
(1,117,461)
---------
Net deferred tax liabilities $ (65,510)
---------
---------
- -----------------------------------------------------------------------------

Oglethorpe has federal tax net operating loss carryforwards (NOLs)1996 and unused general business credits (consisting primarily of investment tax credits)
as follows:

- -------------------------------------------------------------
(DOLLARS IN THOUSANDS)
Expiration Date Tax Credits NOLs
- -------------------------------------------------------------

1997 $ 11,197 $ -
1998 6,934 -
1999 37,206 -
2000 3,198 -
2001 7,264 -
2002 130,392 146,362
2003 652 253,665
2004 55,669 114,285
2005 189 213,080
2006 - 209,009
2007 - 86,779
2008 - 102,262
-------- ---------
$ 252,701 $1,125,442
-------- ---------
-------- ---------
- -------------------------------------------------------------

Based on Oglethorpe's historical taxable transactions and the timing1995, substantially all of the reversal of existingfunds were invested in U.S. Government
securities.

k. Cash and temporary differences, management believes it is more
likely than not that Oglethorpe's future taxable income will be sufficient to
realize the benefit of the NOLs existing at December 31, 1993 before their
respective expiration dates. However, as reflected in the above valuation
allowance, management does not believe it is more likely than not that the tax
credits will be utilized before expiration.

During 1992 and 1991, deferred income taxes were provided for significant
timing differences between revenues and expenses for tax and financial statement
purposes. The source and deferred tax effect of these differences are summarized
as follows:

- ----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1992 1991
- ----------------------------------------------------------------------------

Excess of tax over book depreciation $ 16,524 $ 75,042

Difference in recognition of gain/loss
on asset dispositions 6,475 6,832

Difference in accounting for safe harbor leases 6,022 5,487

Accrued nuclear decommissioning expense (558) (740)

Difference in accounting for debt extinguishment 6,956 -

Adjustments to book accrued liabilities 3,514 (425)

Difference in recognition of cost of
discontinued project (532) 8,178

Other (67) (464)

Portion of the above differences not reflected
in expense due to net operating losses (35,875) (74,315)
------- -------
$ 2,459 $ 19,595
------- -------
------- -------
- ----------------------------------------------------------------------------

H. MARGIN POLICY

Oglethorpe's margin policy is based on the provision of a Times Interest
Earned Ratio (TIER) established annually by the Oglethorpe Board of Directors.
For 1993, 1992, and 1991, the margin goal was the amount required to produce a
TIER of 1.07. Oglethorpe's Board of Directors adopted a new margin and patronage
capital retirements policy in 1992. Pursuant to the new policy, the annual net
margin goal will be the amount required to produce a TIER of 1.07 each year
through 1995, 1.08 in 1996, 1.09 in 1997 and 1.10 in 1998 and thereafter.

The Oglethorpe Board of Directors adopted resolutions annually requiring
that Oglethorpe's net margins for the years 1985 through 1993 in excess of its
annual margin goals be deferred and used to mitigate rate increases associated
with Plant Vogtle. In addition, during 1986 and 1987, Oglethorpe's wholesale
electric rate to its Members provided for a one mill per kilowatt-hour charge
(Vogtle Surcharge), also to be used to mitigate the effect of Plant Vogtle on
rates. In addition, two of Oglethorpe's Members, with the concurrence of REA,
elected to increase the level of this charge for their systems during this
period.

Pursuant to rate actions by Oglethorpe's Board of Directors, specified
amounts of deferred margins and Vogtle Surcharge were returned in 1989 through
1993 and will be returned in 1994. A summary of deferred margins and Vogtle
Surcharge as of December 31, 1993 and 1992 is as follows:

- ---------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993 1992
- ---------------------------------------------------------------------------

Deferred margins:
1985-90 $ 113,385 $ 113,385
1991 11,703 11,703
1992 40,464 40,464
1993 5,083 -
-------- --------
170,635 165,552
Vogtle Surcharge:
1986-87 36,613 36,613
-------- --------
Subtotal 207,248 202,165

Less: Amounts returned in:
1989-90 (80,602) (80,602)
1991 (31,990) (31,990)
1992 (41,058) (41,058)
1993 (5,738) (5,738)
1994 (26,777) -

-------- --------
Balance* $ 21,083 $ 42,777
-------- --------
-------- --------

* THE PORTION RELATING TO AMOUNTS PROVIDED VOLUNTARILY BY TWO OF OGLETHORPE'S
MEMBERS WAS APPROXIMATELY $3,320,000 OF THE BALANCE AT DECEMBER 31, 1993.

- ---------------------------------------------------------------------------

I. CASH AND TEMPORARY CASH INVESTMENTScash 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.

J. ENERGY COST BILLED IN EXCESS OF ACTUALOf the amount reported as cash and temporary cash investments at December 31,
1996, approximately $65,600,000 is restricted by RUS for the purpose of
prepaying certain Federal Financing Bank (FFB) long-term debt on or before March
31, 1997.

l. Inventories

Oglethorpe maintains inventories of fossil fuels for its generation plant and
spare parts for certain of its generation and transmission plant. These
inventories are stated at weighted average cost on the accompanying balance
sheets.

At December 31, 1996 and 1995, fossil fuels inventories were $23,062,000 and
$12,296,000, respectively. Inventories for spare parts at December 31, 1996 and
1995 were $66,763,000 and $70,653,000, respectively.

m. Deferred charges

Prior to 1996, Oglethorpe expensed nuclear refueling outage costs as
incurred. In 1996, Oglethorpe began accounting for these 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, 1996 were $12,961,000.

As a result of the availability of long-term capacity purchases at similar
costs but with reduced risks to Oglethorpe and its Members, Oglethorpe
determined that the Smarr Combustion Turbine Project was not needed within the
present planning horizon. Therefore, Oglethorpe is amortizing the accumulated
project costs in excess of the current value of the land purchased. The
remaining project costs of $6,445,000 are reflected as deferred charges on the
accompanying balance sheets. In 1995, Oglethorpe's wholesale power rate sets forthBoard of Directors authorized
that these project costs be amortized and fully recovered through future rates
over a period of 15 years beginning in that year.

n. Deferred credits

In October 1989, Oglethorpe sold to Georgia Power Company (GPC) a 24.45%
ownership interest in the mannerPlant Scherer common facilities as required under the
Plant Scherer Purchase and Ownership Agreement to adjust its ownership in the
Scherer units. Oglethorpe realized a gain on the sale of $50,600,000. RUS and
Oglethorpe's Board of Directors approved a plan whereby this gain was deferred
and was amortized over 60 months ending in September 1994.

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 accounts for the net benefits as a
deferred credit and

is amortizing the amount over the 20-year term of the leases.

In December 1996, Oglethorpe entered into long-term lease transactions for a
portion of its 74.6% undivided ownership interest in the Rocky Mountain Pumped
Storage Hydroelectric Project (Rocky Mountain). 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 $70,701,000 which energywas deferred and will be amortized to income
over the 30-year lease-back period. The lease transactions increased
Oglethorpe's Capitalization and Investments and funds by $41,685,000,
respectively (see Note 2 where discussed further).

In January 1997, Oglethorpe completed long-term lease transactions for the
remainder of its interest in Rocky Mountain resulting in a net benefit of
$24,859,000. The net benefit will be deferred and amortized to income over the
30-year term of the leases. Oglethorpe will increase Capitalization and
Investments and funds by $15,810,000, respectively.

o. Regulatory assets and liabilities

Oglethorpe is subject to the provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation."
Regulatory assets represent probable future revenues to Oglethorpe associated
with certain costs which will be recovered from Members through the rate-making
process. Regulatory liabilities represent probable future reduction in revenues
associated with amounts that are to be recovered from its Members.credited to Members through the
rate-making process. The rate in effect for 1993following regulatory assets and 1992 provided that an energy rate be determined basedliabilities were
reflected on projected costs and
kilowatt-hour sales and that the resulting rate be used to bill Members for a
six-month period. Actual energy costs were compared, on a monthly basis, to the
billed energy costs, and an adjustment to revenues was made such that energy
revenues were equal to actual energy costs. The offset to this adjustment is a
payable to or receivable from Members for over or under-collected energy costs.
The rate further provides that any cumulative over or under-collection for the
previous six-month period be utilized to adjust projected costs for the next
six-month period. Therefore, the amounts owed to Membersaccompanying balance sheets as of December 31, 19931996 and 19921995:

- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
- --------------------------------------------------------------------------------
Premium and loss on reacquired debt $ 201,007 $ 200,794
Deferred amortization of Scherer leasehold 90,717 87,134
Other regulatory assets 29,308 33,666
Net benefit of sale of income tax benefits (42,049) (50,194)
Net benefit of Rocky Mountain transactions (70,701) --
Deferred margins -- (32,047)
Energy costs -- 4,237
--------- ---------
$ 208,282 $ 243,590
========= =========
- --------------------------------------------------------------------------------

In the event that Oglethorpe is no longer subject to the provisions of
Statement No. 71, Oglethorpe would be required to write off related regulatory
assets and liabilities. In addition, Oglethorpe would be required to determine
any impairment to other assets, including plant, and write down the assets, if
impaired, to their fair value.

p. Presentation

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

2. Fair value of financial instruments:

A detail of the estimated fair values of Oglethorpe's financial instruments
as of December 31, 1996 and 1995 is as follows:

- ------------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
Fair Fair
Cost Value Cost Value
- ------------------------------------------------------------------------------------------------------------------------------------

Cash and temporary cash investments:
Commercial paper $ 52,700 $ 52,700 $ 179,055 $ 179,055
Certificates of deposit 10,000 10,000 20,000 20,000
Cash and money market
securities 70,083 70,083 2,096 2,096
---------- ---------- ---------- ----------
Total $ 132,783 $ 132,783 $ 201,151 $ 201,151
========== ========== ========== ==========
Other short term
investments:
Commingled
investment fund $ 91,712 $ 91,499 $ 76,180 $ 79,165
---------- ---------- ---------- ----------
Total $ 91,712 $ 91,499 $ 76,180 $ 79,165
========== ========== ========== ==========
Bond, reserve and construction funds:
U. S. Government
securities $ 36,505 $ 35,873 $ 49,348 $ 49,932
Repurchase agreements 18,082 18,082 6,579 6,579
---------- ---------- ---------- ----------
Total $ 54,587 $ 53,955 $ 55,927 $ 56,511
========== ========== ========== ==========
Decommissioning fund:
U. S. Government
securities $ 24,034 $ 23,950 $ 23,087 $ 23,568
Foriegn government
securities 1,228 1,278 -- --
Commercial paper -- -- 4,036 4,036
Corporate bonds 11,953 11,868 5,875 6,073
Equity securities 30,339 34,073 19,514 21,271
Asset-backed securities 3,103 3,125 12,484 12,614
Other bonds 5,445 5,453 -- --
Cash and money market
securities 6,522 6,522 6,937 6,930
---------- ---------- ---------- ----------
Total $ 82,624 $ 86,269 $ 71,933 $ 74,492
========== ========== ========== ==========
Long-term debt $4,118,117 $4,228,317 $4,207,320 $4,506,925
========== ========== ========== ==========
Interest rate swap $ -- $ 33,938 $ -- $ 52,089
========== ========== ========== ==========
- ------------------------------------------------------------------------------------------------------------------------------------

The contractual maturities of debt securities available for sale at December
31, 1996 and 1995, regardless of their balance sheet classification, are as
follows:

- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
Fair Fair
Cost Value Cost Value
- --------------------------------------------------------------------------------
Due within one year $33,944 $33,819 $21,050 $21,300
Due after one year through five years 17,439 17,266 37,172 37,452
Due after five years through ten years 27,912 27,302 27,628 27,966
Due after ten years 15,610 15,789 11,523 12,049
------- ------- ------- -------
$94,905 $94,176 $97,373 $98,767
======= ======= ======= =======
- --------------------------------------------------------------------------------

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.

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 was $199,690,000 and the fixed swap rate is 5.67%
(the variable rate at December 31, 1996 and 1995 was 4.00% and 5.15%
respectively). With respect to the Series 1994A notes, the notional principal
was $122,740,000 and the fixed swap rate is 6.01% (the variable rate at December
31, 1996 and 1995 was 4.00% and 5.05%, 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. The estimated fair value of Oglethorpe's liability
under the swap arrangements at December 31, 1996 and 1995 was $33,938,000 and
$52,089,000, respectively. This amount represents payment Oglethorpe would pay
if the swap arrangements were terminated. Oglethorpe may be exposed to losses in
the event of nonperformance of the counterparty, but does not anticipate such
nonperformance.

Oglethorpe adopted Statement of Financial Accounting Standards No. 115,
"Accounting for Certain Investments in Debt and Equity Securities," as of
January 1, 1994. Under this Statement, 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, 1996 were $7,785,000 and $4,985,000, respectively. Gross
unrealized gains and losses at December 31, 1995 were $6,497,000 and $368,000,
respectively. For 1996 and 1995, proceeds from sales of available-for-sale
securities totaled $425,772,000 and $438,643,000, respectively. Gross realized
gains and losses from the 1996 sales were $6,410,000 and
$3,671,000,respectively. Gross realized gains and losses from the 1995 sales
were $5,098,000 and $1,308,000, respectively.

Investments in associated organizations were as follows at December 31, 1996
and 1995:

- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
- --------------------------------------------------------------------------------
National Rural Utilities
Cooperative Finance Corp. (CFC) $13,476 $13,476
CoBank, ACB 1,664 2,132
Other 239 245
------- -------
Total $15,379 $15,853
======= =======
- --------------------------------------------------------------------------------

The investments in these associated organizations are similar to compensating
bank balances in that they are required in order to maintain current financing
arrangements. Accordingly, there is no market for these investments.

The $41,685,000 deposit on the Rocky Mountain transactions (see Note 1 where
discussed) as of December 31, 1996 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 fully intends to use the deposit to repurchase
tax ownership and to retain all other rights of ownership with respect to the
plant. The deposit is carried at cost.

In addition, from the proceeds of the Rocky Mountain transactions, Oglethorpe
paid $460,769,000 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 Member and non-Member activities.
Any Member taxable income has been offset with a patronage exclusion and member
loss carryforwards.

Oglethorpe accounts for its income taxes pursuant to Statement of Financial
Accounting Standards (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 1996, 1995 and 1994 is shown as
follows:

- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995 1994
- --------------------------------------------------------------------------------
Current
Federal $ 3,525 $ -- $ --
State -- -- --
------- ------- -------
3,525 -- --
------- ------- -------
Deferred
Federal (3,525) -- --
State -- -- --
------- ------- -------
(3,525) -- --
------- ------- -------
Income taxes charged
to operations $ -- $ -- $ --
======= ======= =======
- --------------------------------------------------------------------------------

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:

- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Patronage exclusion (35.7%) (35.6%) (35.4%)
Other 0.7% 0.6% 0.4%
------ ------ ------
Effective income tax rate 0.0% 0.0% 0.0%
====== ====== ======
- --------------------------------------------------------------------------------

The components of the net deferred tax liabilities as of December 31,
1996 and 1995 were as follows:

Net operating losses $ 473,114 $ 538,067
Member loss carryforwards 328,912 342,370
Tax credits (alternative minimum tax
and other) 256,205 252,680
Accounting for Rocky Mountain

transactions 233,045 --
Accounting for sale of income tax benefits 77,429 86,599
Accrued nuclear decommissioning expense 49,127 45,042
Accounting for asset dispositions 32,545 33,496
Other 3,318 18,277
----------- -----------
1,453,695 1,316,531
Less: Valuation allowance (252,680) (252,680)
----------- -----------
1,201,015 1,063,851
----------- -----------
Deferred tax liabilities
Depreciation (1,008,714) (1,034,153)
Accounting for Rocky Mountain
transactions (156,557) --
Accounting for debt extinguishment (64,841) (64,006)
Other (32,888) (31,202)
----------- -----------
(1,263,000) (1,129,361)
----------- -----------
Net deferred tax liabilities $ (61,985) $ (65,510)
=========== ===========
- --------------------------------------------------------------------------------

As of December 31, 1996, 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 Credits Tax Credits NOLs

1997 $ -- $ 11,197 $ --
1998 -- 6,934 --
1999 -- 37,206 --
2000 -- 3,198 --
2001 -- 7,264 --
2002 -- 130,377 --
2003 -- 652 242,187
2004 -- 55,663 114,285
2005 -- 189 213,080
2006 -- -- 209,009
2007 -- -- 86,779
2008 -- -- 94,927
2009 -- -- 96,394
2010 -- -- 77,970
None 3,525 -- --
-------- ---------- ----------
$ 3,525 $ 252,680 $1,134,631
======== ========== ==========
- --------------------------------------------------------------------------------

Based on Oglethorpe's historical taxable transactions, the timing of the
reversal of existing temporary differences, future income, and tax planning
strategies, it is more likely than not that Oglethorpe's future taxable income
will be sufficient to realize the benefit of NOLs before their respective
expiration dates. The NOLs expiration dates start in the year 2003 and end in
the year 2010. However, as reflected in the above valuation allowance, it is
more likely than not that the tax credits will not be utilized to reduce Member billings in 1994
and 1993, respectively.

2. CAPITAL LEASES:before
expiration. It is more likely than not that the AMT credit will be utilized.

4. 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 gain
from the sale is being amortized over the 36-year term of the leases. The
minimum lease payments under the capital leases together with the present value
of net minimum lease payments as of December 31, 19931996 are as follows:

- -----------------------------------------------------------------------------
YEAR ENDING DECEMBER 31, (DOLLARS IN THOUSANDS)
- -----------------------------------------------------------------------------

1994 $ 33,258
1995 36,016
1996 38,142
1997 35,239
1998 37,302
1999-2021 682,454
-------
Total minimum lease payments 862,411
Less: Amount representing interest (558,953)
-------
Present value of net
minimum lease payments $ 303,458
-------
-------

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 Scherer Unit No. 2. The
debt of three of the lessors is financed at fixed interest rates averaging
9.58%9.70%. As of December 31, 1993,1996, the variable interest rates of the debt of the
remaining lessor ranged from 5.93%6.40% to 8.25%8.05% for an average rate of 7.27%6.83%.
Oglethorpe's future rental payments under its leases will vary from amounts
shown in the table above to the extent that the actual interest rates associated
with the fixed and variable rate debt of the lessors vary from the 11.05% debt
rate assumed in the table.

The Scherer Unit No. 2 lease meets the definitional criteria to be reported
on Oglethorpe's balance sheets as a capital lease. For rate-making purposes,
however, Oglethorpe treats this lease as an operating lease; that is, Oglethorpe
considers the actual rental payment on the leased asset in its cost of service.
Oglethorpe's accounting treatment for this capital lease has been modified,
therefore, to reflect itits rate-making treatment. Interest expense is applied to
the obligation under the capital lease; then, amortization of the leasehold is
recognized, such that interest and amortization equal the actual rental payment.
Through 1994, the level of actual rental payments iswas such that amortization of
the Scherer Unit No. 2 leasehold calculated in this manner iswas less than zero.
Thereafter, the scheduled cash rental payments increase such that positive
amortization of the leasehold occurs and the entire cost of the leased asset is
recovered through the rate-making process. The difference in the amortization
recognized in this manner on the statements of revenues and expenses and the
straight-line amortization of the leasehold is reflected on Oglethorpe's balance
sheets as a deferred charge.

41
In 1991 and 1992, all four of the lessors received Notices of Proposed
Adjustments from the IRS proposing adjustments to the tax benefits claimed by
these lessors in connection with their purchase and ownership of an undivided
interest in Scherer Unit No.No 2. The proposed adjustments, if ultimately upheld,
would have the effect of reducing the lessors' tax benefits resulting from the
sale and leaseback transactions. The lessors filed responses contesting the
IRS's assertions as contained in the Notices of Proposed Adjustments.

In February 1994, the IRS issued a revised Notice of
Proposed Adjustments to one of the lessors which reduced the proposed
adjustmentsadjustments. During 1995, this lessor advised Oglethorpe that it had settled
this issue on the basis of the revised Notice of Proposed Adjustments.
Oglethorpe subsequently made a lump sum indemnity payment of $362,000 to the
lessor in order to compensate for the reduction in the lessor's tax benefits
claimed by this lessor in connection with its purchaseresulting from the sale and ownership of an
undivided interest in Scherer Unit No. 2.leaseback transaction. The IRS has indicated that it
will take consistent positions with the other three lessors. If the IRS's
current positions regarding the sale and leaseback transactions were ultimately
upheld, Oglethorpe would be required to indemnify the fourother three lessors.
Oglethorpe's potential indemnification liability in this eventto the three lessors is estimated to be
approximately $1,200,000 as of February 1994.

3. FAIR VALUE OF FINANCIAL INSTRUMENTS:

A detail of the estimated fair values of Oglethorpe's financial instruments$1,290,000 as of December 31, 1993 and 1992 is as follows:

- -----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993 1992
---------------- ----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- -----------------------------------------------------------------------------

Cash and temporary
cash investments $244,173 $244,173 $275,624 $275,624

Other short-term
investments -- -- 66,165 66,165

Bond, reserve
and construction funds 110,390 112,015 163,964 164,135

Decommissioning fund 56,911 56,686 47,921 48,508

Long-term debt 4,058,251 4,525,248 4,095,796 4,564,262
- -----------------------------------------------------------------------------

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 and other short-term investments, the carrying amount approximates
fair value because of the short-term maturity of those instruments. The fair
values of bond, reserve and construction funds and the decommissioning fund are
estimated based on quoted market prices for the investments held in the
respective funds. The fair value of Oglethorpe's long-term debt is estimated
based1996. This liability has been
reflected on the quoted market prices for the same or similar issues or on the
current rates offered to Oglethorpe for debt of similar maturities.

Investment in associated organizations was as follows at December 31, 1993
and 1992:

- --------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993 1992
- --------------------------------------------------------------------------------

National Rural Utilities
Cooperative Finance Corp. $ 13,476 $ 13,476
National Bank for Cooperatives 5,546 6,362
Other 101 71
---------- ----------
Total $ 19,123 $ 19,909
---------- ----------
---------- ----------
- --------------------------------------------------------------------------------

As a member of National Rural Utilities Cooperative Finance Corporation
(CFC), Oglethorpe was obligated to purchase CFC Capital Term Certificates
annually through 1984. Such certificates begin maturing in the year 2075 and
bear interest at 5%. As a borrower from the National Bank for Cooperatives
(CoBank), Oglethorpe is obligated to purchase capital stock in that bank. Under
CoBank's capitalization plan, Oglethorpe is required to maintain an investment
in the bank equal to 7%-13% of its five-year average loan volume with the bank.
The required investment of 1993 was 11.5% of Oglethorpe's five-year average loan
volume. It is not anticipated that Oglethorpe will be required to make any
additional investments during 1994. The investments in these associated
organizations are similar to compensating bank balances in that they are
required in order to maintain current financing arrangements. Accordingly, there
is no market for these investments.

4. BOND, RESERVE AND CONSTRUCTION FUNDS:

Bond, reserve and construction funds for pollution control bonds 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,
1993 and 1992, substantially all of the funds were invested in U.S. Government
securities.accompanying balance sheet.

5. LONG-TERM DEBT:

Long termLong-term debt:

Long-term debt consists of mortgage notes payable to the UnitesUnited States of
America acting through the FFB and the REA,RUS, mortgage notes issued in conjunction
with the sale by public authorities of pollution control revenue bonds, and
notes payable to CoBank. Oglethorpe's headquarters facility is pledged as
securitycollateral for the CoBank headquarters note; substantially all of the owned
tangible and certain of the intangible assets of Oglethorpe are pledged as
securitycollateral for the FFB and REARUS notes, the remaining CoBank notes and the notes
issued in conjunction with the sale of pollution control revenue bonds. The
detail of the notes is included in the statements of capitalization.

42
Oglethorpe currently has ten REA-guaranteedRUS-guaranteed FFB notes of which $3,040,767,000$3,172,851,000
and $3,111,160,000$3,253,636,000 were outstanding at December 31, 19931996 and 1992,1995, respectively,
with rates ranging from 6.61%5.27% to 10.95%9.51%. In March 1993,January 1996, Oglethorpe entered into two forward interest rate swap
arrangements obligatingcompleted
note modifications pursuant to which it repriced $89,447,000 of FFB advances. In
connection with such modification, Oglethorpe to sell $199,690,000paid a premium of variable rate
refunding bonds in$9,332,000.
These amounts are reported as deferred charges on the fall of 1993 and $122,740,000 of variable rate refunding
bonds in the fall of 1994, the proceeds of which, together with certain other
funds provided or to be provided by Oglethorpe, have beenbalance sheet, and will be
used in
January 1994 and January 1995, respectively, to refund certainamortized over 22 years, the longest remaining life of the subject advances.

In October 1996, Oglethorpe completed a current refunding transaction whereby
$37,885,000 of fixed rate pollution control revenue bonds previouslywere issued. At December 31, 1993, Oglethorpe accounted for
the pending January 1994 retirementThe
proceeds of $233,010,000this transaction were used to retire $37,885,000 of previously issued bonds
as an in-substance defeasance. Therefore, debt service reserve funds, bonds
payable, and the premium and loss on reacquired debt are stated as though the
event of retiring the refunded bonds had occurred in 1993.

In connection with the March 1993 swap transaction, Oglethorpe recorded
redemption premiums which, combined withexisting bonds.
The unamortized transaction costs totaled
$38,128,000. This amount hasrelated to this transaction have been reported
as a deferred charge on the balance sheetssheet and isare being or will be amortized over the life
of the related new
bonds.

Pursuant to the forward interest rate swap arrangements, Oglethorpe makes
payments to the counterparty based on the notional principal at a fixed rate and
the counterparty makes payments to Oglethorpe based on the notional principal
and on 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. For the fall 1993 transaction, the notional
principal was $199,690,000 and the fixed swap rate is 5.67% (the variable rate
at December 31, 1993 was 3.10%). With respect to the fall 1994 transaction,
the notional principal will be $122,740,000 and the fixed swap rate is 6.01%.
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.

The annual interest requirement for 1994, based upon all debt outstanding
at December 31, 1993, will1997 is estimated to be approximately $339,000,000.$294,000,000.

Maturities for the long-term debt through 19982001 are as follows:

- --------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1994 1995 1996 1997 1998
- --------------------------------------------------------------------------------

FFB and REA $56,224 $52,095 $57,725 $63,625 $69,008
CoBank 460 468 478 489 502
1978 Bonds 780 830 880 930 980
1982 Bonds 4,985 5,485 6,050 6,675 --
1984 Bonds 6,540 7,160 7,850 8,640 9,520
1984B Bonds 2,500 2,730 3,000 3,300 --
1985 Bonds 2,685 2,915 3,170 3,445 3,760
1992A Bonds 4,470 4,640 4,840 5,070 5,330
1992 Bonds -- -- -- -- 2,085
1993A Bonds -- -- -- -- 2,265
------- ------- ------- ------- -------
Total $78,644 $76,323 $83,993 $92,174 $93,450
------- ------- ------- ------- -------
------- ------- ------- ------- -------
- -----------------------------------------------------------------------------
- --------------------------------------------------------------------------------
(dollars in thousands) 1997 1998 1999 2000 2001
- --------------------------------------------------------------------------------
FFB and RUS $147,279 $ 86,894 $ 91,123 $ 98,867 $105,941
CoBank 376 502 516 532 550
PCB Bonds 7,880 17,970 19,730 23,995 26,260
Capital Leases 4,087 5,143 6,240 7,075 7,775
-------- -------- -------- -------- --------
Total $159,622 $110,509 $117,609 $130,469 $140,526
======== ======== ======== ======== ========
- --------------------------------------------------------------------------------

The estimated annual interest expense and the long-term debt maturities
described above do not take into account Oglethorpe's proposed corporate
restructuring, discussed in Note 11.

Oglethorpe has a commercial paper program under which it may issue commercial
paper not to exceed a $355,000,000$250,000,000 balance outstanding at any time. The
commercial paper may be used as a source of short-term fundsfor working capital requirements and is not
intended for any specific purpose.general
corporate purposes. Oglethorpe's commercial paper is backed 100% by a committed
linelines of credit provided by a group of banks for which Trust
Company Bank (Trust Company) acts as agent.banks.

As of December 31, 19931996 and 1992,1995, no commercial paper was outstanding.

Oglethorpe has arranged fora $50,000,000 uncommitted short-term linesline of credit with CoBank and CFC
and a $30,000,000 committed line of credit with Trust Company.SunTrust Bank, Atlanta
(SunTrust). The CoBank
line amounts to $70,000,000; the CFC line amounts to $50,000,000; and the Trust
Company line amounts to $30,000,000. The maximum combined amount that can be outstanding under these
lines of credit and the commercial paper program at any one time totals
$425,000,000$250,000,000 due to certain restrictions contained in the CFC and Trust
CompanySunTrust line
of credit agreements. No balance was outstanding on anyeither of these threetwo lines of
credit was outstanding at either December 31, 19931996 or 1992.

In January 1994, Oglethorpe completed a note modification pursuant to which
it repriced $590,909,000 of FFB advances. In connection with such modification,
Oglethorpe paid a premium of $50,745,000. This amount will be reported as a
deferred charge on the balance sheets1995.

6. Electric plant and will be amortized over 22 years, the
longest remaining life of the subject advances.

6. ELECTRIC PLANT AND RELATED AGREEMENTS: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
and transmission facilities. A summary of Oglethorpe's plant investments and
related accumulated depreciation as of December 31, 19931996 is as follows:

- -----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
ACCUMULATED
PLANT INVESTMENT DEPRECIATION
- -----------------------------------------------------------------------------

In-service:
Owned property:
VOGTLE UNITS NO. 1 & NO. 2
(NUCLEAR - 30% OWNERSHIP) $ 2,773,510 $ 453,918
HATCH UNITS NO. 1 & NO. 2
(NUCLEAR - 30% OWNERSHIP) 510,670 173,992
WANSLEY UNITS NO. 1 & NO. 2
(FOSSIL - 30% OWNERSHIP) 165,977 78,057

SCHERER UNIT NO. 1
(FOSSIL - 60% OWNERSHIP) 427,377 165,387
TALLASSEE (HARRISON DAM)
(HYDRO - 100% OWNERSHIP) 9,277 1,286
WANSLEY (COMBUSTION TURBINE-
30% OWNERSHIP) 3,665 955
TRANSMISSION AND
DISTRIBUTION PLANT 749,366 143,123
OTHER 108,972 27,146
Property under capital lease:
SCHERER UNIT NO. 2
(FOSSIL - 60% LEASEHOLD) 298,925 66,432
----------- -----------
Total in-service $ 5,047,739 $ 1,110,296
----------- -----------
----------- -----------

Construction work in progress:
ROCKY MOUNTAIN
(HYDRO - 70% OWNERSHIP*) $ 414,187
GENERATION IMPROVEMENTS 19,067
TRANSMISSION AND
DISTRIBUTION PLANT 16,287
OTHER 1,424
-----------
Total construction work in progress $ 450,965
-----------
-----------

* ESTIMATED OWNERSHIP PERCENTAGE AS OF DECEMBER 31, 1993. OWNERSHIP PERCENTAGE
AT PROJECT COMPLETION IS EXPECTED TO BE APPROXIMATELY 75%.
- -----------------------------------------------------------------------------
- --------------------------------------------------------------------------------
(dollars in thousands)
Accumulated
Plant Investment Depreciation
- --------------------------------------------------------------------------------
In-service
Owned property
Vogtle Units No. 1 & No. 2
(Nuclear - 30% ownership) $2,781,446 $ 665,953
Hatch Units No. 1 & No. 2
(Nuclear - 30% ownership) 523,163 208,687
Wansley Units No. 1 & No. 2
(Fossil - 30% ownership) 173,192 84,388
Scherer Unit No. 1
(Fossil - 60% ownership) 429,299 193,129
Rocky Mountain Units No. 1,
No. 2 & No. 3
(Hydro - 74.6% ownership) 556,470 17,401
Tallassee (Harrison Dam)
(Hydro - 100% ownership) 9,270 1,797
Wansley (Combustion Turbine -
30% ownership) 3,718 1,319
Generation step-up substations 55,877 19,173
Transmission and distribution plant 815,929 179,960
Other 94,002 25,060
Property under capital lease
Scherer Unit No. 2
(Fossil - 60% leasehold) 300,231 91,405
---------- ----------
Total in-service $5,742,597 $1,488,272
========== ==========
Construction work in progress
Generation improvements $ 11,963
Transmission and distribution plant 18,715
Other 503
----------
Total construction work in progress $ 31,181
==========
- --------------------------------------------------------------------------------

In 1988, Oglethorpe acquired from GPC an undivided ownership interest in
the Rocky Mountain Project, a pumped storage hydroelectric facility (Rocky
Mountain).Mountain. Under the Rocky Mountain agreements, Oglethorpe assumed
responsibility for construction of the facility, which construction was commenced by GPC.
Under the agreements, GPC retained its current investment in Rocky Mountain. TheMountain with
the ultimate ownership interests of Oglethorpe and GPC in the facility will be based on
the ratio of each party's direct construction costs to total project direct
construction costs with certain adjustments.

It is expected
thatOn June 1, 1995, Unit 3 and the completed Unit Common facilities were
declared to be in commercial operation by Oglethorpe. Unit 2 and Unit 1 were
declared to be in commercial operation on June 19, 1995 and July 24, 1995,
respectively. In accordance with the Rocky Mountain agreements, the final
ownership interests of Oglethorpe and GPC in Rocky Mountain atis 74.6% and 25.4%,
respectively. The final ownership interests in the project
completion will be approximately 75% and 25%, respectively. Rocky Mountain is
subjectapplied to
a license issued by FERC to Oglethorpe and GPC. This license requires
that construction be completed by June 1, 1996. The current schedule anticipates
commercial operation in early 1995. Rocky Mountain was approximately 90%
complete as of December 31, 1993.

Oglethorpe is financing its share of Rocky Mountain from the proceeds of an
REA-guaranteed loan funded through the FFB. As of December 31, 1993, a total of
approximately $459,000,000 remained available to be drawn as permanent financing
for Rocky Mountain. Such amount is considered more than adequate by Oglethorpe
to complete the project. The obligation to advance funds under the FFB loan
commitment, however, is subject to certain conditions, including the requirement
that Oglethorpe maintain an annual TIER of at least 1.0 and that the REA shall
not have determined that there has occurred any material adverse change in the
assets, liabilities, operations, or financial condition of Oglethorpe or any
circumstances involving the nature or operation of the business of Oglethorpe.
In management's opinion, no such material adverse change has occurred.all future capital costs.

Oglethorpe is engaged in a continuous construction program and, as of
December 31, 1993,1996, estimates property additions (including capitalized interest)
to be approximately $284,000,000$108,000,000 in 1994, $204,000,0001997, $98,000,000 in 19951998 and $148,000,000$100,000,000
in 1996,1999, primarily for construction of Rocky Mountain and replacements and additions to generation and transmission
facilities.

Primarily as a result of its ownership of a majority interest in Rocky
Mountain, Oglethorpe has determined that the Pickens County Pumped Storage
Hydroelectric Project is not needed within its present planning horizon.
Accordingly, Oglethorpe is amortizing the accumulated project costs in excess of
the value of the land purchased. The remaining unamortized project costs of
approximately $18,314,000 are reflected as deferred charges on the accompanying
balance sheets. Oglethorpe's Board of Directors has authorized that these
projects costs be amortized and fully recovered through future rates over a
period of 15 years beginning in 1992.

In April 1992, 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 accounts for the proceeds as a deferred
credit, sale of income tax benefits, and is amortizing the amount over the 20-
year term of the leases.

In October 1989, Oglethorpe sold to GPC a 24.45% ownership interest in the
Plant Scherer common facilities as required under the Plant Scherer Purchase and
Ownership Agreement to adjust its ownership in the Scherer units. Oglethorpe
realized a gain on the sale of $50,600,000. The REA and Oglethorpe's Board of
Directors approved a plan whereby this gain was deferred and is being amortized
over 60 months beginning in October 1989.

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.

7. INVENTORIES:

Oglethorpe maintains inventories of fossil fuels for its generation plant
and spare parts for certain of its generation and transmission plant. These
inventories are stated at weighted average cost on the accompanying balance
sheets.

For its co-owned generating plants, Oglethorpe accounts for inventories on
the basis of information furnished by its operating agent, GPC. GPC has
historically accounted for spare parts at its generating plants on an expensed-
as-purchased basis. Prior to the commercial operation of Vogtle Unit No. 1 in
1987, GPC established a spare parts inventory for that generating facility and
used an expensed-as-consumed method of inventory accounting. Subsequently, the
spare parts inventories at Plants Hatch, Wansley and Scherer were converted to
an expensed-as-consumed method. In connection with these conversions, other
income totaling $18,877,000 was recorded by Oglethorpe in 1988 and 1989.

In 1992, GPC completed a study the objective of which was to determine the
original accounting for spare parts inventory at all of its generating plants,
including Plants Hatch, Wansley and Scherer. As a result of this study,
Oglethorpe recorded an adjustment of $4,827,000 to the original conversion which
reduced other income and plant investment.

A detail of Oglethorpe's investment in inventories at December 31, 1993 and
1992 is as follows:

- -----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993 1992
- -----------------------------------------------------------------------------

Fossil fuels:
Plant Scherer $ 13,481 $ 15,366
Plant Wansley 2,264 7,733
Plant Wansley Combustion Turbine 96 113
Other generation plant fuel oils 361 121
------- -------
Total fossil fuels 16,202 23,333
------- -------

Spare parts:
Plant Vogtle 23,173 24,892
Plant Hatch 22,947 18,125
Plant Wansley 8,415 8,070
Plant Scherer 5,947 5,513
Plant Tallassee 86 86
Transmission plant 9,672 13,606
General plant 26 15
------- -------
Total spare parts 70,266 70,307
------- -------
Total inventories $ 86,468 $ 93,640
------- -------
------- -------

- -----------------------------------------------------------------------------

8. EMPLOYEE BENEFIT PLANS:Employee benefit plans:

Oglethorpe has a noncontributory defined benefit pension plan covering
substantially all employees. Oglethorpe's pension cost was approximately
$1,038,000$1,388,000 in 1993, $362,0001996, $1,954,000 in 19921995 and $1,113,000$1,262,000 in 1991.1994. For 1992,1995, pension
cost was reducedincreased by $539,000 by a net gain from a plan curtailment.$912,000 related to termination benefits. The plan
curtailmenttermination
benefits resulted from a workforce reductionan early retirement program undertaken in the secondfourth
quarter of 1992.1995. Plan benefits are based on years of service and the employee's
compensation during the last ten years of employment. Oglethorpe's funding
policy is to contribute annually an amount not less than the minimum required by
the Internal Revenue Code and not more than the maximum tax deductible amount.

The plan's funded status and pension cost recognized in 1996, 1995 and 1994 was shown as
follows:

- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995 1994
- --------------------------------------------------------------------------------
Pension cost was comprised of the
following
Service cost - benefits earned
during the year $ 1,149 $ 913 $ 1,084
Interest cost on projected benefit
obligation 872 742 714
Actual return on plan assets (984) (1,889) 387
Net amortization and deferral 351 1,288 (911)
Net gain from a plan curtailment -- (12) (12)
------- ------- -------
Net pension cost $ 1,388 $ 1,042 $ 1,262
======= ======= =======
- --------------------------------------------------------------------------------

The plan's funded status in Oglethorpe's financial statements as of December
31, 19931996 and 19921995 were as follows:

- -----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993 1992
- -----------------------------------------------------------------------------

Actuarial present value
of accumulated plan benefits:
Vested $ 5,237 $ 3,385
Nonvested 407 344
------ ------
$ 5,644 $ 3,729
------ ------
------ ------

Projected benefit obligation $(9,920) $(6,973)
Plan assets at fair value 6,911 6,364
------ ------
Projected benefit obligation in
excess of plan assets (3,009) (609)
Unrecognized net loss (gain) from
past experience different from
that assumed and effects of
changes in assumptions 390 (1,013)
Prior service cost not yet recognized
in net periodic pension cost 693 747
Unrecognized net asset at transition
date being recognized over 19 years (145) (158)
------ ------
Pension accrual $(2,071) $(1,033)
------ ------
------ ------

Pension cost was comprised of the
following:
Service cost -- benefits earned
during the year $ 884 $ 854
Interest cost on projected benefit
obligation 617 535
Actual return on plan assets (698) (424)
Net amortization and deferral 247 (64)
Net gain from a plan curtailment (12) (539)
------ ------
Net pension cost $ 1,038 $ 362
------ ------
------ ------

- -----------------------------------------------------------------------------
- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
- --------------------------------------------------------------------------------
Actuarial present value of accumulated
plan benefits
Vested $ 7,554 $ 6,868
Nonvested 540 591
-------- --------
$ 8,094 $ 7,459
======== ========
Projected benefit obligation $(13,211) $(12,326)
Plan assets at fair value 9,218 7,760
-------- --------
Projected benefit obligation in excess of
plan assets (3,993) (4,566)
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions (880) 223
Prior service cost not yet recognized in net
periodic pension cost 498 548
Unrecognized net asset at transition date
being recognized over 19 years (109) (121)
-------- --------
Pension accrual $ (4,484) $ (3,916)
======== ========
- --------------------------------------------------------------------------------

The discount rate and rate of increase in future compensation levels used in
determining the actuarial present value of the projected benefit obligations
shown above were 7.5%7.50% and 5.0% in 1993,1996, and 8.5%7.25% and 5.5%5.0% in 1992,1995,
respectively. The expected long-term rate of return on plan assets was 8.5% in
1996 and 1995, and 8% in 1993 and 1992,1994, and the discount rate used in determining the
pension expense was 7.25% in 1996, 8.5% in 19931995 and 1992.

7.5% in 1994.

Oglethorpe has a contributory employee thriftretirement savings plan covering
substantially all employees. Employee contributions to the plan may be invested
in one or more of threenine funds. The employee may contribute, subject to
IRSlimitations, up to 10%16% of his annual compensation. Oglethorpe will match the
employee's contribution up to one-half of the first 6% of the employee's annual
compensation, as long as there is sufficient net margin to do so. Oglethorpe's
contributions to the plan were approximately $503,000$561,000 in 1993,
$503,0001996, $589,000 in 19921995
and $491,000$565,000 in 1991.

In December 1990, the FASB issued Statement No. 106 on postretirement
benefits other than pensions. The new statement requires the accrual of the
expected cost of such benefits during the employees' years of service.
Oglethorpe has no postretirement benefits other than pensions available to
retirees.

9. NUCLEAR INSURANCE:1994.

8. Nuclear insurance:

GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member
of Nuclear Mutual Limited (NML), 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 participation in the mutual insurer). The portion of the current
maximum annual assessment for GPC that would be payable by Oglethorpe, based on
ownership share, adjusted for sell-back, is limited to approximately $8,600,000$6,351,000 for each nuclear
incident.

GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is also a
member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer, and
Oglethorpe has coverage with American Nuclear Insurers and Mutual Atomic Energy Liability
Underwriters,under NEIL II, which provideprovides insurance to cover
decontamination, debris removal and premature decommissioning as well as excess
property damage to nuclear generating facilities of up tofor an additional
$2,250,000,000 for losses in excess of the $500,000,000 NML coverage described
above. Under the NEIL policy,policies, members are subject to retroactive assessments
in proportion to their participation 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, adjusted for sell-back, is limited to approximately $8,000,000 for each nuclear incident.$12,960,000.

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 $9,400,000,000,$8,900,000,000, which amount
is to be covered by private insurance and agreements of indemnity with the NRC.
Such private insurance (in the amount of $200,000,000 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 $79,275,000 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 $89,320,000$95,130,000 per incident, but not more than $11,270,000$12,000,000 in
any one year.

Oglethorpe participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, Oglethorpe could be subject to a total
maximum assessment of $3,750,000.

10. POWER PURCHASE AGREEMENTS:$3,365,000.

All retrospective assessments, whether generated for liability or property,
may be subject to applicable state premium taxes.

9. Power purchase and sale agreements:

Oglethorpe has entered into long-term power purchase agreements with GPC, Big
Rivers Electric Corporation (Big Rivers), and Entergy Power, Inc. (EPI). Under
the agreement with GPC, Oglethorpe will purchasepurchased on a take-or-pay basis 1,250
megawatts (MW) of capacity through the period ending August 31, 1996. Effective
September 1, 1996, Oglethorpe will purchase 1,000 MW of capacity through the
period ending August 31, 1997. Effective September 1, 1997, Oglethorpe will
purchase 750 MW of capacity through the period ending August 31, 1998. Effective
September 1,1998, Oglethorpe will purchase 500 MW of capacity through the period
ending December 31, 2001,31,2004, subject to reductions or extension with proper notice.
The Big Rivers agreement commenced in August 1992 and is effective through July
2002. Oglethorpe is obligated under this agreement to purchase on a take-or-pay
basis 100 MW of firm capacity and certain minimum energy amounts associated with
that capacity. The EPI agreement commenced in July 1992, has a term of ten years
and represents a take-or-pay commitment by Oglethorpe to purchase 100 MW of
capacity.

The EPI
contract is subject to approval by REA.

Oglethorpe has a contract with Hartwell Energy Limited Partnership (Hartwell), a partnership 50% owned by Destec Energy, Inc. and 50% owned by
American National Power, Inc., a subsidiary of National Power, PLC, for the
purchase of approximately 300 MW of capacity from two 150 MW gas-fired turbine
generating units, now under construction, for a 25-year period commencing no
later than Junein
April 1994.

Oglethorpe has entered into a short-term seasonal power purchase agreement
with Florida Power Corporation. Under the termsagreement, Oglethorpe will purchase 50
MW of this contract, Oglethorpe does not have
responsibilitycapacity on a take-or-pay basis for constructing or financing this project.

the period June 1, 1997 through
September 30, 1997 and 275 MW for the period June 1, 1998 through September 30,
1998.

As of December 31, 1993,1996, Oglethorpe's minimum purchase commitments under the
above agreements, without regard to capacity reductions or adjustments for
changes in costs, for the next five years are as follows:

- --------------------------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
1997 $ 130,457
1998 111,539
1999 92,873
2000 94,917
2001 97,116
- --------------------------------------------------------------------------------
Year Ending December 31. (dollars in thousands)
- --------------------------------------------------------------------------------

1994 $ 140,009
1995 150,956
1996 154,976
1997 159,296
1998 163,311
- --------------------------------------------------------------------------------

Oglethorpe's power purchases from these agreements amounted to approximately
$192,059,000$190,760,000 in 1993, $192,321,0001996, $206,641,000 in 19921995 and $88,500,000$182,965,000 in 1991.

11. QUARTERLY FINANCIAL DATA (UNAUDITED)1994.

Oglethorpe has entered into an agreement with Alabama Electric Cooperative to
sell 100 MW of

capacity for the period June 1998 through December 2005.

As a means of reducing the cost of power provided to the Members, in 1996,
Oglethorpe utilized short-term power supply agreements. The initial agreement
was with Enron Power Marketing, Inc. and was in place from January 4, 1996
through August 31, 1996. From September 1, 1996 through December 31, 1996,
Oglethorpe utilized a short-term power supply transaction with Duke/Louis
Dreyfus L.L.C. Under both of the agreements, the power marketer was required to
provide to Oglethorpe at a favorable fixed rate all the energy necessary to meet
the Members' requirements and Oglethorpe was required to provide to the power
marketer at cost, subject to certain limitations, upon request all energy
available from Oglethorpe's total power resources. Under both agreements,
Oglethorpe continued to operate the power supply system and continued to
dispatch the generating resources to ensure system reliability.

10. Quarterly financial data (unaudited):

Summarized quarterly financial information for 19931996 and 19921995 is as follows:

- --------------------------------------------------------------------------------
First Second Third Fourth
(dollars in thousands) Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
1996
Operating revenues $270,689 $275,228 $286,648 $ 268,872
Operating margin 73,568 72,514 75,009 61,658
Net margin 8,988 4,732 12,508 (4,476)

1995
Operating revenues $257,547 $281,228 $317,536 $ 293,250
Operating margin 68,682 82,048 82,949 74,998
Net margin 8,462 20,292 10,656 (17,152)
- --------------------------------------------------------------------------------
First Second Third Fourth
(dollars in thousands) Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
1993

Operating revenues $272,143 $283,319 $284,737 $260,461
Operating margin 93,807 85,945 76,515 68,025
Net margin 30,090 10,020 (43) (14,346)

1992
Operating revenues $260,817 $272,307 $290,845 $260,794
Operating margin 97,630 91,331 93,455 92,375
Net margin 21,083 15,899 20,387 (29,897)
- --------------------------------------------------------------------------------

Oglethorpe's business is influenced by seasonal weather conditions. Second
quarter 1996 net margin was lower than the same period of 1995 primarily as a
result of unbudgeted savings in 1995 from the continued capitalization of costs
of Rocky Mountain due to delay in commercial operation of the initial unit from
April 1995 to June 1995.

The negative net margin for the fourth quarter of 1993 was attributable to the
deferral of excess margins1996 is consistent with
expectations and to thereflects incurrence of certain non-recurringnonrecurring expenses.

The negative net margin for the same periodfourth quarter of 19921995 was primarily
dueattributable to the deferral of excess margins.margin. For a discussion of the amountsamount of
excess marginsmargin deferred, see Note 1.

4711. Subsequent events:

a. Power supply arrangements

Oglethorpe has entered into power supply agreements for approximately 50% of
its Members' load requirements with LG&E Power Marketing Inc. These agreements
commenced on January 1, 1997, initially on a short-term basis. These agreements
converted to a long-term arrangement upon the closing of the Corporate
Restructuring discussed below. Oglethorpe is now working to complete a long-term
contract for the remaining approximately 50% of its load.

b. Corporate restructuring

Oglethorpe and the Members completed on March 11, 1997, a corporate
restructuring (the Corporate Restructuring). Pursuant to the Corporate
Restructuring, Oglethorpe divided itself into three specialized companies to
respond to increasing competition and deregulation in the electric industry. As
part of the Corporate Restructuring, Oglethorpe transferred its transmission
business and assets to a newly formed Georgia electric membership corporation,
Georgia Transmission Corporation (An Electric Membership Corporation) (GTC), and
transferred its system operations business to a newly formed Georgia nonprofit
corporation, Georgia System Operations Corporation (GSOC). Oglethorpe retained
its generation business and owned and leased generation assets.

The following unaudited pro-forma balance sheet as of December 31, 1996
reflects the financial position of Oglethorpe as reported and as restated
reflecting the exclusion of the transmission business as though the Corporate
Restructuring had occurred at December 31, 1996.

The following unaudited pro-forma statement of revenues and expenses for the
year ended December 31, 1996 reflects the operations of Oglethorpe as reported
and as restated, reflecting the exclusion of the transmission business as though
the Corporate Restructuring had occurred at the beginning of 1996.

These unaudited pro-forma financial statements have been prepared based on
assumptions and estimates deemed appropriate and are presented for illustrative
purposes only and are not necessarily indicative of the financial position or
results of operations which would have actually been reported had the
transactions occurred in the period reported.

The columns titled Oglethorpe post-restructuring in the following unaudited
pro-forma financial statements have been restated reflecting the exclusion of
the system operations business as though the Corporate Restructuring had
occurred in the period reported. The system operations business is not shown
separately due to immateriality.

Pro-Forma Balance Sheet
(Unaudited)
As of December 31,1996
(dollars in thousands)

- ------------------------------------------------------------------------------------------------------------------------------------
Oglethorpe Transmission
Oglethorpe Pro-Forma Pro-Forma
(Pre- (Post- (Post-
Restructuring) Restructuring) Restructuring)
- ------------------------------------------------------------------------------------------------------------------------------------

Assets
Electric plant, at original cost:
In service $ 5,742,597 $ 4,908,752 $ 815,929
Less: Accumulated provision for depreciation (1,488,272) (1,299,328) (179,960)
----------- ----------- -----------
4,254,325 3,609,424 635,969
Nuclear Fuel, at amortized cost 86,722 86,722 --
Plant acquisition adjustments, at amortized cost 4,153 -- 8,780
Construction work in progress 31,181 12,466 18,715
----------- ----------- -----------
4,376,381 3,708,612 663,464
----------- ----------- -----------
Investments and funds 197,288 200,812 --
----------- ----------- -----------
Current assets:
Cash and temporary cash investments, at cost 224,282 245,424 --
Receivables 113,289 113,289 --
Inventories, at average cost 89,825 84,018 5,807
Prepayments and other current assets 14,625 14,264 361
----------- ----------- -----------
442,021 456,995 6,168
----------- ----------- -----------
Deferred charges:
Premium and loss on reacquired debt,
being amortized 201,007 169,081 31,926
Deferred debt expense, being amortized 21,703 18,256 3,447
Other 123,775 123,775 --
----------- ----------- -----------
346,485 311,112 35,373
----------- ----------- -----------
$ 5,362,175 $ 4,677,531 $ 705,005
=========== =========== ===========
Equities and Liabilities
Capitalization:
Patronage capital and membership fees $ 356,229 $ 356,229 $ --
Long-term debt 4,052,470 3,380,581 688,878
Obligations under capital leases 293,682 293,682 --
Obligations under Rocky Mountain
transactions 41,685 41,685 --
----------- ----------- -----------
4,744,066 4,072,177 688,878
----------- ----------- -----------
Current liabilities:
Long-term debt and capital leases due
within one year 159,622 144,565 15,057
Accounts payable 42,891 41,788 --
Accrued interest 15,931 15,931 --
Accrued and witheld taxes 4,940 4,940 --
Other current liabilities 14,022 12,799 1,070
----------- ----------- -----------
237,406 220,023 16,127
----------- ----------- -----------
Deferred credits and other liabilities 380,703 385,331 --
----------- ----------- -----------
$ 5,362,175 $ 4,677,531 $ 705,005
=========== =========== ===========
- ------------------------------------------------------------------------------------------------------------------------------------

Pro-Forma Statement of Revenues and Expenses
(Unaudited)
For the year ended December 31,1996
(dollars in thousands)

Operating revenues:
Sales to Members $ 1,023,094 $ 927,156 $ 95,938
Sales to non-Members 78,343 68,554 9,789
----------- ----------- -----------
Total operating revenues 1,101,437 995,710 105,727
----------- ----------- -----------
Operating expenses:
Fuel 206,524 206,524 --
Production 129,178 129,178 --
Purchased power 229,089 229,089 --
Power delivery 18,216 -- 18,216
Depreciation and amortization 163,130 138,008 25,122
Taxes other than income taxes 30,262 22,728 7,534
Other operating expenses 42,289 33,307 8,982
----------- ----------- -----------
Total operating expenses 818,688 758,834 59,854
----------- ----------- -----------
Operating margin 282,749 236,876 45,873
----------- ----------- -----------
Other income (expense):
Interest income 23,485 20,129 3,356
Amortization of deferred margins 32,047 29,336 2,711
Allowance for equity funds used during
construction 238 114 124
Other 9,564 10,270 (706)
----------- ----------- -----------
Total other income 65,334 59,849 5,485
----------- ----------- -----------
Interest charges:
Interest on long-term debt and other obligations 328,907 279,542 49,365
Allowance for debt funds used during
construction (2,576) (1,231) (1,345)
----------- ----------- -----------
Net interest charges 326,331 278,311 48,020
----------- ----------- -----------
Net margin $ 21,752 $ 18,414 $ 3,338
=========== =========== ===========
- ------------------------------------------------------------------------------------------------------------------------------------

The above pro-forma balance sheet reflects the transfer of the transmission
and system operations businesses, and the related financing activities related
to the transfer based on the purchase price formula. In connection with the
Corporate Restructuring, Oglethorpe also made a special patronage capital
distribution to the Members totaling $48,863,000 which was used by the Members
to establish equity in and to provide initial working capital to GTC.

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 judgementsjudgments 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
its qualified internal audit staff. The Corporation's independent public
accountants (Arthur Andersen(Coopers & Co.Lybrand L.L.P.) 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.

Arthur AndersenCoopers & Co.Lybrand L.L.P. 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 flowflows
of Oglethorpe Power Corporation.

/s/T.D. Kilgore

T.D.T. D. Kilgore
President and Chief Executive Officer

/s/Eugen Heckl

Eugen Heckl
Senior Vice President and
Chief Financial Officer

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors of Oglethorpe Power Corporation:

We have audited the accompanying balance sheets and statements of
capitalization of Oglethorpe Power Corporation (a Georgia corporation) as of
December 31, 19931996 and 19921995 and the related statements of revenues and expenses,
patronage capital, and cash flows for each of the three years in the period
ended December 31, 1993.then ended. These financial
statements and the schedules referred
to below are the responsibility of Oglethorpe's management. Our responsibility
is to express an opinion on these financial statements and schedules based on our audits.

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

In our opinion, the financial statements (pages 33 through 47) referred to above present fairly, in
all material respects, the financial position of Oglethorpe Power Corporation as
of December 31, 19931996 and 19921995 and the results of its operations and its cash
flows for eachthe years then ended in conformity with generally accepted accounting
principles.

Coopers & Lybrand L.L.P.

Atlanta, Georgia,

February 21, 1997, except for Note 11, as to which the date is March 11,
1997.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To the Board of Directors of Oglethorpe Power Corporation:

We have audited the three years instatement of revenues and expenses, patronage capital,
and cash flows of Oglethorpe Power Corporation (a Georgia corporation) for the
periodyear ended December 31, 19931994. These financial statements are the responsibility
of Oglethorpe's management. Our responsibility is to express an opinion on these
financial statements based on our audit.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the results of operations, changes in patronage capital,
and cash flows of Oglethorpe Power Corporation for the year ended December 31,
1994 in conformity with generally accepted accounting principles.

As explained in Note 12 of notes to financial statements, effective January 1,
1993,1994, Oglethorpe Power Corporation changed its method of accounting for income taxes.

Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listedcertain
investments in the index in Item
14 are presented for purposes of complying with the Securitiesdebt and Exchange
Commission's rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the audits
of the basic financial statements and, in our opinion, fairly state in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.

/s/equity securities.

Arthur Andersen & Co.
Arthur Andersen & Co.LLP

Atlanta, Georgia,
February 11, 1994.

4824, 1995.

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

None.

PART III

ITEMItem 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

(a) IDENTIFICATION OF DIRECTORS:Identification of Directors:

As part of the Corporate Restructuring, Oglethorpe amended its Bylaws
to provide for an eleven member board of directors consisting of six directors
elected from the Members (the "Member Directors"), four independent outside
directors (the "Outside Directors") and Oglethorpe's President and Chief
Executive Officer. The Member Directors must be a director or general manager of
an Oglethorpe Member. Five of the six Member Directors must be located in one of
five geographical regions of the State of Georgia. The sixth Member Director is
governedelected statewide. The four Outside Directors must not be a director, officer or
employee of Oglethorpe or any Member. All eleven 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 Boardmajority vote of 39each Member, voting on a one-Member,
one-vote basis.

All of the new directors have been elected with terms beginning on
March 11, 1997, except for two of the four Outside Directors 13which are expected
to be elected at the annual meeting of whom areMembers on March 27, 1997. The Bylaws
provide for staggering the terms of the directors by dividing the number of
directors into three groups. As noted below, some of the directors were elected
eachto an initial term of 1 year, some 2 years and some 3 years. As these initial
terms expire, directors will thereafter be elected for a three-year term. Eachterm of the 39 Members nominates one Director
who must also be on the Member's Board of Directors.three years.

The Directors are then
elected by the Members at their annual meeting. The Members also elect Alternate
Directors. Each Alternate Director must serve as the manager of a Member to be
eligible to serve as an Alternate Director. Under Oglethorpe's Bylaws, Alternate
Directors may attend all Board meetings, but can be counted for quorum purposes
and can exercise the powers and duties of a Director only during the period when
the directorship for whom he is the alternate is vacant or at any meeting of the
Board of Directors when the Director for whom he is the alternate is absent. The
Board of Directors generally meets monthly.

Six standing committees are appointed by the Chairman of the Board and
include both Directors and Alternate Directors. Two of these Committees, the
External Affairs Committee and the Human Resources Management Committee, are
joint committees of Oglethorpe and Georgia Electric Membership Corporation
("GEMC"), an affiliated trade organization, and include directors of GEMC.
Special committees, as deemed necessary, are also appointed by the Chairman of
the Board or the Board of Directors. Committee recommendations and management
recommendations, subject to the approval of the Board of Directors, determine
the policies and activities of Oglethorpe.

The Directors and Alternate Directors of Oglethorpe are as follows:

ALTAMAHA EMC

Jmon Warnock--Director,Larry N. Chadwick, age 68, is a farmer. He has served on the Board of
Directors of Oglethorpe since September 1974. His present term as a Director
will expire in March 1995. He is a member of the Finance Committee of
Oglethorpe. Mr. Warnock56, is the President of Altamaha EMC and aMember Director of GEMC.

James D. Musgrove--Alternate Director, age 47, isfrom the General Manager of
Altamaha EMC.Northwest
Region. He has served as an Alternate Director of Oglethorpe since May
1989, with his present term to expire in March 1995. Mr. Musgrove is a Director
of Montgomery County Bankshares in Ailey, Georgia.

AMICALOLA EMC

Charles R. Fendley--Director, age 48, is a Vice-President of Jasper Yarn
Processing, Inc., which processes yarn. He has served on the Board of Directors
of Oglethorpe since November 1993, with his present term to expire in March
1995. Mr. Fendley is the President of Amicalola EMC. He is also a Director of
GEMC and a Director of Crescent Bank & Trust Co. in Jasper, Georgia.

John S. Dean, Sr.--Alternate Director. For a description of Mr. Dean's
background and experience, see "Identification of Executive Officers and Senior
Executives" below.

CANOOCHEE EMC

George C. Martin--Director, age 76, is the owner and operator of a farm in
Ellabell, Bryan County, Georgia where he raises beef cattle. He also manages
timberland in Bryan County, Georgia and rental properties in Savannah and
Pembroke, Georgia. He has served on the Board of Directors of Oglethorpe since
March 1977, with his present term to expire in March 1995. From March 1978 to
March 1984, he served as Vice President of Oglethorpe.

Donald F. Kennedy--Alternate Director, age 64, is the General Manager of
Canoochee EMC. He has served as an Alternate Director of Oglethorpe since 1985,
with his present term to expire in March 1995. He is a member of the
GEMC/Oglethorpe External Affairs Committee. Mr. Kennedy is also a Director of
the Tattnall Bank in Reidsville, Georgia.

CARROLL EMC

J. G. McCalmon--Director, age 76, is the owner of a farm in Carrollton,
Georgia, where he raises chickens and beef cattle. He has served on the Board of
Directors of Oglethorpe since September 1974, with his present term to expire in
March 1996. He is Chairman of the Board of Carroll EMC. Mr. McCalmon is also a
Director of GEMC, a Director of the Farm Bureau, a Director of Carroll County
Sales Barn, and a Director of the Carroll County Chamber of Commerce.

Gary M. Bullock--Alternate Director, age 52, is President and Chief
Executive Officer of Carroll EMC. He has served as an Alternate Director of
Oglethorpe since June 1978, and his present term will expire in March 1996. He
is a member of the Operations Committee. Mr. Bullock is also the Secretary of
Southeastern Data Cooperative, Inc., a member of the Institute of Electrical and
Electronic Engineers, a Trustee for the GEMC Workers' Compensation Fund, a
Director for the Georgia Council of Farmer Cooperatives, a Director of the
Carroll County Chamber of Commerce, and a Director of Carrollton Federal Savings
& Loan Association in Carrollton, Georgia.

CENTRAL GEORGIA EMC

D. A. Robinson, III--Director, age 53, is the owner and operator of a dairy
farm in Griffin, Georgia. He has served on the Board of Directors of Oglethorpe
since March 1984, and his term will expire in March 1995. He serves as
Secretary-Treasurer of Central Georgia EMC.

George L. Weaver--Alternate Director, age 46, has been the President of
Central Georgia EMC since 1989. Prior to that time he was General Manager,
Manager of Accounting, and Financial Manager. He has served as an Alternate
Director of Oglethorpe since 1983, and his present term will expire in March
1995. He is a member of the Operations Committee. He is also a Director of
Federated Rural Electric Insurance Corporation in Shawnee Mission, Kansas and
serves on the Advisory Board of NationsBank of GA, N.A.

COASTAL EMC

James E. Estes--Director, age 58, has served on the Board of Directors of
Oglethorpe since March 1982, with his present term to expire in March 1994. He
is a member of the Executive Committee. He is also Vice President of the Board
of Directors of Coastal EMC. Additionally, he works in avionic maintenance for
Georgia Air National Guard, is President of Ways Company, Inc., a real estate
development company in Richmond Hill, Georgia, and is a proprietor of Estes Tax
Service, an income tax service in Richmond Hill, Georgia.

Wayne Collins--Alternate Director, age 43, is the General Manager of
Coastal EMC and has served as an Alternate Director of Oglethorpe since March
1977. His present term as an Alternate Director will expire in March 1994.

COBB EMC

Larry N. Chadwick--Director, age 53, is the owner of Chadwick's Hardware in Woodstock, Georgia. He has
served on the Board of Directors of Oglethorpe since July 1989, with his1989. His present term
towill expire in March 1995.1999. Mr. Chadwick is an engineer, with experience in the
design of hydrogen gas plants. He is Chairman of the Board of Cobb EMC.

HeBenny W. Denham, age 66, is the Vice Chairman of the Operations Committee.

Dwight Brown--AlternateBoard and is the
Member Director age 48, is President and Chief
Executive Officer of Cobb EMC. He previously served as Vice President of
Engineering and Operations for Cobb EMC. Hefrom the Southwest Region. Mr. Denham has served as an Alternate Directorexecutive
officer of Oglethorpe since October 1993, with his present term to expire in March 1995.

COLQUITT EMC

Simmie King--Director, age 50, is the owner and operator of a farm.1993. He has served on the Board of Directors
of Oglethorpe since March 1991, with his
present term to expire in March 1996.

R. L. Gaston--Alternate Director, age 46, is the General Manager of
Colquitt EMC. From January 1985 to January 1990, he was Manager of Engineering
and Operations for Colquitt EMC. He has served as an Alternate Director of
Oglethorpe since February 1990, with his present term to expire in March 1996.
He is currently a member of the Planning and Construction Committee.

COWETA-FAYETTE EMC

W. F. Farr--Director, age 81, is a banker. He has served on the Board of
Directors of Oglethorpe since March 1975, with his present term to expire in
March 1995. He is currently the Chairman of the GEMC/Oglethorpe Human Resources
Management Committee. He has been President of Coweta-Fayette EMC since 1974. He
previously served as President of the Fayette State Bank in Peachtree City,
Georgia and as a Director and Consultant for Citizens and Southern National
Bank, South Metro Board in Atlanta, Georgia. Since June 1985, he has been the
owner and President of Pioneer Financial Associates, Inc. in Peachtree City,
Georgia.

Michael C. Whiteside--Alternate Director, age 51, has been General Manager
of Coweta-Fayette EMC since August 1983. He previously served as Administrative
Assistant of Coweta-Fayette EMC. He has served as an Alternate Director of
Oglethorpe since September 1983, with his present term to expire in March 1995.
He is currently a member of Oglethorpe's Planning and Construction Committee.

EXCELSIOR EMC

Vacant--Director

Gary T. Drake--Alternate Director, age 45, is the General Manager of
Excelsior EMC. He has served as an Alternate Director of Oglethorpe since
January 1979, with his present term to expire in March 1994. He was
Secretary-Treasurer of Oglethorpe from March 1984 through March 1989. He is
currently a member of the Operations Committee. Mr. Drake is also a Director of
GEMC and a Director of Pineland State Bank in Metter, Georgia.

FLINT EMC

Jeff S. Pierce, Jr.--Director, age 62, has served on the Board of Directors
of Oglethorpe since June 1992, with his present term to expire in March 1994.
He has served as a Director of Flint EMC since 1964. He previously served 28
years as Chief Executive Officer and as a Director for the First Federal
Savings and Loan Association in Warner Robins, Georgia. He is also a Director
of GEMC.

Harold B. Smith--Alternate Director, age 57, has been employed as General
Manager of Flint EMC since November 1978. He has served as an Alternate Director
of Oglethorpe since 1978, with his present term to expire in March 1994. He is
currently a member of the Planning and Construction Committee of Oglethorpe and

Chairman of the GEMC/Oglethorpe External Affairs Committee. Mr. Smith is also
the Chairman of the Board of the Food and Energy Council.

GRADY EMC

Donald C. Cooper--Director, age 63, is the owner, operator and President of
Cooper Farms, Inc., a farm in Grady County, Georgia where he grows row crops and
raises cattle. He has served on the Board of Directors of Oglethorpe since March
1975, with his present term to expire in March 1996.

Thomas A. Rosser--Alternate Director, age 46, has been employed as General
Manager of Grady EMC since January 1992. He has served as an Alternate Director
of Oglethorpe since January 1992, with his present term to expire in March 1996.
Mr. Rosser is also a Director of the Cairo Banking Company in Cairo, Georgia.

GREYSTONE POWER CORPORATION, AN EMC

J. Calvin Earwood--Director. For a description of Mr. Earwood's background
and experience, see "Identification of Executive Officers and Senior Executives"
below.

Tim B. Clower--Alternate Director, age 57, is President and Chief Executive
Officer of GreyStone Power Corporation, an EMC. He has served as an Alternate
Director of Oglethorpe since September 1974, with his present term to expire in
March 1995. Mr. Clower serves on the Boards of Directors of Citizens & Merchants
State Bank and GEMC Workers' Compensation Fund.

HABERSHAM EMC

Herbert Church--Director, age 57, is a logging contractor. He has served on
the Board of Directors of Oglethorpe since August 1991, with his present term to
expire in March 1996. He has been a Director of Habersham EMC since 1977.

William E. Canup--Alternate Director, age 58, is the General Manager of
Habersham EMC. Mr. Canup was Manager of Engineering/Operations of Habersham EMC
from 1979 to 1984 and served as Assistant Manager of Habersham EMC from 1984 to
1986. He has served as an Alternate Director of Oglethorpe since July 1986, with
his present term to expire in March 1996.

HART EMC

Mac F. Oglesby--Director, age 61, served as Assistant Secretary-Treasurer
of Hart EMC from July 1986 through December 1987, when he was appointed
President. He has served as a Director of Oglethorpe since February 1987, with
his present term to expire in March 1994. He is currently a member of the
Planning and Construction Committee of Oglethorpe. He also was a U.S. Postal
Service Rural Carrier for 30 years.

Grooms Johnson--Alternate Director, age 64, has been the General Manager
of Hart EMC since March 1991. Prior to that time, he served as Assistant Manager
of Hart EMC. He has served as an Alternate Director of Oglethorpe since March
1991, with his present term to expire in March 1994. Mr. Johnson is also a
Director of Bank of Hartwell in Hartwell, Georgia.

IRWIN EMC

Benny W. Denham--Director. For a description of Mr. Denham's background and
experience, see "Identification of Executive Officers and Senior Executives"
below.

Harold Randall Crenshaw--Alternate Director, age 42, has been the General
Manager of Irwin EMC since February 1988. He has served as an Alternate Director
of Oglethorpe since February 1988, with his present term to expire in March
1995. He is a member and past Vice Chairman of the Finance Committee of
Oglethorpe.

JACKSON EMC

E. L. McLocklin--Director, age 81, is a cattle farmer. He is also Chairman
of the Board of Directors of Jackson EMC. He has served as a Director of
Oglethorpe since October 1989, with his present term to expire in March 1996.

Randall Pugh--Alternate Director, age 50, is President and Chief Executive
Officer of Jackson EMC. From August 1984 to January 1988 he was General Manager
of Jackson EMC. He was also General Manager of Walton EMC from 1977 to August
1984. He has served as an Alternate Director of Oglethorpe since 1977. His
present term as Alternate Director will expire in March 1996. He is currently
the Chairman of the Finance Committee. Mr. Pugh is also a Director of the First
National Bank of Jackson County in Gainesville, Georgia.

JEFFERSON EMC

Sam Rabun--Director, age 62, is part owner of a livestock farm. He has
served as a Director of Oglethorpe since March 1993 with his present term to
expire in March 1996. Mr. Rabun is the President of Jefferson EMC.

Ralph E. Lewis--Alternate Director, age 49, has been the General Manager of
Jefferson EMC since 1979. He has served as an Alternate Director of Oglethorpe
since 1979, with his present term to expire in March 1996. He is also Vice
President of the GEMC Workers' Compensation Fund.

LAMAR EMC

E. J. Martin, Jr.--Director, age 66, is the owner of the Country Kitchen
restaurant in Barnesville, Georgia. He is a retired tax assessor and appraiser
for Lamar County. He has served on the Board of Directors of Oglethorpe since
March 1982, with his present term to expire in March 1994. He is a member of the
GEMC/Oglethorpe Human Resources Management Committee. Mr. Martin is the
President of Lamar EMC and a Director of GEMC.

J. Raleigh Henry--Alternate Director, age 43, is General Manager of Lamar
EMC. Prior to becoming General Manager, he served as Office Manager of Lamar
EMC. He has served as an Alternate Director of Oglethorpe since 1990, with his
present term to expire in March 1994.

LITTLE OCMULGEE EMC

J. D. Williams--Director, age 81, is currently retired. He has served on
the Board of Directors of Oglethorpe since March 1986, with his present term to
expire in March 1994. He is a member of Oglethorpe's Planning and Construction
Committee. He previously served as President, then as Vice President of Little
Ocmulgee EMC. Mr. Williams is also a Director of Security State Bank in McRae,
Georgia, and a Director of Farmers State Bank in Dublin, Georgia.

A. Arnold Horton--Alternate Director, age 47, is the General Manager of
Little Ocmulgee EMC. He previously served as Manager of Engineering and
Operations, and has been with Little Ocmulgee EMC since 1983. He has served as
the Alternate Director of Oglethorpe since March 1993, with his present term to
expire in March 1994.

MIDDLE GEORGIA EMC

Ronnie Fleeman--Director, age 59, is a self-employed land and timber
developer. He has served on the Board of Directors of Oglethorpe since 1990. His
present term as a Director will expire in March 1995. He is a member of the
GEMC/Oglethorpe Human Resources Management Committee.

Charles Hugh Richardson--Alternate Director, age 40, has been General
Manager of Middle Georgia EMC since June 1983. From January 1983 to June 1983,
he was Acting General Manager of Middle Georgia EMC, and

from September 1976 to January 1983, he was Manager of Engineering at Middle
Georgia EMC. He has served as an Alternate Director of Oglethorpe since 1983,
with his present term to expire in March 1995.

MITCHELL EMC

D. Lamar Cooper--Director, age 58, operates a dairy farm. He has served on
the Board of Directors of Oglethorpe since September 1974. His present term as a
Director will expire in March 1996. He is a member of the Operations Committee
of Oglethorpe.

Gerald Freehling--Alternate Director, age 50, has been General Manager of
Mitchell EMC since September 1987. Since that time, he has served as an
Alternate Director of Oglethorpe. His present term expires in March 1996. He
previously served as General Manager of Steuben Rural Electric Cooperative in
Bath, New York.

OCMULGEE EMC

Barry H. Martin--Director, age 45, is a farmer. He has served on the Board
of Directors of Oglethorpe since March 1983. His present term as a Director
expires in March 1994. Mr. Martin is the President of Ocmulgee EMC.

Dennis Grenade--Alternate Director, age 53, has been employed by Ocmulgee
EMC since December 1957. He has been General Manager since October 1987 and was
previously Acting Manager and Manager of Operations. He has served as an
Alternate Director since October 1987 and his present term expires in March
1994. He is a member of the Finance Committee.

OCONEE EMC

John B. Floyd, Jr.--Director, age 51, has served on the Board of Directors
of Oglethorpe since March 1980, with his present term to expire in March 1996.
He is currently a member of the Finance Committee. He is the Vice Chairman of
the Board of Oconee EMC and is a Director of CFC. Mr. Floyd also serves as First
Vice President of The Four County Bank, as Vice President of The Four County
Insurance Agency, Inc., and as President of Twiggs Gin, Inc., a home
construction company in Allentown, Georgia.

Preston L. Johnson--Alternate Director, age 59, is President and Chief
Executive Officer of Oconee EMC. He has served as an Alternate Director of
Oglethorpe since September 1974, with his present term to expire in March 1996.
He was Secretary-Treasurer of Oglethorpe from September 1974 to March 1984.

OKEFENOKE RURAL EMC

Steve Rawl, Sr.--Director, age 47, has been President of Rawls, Inc., a
gift shop, since 1972. He has served as a Director of Oglethorpe since September
1993, with his present term to expire in March 1994. He is also a Director of
GEMC.

W. Don Holland--Alternate Director, age 43, is General Manager of Okefenoke
Rural EMC. He has served as an Alternate Director of Oglethorpe since 1979, with
his present term to expire in March 1994. He was formerly General Manager of
Little Ocmulgee EMC. He is currently Chairman of the Planning and Construction
Committee of Oglethorpe.

PATAULA EMC

James Grubbs--Director, age 71, is a farmer. He is involved with fertilizer
and chemical sales, and operates an air spray service and a peanut purchasing
plant. He has served on the Board of Directors of Oglethorpe since March 1983.
His present term as a Director will expire in March 1996. He is a member of the
Finance Committee of Oglethorpe.

Gary W. Wyatt--Director, age 41, is General Manager of Pataula EMC. He has
served as an Alternate Director of Oglethorpe since July 1986, with his present
term to expire in March 1996. He previously was Operations Manager and
Assistant Operations Superintendent of Coosa Valley Electric Cooperative.

PLANTERS EMC

Sammy M. Jenkins--Director, age 67, is in the farm machinery business and
has been President of Jenkins Ford Tractor Co., Inc. since 1973. He has served
on the Board of Directors of Oglethorpe since March 1988, with his present term
to expire in March 1994. He is Vice President of Planters EMC. He was Vice
Chairman of the Board of Oglethorpe from March 1989 to March 1990.

Ellis H. Lovett--Alternate Director, age 58, is General Manager of Planters
EMC and has served as an Alternate Director of Oglethorpe since 1983. His
present term as an Alternate Director will expire in March 1994. He is a member
of the Operations Committee of Oglethorpe.

RAYLE EMC

J. M. Sherrer--Director, age 58, is the owner of a grocery, hardware, gas
and feed store. He has served on the Board of Directors of Oglethorpe since
September 1993, with his present term to expire in March 1994.

Wayne Poss--Alternate Director, age 48, has served as General Manager of
Rayle EMC since December 1992. Prior to that time, he served as Manager of
Engineering for Rayle EMC. He has served as an Alternate Director to Oglethorpe
since February 1993, with his present term to expire in March 1994. He is a
member of the GEMC/Oglethorpe External Affairs Committee.

SATILLA RURAL EMC

Jack D. Vickers--Director, age 76, is the owner and operator of a farm in
Coffee County, Georgia. He has served on the Board of Directors of Oglethorpe
since March 1975. His present term will expire in March 1994.

R. Lehman Lanier--Alternate Director, age 74, is President and Chief
Executive Officer of Satilla Rural EMC.1998.
He has served as an Alternate Director
of Oglethorpe since September 1974, and his present term expires in March 1994.
He is a member ofwas previously the Operations Committee of Oglethorpe. He is also a Director
of Southeastern Data Cooperative, Inc.

SAWNEE EMC

C. W. Cox, Jr.--Director, age 66, is the owner of Cox Digging & Grading, a
general contracting sole proprietorship. He has served as a member of the Board
of Directors of Oglethorpe since February 1987, with his present term to expire
in March 1994. He is a member of the Planning and Construction Committee.

Michael A. Goodroe--Alternate Director, age 37, is Executive Vice President
and General Manager of Sawnee EMC. He previously served as Assistant General
Manager of Sawnee EMC. He has served as an Alternate Director of Oglethorpe
since 1990, with his present term to expire in March 1994. He is a member of the
GEMC/Oglethorpe External Affairs Committee.

SLASH PINE EMC

Johnnie Crumbley--Director, age 71, is President of Slash Pine EMC. He
retired in 1982 from the Seaboard Coastline System. He has served as a member of
the Board of Directors of Oglethorpe since March 1978, with his present term to
expire in March 1996. He is also a Director of GEMC.

Edward Teston--Alternate Director, age 59, is Manager of Slash Pine EMC. He
has served as an Alternate Director of Oglethorpe since 1985, with his present
term to expire in March 1996.

SNAPPING SHOALS EMC

Jarnett W. Wigington--Director, age 61, is a self-employed wallpapering
contractor. He has served on the Board of Directors of Oglethorpe since 1990.
His present term expires in March 1994. He is a memberVice-Chairman of the Executive Committee of Oglethorpe.

J. E. Robinson--Alternate Director, age 74, is President, Cheif Executive
Officer and Manager of Snapping Shoals EMC. He has been Manager of Snapping
Shoals EMC since 1953. He has served as an Alternate Director of Oglethorpe
since September 1974, with his present term to expire in March 1994. Mr.
Robinson is also a Director of the First National Bank of Newton County.

SUMTER EMC

Bob Jernigan--Director, age 66, is a manager for Mike L. Moon Enterprises
in Columbus, Georgia, which among other things, is involved in real estate
development and wholesale and retail women's apparel. He has served as a
Director of Oglethorpe since March 1976, with his present term to expire in
March 1996. He served as Vice Chairman of the Board of Directors of Oglethorpe
from March 1990 to March 1993. He is currently a member of the Executive
Committee. He is the President of Sumter EMC and a Director of GEMC.

James T. McMillan--Alternate Director, age 44, has been General Manager of
Sumter EMC since 1984. Prior to that time, he served as Manager of the Staff
Services Department of Sumter EMC, Manager of the Construction and Maintenance
Department of Sumter EMC, and Manager of the Office Services Department of
Sumter EMC. He has served as an Alternate Director of Oglethorpe since 1984,
with his present term to expire in March 1996.

THREE NOTCH EMC

C. Willard Mims--Director, age 47, is a farmer. He has served on the Board
of Directors since 1991, with his present term to expire in March 1996. He is a
member of the GEMC/Oglethorpe External Affairs Committee. He is also a Director
of GEMC.

Carlton O. Thomas--Alternate Director, age 46, has been General Manager of
Three Notch EMC since 1990. Prior to that time, he served as Office Manager of
Three Notch EMC. He has served as an Alternate Director of Oglethorpe since
1990, with his present term to expire in March 1996. He is also a Director of
First Federal Savings Bank of Southwest Georgia.

TRI-COUNTY EMC

James E. Dooley--Director, age 67, is self-employed in the real estate
business. He has served on the Board of Directors of Oglethorpe since November
1986, with his present term to expire in March 1996. Prior to his retirement in
1982, he was employed as a Director in the U.S. Department of Agriculture.

Carol Robertson--Alternate Director, age 45, is the General Manager of
Tri-County EMC. She has served as an Alternate Director of Oglethorpe since July
1988, with her present term to expire in March 1996. She is a member of the
GEMC/Oglethorpe External Affairs Committee.

TROUP EMC

Willis T. Woodruff--Director, age 68, is a self-employed cattleman. He has
served on the Board of Directors of Oglethorpe since March 1987, with his
present term to expire in March 1995. He is also a Director of GEMC.

Wayne Livingston--Alternate Director, age 42, has been the Executive Vice
President and General Manager of Troup EMC since September 1987. Prior to that
time, he was General Manager of Ocmulgee EMC. He has served

as an Alternate Director of Oglethorpe since 1978, with his present term to
expire in March 1995. He is a member of the Finance Committee.

UPSON COUNTY EMC

Hubert Hancock--Director, age 77, has been President of the Upson County
EMC for the past 33 years. He has served as a Director of Oglethorpe since
September 1974, serving as Vice President from 1975 to 1978, as President from
March 1984 to July 1986, and as Chairman of the Board from July 1986 to March
1989. His present term as Director expires in March 1995, and he currently
serves on the Executive Committee of Oglethorpe. Prior to his involvement with
Oglethorpe and Upson County EMC, Mr. Hancock was a general farmer as well as a
peach farmer and cattle farmer. Mr. Hancock is also a Director of West Central
Georgia Bank in Thomaston, Georgia, Chairman of Upson County Hospital Authority, and a member of
the Thomaston UpsonPower Planning and Technical Advisory Committee. Mr. Denham is co-owner of
Denham Farms in Turner County, Industrial Authority.

Walter E. Hammond--AlternateGeorgia. He served on the Turner County
Commission from 1980 to 1990, and was Chairman for six of those years. Mr.
Denham is a Director of Community National Bank in Ashburn, Georgia and a
Director of Irwin EMC.

J. Calvin Earwood, age 62,55, is General Managerthe Chairman of Upson
County EMC. Hethe Board and is the
Member Director elected statewide. Mr. Earwood has served as an Alternate Director of Oglethorpe since 1978, and
his present term will expire in March 1995.

WALTON EMC

Bob J. Dickens--Director, age 67, retired in 1988 from Thornton Brothers
Paper Company, Inc. in Athens, Georgia. He has served on the Board of Directors
of Oglethorpe since March 1987, and his present term expires in March 1995. He
is a member of Oglethorpe's Operations Committee.

D. Ronnie Lee--Alternate Director, age 45, has been General Manager of
Walton EMC since August 1993. Prior to that time, he served as Manager of
Engineering and Operations from January 1979 to August 1993 for Walton EMC. He
has served as an Alternate Director of Oglethorpe since September 1993, with his
present term to expire in March 1995.

WASHINGTON EMC

W. W. Archer--Director, age 62, is a self-employed insurance agent and
cattle farmer. He has served on Oglethorpe's Board of Directors since September
1987, and his present term expires in March 1995. He is also a Director of the
Bank of Hancock County in Sparta, Georgia.

Robert S. Moore, Sr.--Alternate Director, age 64, has been General Manager
of Washington EMC since April 1982. Prior to that time, he was Assistant General
Manager of Washington EMC. He has served as an Alternate Director of Oglethorpe
since 1982, with his present term to expire in March 1995. He is a member of the
Planning and Construction Committee of Oglethorpe.

(b) IDENTIFICATION OF EXECUTIVE OFFICERS AND SENIOR EXECUTIVES:

Oglethorpe is managed and operated under the direction of a President and
Chief Executive Officer, who is appointed by the Board of Directors. The
executive officers of Oglethorpe and their principal occupations are as follows:

J. Calvin Earwood, Chairman of the Board, age 52, has served as a principal executive
officer of Oglethorpe since March 1984 (from March 1984 to July 1986, as Vice
President; from July 1986 to March 1989, as Vice Chairman of the Board; and
since March 1989, as Chairman of the Board). Mr. Earwood has served as a
Director of Oglethorpe since March 1981, with his1981. His present term towill expire in March
1995. He is currently the Chairman of the Executive Committee of
Oglethorpe and a member of the GEMC/Oglethorpe Human Resources Management
Committee.2000. He was previously a member of the Operations Review Committee of
Oglethorpe.Committee. From 1965
through

1982, Mr. Earwood was a salesman and part owner of Builders Equipment
Company. Since January 1983, he has been the owner and President of Sunbelt
Fasteners, Inc., which sells specialty tools and fasteners to the 57

commercial
construction trade. He is also Vice Chairman of the Board of Directors of
Community Trust Bank in Hiram, Georgia and a Director of GreyStone Power
Corporation.

Benny W. Denham--Vice ChairmanSammy M. Jenkins, age 70, is the Member Director from the Southeast
Region. He is in the farm machinery business and has been President of the Board, age 63, has served as a
principal executive officer of OglethorpeJenkins
Ford Tractor Co., Inc. since March 1993.1973. He has served as a
member of Oglethorpe's Executive Committee and on the Board of Directors of
Oglethorpe since DecemberMarch 1988. His present term will expire in March 1995.1999. He was
previously a memberVice Chairman of the Power PlanningBoard of Oglethorpe from March 1989 to March 1990.

Mac F. Oglesby, age 64, is the Member Director from the Northeast
Region. He served as Assistant Secretary-Treasurer of Hart EMC from July 1986
through December 1987, when he was appointed President. He has served as a
Director of Oglethorpe since February 1987. His present term will expire in
March 2000. Mr. Oglesby was a U.S. Postal Service Rural Carrier for 30 years.

J. Sam L. Rabun, age 65, is the Member Director from the Central
Region. He is the owner and Technical Advisory Committeeoperator of Oglethorpe.a farm in Jefferson County, Ga. He is
also the past Presidenta 50% owner of GEMC and currently serves on
GEMC's Executive Committee and is a Director of Community National Bank in
Ashland, Georgia. Mr. Denham is a Director of Irwin EMC.

John S. Dean, Sr., Secretary-Treasurer, age 54,R&R Livestock Farms, Inc. He has served as Secretary-Treasurera Director of
Oglethorpe since March 1989. He has served as an
Alternate Director of Oglethorpe since 1975,1993, with his present term to expire in March 1995.1998. Mr.
Rabun served as the President of Jefferson EMC from 1993 to 1996.

Ashley C. Brown, age 51, is an Outside Director. His present term will
expire in March 1999. He is currently a memberExecutive Director of the Finance CommitteeHarvard Electricity Policy
Group at Harvard University's John F. Kennedy School of Government. He is Of
Counsel to the law firm of Verner, Liipfert, Bernhard, McPherson and an ex officio
memberHand of
Washington, D.C. In addition, he is a Principal Consultant with the firm of
Hagler Bailly Consulting, Inc. From April 1983 through April 1993, Mr. Brown
served as Commissioner of the Executive Committee.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. While practicing law, he specialized in litigation in federal and state
courts, as well as before administrative bodies. 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 Administration degree
from the University of Cincinnati, and a Bachelor of Science degree from Bowling
Green State University.

Newton A. Campbell, age 68, is an Outside Director. His term will
expire in March 2000. He previously served on Oglethorpe's
Operations Review Committee. Mr. Dean has been General Manager/retired in January 1994 as Chairman and Chief Executive
Officer of Amicalola EMC since 1974. Prior toBurns & McDonnell Engineering Company after serving 41 years with the
firm. Mr. Campbell directed the overall operations of Burns & McDonnell from
1982 until his employment with Amicalola EMC,retirement. From 1976 through 1982, he served as Vice President
and General Manager of the Power Division, and was Controllerresponsible for directing the
company's work in the planning and design of Pickens General Hospital. Currently, he is onfossil fueled power generation
facilities, high voltage transmission systems, and other power related
facilities. Mr. Campbell has been involved in feasibility, planning and
financial studies for numerous new and existing public and privately owned
electric utilities during various phases of their organization and development.
He also has considerable experience in conceptual studies, design, and project
management for large electric utility generation, transmission, substation and
distribution facilities throughout the BoardUnited States. Mr. Campbell received a
Master of Directors of Southeastern Data Cooperative, Inc., Crescent Bank & Trust Company,
CoBank, and GEMC Workers' Compensation Fund. Mr. Dean has a Bachelor of ArtsBusiness Administration degree in Accounting from the University of Georgia.Missouri at
Kansas City with a concentration in finance. He also holds a Bachelor of Science
degree in Electrical Engineering from the University of Illinois.

T. D. Kilgore, age 49, is the President and Chief Executive Officer age 46,of
Oglethorpe and has served as an executive of Oglethorpe since July 1984 (from
July 1984 to July 1986, as Division Manager, Power Supply; July 1986 to July
1991, as Senior Vice President, Power Supply; and since July 1991, as President
and Chief Executive Officer). Mr. Kilgore servedHe also currently serves as Executive Vice President of GEMC from December
1991 to June 1992. He has served asthe President and
Chief Executive Officer and as a director of GEMC from June 1992 until the present.both GTC and GSOC. Mr. Kilgore has
over 20 years of utility experience, including five years in senior management positions
with

Arkansas Power & Light Co. and seven years as a civilian employee with the
Department of the Army in positions ranging from reliability engineering to
construction management. Mr. Kilgore has served on various industry committees
including Electric Power Research Institute's Board of Directors and its
Advanced Power Systems Division and Coal System Division Advisory Committees. He
has also served on the Boards of Directors of the U.S. Committee for Energy
Awareness, the Advanced Reactor Corporation, on the Edison Electric Institute's
Power Plant Availability Improvement Task Force and the Nuclear Power Oversight
Committee,
an organization of industry executives which considers policy issues for the
nation's nuclear power industry.Committee. Mr. Kilgore currently serves on the Board of Directors of the Georgia
Chamber of Commerce and on the National Rural Electric Cooperative Association's
Power and Generation Committee. Mr. Kilgore has a BSBachelor of Science degree in
mechanical engineeringMechanical Engineering from the University of Alabama, where he has been
recognized as a Distinguished Engineering Fellow, and a MEan Masters of Engineering
degree in industrial engineering from Texas A&M.

(b) Identification of Senior Executives:

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 executives assisting Mr. Kilgore, their areas of responsibility and a
brief summary of their experience are as follows:

Charles T. Autry,Clarence D. Mitchell, Senior Vice President, and General Counsel,Power Supply, age 45,43, has
served as an executive of Oglethorpe since February 1986 (from February 1986 to
July 1986, as Corporate Counsel; from July 1986 to December 1989, as General
Counsel; from December 1989 to November 1991, as Senior Vice President,
Governmental Affairs and General Counsel; from November 1991 to February 1994,
as Senior Vice President, Corporate Services and General Counsel; and since
February 1994, as Senior Vice President and General Counsel).January 1995. Prior to that time, Mr.
AutryMitchell served as Staff Attorney from August 1979Assistant to January 1985 and as
Corporate Attorney from January 1985 to February 1986. Mr. Autry joined
Oglethorpe in August 1979 after five years of military and private practice
experience. He has been admitted to practice before all State Courts in Georgia
as well as the Federal District Court for the Northern District of Georgia, and
the Fifth and Eleventh Circuit Courts of Appeal and the U. S. Tax Court. He has
a BA degree from the University of Georgia, a JD degree from the University of
Alabama School of Law, a LLM degree in Taxation from Emory University School of
Law, and an MBA degree from Georgia State University.

Eugen Heckl, Senior Vice President and Chief Financial Officer, age 59, has
served as an executive of Oglethorpe since March 1975 (from March 1975 to July
1986, as senior finance and accounting executive;for Generation from July 1986 to
February 1994 as Senior Vice President, Finance; and since February 1994, as Senior Vice
President and Chief Financial Officer). Mr. Heckl has approximately 30 yearsto December 1994; Manager of experience, including ten years as a consultant and auditorCorporate Planning from September
1992 to electric
utilities with Arthur Andersen & Co. and two years as Secretary-TreasurerJanuary 1994; Manager of Davis Brothers, Inc. Mr. Heckl is a Certified Public Accountant in Georgia and
has a BS degree in accountingConstruction from Samford University and an MBA degree from
Emory University. Mr. Heckl has served as aJanuary 1992 to August 1992;
Program Director of the GEMC Federal Credit
Union since 1983,Technical Services (environmental, survey and as its Chief Financial Officer since 1984.

G. Stanley Hill, Senior Vice President, External Affairs, age 58, has
served as an executive of Oglethorpe since October 1975 (from October 1975 to
November 1988, as Director of Planning, Director of Power Supplymapping, land
acquisition and Planning,
Division Manager, Power Supply and Engineering, Division Manager, Engineering,
Senior Vice President, Planning and System Operations;R&D) from November 1988 to
November 1991, as Senior Vice President, Administration; from November 1991 to
February 1994, as Senior Vice President, Marketing and Customer Service and
since February 1994, as Senior Vice President, External Affairs). Mr. Hill has
approximately 36 years experience with electric utilities, including four years
in the Engineering Department of the South Carolina Public Service Authority and
11 years as engineer and senior engineer with Southern Engineering Company of
Georgia, a consulting engineering firm. Mr. Hill is a registered Professional
Engineer and a certified Cogeneration Professional in Georgia and has a BS
degree in electrical engineering from Clemson University and an MBA degree from
Georgia State University. Mr. Hill is presently an Oglethorpe representative on
the Joint Committee. For information about the Joint Committee, see "CO-OWNERS
OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS-The Joint Committee
Agreement" in Item 1.

W. Clayton Robbins, Senior Vice President and Group Executive, Support
Services, age 47, has served as an executive of Oglethorpe since December 1991
(from December 1991 to February 1994, as Vice President, Corporate Performance,
and since February 1994, as Senior Vice President and Group Executive, Support
Services). Prior to that time, Mr. Robbins served as Department Manager, Project
Services, from September 1986 to November 1988; as Program Director, Marketing
Research and Analysis, from November 1988 to December 1989; and as Vice
President, Marketing Research and Analysis, from DecemberJanuary 1989 to December 1991.1991; and from April 1981 to
December 1988 held various positions in the generation area, including
supervisor, project engineer and generation engineer. Before coming to
Oglethorpe, Mr. RobbinsMitchell spent 17four years as a field engineer with the
Stearns-Catalytic World CorporationGeneral
Electric Company and worked various subsidiaries, including 13 years
in management positions responsible for Human Resources, Information Systems,
Contracts, Insurance, Accounting,installation and Project Controls.maintenance projects
related to coal, nuclear, gas and oil-fired generation. Mr. RobbinsMitchell has a BAan MS
degree in Business AdministrationManagement from theGeorgia State University, a Bachelor of North Carolina at
Charlotte.

David L. Self, Senior Vice PresidentScience degree
in Mechanical Engineering from Georgia Institute of Technology and Group Executive, Generation, age
65, has served as an executivea Bachelor of
Oglethorpe since August 1991 (from August 1991
to November 1991, as Senior Vice President, Power Supply;Science degree in Interdisciplinary Science from November 1991 to
February 1994, Senior Vice President, Operations; and since February 1994, as
Senior Vice President and Group Executive, Generation).Morehouse College. Mr. Self joined
Oglethorpe in February 1988 as the corporation's on-site representative at Plant
Hatch after 30 years in the United States Navy and five years with Illinois
Power Company. He is a member of the Board of Trustees of Southern Tech
Foundation, Inc. He has a BS degree from Saint Mary's College in California. Mr.
SelfMitchell
is presently the Oglethorpe representative on both the Nuclear Managing Board
and the Plant Scherer Managing Board, and is an Oglethorpe representative
on the Joint Committee.Board. For information about the Managing Boards and the
Joint Committee,
see "CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION
AGREEMENTS-TheAGREEMENTS--The Plant Agreements" and "-The Joint Committee Agreement" in
Item 1.2. Mr. Mitchell also serves as a Trustee of the Foundation of the Southern
Polytechnic State University.

Nelson G. Hawk, Senior Vice President and Group Executive, Marketing,
age 44,
joined47, has served as an executive at Oglethorpe insince February 1994,
after almost 24 years of electric utility
experience.responsible for Market Planning, Economic Development, Commercial/Industrial
Marketing and Pricing, Commercial/Industrial Services, and Residential
Marketing. Prior to coming to Oglethorpe, he held various management positionsMr. Hawk spent almost 24 years with
the Florida Power & Light Company and related subsidiaries, includingserving as Director
of Regulatory Affairs at Florida Power & Light from October 1993 to January 1994; as1994, Director of Market
Planning from July 1991 to September 1993;1993, and as Director of Strategic Business
and President of FPL Enersys Services, Inc. (a(A utility subsidiary providing
energy services to commercial/industrial customers) from April 1989 to June
1991. Mr. Hawk has a BSwide range of utility management experience in energy
management, finance, strategic planning, marketing, system planning, quality
assurance, and distribution engineering. Mr. Hawk is a board member of the
Georgia Electrification Council, Inc. and the Georgia Partnership for Excellence
in Education, and served on the board of directors as well as President of the
National Association of Energy Services Companies (NAESCO), a national trade
association, during the late 1980s. Mr. Hawk is a registered Professional
Engineer in Florida and has a Bachelor of Science degree in Electrical
Engineering from the Georgia Institute of Technology and an MBAa Master of Business
Administration degree from Florida International University.

5964

Wylie H. Sanders, Vice President and Group Executive, Transmission, age 57,
joined Oglethorpe in January 1994 after 35 years of utility experience,
including 20 years in management positions with Florida Power & Light Company.
Prior to coming to Oglethorpe, he served as Division Commercial Manager from
April 1973 to August 1983; as District General Manager from August 1983 to July
1991; and as Director of Transmission from July 1991 to September 1993 with
Florida Power & Light. Mr. Sanders has a Bachelor's degree in Industrial
Engineering from Georgia Institute of Technology and has participated in Harvard
University's postgraduate Program for Management Development.

ITEMItem 11. EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLESummary Compensation Table

The following table sets forth, for Oglethorpe's President and Chief
Executive Officer and the fourfive most highly compensated senior executives, all
compensation paid or accrued for services rendered in all capacities during the
years ended December 31, 1993, 19921996, 1995 and 1991.1994. Amounts included in the table
under "Bonus" represent payments based on an incentive compensation policy. All
amounts paid under this policy are fully at risk each year and are earned based
upon the achievement of corporate goals and each individual's contribution to
achieving those goals. In conjunction with this policy, base salaries remain
fairly stable and are
targeted below the market valuations for similar positions.positions and remain fairly
stable unless the job content changes.

ANNUAL
COMPENSATION
NAME AND ------------ ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS(3) COMPENSATION
-Annual
Name and Compensation All Other
Principal Position Year Salary Bonus (2) Compensation
------------------ ---- -------- ----------------- ---------- ------------

T. D. Kilgore 1993 $211,250 $ 0 $6,256(1)1996 $265,627 $0 $6,246 (1)
President and Chief Executive Officer 1992 195,0001995 235,000 10,000 6,012
1994 224,997 0 5,891
1991 181,147 0 (2)

Eugen Heckl 1993 142,114 12,228 5,103(1)6,758

W. Clayton Robbins (3) 1996 144,460 17,112 5,425 (1)
Sr. Vice President, and Chief 1992 142,114 19,135 4,079
Financial Officer 1991 142,114 0 (2)1995 142,310 10,631 4,716
Support Services 1994 140,366 11,946 4,986

Nelson G. Stanley Hill 1993 140,000 12,580 4,905(1)Hawk 1996 142,535 16,530 5,246 (1)
Sr. Vice President, 19921995 140,000 18,195 4,391
External Affairs 1991 134,872 0 (2)

Charles T. Autry 1993 139,750 10,991 4,326(1)10,899 4,589
Marketing 1994 116,005 9,620 32,821

Clarence D. Mitchell 1996 133,369 17,112 3,887 (1)
Sr. Vice President, and 1992 139,750 16,950 4,232
General Counsel 1991 139,750 0 (2)

David L. Self 19931995 110,058 7,776 4,251
Power Supply 1994 91,705 5,765 3,354

Wiley H. Sanders (4) 1996 123,750 9,340 82,715 (1) (4)
Vice President, Transmission 1995 135,000 12,143 5,077(1)9,295 5,703
1994 119,785 12,737 25,178

Eugen Heckl (5) 1996 99,480 16,734 117,245 (1) (5)
Sr. Vice President, and 1992 131,800 18,286 4,168
Group Executive, Generation 1991 110,067 0 (2)

- -------------------------
(1) Includes contributions made in 1993 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. Kilgore, Heckl, Hill, Autry and
Self in the amounts of $4,497, $4,497, $4,200, $4,193 and $4,050, respectively,
and above market amounts of interest earned by Messrs. Kilgore, Heckl, Hill,
Autry and Self on deferred compensation amounts paid by Oglethorpe in the
amounts of $1,759, $606, $705, $133, and $1,027, respectively.

(2) In accordance with the transition provision applicable to the Commission's
new rules regarding executive compensation disclosure, Oglethorpe is not
required to provide any information for fiscal year 1991.

(3) Mr. Kilgore is not a participant in the incentive compensation program. HisFinance 1995 142,114 13,174 7,651
1994 142,114 13,919 7,600

- ----------
(1) Includes contributions made in 1996 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. Kilgore, Robbins, Hawk, Mitchell,
Sanders and Heckl of $4,750, $4,072, $4,446, $2,969, $3,654 and $2,958,
respectively; and insurance premiums paid on term life insurance on behalf of
Messrs. Kilgore, Robbins, Hawk, Mitchell, Sanders and Heckl of $1,496, $1,353,
$800, $918, $2,831 and $2,200, respectively.

(2) All executives listed above, except Mr. Kilgore, participate in an incentive
compensation program. Mr. Kilgore's compensation is governed solely by the Board
of Directors.

61(3) In conjunction with the Corporate Restructuring, Mr. Robbins ceased to be a
senior executive of Oglethorpe as of January 31, 1997. Mr. Robbins now serves as
Vice President of Intellisource's Southeast operations, including support
services to Oglethorpe, GTC and GSOC. See "OGLETHORPE POWER
CORPORATION--Relationship with Intellisource" in Item 1 for further discussion.

(4) Mr. Sanders retired from Oglethorpe as of November 30, 1996. Mr. Sanders'
1996 compensation includes accrued severance benefits of $59,114, payment of
accrued vacation and sick benefits of $4,998 and relocation costs of $12,118.

PENSION PLAN TABLE(5) Mr. Heckl elected to retire from Oglethorpe under the provisions of an early
retirement program as of September 11, 1996. Mr. Heckl's 1996 compensation
includes severance benefits of $65,258, retirement-related contributions to his
deferred compensation account of $34,938 and payment of accrued vacation and
sick benefits of $11,891.

Pension Plan Table

YEARS OF CREDITED SERVICE
--------------------------------
AVERAGE COMPENSATIONYears of Credited Service
-----------------------------------------------
Average Compensation 15 20 25
OR MORE
- -------------------- ------ ------ ---------- --------- ---------
$125,000 . . . . . . . . . . . . . . $35,592 $47,456
$ 59,320
150,000 . . . . . . . . . . . . . . 43,092 57,456 71,820
175,000 . . . . . . . . . . . . . . 50,592 67,456 84,320
200,000 . . . . . . . . . . . . . . 58,092 77,456 96,820
225,000 . . . . . . . . . . . . . . 65,592 87,456 109,320
250,000 . . . . . . . . . . . . . . 68,844 91,792 114,74050,000.................................................. $12,684 $16,911 $21,139
75,000.................................................. 20,184 26,911 33,639
100,000.................................................. 27,684 36,911 46,139
125,000.................................................. 35,184 46,911 58,639
150,000.................................................. 42,684 56,911 71,139
175,000.................................................. 50,184 66,911 83,639
200,000.................................................. 57,684 76,911 96,139
225,000.................................................. 65,184 86,911 108,639
250,000.................................................. 72,684 96,911 121,139
275,000.................................................. 80,184 106,911 133,639

The preceding table shows estimated annual straight life annuity
benefits payable upon retirement to persons in specified compensation and
years-of-service classifications assuming such persons had attained age 65 and
retired during 1993.1996. For purposes of calculating pension benefits, compensation
is defined as total salary and bonus, as shown in the above Summary Compensation
Table. Because covered compensation changes each year, the estimated pension
benefits for the classifications above will also change in future years. The
above pension benefits are not subject to any deduction for Social Security or
other offset amounts.

As of December 31, 1993,1996, the years of credited service under the Pension
Plan for the individuals listed in the Summary Compensation Table are as
follows:

YEARS OF
NAME CREDITED SERVICE
---- ----------------

Mr. Kilgore. . . . . . . . . . . . . . . . . . . . . . . . . . 8
Mr. Heckl. . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Mr. Autry. . . . . . . . . . . . . . . . . . . . . . . . . . . 14
Mr. Hill . . . . . . . . . . . . . . . . . . . . . . . . . . . 17
Mr. Self . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

COMPENSATION OF DIRECTORSYears of
Name Credited Service
---- ----------------

Mr. Kilgore.......................................... 11
Mr. Robbins.......................................... 10
Mr. Hawk ............................................ 1
Mr. Mitchell......................................... 15
Mr. Sanders.......................................... 1
Mr. Heckl............................................ 20

Compensation of Directors

Under a proposed policy which is scheduled for approval at the March 27,
1997 Board meeting, Oglethorpe payswill pay its Outside Directors a per diem fee of
$200$5,500 per Board meeting for the first four meetings attendedin a year; a per diem of
$1,000 per Board meeting will be paid for the fifth and subsequent meetings in a
year. Outside Directors will also be paid $1,000 per day for attending committee
meetings, annual meetings of the Members or $50other official meetings of
Oglethorpe. Under the proposed policy, Member Directors will be paid a per diem
fee of $1,000 per Board meeting and a per diem of $300 per day for attending
committee meetings, conducted by conference call. Additionally,annual meetings of the Members or other official meetings of
Oglethorpe. In addition, Oglethorpe reimburses itswill reimburse all Directors for

out-of-pocket expenses incurred in attending a meeting. AlternateAll Directors serving aswill be
paid a Director at any meeting receive
neither the per diem payment nor the expense reimbursement to which a Director
is entitled. The Memberfee of which the Alternate Director is the manager receives
reimbursement for the Alternate Director's out-of-pocket expenses.$50 per day when participating in meetings conducted by
conference call. The Chairman of the Board is alsowill be paid at least one day'san additional 20% of the
per diem of $200
each monthper Board meeting for time involved in carrying out his official duties in additionpreparing for the meetings.

Employment Contracts

Effective January 1, 1996, Oglethorpe entered into an employment
agreement with its President and Chief Executive Officer. The term of the
agreement extends to December 31, 1998, with certain automatic annual extension
provisions beyond that date unless either party gives notice of termination 60
days prior to an extension. Pursuant to the regularly scheduledagreement, Mr. Kilgore's base salary
and bonus will be determined by Oglethorpe's Board, Meeting.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

W. F. Farr,with annual base salary
being at least $240,000. Under the agreement, if Oglethorpe terminates Mr.
Kilgore's employment without cause, he will be entitled to all salary and
benefits he would have received between the date of termination to the end of
the agreement. In addition, if Oglethorpe terminates Mr. Kilgore's employment
without cause or meaningfully reduces his stated duties or prerogatives within
three months prior to or 24 months subsequent to a Change in Control of
Oglethorpe (as defined in the agreement), a severance payment will be paid in an
amount not less than two times Mr. Kilgore's annual base salary on the date of
termination or the date on which his duties or prerogatives are reduced,
whichever is applicable. If such reduction in duties occurs, Mr. Kilgore will be
entitled to severance regardless whether he is terminated or resigns. If Mr.
Kilgore voluntarily separates himself from Oglethorpe, he will be prohibited
from working with a competitor of Oglethorpe for a period of one year thereafter
and will be paid an amount equal to his then current salary, bonus and benefits
for such period.

Compensation Committee Interlocks and Insider Participation

E. J. Martin, Jr., J. Calvin Earwood, Ronnie Fleeman, E.John B. Floyd, Jr., and J. Martin, Jr. and
Robert A. Reeves serveG.
McCalmon served as members of the GEMC/Oglethorpe Human Resources Management
Committee which functionsfunctioned as Oglethorpe's compensation committee.committee for 1996. J.
Calvin Earwood has served as an executive officer of Oglethorpe since 1984 and
has served as the Chairman of the Board since 1989.

6267

ITEMItem 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Not applicable.

ITEMItem 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

None.

63T. D. Kilgore is the President and Chief Executive Officer and a
Director of Oglethorpe, GTC and GSOC. Oglethorpe plans to make payments to GSOC
for system operations services in 1997 of approximately $6.8 million, which is
55% of GSOC's budgeted revenues. (See "OGLETHORPE POWER CORPORATION--Corporate
Restructuring" in Item 1.)

PART IV

ITEMItem 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

PAGEPage
----
(a) LIST OF DOCUMENTS FILED AS A PART OF THIS REPORT.List of Documents Filed as a Part of This Report.

(1) FINANCIAL STATEMENTSFinancial Statements (Included under "Item 8. Financial
Statements and Supplementary Data")

Statements of Revenues and Expenses, For the Years
Ended December 31, 1993, 19921996, 1995 and 1991. . . . . . . . . . 331994.............................. 43
Statements of Patronage Capital, For the Years Ended
December 31, 1993, 19921996, 1995 and 1991. . . . . . . . . . . . . 331994.................................... 43
Balance Sheets, As of December 31, 19931996 and 1992 . . . . . 341995...................... 44
Statements of Capitalization, As of December 31, 19931996
and 1992. . . . . . . . . . . . . . . . . . . . . . . . . 361995............................................................ 46
Statements of Cash Flows, For the Years Ended December 31,
1993, 19921996, 1995 and 1991 . . . . . . . . . . . . . . . . . 371994................................................. 47
Notes to Financial Statements. . . . . . . . . . . . . . . 38
Report of Management . . . . . . . . . . . . . . . . . . .Statements, including pro-forma financial
statements relating to the Corporate Restructuring.................. 48
Report of Management.................................................. 60
Reports of Independent Public Accountants . . . . . . . . . 48Accountants............................. 60

(2) FINANCIAL STATEMENT SCHEDULES

Schedule IFinancial 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(1) -- Marketable Securities--Other Security
Investments, AsSecond 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.

2.2(1) -- 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 December 31, 1993 78
Schedule V -- Utility Plant, Including Intangibles, For the
Years Ended December 31, 1993, 1992 and 1991 79
Schedule VI -- Accumulated Provision for Depreciation
of Utility Plant, For the Years Ended
December 31, 1993, 1992 and 1991 82
Schedule X -- Supplementary Income Statement
Information, For the Years Ended
December 31, 1993, 1992 and 1991 85

(3) EXHIBITS

NUMBER DESCRIPTION
- ------ -----------Oglethorpe.

*3(i)(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(ii)3(i)(b) -- Amendment to Articles of Incorporation of Oglethorpe,
dated as of March 11, 1997.

3(ii) -- Bylaws of Oglethorpe, as amended November 8, 1993. (Filedon February 24, 1997,
and effective as Exhibit 3.2 to the Registrant's Form 10-Q for the quarterly
period ended September 30, 1993, File No. 33- 7591.)of March 11, 1997.

*4.1 -- Serial Facility Bond (included in Collateral Trust
Indenture listed as Exhibit 4.2).

*4.2 -- Collateral Trust Indenture, dated as of October 15,
1986, between OPC Scherer Funding Corporation,
Oglethorpe and Trust Company Bank, a banking
corporation, as Trustee. (Filed 64

NUMBER DESCRIPTION
- ------ -----------

as Exhibit 4.2 to the
Registrant's Form S-1 Registration Statement, File No.
33- 7591,33-7591, filed on October 9, 1986.)

*4.3 -- Refunding Lessor Notes. (Filed as Exhibit 4.3.1 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)

*4.4(a) -- Nonrecourse Promissory Secured Note, due June 30, 2011,
from Wilmington Trust Company and William J. Wade, as
Owner Trustees, to Columbia Bank for Cooperatives.
(Filed as Exhibit 4.3.4 to the Registrant's Form S-1
Registration Statement, File No. 33- 7591,33-7591, filed on
October 9, 1986.)

*4.4(b) -- First Amendment to Nonrecourse Promissory Secured Note,
dated as of June 30, 1987, by Wilmington Trust Company
and The Citizens and Southern National Bank, as Owner
Trustee under Trust Agreement No. 1 with IBM Credit
Financing Corporation, to Columbia Bank for
Cooperatives. (Filed as Exhibit 4.3.4(a) to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1987, File No. 33-7591.)

*4.5(a) -- Indenture of Trust, Deed to Secure Debt and Security
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 and The First
National Bank of Atlanta, as Indenture Trustee, together
with a Schedule identifying three other substantially
identical Indentures of Trust, Deeds to Secure Debt and
Security Agreements. (Filed as Exhibit 4.4(b) to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)

*4.5(b) -- First Supplemental Indenture of Trust, Deed to Secure
Debt and Security Agreement No. 2 (included as Exhibit A
to the Supplemental Participation Agreement No. 2 listed
as 10.1.1(b)).

*4.5(c) -- First Supplemental Indenture of Trust, Deed to Secure
Debt and Security Agreement No. 1, dated as of June 30,
1987, between Wilmington Trust Company and The Citizens
and Southern National Bank, collectively as Owner
Trustee under Trust Agreement No. 1 with IBM Credit
Financing Corporation, and The First National Bank of
Atlanta, as Indenture Trustee. (Filed as Exhibit 4.4(c)
to the Registrant's Form 10-K for the fiscal year ended
December 31, 1987, File No. 33-7591.)

*4.6(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, filed on
October 9, 1986.)

70
*4.6(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)).

*4.6(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.)

NUMBER DESCRIPTION
- ------ -----------

*4.7(a)4.7 -- Amended and Consolidated Loan Contract, dated as of
JuneMarch 1, 19841997, between Oglethorpe and the United States
of America, as
amended and supplemented, together with elevenfour notes executed and
delivered pursuant thereto.

(Filed as Exhibit
4.6 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)

*4.7(b)4.8.1 -- Amendments, dated October 17, 1986, and January 9, 1987, to
Amended and Consolidated Loan ContractIndenture, dated as of JuneMarch 1, 1984 between Oglethorpe and the United States of America.
(Filed as Exhibit 4.6(a) to the Registrant's Form 10-K for
the fiscal year ended December 31, 1986, File No. 33-7591.)

*4.7(c) -- Amendment, dated September 30, 1988, to Amended and
Consolidated Loan Contract dated as of June 1, 1984 between
Oglethorpe and the United States of America. (Filed as
Exhibit 4.6(b) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1988, File No. 33-7591.)

*4.7(d) -- Amendment, dated March 20, 1990, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe
and the United States of America. (Filed as Exhibit 4.6(c)
to the Registrant's Form 10-K for the fiscal year ended
December 31, 1989, File No. 33-7591.)

*4.7(e) -- Amendment, dated July 1, 1991, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe
and the United States of America. (Filed as Exhibit 4.6(d)
to the Registrant's Form 10-K for the fiscal year ended
December 31, 1991, File No. 33-7591.)

*4.7(f) -- Amendment, dated April 6, 1992, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe
and the United States of America. (Filed as Exhibit 4.6(e)
to the Registrant's Form 10-K for the fiscal year ended
December 31, 1992, File No. 33-7591.)

*4.7(g) -- Amendment, dated June 12, 1992, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe
and the United States of America. (Filed as Exhibit 4.6(f)
to the Registrant's Form 10-K for the fiscal year ended
December 31, 1992, File No. 33-7591.)

*4.7(h) -- Amendment, dated October 20, 1992, to Amended and
Consolidated Loan Contract dated as of June 1, 1984 between
Oglethorpe and the United States of America. (Filed as
Exhibit 4.6(g) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1992, File No. 33-7591.)

*4.7(i) -- Amendment, dated February 25, 1993, to Amended and
Consolidated Loan Contract dated as of June 1, 1984 between
Oglethorpe and the United States of America. (Filed as
Exhibit 4.6(h) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1992, File No. 33-7591.)

4.7(j) -- Amendment, dated August 26, 1993, to Amended and
Consolidated Loan Contract dated as of June 1, 1984 between
Oglethorpe and the United States of America.

NUMBER DESCRIPTION
- ------ -----------

*4.8.1(a) -- Mortgage and Security Agreement1997, made by Oglethorpe
to United
States of America datedSunTrust Bank, Atlanta, as of January 8, 1975. (Filed as
Exhibit 4.12(b) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)

*4.8.1(b)trustee.

4.8.2 -- Supplemental Mortgage made by Oglethorpe to United States of
America dated as of January 6, 1977. (Filed as Exhibit
4.12(a) to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)

*4.8.2(a) -- Consolidated Mortgage and Security Agreement made by and
among Oglethorpe, Mortgagor, and United States of America
and Trust Company Bank, as trustee under certain indentures
identified therein, Mortgagees, dated as of November 1,
1978. (Filed as Exhibit 4.11(c) to the Registrant's Form S-1
Registration Statement, File No. 33- 7591, filed on October
9, 1986.)

*4.8.2(b) -- Confirmation of Execution And Delivery of Notes And First
Amendment to Consolidated Mortgage and Security Agreement, dated as of January 11, 1979. (Filed as Exhibit 4.11(b) to
the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)

*4.8.2(c) -- Supplement and Second Amendment to Consolidated Mortgage and
Security AgreementMarch 1, 1997, made by
and among Oglethorpe Mortgagor,
and United States of America and Trust Companyto SunTrust Bank, Atlanta, as Trustee, Mortgagees, dated April 30, 1980. (Filed as Exhibit
4.11(a) to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)

*4.8.3 -- Consolidated Mortgage and Security Agreement made by and
among Oglethorpe, Mortgagor, and United States of America
and Trust Company Bank, as trustee under certain indentures
identified therein, Mortgagees, dated as of September 15,
1982. (Filed as Exhibit 4.10 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October
9, 1986.)

*4.8.4 -- Consolidated Mortgage and Security Agreement made by and
among Oglethorpe, Mortgagor, and United States of America,
Columbia Bank for Cooperatives, and Trust Company Bank, as
trustee under certain indentures identified therein,
Mortgagees, dated as of June 1, 1984. (Filed as Exhibit 4.9
to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)

*4.8.5 -- Consolidated Mortgage and Security Agreement made by and
among Oglethorpe, Mortgagor, and United States of America,
Columbia Bank for Cooperatives, and Trust Company Bank, as
trustee under certain indentures identified therein,
Mortgagees, dated as of December 1, 1984. (Filed as Exhibit
4.8 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)

*4.8.6(a) -- Consolidated Mortgage and Security Agreement made by and
among Oglethorpe, Mortgagor, and United States of America,
Columbia Bank for Cooperatives, and Trust Company Bank, as
trustee under certain indentures identified therein,
Mortgagees, dated as of October 15, 1985. (Filed as Exhibit
4.7 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)

*4.8.6(b) -- First Supplement and Amendment to Consolidated Mortgage and
Security Agreement made by and among Oglethorpe, Mortgagor,
and United States of America, Columbia Bank for

NUMBER DESCRIPTION
- ------ -----------

Cooperatives, and Trust Company Bank, as trustee under
certain indentures identified therein, Mortgagees, dated as
of November 1, 1988. (Filed as Exhibit 4.7(a) to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1988, File No. 33- 7591.)

*4.8.7(a) -- Consolidated Mortgage and Security Agreement made by and
among Oglethorpe, Mortgagor, and United States of America,
National Bank for Cooperatives, and Trust Company Bank, as
trustee under certain indentures identified therein,
Mortgagees, dated as of December 1, 1989. (Filed as Exhibit
4.19 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1989, File No. 33-7591.)

*4.8.7(b) -- Supplement to Consolidated Mortgage and Security Agreement
made by and among Oglethorpe, Mortgagor, and United States
of America, National Bank for Cooperatives, and Trust
Company Bank, as trustee under certain indentures identified
therein, Mortgagees, dated as of November 20, 1990. (Filed
as Exhibit 4.19(a) to the Registrant's Form 10-K for the
fiscal year ended December 31, 1990, File No. 33-7591.)

*4.8.8 -- Consolidated Mortgage and Security Agreement made by and
among Oglethorpe, Mortgagor, and United States of America,
National Bank for Cooperatives, Credit Suisse, acting by and
through its New York branch, and Trust Company Bank, as
trustee under certain indentures identified therein,
Mortgagees, dated as of April 1, 1992. (Filed as Exhibit
4.21 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1992, File No. 33-7591.)

*4.8.9 -- Consolidated Mortgage and Security Agreement made by and
among Oglethorpe, Mortgagor, and United States of America,
National Bank for Cooperatives, Credit Suisse, acting by and
through its New York branch, and Trust Company Bank, as
trustee under certain indentures identified therein,
Mortgagees, dated as of October 1, 1992. (Filed as Exhibit
4.22 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1992, File No. 33-7591.)

*4.8.10 -- Consolidated Mortgage and Security Agreement made by and
among Oglethorpe, Mortgagor, and United States of America,
National Bank for Cooperatives, Credit Suisse, acting by and
through its New York branch, and Trust Company Bank, as
trustee under certain indentures identified therein,
Mortgagees, dated as of December 1, 1992. (Filed as Exhibit
4.23 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1992, File No. 33-7591.)

4.8.11 -- Consolidated Mortgage and Security Agreement made by and
among Oglethorpe, Mortgagor, and United States of America,
National Bank for Cooperatives, Credit Suisse, acting by and
through its New York branch, and Trust Company Bank, as
trustee under certain indentures identified therein,
Mortgagees, dated as of September 1, 1993.

++4.9.1trustee.

4.9.1(3) -- 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.

++4.9.24.9.2(3) -- 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.

NUMBER DESCRIPTION
- ------ -----------

++4.9.34.9.3(3) -- 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.

+4.10.1 -- Loan Agreement, dated as of April 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 1992A.

+4.10.2 -- Note, dated April 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated
as of April 1, 1992, between Development Authority of Burke
County and Trust Company Bank.

+4.10.3 -- Trust Indenture, dated as of April 1, 1992, between
Development Authority of Burke County and Trust Company
Bank, as trustee, relating to Development Authority of Burke
County Adjustable Tender Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1992A.

+4.10.4 -- First Amended and Restated Letter of Credit Reimbursement
Agreement, dated as of June 1, 1992, as amended by First
Amendment to First Amended and Restated Letter of Credit
Reimbursement Agreement, dated as of September 15, 1993,
between Credit Suisse and Oglethorpe relating to an
Irrevocable Letter of Credit issued in connection with the
Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1992A.

+++4.11.14.10.1(4) -- 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.

+++4.11.24.10.2(4) -- 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.

+++4.11.34.10.3(4) -- 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.

+++4.11.44.10.4(4) -- 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.

+++4.11.571

4.10.5(4) -- 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.

NUMBER DESCRIPTION
- ------ -----------

+4.11.64.10.6(2) -- Standby Bond Purchase Agreement, dated as of November 30,
1993,December
14, 1995, between Oglethorpe and The IndustrialCanadian Imperial Bank
of Japan,
LimitedCommerce, New York Agency, relating to Development
Authority of Burke County Adjustable Tender Pollution
Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A.

*4.12.14.10.7(2) -- 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 the
Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1994A.

4.11.1(4) -- 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.

4.11.2(4) -- 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.

4.11.3(4) -- 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.

4.12.1(2) -- Loan No. T-840901,Agreement, dated as of April 2, 1992, between the
Development Authority of Burke County and Oglethorpe, as
amended and supplemented by First Amendatory and
Supplemental Loan Agreement, dated as of March 1, 1997,
relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1997A.

4.12.2(2) -- Note, dated March 1, 1997, from Oglethorpe to SunTrust
Bank, Atlanta, as trustee acting pursuant to a Trust
Indenture, dated as of April 1, 1992, between
Development Authority of Burke County and SunTrust Bank,
Atlanta, as supplemented by First Supplemental Trust
Indenture, dated as of March 1, 1997.

4.12.3(2) -- Trust Indenture, dated as of April 2, 1992, between
Development Authority of Burke County and SunTrust Bank,
Atlanta, as trustee, as supplemented by a First
Supplemental Trust Indenture, dated as of March 1, 1997,
relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1997A.

4.13.1 -- Indemnity Agreement, dated as of March 1, 1997, by and
between Oglethorpe and Columbia Bank for Cooperatives,Georgia Transmission Corporation
(An Electric Membership Corporation).

4.13.2 -- Indemnification Agreement, dated as of September 14,
1984. (FiledMarch 11, 1997,
by Oglethorpe and Georgia Transmission Corporation (An
Electric Membership Corporation) for the benefit of the
United States of America.

4.14.1(2) -- Master Loan Agreement, dated as Exhibit 4.14.1of March 1, 1997,
between Oglethorpe and CoBank, ACB, MLA No. 0459.

4.14.2(2) -- Consolidating Supplement, dated as of March 1, 1997,
between Oglethorpe and CoBank, ACB, relating to the Registrant's Form S-1
Registration Statement, FileLoan No.
33-7591, filed on
October 9, 1986.)

*4.12.2ML0459T1.

4.14.3(2) -- Promissory Note, Loan No. T-840901,dated March 1, 1997, in the original
principal amount of $8,995,000$7,102,740.26, from Oglethorpe to
Columbia
Bank for Cooperatives,CoBank, ACB, relating to Loan No. ML0459T1.

4.14.4(2) -- Consolidating Supplement, dated as of NovemberMarch 1, 1984. (Filed
as Exhibit 4.14.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)

*4.13.1 -- Loan Agreement, Loan No. T-831222,1997,
between Oglethorpe and Columbia Bank for Cooperatives, dated as of December 30,
1983. (Filed as Exhibit 4.16.1CoBank, ACB, relating to the Registrant's Form S-1
Registration Statement, FileLoan No.
33-7591, filed on
October 9, 1986.)

*4.13.2ML0459T2.

4.14.5(2) -- Promissory Note, Loan No. T-831222,dated March 1, 1997, in the original
principal amount of $2,376,000 from$1,856,475.12, made by Oglethorpe to
Columbia
Bank for Cooperatives, dated as of June 1, 1984. (Filed as
Exhibit 4.16.2CoBank, ACB, relating to the Registrant's Form S-1 Registration
Statement, FileLoan No. 33-7591, filed on October 9, 1986.)

*4.14.1ML0459T2.

*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, filed
on October 9, 1986.)

*4.14.2*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, filed on
October 9, 1986.)

*4.14.3*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.)

*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, filed on October 9, 1986.)

*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, filed on
October 9, 1986.)

*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 70

NUMBER DESCRIPTION
- ------ -----------

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.)

*10.1.2 -- 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, filed on October 9, 1986.)

*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, filed on October 9, 1986.)

*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.)

*10.1.4(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, filed on October 9, 1986.)

*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.)

*10.1.5 -- 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, filed on October 9, 1986.)

*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, filed on October 9, 1986.)

*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 71

NUMBER DESCRIPTION
- ------ -----------

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, filed on October 9, 1986.)

*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, filed
on October 9, 1986.)

*10.2.2 -- Section 168 Agreement and Election dated as of April 9,
1982, between National Service Industries, Inc. and
Oglethorpe. (Filed as Exhibit 10.3 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed
on October 9, 1986.)

*10.2.3 -- 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, filed on October 9, 1986.)

*10.2.4 -- Section 168 Agreement and Election dated as of December
13, 1982, between Selig Enterprises, Inc. and
Oglethorpe. (Filed as Exhibit 10.5 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed
on October 9, 1986.)

*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, filed on October 9, 1986.)

*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, filed on October 9, 1986.)

*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.)

*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,
72

NUMBER DESCRIPTION
- ------ -----------

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, filed on
October 9, 1986.)

*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, filed on
October 9, 1986.)

*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, filed on October 9, 1986.)

*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.)

NUMBER DESCRIPTION
- ------ -----------

*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, filed on
October 9, 1986.)

*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

76
the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)

*10.5.2*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, filed on
October 9, 1986.)

*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, filed on
October 9, 1986.)

*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, filed on October 9, 1986.)

*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, filed on October 9, 1986.)

*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(a)10.8.1 -- Amended and Restated Wholesale Power Contract, dated September 5, 1974,as
of August 1, 1996, between Oglethorpe and PlantersAltamaha
Electric Membership Corporation and all schedules
thereto, the Supplemental Agreement dated
September 5, 1974, between Oglethorpe and Planters Electric
Membership Corporation, relating to such Wholesale Power
Contract, and Amendment No. 1 to Wholesale Power Contract
dated May 12, 1980, between Oglethorpe and Planters Electric
Membership Corporation, 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 herewith to reflect update to
Schedule A to Wholesale Power Contract). (Filed as Exhibit
10.10 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)

*10.8.1(b)identical.

10.8.2 -- Amended and ConsolidatedRestated 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.

10.8.3 -- Supplemental Agreement to the Amended Restated Wholesale
Power Contract, dated as of DecemberJanuary 1, 1988, between1997, by and
among Georgia Power Company, Oglethorpe and Planters
Electric Membership Corporation and all schedules thereto,
and the Amended and Consolidated Supplemental Agreement,
dated December 1, 1988,

NUMBER DESCRIPTION
- ------ -----------

between Oglethorpe and PlantersAltamaha
Electric Membership Corporation, together with a
Schedule identifying 3738 other substantially identical
Supplemental Agreements.

10.8.4 -- Supplemental Agreement to the Amended Restated Wholesale
Power Contracts,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 Wholesale Power ContractSupplemental Agreement that is not
substantially identical.

(Filed as Exhibit 10.10(a)10.8.5 -- Supplemental Agreement to the Registrant's Form 10-K for the fiscal year ended
December 31, 1988, File No. 33-7591.)Amended 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.

*10.9 -- Transmission Facilities Operation and Maintenance
Contract between Georgia Power Company and Oglethorpe
dated as of June 9, 1986. (Filed as Exhibit 10.13 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)

*10.10(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, filed
on October 9, 1986.)

*10.10(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, filed on October 9, 1986.)

*10.11 -- Interconnection Agreement between Oglethorpe and Alabama
Electric Cooperative, Inc., dated as of November 12,
1990. (Filed as Exhibit 10.16(a) to the Registrant's
Form 10- K10-K for the fiscal year ended December 31, 1990,
File No. 33-7591.)

*10.11(a) -- Amendment No. 1 to Interconnection Agreement between
Alabama Electric Cooperative, Inc. and Oglethorpe, dated
as of April 22, 1994. (Filed as Exhibit 10.11(a) to the
Registrant's Form 10-Q for the quarter ended June 30,
1994, File No. 33-7591.)

*10.11(b) -- 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.)

*10.12 -- Oglethorpe Deferred Compensation Plan for Key Employees,
as Amended and Restated January, 1987. (Filed as Exhibit
10.19 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1986, File No. 33-7591.)

*10.13.1 -- 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, filed on October 9, 1986.)

*10.13.2 -- 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

78
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)

*10.13.3 -- 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, filed on October 9, 1986.)

*10.14 -- Distribution Facilities Joint Use Agreement between
Oglethorpe and Georgia Power Company, dated as of May
12, 1986. (Filed as Exhibit 10.21 to the Registrant's
Form 0-K10-K for the fiscal year ended December 31, 1986,
File No. 33-7591.)

*10.15.1 -- Long Term Firm Power Purchase Agreement, dated as of
July 19, 1989, by and between Oglethorpe and Big Rivers
Electric Corporation. (Filed as Exhibit 10.24.1 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1989, File No. 33-7591.)

*10.15.2 -- Coordination Services Agreement, dated as of August 21,
1989, by and between Oglethorpe and Georgia Power
Company. (Filed as Exhibit 10.24.2 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1989,
File No. 33-7591.)

NUMBER DESCRIPTION
- ------ -----------

*10.15.3 -- 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.)

*10.15.4 -- Interchange Agreement between Oglethorpe and Big Rivers
Electric Corporation, dated as of November 12, 1990.
(Filed as Exhibit 10.24.4 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1990, File No.
33-7591.)

*10.16 -- Block Power Sale Agreement between Georgia Power Company
and Oglethorpe, dated as of November 12, 1990. (Filed as
Exhibit 10.25 to the Registrant's Form 8-K, filed
January 4, 1991, File No. 33-7591.)

*10.17 -- Coordination Services Agreement between Georgia Power
Company and Oglethorpe, dated as of November 12, 1990.
(Filed as Exhibit 10.26 to the Registrant's Form 8-K,
filed January 4, 1991, File No. 33-7591.)

*10.18 -- Revised and Restated Integrated Transmission System
Agreement between Oglethorpe and Georgia Power Company,
dated as of November 12, 1990. (Filed as Exhibit 10.27
to the Registrant's Form 8-K, filed January 4, 1991,
File No. 33-7591.)

*10.19 -- 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.)

*10.20 -- 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.)

*10.21 -- Supplemental Agreement by and among Oglethorpe,
Tri-County Electric Membership Cooperation and Georgia
Power Company, dated as of November 12, 1990, together
with

79
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.)

*10.22 -- 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.)

*10.23 -- Interchange Agreement between Oglethorpe and Arkansas
Power & Light Company, Louisiana Power & Light Company,
Mississippi Power & Light Company, New Orleans Public
Service, Inc., Energy Services, Inc., dated as of
November 12, 1990. (Filed as Exhibit 10.32 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)

*10.24 -- Interchange Agreement between Oglethorpe and Seminole
Electric Cooperative, Inc., dated as of November 12,
1990. (Filed as Exhibit 10.33 to the Registrant's Form
10-K for the fiscal year ended December 31, 1990, File
No. 33-7591.)

NUMBER DESCRIPTION
- ------ -----------

*10.25.1 -- Excess Energy and Short-term Power Agreement between
Oglethorpe and Tennessee Valley Authority, effective as
of January 23, 1991. (Filed as Exhibit 10.34.1 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)

*10.25.2 -- Transmission Service Agreement between Oglethorpe and
Tennessee Valley Authority, effective as of January 23,
1991. (Filed as Exhibit 10.34.2 to the Registrant's Form
10-K for the fiscal year ended December 31, 1990, File
No. 33-7591.)

*10.26 -- 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).

22.1*10.27(5) -- SubsidiaryMaster Power Purchase and Sale Agreement between Enron
Power Marketing, Inc. and Oglethorpe, dated as of
January 3, 1996. (Filed as Exhibit 10.27 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1995, File No. 33-7591.)

*10.27(a) (5) -- Extension and Modification Agreement between Enron Power
Marketing, Inc. and Oglethorpe, (notdated as of April 30,
1996. (Filed as Exhibit 10.27(a) to the Registrant's
Form 10-Q for the quarterly period ended March 31, 1996,
File No. 33-7591.)

*10.28(6) -- Employment Agreement between Oglethorpe and T. D.
Kilgore, dated as of December 20, 1995. (Filed as
Exhibit 10.28 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1995, File No. 33-7591.)

*10.29(5) -- Master Power Purchase and Sale Agreement between
Duke/Louis Dreyfus L.L.C. and Oglethorpe, dated as of
August 31, 1996. (Filed as Exhibit 10.29 to the
Registrant's Form 10-Q for the quarterly period ended
September 30, 1996, File No. 33-7591.)

10.30(5) -- Power Purchase and Sale Agreement among LG&E Power
Marketing Inc., LG&E Energy Corp. and Oglethorpe, dated
as of November 19, 1996.

10.31(5) -- Power Purchase and Sale Agreement among LG&E Power
Marketing Inc., LG&E Power Inc. and Oglethorpe, dated as
of January 1, 1997.

10.32.1 -- 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.

10.32.2 -- 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.

10.32.3 -- 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.

10.32.4 -- 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.

10.32.5 -- 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.

10.32.6 -- 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.

10.32.7 -- Rocky Mountain Agreements Re-assignment and Assumption
Agreement (P1), dated as of December 30, 1996, between
SunTrust and Rocky Mountain Leasing Corporation,
together with a Schedule identifying five other
substantially identical Rocky Mountain Agreements
Re-assignment and Assumption Agreements.

10.32.8 -- 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.

10.32.9 -- 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.

10.32.10 -- 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.

10.32.11 -- 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.

10.32.12 -- 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.

10.32.13 -- 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.

10.32.14 -- 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.

10.32.15 -- 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.

10.32.16 -- 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.

10.32.17 -- 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.

10.32.18 -- 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.

10.32.19 -- 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.

10.33.1 -- Member Transmission Service Agreement, dated as of March
1, 1997, by and between Oglethorpe and Georgia
Transmission Corporation (An Electric Membership
Corporation).

10.33.2 -- Generation Services Agreement, dated as of March 1,
1997, by and between Oglethorpe and Georgia System
Operations Corporation.

10.33.3 -- Operation Services Agreement, dated as of March 1, 1997,
by and between Oglethorpe and Georgia System Operations
Corporation.

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

27.1 -- Financial Data Schedule (for SEC use only)

- ----------

(1) Pursuant to 17 C.F.R. 229.601(b)(2), the schedules and exhibits to this
document are identified on a list of schedules and exhibits included
becausewithin this document and are not filed herewith; however the subsidiary does not constitute a "significant subsidiary"
under Rule 1-02(v) of Regulation S-X).

- -------------------------
* Incorporated herein by reference.

+registrant
hereby agrees that such schedules and exhibits will be provided to the
Commission upon request.

(2) Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this document is not filed
herewith,herewith; however the registrant hereby agrees that such documentsdocument will be
provided to the Commission upon request.

++(3) For the reason stated in footnote (+)(2), this document and eightfive other
substantially identical documents are not filed as exhibits to this
Registration Statement.

+++(4) For the reason stated in the footnote (+)(2), this document and another
substantially identical document are not filed as exhibits to this
Registration Statement.

(5) Certain portions of this document have been omitted as confidential and
filed separately with the Commission.

(6) Indicates a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this form pursuant to Item 14(c) of
this report.

All other schedules and exhibits are omitted because of the absence of the
conditions under which they are required or because the required information is
included in the financial statements and related notes to financial statements.

(b) REPORTS ON FORMReports on Form 8-K.

No reports on Form 8-K were filed by Oglethorpe for the quarter ended
December 31, 1993.

SCHEDULE I

OGLETHORPE POWER CORPORATION
MARKETABLE SECURITIES--OTHER SECURITY INVESTMENTS
AS OF DECEMBER 31, 1993
(DOLLARS IN THOUSANDS)

NAME OF ISSUER AND PRINCIPAL MARKET CARRYING
TITLE OF EACH ISSUE AMOUNT COST VALUE AMOUNT
------------------- --------- ---- ------ --------

BOND, RESERVE AND CONSTRUCTION FUNDS:
United States Government
securities . . . . . . . . . . . . . $ 58,416 $ 57,622 $ 59,247 $ 57,622
Repurchase agreements. . . . . . . . . 52,768 52,768 52,768 52,768
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . $111,184 $110,390 $112,015 $110,390
-------- -------- -------- --------
-------- -------- -------- --------
DECOMMISSIONING FUND:
United States Government
securities . . . . . . . . . . . . . $ 37,112 $ 40,182 $ 39,694 $ 40,182
Corporate bonds. . . . . . . . . . . . 8,305 8,669 8,932 8,669
Cash and money market securities . . . 8,060 8,060 8,060 8,060
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . $ 53,477 $ 56,911 $ 56,686 $ 56,911
-------- -------- -------- --------
-------- -------- -------- --------
CASH AND TEMPORARY CASH INVESTMENTS:
Financial institution commercial
paper. . . . . . . . . . . . . . . . $ 55,700 $ 55,593 $ 55,593 $ 55,593
Other corporate commercial paper . . . 160,920 152,793 152,793 152,793
CFC commercial paper . . . . . . . . . 9,935 9,935 9,935 9,935
Repurchase agreements. . . . . . . . . 25,549 25,549 25,549 25,549
Cash and money market securities . . . 303 303 303 303
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . $252,407 $244,173 $244,173 $244,173
-------- -------- -------- --------
-------- -------- -------- --------

SCHEDULE V

OGLETHORPE POWER CORPORATION
UTILITY PLANT, INCLUDING INTANGIBLES
FOR THE YEAR ENDED DECEMBER 31, 1993
(DOLLARS IN THOUSANDS)

BALANCE AT OTHER BALANCE
BEGINNING ADDITIONS CHANGES AT END
CLASSIFICATION OF PERIOD AT COST RETIREMENTS(1) DEBIT/(CREDIT) OF PERIOD
- -------------- ---------- --------- -------------- -------------- ---------

Plant in service:
Intangible . . . . . . . . .$ 8,002 $ 1,214 $ - $ - $ 9,216
Production plant
Steam. . . . . . . . . . . 889,989 2,818 (354) (174)(4) 892,279
Nuclear. . . . . . . . . . 3,271,428 19,566 (2,553) (4,261)(4) 3,284,180
Hydro. . . . . . . . . . . 10,344 5 (8) - 10,341
Other. . . . . . . . . . . 3,665 - - - 3,665
Transmission plant . . . . . 469,275 7,455 (2,407) - 474,323
Distribution plant . . . . . 243,233 37,537 (5,727) - 275,043
General plant. . . . . . . . 72,624 13,971 (2,996) - 83,599
Construction work in
progress . . . . . . . . . . 322,628 128,337(2) - - 450,965
Plant held for future use. . . 11,720 3,375(3) - - 15,095
Plant acquisition
adjustments. . . . . . . . . 34,832 - - - 34,832
Nuclear fuel . . . . . . . . . 269,476 35,547 (73,773) - 231,250
---------- -------- -------- ------- ----------
Total Utility Plant. . . . .$5,607,216 $249,825 $(87,818) $(4,435) $5,764,788
---------- -------- -------- ------- ----------
---------- -------- -------- ------- ----------

- -----------------

Notes:
(1) Retirements have been charged to accumulated provision for depreciation
(Schedule VI).

(2) CWIP additions represent transfers to plant in service of $(72,512) and
additions and other miscellaneous transfers of $200,849.

(3) Plant held for future use additions represent transfers to plant in service
of $(66) and additions and other miscellaneous transfers of $3,441.

(4) Amounts represents an adjustment related to a change in inventory methods
at jointly owned generating plants. Certain items of spare parts inventory
were originally charged to plant investment.

SCHEDULE V

OGLETHORPE POWER CORPORATION
UTILITY PLANT, INCLUDING INTANGIBLES
FOR THE YEAR ENDED DECEMBER 31, 1992
(DOLLARS IN THOUSANDS)

Plant in service:
Intangibles. . . . . . . . .$ 7,925 $ 77 $ - $ - $ 8,002
Production plant
Steam. . . . . . . . . . . 894,904 1,465 (2,017) (4,363)(4) 889,989
Nuclear. . . . . . . . . . 3,270,823 13,016 (3,348) (9,063)(4) 3,271,428
Hydro. . . . . . . . . . . 10,327 17 - - 10,344
Other. . . . . . . . . . . 3,867 (202) - - 3,665
Transmission plant . . . . . 444,678 28,342 (3,745) - 469,275
Distribution plant . . . . . 216,326 28,927 (2,020) - 243,233
General plant. . . . . . . . 69,328 3,764 (468) - 72,624
Construction work in
progress . . . . . . . . . . 178,980 143,648 (2) - - 322,628
Plant held for future use. . . 11,803 (83)(3) - - 11,720
Plant acquisition
adjustments. . . . . . . . . 34,796 36 - - 34,832
Nuclear fuel . . . . . . . . . 309,102 51,992 (91,618) - 269,476
---------- -------- --------- -------- ----------
Total Utility Plant. . . . .$5,452,859 $270,999 $(103,216) $(13,426) $5,607,216
---------- -------- --------- -------- ----------
---------- -------- --------- -------- ----------
- ------------------

Notes:

(1) Retirements have been charged to accumulated provision for depreciation
(Schedule VI).

(2) CWIP additions represent transfers to plant in service of $(62,280) and
additions and other miscellaneous transfers of $205,928.

(3) Plant held for future use additions represent transfers to plant in service
of $(165) and additions and other miscellaneous transfers of $82.

(4) Amount represents an adjustment related to a change of inventory accounting
methods at jointly owned generating plants. Certain items of spare parts
inventory were originally charged to plant investment.

SCHEDULE V

OGLETHORPE POWER CORPORATION
UTILITY PLANT, INCLUDING INTANGIBLES
FOR THE YEAR ENDED DECEMBER 31, 1991
(DOLLARS IN THOUSANDS)

Plant in service:
Intangibles. . . . . . . . .$ 7,642 $ 283 $ - $ - $ 7,925
Production plant
Steam. . . . . . . . . . . 894,045 872 (13) - 894,904
Nuclear. . . . . . . . . . 3,254,930 21,298 (5,405) - 3,270,823
Hydro. . . . . . . . . . . 9,482 845 - - 10,327
Other. . . . . . . . . . . 3,867 - - - 3,867
Transmission plant . . . . . 422,946 22,838 (1,106) - 444,678
Distribution plant . . . . . 175,012 46,030 (4,716) - 216,326
General plant. . . . . . . . 67,311 2,152 (135) - 69,328
Construction work in
progress . . . . . . . . . . 102,045 76,935 (2) - - 178,980
Plant held for future use. . . 22,325 (10,522)(3) - - 11,803
Plant acquisition
adjustments. . . . . . . . . 34,588 208 - - 34,796
Nuclear fuel . . . . . . . . . 309,643 41,229 (41,770) - 309,102
---------- -------- -------- ---- ----------
Total Utility Plant. . . . .$5,303,836 $202,168 $(53,145) $ - $5,452,859
---------- -------- -------- ---- ----------
---------- -------- -------- ---- ----------
- ----------------

Notes:

(1) Retirements have been charged to accumulated provision for depreciation
(Schedule VI).

(2) CWIP additions represent transfers to plant in service of $(93,151) and
additions and other miscellaneous transfers of $170,086.

(3) Plant held for future use additions represent transfers to deferred debits
of $(21,131) and additions and other miscellaneous transfers of $10,609.

SCHEDULE VI

OGLETHORPE POWER CORPORATION
ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1993
(DOLLARS IN THOUSANDS)

BALANCE RETIREMENTS ADJUSTMENTS BALANCE
BEGINNING ANNUAL LESS NET AND AT END
DESCRIPTION OF PERIOD ACCRUALS(1) SALVAGE(2) TRANSFERS OF PERIOD
- ----------- ---------- ----------- ----------- ----------- ---------

Production plant:
Steam. . . . . . . . . . . $ (285,448) $ (24,830) $ 402 $ - (309,876)
Nuclear. . . . . . . . . . (546,748) (85,612) 4,450 - (627,910)
Hydro. . . . . . . . . . . (1,261) (252) 8 - (1,505)
Other. . . . . . . . . . . (915) (40) - - (955)
Transmission plant . . . . . (103,602) (11,057) 2,027 - (112,632)
Distribution plant . . . . . (27,105) (6,681) 3,295 - (30,491)
General plant. . . . . . . . (18,887) (4,240) 2,931 - (20,196)
Nuclear fuel . . . . . . . . (145,850) (48,996) 73,773 - (121,073)
Plant acquisition
adjustments. . . . . . . . (26,435) (1,061) - - (27,496)
Other miscellaneous. . . . . (5,926) (805) - - (6,731)
----------- --------- ------- ---- -----------
Total Accumulated
Provision For
Depreciation . . . . . . $(1,162,177) $(183,574) $86,886 $ - $(1,258,865)
----------- --------- ------- ---- -----------
----------- --------- ------- ---- -----------
- ----------------

Notes:

(1) Amount of annual accrual charged to:
Expense $(171,431)
Other accounts (12,143)
---------
$(183,574)
---------
---------

(2) Property Retirements:
Book cost $ 87,581
Removal cost 2,617
Salvage materials (3,312)
---------
$ 86,886
---------
---------

SCHEDULE VI

OGLETHORPE POWER CORPORATION
ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1992
(DOLLARS IN THOUSANDS)

Production plant:
Steam. . . . . . . . . . . $ (262,639) $ (24,924) $ 2,115 $ - $ (285,448)
Nuclear. . . . . . . . . . (466,631) (84,093) 3,976 - (546,748)
Hydro. . . . . . . . . . . (1,010) (251) - - (1,261)
Other. . . . . . . . . . . (873) (42) - - (915)
Transmission plant . . . . . (96,070) (10,795) 3,263 - (103,602)
Distribution plant . . . . . (22,134) (6,165) 1,194 - (27,105)
General plant. . . . . . . . (15,469) (3,921) 503 - (18,887)
Nuclear fuel . . . . . . . . (181,833) (55,635) 91,618 - (145,850)
Plant acquisition
adjustments. . . . . . . . (25,229) (1,206) - - (26,435)
Other miscellaneous. . . . . (5,025) (901) - - (5,926)
----------- --------- -------- ---- -----------
Total Accumulated
Provision For
Depreciation . . . . . . . $(1,076,913) $(187,933) $102,669 $ - $(1,162,177)
----------- --------- -------- ---- -----------
----------- --------- -------- ---- -----------
- ----------------

Notes:

(1) Amount of annual accrual charged to:
Expense $(170,916)
Other accounts (17,017)
---------
$(187,933)
---------
---------
(2) Property Retirements:
Book cost $103,215
Removal cost 1,538
Salvage materials (2,084)
---------
$102,669
---------
---------
1996.

SCHEDULE VI

OGLETHORPE POWER CORPORATION
ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1991
(DOLLARS IN THOUSANDS)

Production plant:
Steam. . . . . . . . . . . $(237,102) $ (25,603) $ 66 $ - $ (262,639)
Nuclear. . . . . . . . . . (379,311) (93,931) 6,611 - (466,631)
Hydro. . . . . . . . . . . (756) (254) - - (1,010)
Other. . . . . . . . . . . (829) (44) - - (873)
Transmission plant . . . . . (86,901) (10,301) 1,132 - (96,070)
Distribution plant . . . . . (19,493) (5,229) 2,588 - (22,134)
General plant. . . . . . . . (11,731) (3,856) 118 - (15,469)
Nuclear fuel . . . . . . . . (169,122) (54,481) 41,770 - (181,833)
Plant acquisition
adjustments. . . . . . . . (23,970) (1,259) - - (25,229)
Other miscellaneous. . . . . (4,137) (888) - - (5,025)
--------- --------- ------- ---- -----------
Total Accumulated
Provision For
Depreciation . . . . . . $(933,352) $(195,846) $52,285 $ - $(1,076,913)
--------- --------- ------- ---- -----------
--------- --------- ------- ---- -----------

- ----------------

Notes:

(1) Amount of annual accrual charged to:
Expense $(184,094)
Other accounts (11,752)
---------
$(195,846)
---------

(2) Property Retirements:
Book cost $ 53,047
Removal cost 1,631
Salvage materials (2,393)
---------
$ 52,285
---------
---------

SCHEDULE X

OGLETHORPE POWER CORPORATION
SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(DOLLARS IN THOUSANDS)

COLUMN A COLUMN B
- -------- -----------------------
CHARGED TO COSTS AND EXPENSES
-----------------------------
ITEM 1993 1992 1991
---- ---- ---- ----

Maintenance & repairs. . . . . . . . . . . . . . $67,572 $57,890 $74,050
Taxes other than payroll and income taxes:
Real & personal property taxes . . . . . . . . 21,992 14,640 22,431

J
- -

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 31st26th day of
March 1994.1997.

OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION &
TRANSMISSION CORPORATION)

By: /s/ J. CALVIN EARWOOD
---------------------------------------------------------------------------------------
J. CALVINCalvin EARWOOD, CHAIRMAN OF THE BOARD

PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OFPursuant 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.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 DATESignature Title Date
--------- ----- ----

/s/ J. CALVIN EARWOOD Chairman of the Board, March 31, 199426, 1997
- ---------------------------------------------------------------- Director (Principal Executive
J. CALVIN EARWOOD Officer)

/s/ T. D. KILGORE President and Chief Executive March 31, 199426, 1997
- ---------------------------------------------------------------- Officer (Principal Executive
T. D. KILGORE Officer)

/s/ JOHN S. DEAN, SR. Secretary-TreasurerVACANT (Principal March 31, 1994
- --------------------------- Financial Officer) JOHN S. DEAN, SR.March 26, 1997
- -------------------------------------
VACANT

/s/ EUGEN HECKL Senior Vice President and Chief March 31, 1994
- --------------------------- Financial Officer (Principal
EUGEN HECKL Financial Officer)

/s/ LARRY N. BROWNLEEROBERT D. STEELE Controller March 31, 199426, 1997
- ---------------------------------------------------------------- (Principal Accounting Officer)
LARRY N. BROWNLEEROBERT D. STEELE

/s/ JMON WARNOCKASHLEY C. BROWN Director March 31, 199426, 1997
- ---------------------------
JMON WARNOCK-------------------------------------
ASHLEY C. BROWN

/s/ CHARLES R. FENDLEYNEWTON A. CAMPBELL Director March 31, 199426, 1997
- ---------------------------
CHARLES R. FENDLEY

/s/ GEORGE C. MARTIN Director March 31, 1994
- ---------------------------
GEORGE C. MARTIN

SIGNATURE TITLE DATE
--------- ----- ----

/s/ J. G. MCCALMON Director March 31, 1994
- ---------------------------
J. G. MCCALMON

/s/ D.-------------------------------------
NEWTON A. ROBINSON, III Director March 31, 1994
- ---------------------------
D. A. ROBINSON, III

/s/ JAMES E. ESTES Director March 31, 1994
- ---------------------------
JAMES E. ESTESCAMPBELL

/s/ LARRY N. CHADWICK Director March 31, 199426, 1997
- ----------------------------------------------------------------
LARRY N. CHADWICK

/s/ SIMMIE KINGBENNY W. DENHAM Director March 31, 199426, 1997
- ---------------------------
SIMMIE KING-------------------------------------
BENNY W. DENHAM

/s/ W. F. FARRSAMMY M. JENKINS Director March 31, 199426, 1997
- ---------------------------
W. F. FARR

/s/ GARY T. DRAKE Alternate Director March 31, 1994
- ---------------------------
GARY T. DRAKE

/s/ JEFF S. PIERCE, JR. Director March 31, 1994
- ---------------------------
JEFF S. PIERCE, JR.

/s/ DONALD C. COOPER Director March 31, 1994
- ---------------------------
DONALD C. COOPER

/s/ HERBERT CHURCH Director March 31, 1994
- ---------------------------
HERBERT CHURCH-------------------------------------
SAMMY M. JENKINS

/s/ MAC F. OGLESBY Director March 31, 199426, 1997
- ----------------------------------------------------------------
MAC F. OGLESBY

/s/ BENNY W. DENHAM Director March 31, 1994
- ---------------------------
BENNY W. DENHAM

/s/ E.J. SAM L. MCLOCKLIN Director March 31, 1994
- ---------------------------
E. L. MCLOCKLIN

/s/ SAM RABUN Director March 31, 199426, 1997
- ----------------------------------------------------------------
J. SAM L. RABUN

/s/ E. J. MARTIN, JR. Director March 31, 1994
- ---------------------------
E. J. MARTIN, JR.

SIGNATURE TITLE DATE
--------- ----- ----

/s/ J. D. WILLIAMS Director March 31, 1994
- ---------------------------
J. D. WILLIAMS

/s/ RONNIE FLEEMAN Director March 31, 1994
- ---------------------------
RONNIE FLEEMAN

/s/ D. LAMAR COOPER Director March 31, 1994
- ---------------------------
D. LAMAR COOPER

/s/ BARRY H. MARTIN Director March 31, 1994
- ---------------------------
BARRY H. MARTIN

/s/ JOHN B. FLOYD, JR. Director March 31, 1994
- ---------------------------
JOHN B. FLOYD, JR.

/s/ STEVE RAWL, SR. Director March 31, 1994
- ---------------------------
STEVE RAWL, SR.

/s/ JAMES GRUBBS Director March 31, 1994
- ---------------------------
JAMES GRUBBS

/s/ SAMMY M. JENKINS Director March 31, 1994
- ---------------------------
SAMMY M. JENKINS

/s/ J. M. SHERRER Director March 31, 1994
- ---------------------------
J. M. SHERRER

/s/ JACK D. VICKERS Director March 31, 1994
- ---------------------------
JACK D. VICKERS

/s/ C. W. COX, JR. Director March 31, 1994
- ---------------------------
C. W. COX, JR.

/s/ JOHNNIE CRUMBLEY Director March 31, 1994
- ---------------------------
JOHNNIE CRUMBLEY

/s/ JARNETT W. WIGINGTON Director March 31, 1994
- ---------------------------
JARNETT W. WIGINGTON

/s/ BOB JERNIGAN Director March 31, 1994
- ---------------------------
BOB JERNIGAN

/s/ C. WILLARD MIMS Director March 31, 1994
- ---------------------------
C. WILLARD MIMS

/s/ JAMES E. DOOLEY Director March 31, 1994
- ---------------------------
JAMES E. DOOLEY

/s/ WILLIS T. WOODRUFF Director March 31, 1994
- ---------------------------
WILLIS T. WOODRUFF

SIGNATURE TITLE DATE
--------- ----- ----

/s/ HUBERT HANCOCK Director March 31, 1994
- ---------------------------
HUBERT HANCOCK

/s/ BOB J. DICKENS Director March 31, 1994
- ---------------------------
BOB J. DICKENS

/s/ W. W. ARCHER Director March 31, 1994
- ---------------------------
W. W. ARCHER

8984

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.

90
85