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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

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FORM 10-K

(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 1994
OR

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

FOR THE TRANSITION PERIOD FROM ------------ TO ------------

COMMISSION FILE NO. 33-7591

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OGLETHORPE POWER CORPORATION

(AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION)
(Exact name of registrant as specified in its charter)

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

POST OFFICE BOX 1349
2100 EAST EXCHANGE PLACE
TUCKER, GEORGIA
(Address of principal executive 30085-1349
offices) (Zip Code)

Registrant's telephone number, including area code: (404) 270-7600
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: NONE

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES__X__ NO______

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

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

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OGLETHORPE POWER CORPORATION
1994 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

SELECTED DEFINITIONS

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

TERM MEANING
---- -------
ADSCR Annual Debt 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 CoBank, ACB, formerly known as the 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
RUS Rural Utilities Service, formerly known as the 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

GENERAL

Oglethorpe Power Corporation (An Electric Membership Generation &
Transmission Corporation) ("Oglethorpe") is an electric generation and
transmission cooperative ("G&T") incorporated in 1974 in the State of Georgia.
It is 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&T 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.
Oglethorpe has approximately 500 full-time and 40 part-time employees.

As with cooperatives generally, Oglethorpe operates on a not-for-profit
basis. Oglethorpe's principal business is providing wholesale electric service
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. The
Members serve approximately 1.1 million electric consumers (meters) representing
a total population of approximately 2.5 million people.

MEMBER CONTRACTS

Each Member currently purchases capacity and energy from Oglethorpe
pursuant to a long-term, "all-requirements" wholesale power contract between
Oglethorpe and the Member (each a "Wholesale Power Contract" and collectively
the "Wholesale Power Contracts"). The existing Wholesale Power Contracts have a
term ending December 31, 2025 and continue thereafter until terminated by three
years' written notice by Oglethorpe or the respective Member. Each Wholesale
Power Contract provides that, except for power purchased from the Southeastern
Power Administration ("SEPA"), Oglethorpe shall sell and deliver to the Member,
and the Member shall purchase and receive from Oglethorpe, all electric capacity
and energy that the Member requires for the operation of its system to the
extent that Oglethorpe has capacity and energy and facilities available.
Oglethorpe supplies the 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, principally Georgia Power
Company ("GPC"), a wholly owned subsidiary of The Southern Company. In 1994, the
aggregate SEPA allocation to the Members was 542 megawatts ("MW") plus
associated energy, representing approximately 14% of total Member peak demand
and approximately 6% of total Member energy requirements. 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 "Member Demand and Energy Requirements" herein and "THE
MEMBERS OF OGLETHORPE--Contracts with SEPA".)

The Oglethorpe Board of Directors has authorized the study of three
options which would alter the existing contractual relationships between
Oglethorpe and the Members. The first is a study of the feasibility of changing
the existing "all-requirements" Wholesale Power Contract to allow a Member to
meet some portion of its future capacity and energy requirements with dispersed
generation. Oglethorpe's analysis indicates some economies may be available to
Oglethorpe and the Members through a small amount of Member-owned dispersed
generation. Dispersed generation units could be installed by the Members to
maintain reliability of electric service during emergencies on a Member's
distribution system or to serve specific customer needs.

Some of Oglethorpe's Members have installed small diesel generating units.
The aggregate capacity of these units amounts to approximately 1% of
Oglethorpe's total capacity requirements. During the 1994 Summer season, some of
these units were operated. The Members involved have given Oglethorpe written
assurances that the manner of operation was not in violation of the existing
Wholesale Power Contracts.

The second option is a study of the desirability of changing the existing
Wholesale Power Contract to allow a Member to elect to meet its future power
requirements above current levels either from Member-owned generation,

through purchases from Oglethorpe or from other power suppliers. The Members
who select this option would be responsible for some or all of their
future power requirements, but would be required to continue to purchase
capacity and energy from Oglethorpe's existing plants, committed generating
projects and existing power supply contracts.

The Board of Directors will review the findings of the studies and
determine what changes, if any, to make in the existing Wholesale Power
Contracts. Any changes would have to be approved by Oglethorpe's Board of
Directors and the Rural Utilities Service ("RUS"), formerly known as the Rural
Electrification Administration ("REA"). New contracts would have to be executed
by each Member desiring such changes.

The results of the studies and any action Oglethorpe and the Members might
take based thereon cannot be predicted at this time. However, assuming all three
options are made available to the Members, one or more Members may choose to
pursue each option. Under any of these three options, the Members must maintain
responsibility for their current obligations to Oglethorpe. Therefore,
Oglethorpe's future revenues associated with the Members' current obligations
would be unaffected. However, to the extent the Members choose to secure their
projected load growth from sources other than Oglethorpe, the growth in
Oglethorpe's revenues would decrease as would the related expenses.

Cobb EMC, Snapping Shoals EMC, and Walton EMC, three Members of Oglethorpe
representing a significant portion of Oglethorpe's future load growth, have
reported that they are considering withdrawing from membership in Oglethorpe.
They have also reported that they have initiated a feasibility study of, among
other things, separating from Oglethorpe by acquiring their pro rata shares of
Oglethorpe's assets and either paying or assuming their corresponding portions
of Oglethorpe's indebtedness. The RUS Administrator has advised Oglethorpe and
the three Members that RUS does not believe the asset acquisition approach is
feasible and suggested the parties focus on the three options described above.
Likewise, Oglethorpe's analysis indicates a lack of feasibility of the asset
acquisition concept, and, accordingly, the Oglethorpe Board of Directors has not
directed management to study this alternative.

MEMBER DEMAND AND ENERGY REQUIREMENTS

The following table shows the aggregate peak demand and energy
requirements of the Members for the years 1992 through 1994 and also shows the
amounts of such requirements supplied by Oglethorpe and SEPA. For the years 1992
through 1994, demand and energy requirements increased at an average annual
compound growth rate of 0.9% and 5.4%, 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)
----------- --------------- --------------- --------- ------------ -----------

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
1994.......... 3,938 3,396 542 17,278,812 16,285,127 993,685

<FN>
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(1) System peak demand of the Members measured at the Members' delivery points
(net of system losses). The reduction in peak demand in 1994 was due to a
hotter than normal summer in 1993 and a milder than normal summer in 1994.

(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".)

In 1994, Cobb EMC and Jackson EMC each accounted for approximately 10% of
Oglethorpe's total revenues.

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 "Electric Rates" herein.) During 1992 through 1994,
however, Oglethorpe's rate structure was designed to cause capacity revenues,
which include margins, to remain relatively level throughout the year. These
capacity charges, which were based on the prior year annual peak demands, did
not fluctuate based on a Member's usage during a given year. As of January 1,
1995, Oglethorpe implemented two additional capacity rate options, based on
current year billing determinants, which do fluctuate based on Member's usage
during the year. The two new options were selected by 11 of the 39 Members from
which Oglethorpe receives about 50% of its capacity revenues. Energy revenues
track energy costs as they are incurred and also fluctuate month to month.

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, 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".)

ELECTRIC RATES

Each Member is required to pay Oglethorpe for capacity and energy
furnished under its Wholesale Power Contract in accordance with rates
established by Oglethorpe. Oglethorpe reviews its rates at such intervals as it
deems appropriate but is required to do so at least once every year. Oglethorpe
is required to revise its rates as necessary so that the revenues derived from
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 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
requirements (including coverage ratios) under the Consolidated Mortgage and
Security Agreement dated as of September 1, 1994 (the "RUS Mortgage") among
Oglethorpe, as mortgagor, and the United States of America acting through the
Administrator of RUS, CoBank, ACB, formerly known as 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 RUS Mortgage.
(See "General--RATES AND 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 1994, which amounts will be fully amortized by the end of 1996. (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 commercial and industrial 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 RUS. Oglethorpe is required under the 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 RUS Mortgage. Oglethorpe's current policy is to set rates
to meet a TIER of 1.07 in 1995, 1.08 in 1996, 1.09 in 1997 and 1.10 in 1998 and
thereafter. (See "General--RATES AND FINANCIAL COVERAGE REQUIREMENTS" in Item
7.)

The Wholesale Power Contracts provide that no rate revision shall be
effective unless approved by RUS, but such rate revisions are not subject to the
approval of any other Federal or state agency or authority, including the
Georgia Public Service Commission (the "GPSC"). To date, RUS 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--FACTORS AFFECTING FUTURE
FINANCIAL PERFORMANCE" in Item 7.

CERTAIN FACTORS AFFECTING THE UTILITY INDUSTRY IN GENERAL

The electric utility industry is becoming increasingly competitive as a
result of deregulation, competing energy suppliers, technologies, and other
factors. The Energy Policy Act of 1992 (the "Energy Policy Act") amended the
Federal Power Act and the Public Utility Holding Company Act to 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
level, which is based on a shift to a market-driven environment from a regulated
one. Significant developments at the Federal Energy Regulatory Commission
("FERC") and in state commissions are expected to continue to clarify the
policy and regulatory framework for increased competition. (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 management of resources and respond to the
changing environment. (See "THE POWER SUPPLY SYSTEM--General", "--Future Power
Resources" and "--Environmental and Other Regulations".)

RELATIONSHIP WITH GPC

Oglethorpe's relationship with GPC is a significant factor in several
aspects of Oglethorpe's business. GPC is Oglethorpe's principal supplier of
purchased power, and Oglethorpe is one of GPC's largest customers. In 1994,
Oglethorpe derived 8% of its total revenues from sales to GPC, making GPC one of
Oglethorpe's largest customers. Substantially all of Oglethorpe's generating
facilities were purchased at various stages of construction from GPC and were
constructed and are now operated by GPC. Oglethorpe is the construction and
operating 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 from GPC to schedule its power
resources and its off-system purchases and sales. Oglethorpe, through the
Members, is one of GPC's principal 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 POWER SUPPLY
SYSTEM--General", "--Fuel Supply", "--Power Sales to and Purchases from GPC",
"--Future Power Resources--ROCKY MOUNTAIN", "--Transmission and Other Power
System Arrangements", "CO-OWNERS OF THE PLANTS AND THE PLANT AND

TRANSMISSION AGREEMENTS--Co-Owners of the Plants--GEORGIA POWER COMPANY",
"--The Plant Agreements", "--Agreements Relating to the Integrated
Transmission System", and "--The Joint Committee Agreement".

RELATIONSHIP WITH RUS

Federal loan programs administered by RUS have provided the principal
source of financing for electric cooperatives. Direct loans from RUS have been a
major source of funding for the Members, while loans guaranteed by RUS and made
by the Federal Financing Bank ("FFB") have been a major source of funding for
Oglethorpe. Through provisions of the RUS Mortgage, RUS exercises 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.

In October 1994, the Secretary of Agriculture substantially reorganized
the Department of Agriculture. The electric and telephone loan programs
administered by the Rural Electrification Administration were transferred to
the newly created RUS, and the Rural Electrification Administration was
abolished. This reorganization did not change the provisions of the electric
loan program and thus has had no significant effect on Oglethorpe or its
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.

The President's budget for fiscal year 1996 proposes to set the level of
funding for the 100% guarantee program at $400 million, which if sustained at
that level in future years would not likely provide adequate funding for the
transmission and power supply needs of RUS borrowers. Congress historically has
increased Administration-proposed lending levels to those necessary to meet
borrower demand. Notwithstanding historical practices, the future cost,
availability and magnitude of RUS-guaranteed loans cannot be predicted. See "THE
MEMBERS OF OGLETHORPE--Members' Relationship with RUS" for a discussion of the
impact of the budget proposal on the direct loan program.

RUS continues to reevaluate its regulatory and lending relationship with
its borrowers through what it has described as a comprehensive rule-making
project. The purpose of the project is to improve the credit-worthiness of loans
made or guaranteed by RUS. In addition to adopting new rules regulating policies
and procedures for insured and guaranteed loans and lien accommodations, RUS has
published a proposed rule describing a new form of wholesale power contract and
a new standard form of mortgage for distribution borrowers. In advance notices
of proposed rule-makings, RUS also has requested suggestions for revisions to
its standard form of mortgage for power supply borrowers and comments on
proposals for credit support for loans to power supply borrowers. These
rule-makings continue to take 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
RUS, or the extent to which such initiatives may affect Oglethorpe or the
Members cannot be predicted.

THE MEMBERS OF OGLETHORPE

SERVICE AREA AND COMPETITION

The Members are identified in Item 10(a) of this Report and include 39 of
the 42 electric distribution cooperatives in the State of Georgia. The Members
serve approximately 1.1 million electric consumers (meters) representing a total
population of approximately 2.5 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 1994 amounted to approximately
16.4 million megawatt-hours ("MWh"), with 72% to residential consumers, 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 1994. 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
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 1992
through 1994 of 6.0% in number of consumers, 7.3% in MWh sales and 9.5% 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;
however, the Territorial Act permits competition among electric suppliers for
new retail loads of 900 kilowatts or more outside existing municipal limits.
Except for these 900-kilowatt loads, the Members have the exclusive right to
provide retail electric service in their respective assigned territories, which
are predominately outside of municipal limits. The GPSC may not reassign
territory or transfer service except in limited circumstances provided by the
Territorial Act. 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.

As referenced above, the Territorial Act allows 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 industrial and commercial loads. The number of
commercial and industrial loads served by the Members has increased in recent
years. While the competition for 900-kilowatt loads represents only limited
competition in Georgia, retail competition in the electric utility industry is
currently rare and 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 may be approached by other parties interested
in purchasing their systems. Some of the Members have been approached in the
past by third parties indicating an interest in purchasing their systems. The
Wholesale Power 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 RUS 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 RUS and otherwise complying with such reasonable
terms and conditions as Oglethorpe and RUS may require. The enforceability of
the RUS form of wholesale power contract has been consistently upheld by the
courts in several jurisdictions. In addition, RUS has 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.

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 RUS 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 RUS 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 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--Member Contracts".) The revenues of the Members
are not pledged as security to Oglethorpe but are the source from which moneys
are derived by the Members to pay for power supplied by Oglethorpe under the
Wholesale Power Contracts. Revenues of the Members that borrow from RUS are,
however, pledged under the respective RUS mortgages of the Members.

RATE REGULATION OF MEMBERS

Through provisions in the loan documents securing loans to the Members,
RUS 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 RUS 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.

Snapping Shoals EMC in 1994 and Mitchell EMC in 1995 prepaid their RUS
indebtedness and are no longer RUS borrowers. Cobb EMC and Walton EMC have
applied to RUS to prepay their RUS indebtedness and it is likely that other
Members will also pursue this option. Snapping Shoals EMC and Mitchell EMC now
have financial and other requirements under their loan documents with the
National Rural Utilities Cooperative Finance Corporation ("CFC").

Although the setting of the rates of the Members is not subject to
approval of any Federal or state agency or authority other than RUS, the
Territorial Act prohibits the Members from unreasonable discrimination in the
setting of rates, charges, service rules or regulations and requires the Members
to obtain GPSC approval of long-term borrowings.

CONTRACTS WITH SEPA

In addition to energy received from Oglethorpe under the Wholesale Power
Contracts, the Members purchase hydroelectric power under contracts with SEPA.
In 1994, the aggregate SEPA allocation to the Members was 542 MW plus associated
energy, representing approximately 14% of total Member peak demand and
approximately 6% of total Member energy requirements. (See "OGLETHORPE POWER
CORPORATION--Member Contracts" and "--Member Demand and Energy Requirements" and
the table thereunder.)

On December 8, 1994, SEPA issued its final Power Marketing Policy for the
Georgia - Alabama - South Carolina System of Projects. This policy will govern
the renewal of SEPA's contracts with the Members. There were no significant
changes in this final marketing policy and the Members' allocation of capacity
and energy remained unchanged.

SEPA has contracted with The Southern Company for scheduling and
dispatching services for SEPA's generating projects in Georgia and Alabama and
for transmission services to certain preference customers. During 1994, SEPA
began negotiating revised arrangements for these services. Originally scheduled
for renewal on May 31, 1994, SEPA extended the term of the Members' contracts
until January 31, 1995, with a provision automatically to extend one month at a
time thereafter until negotiations with The Southern Company are completed. In
the event negotiations are not successful, an order may be sought from FERC
requiring the provision of these services at just and reasonable rates.

The President's Budget proposal for fiscal year 1996 includes a proposal
to privatize four of the five federal power marketing administrations. Under the
proposal, legislation would be proposed to privatize SEPA in 1997. The
President's proposal would protect customers from significant rate increases.
Legislation would also be proposed to allow proceeds from this proposed sale to
be counted as offsets to spending under the Balanced Budget and Deficit Control
Act of 1985. The ultimate outcome of this proposal in Congress cannot be
predicted with certainty.

MEMBERS' RELATIONSHIP WITH RUS

Federal loan programs providing direct loans from RUS to electric
cooperatives have been a major source of funding for the Members. Recent changes
and proposals for further changes have made the direct loan program administered
by RUS more costly. Uncertainties continue about the level of funding available
under the RUS loan program. The Rural Electrification Loan Restructuring Act of
1993 eliminated the long-standing 5% 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 have a 7%
cap on interest rates. The President's budget proposal for fiscal year 1996
includes a proposal to remove this 7% cap. The outcome of this budget proposal
and the future cost, availability and amount of RUS direct and guaranteed loans
cannot be predicted.

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

THE POWER SUPPLY SYSTEM

GENERAL

Oglethorpe supplies the current capacity and energy requirements of the
Members from a combination of owned and leased generating plants and power
purchased under long-term contracts with other power suppliers. These resources
are scheduled and dispatched so as to minimize the operating cost of
Oglethorpe's system. In addition, Oglethorpe purchases and sells capacity and
energy in the bulk power market to make the best use of its resources and thus
minimize the cost of capacity and energy delivered to the Members.

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 and expected to be in commercial operation by the
Summer of 1995. 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") and the City of Dalton ("Dalton"). GPC is the operating agent for each
of these plants, except Rocky Mountain. 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
TYPE OF PERCENTAGE PLATE CAPACITY OPERATION EXPIRATION
FUEL INTEREST(1) (MW) DATE DATE
----------- --------------- --------------- --------------- -------------

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)
Unit No. 2 Coal 30 259.5 1978 N/A(3)
Combustion Turbine Oil 30 14.8 1980 N/A(3)
Plant Scherer (near Forsyth)
Unit No. 1 Coal 60 490.8 1982 N/A(3)
Unit No. 2 Coal 60 490.8 1984 N/A(3)
Tallassee (near Athens) Hydro 100 2.1 1986 2023
-------

Total in Service 2,702.5

FACILITIES UNDER CONSTRUCTION:
Rocky Mountain Pumped
(near Rome) Storage 75(2) 635.9 1995 2027
Hydro
-------

Total Ownership 3,338.4
-------
-------
<FN>
------------------------------

(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 conventional hydroelectric capacity.

Oglethorpe and the other co-owners of the above plants also own
transmission facilities which together form 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 parties 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 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:

EQUIVALENT AVAILABILITY(1) CAPACITY FACTOR(2)
------------------------------------ -------------------------------------
Unit 1994 1993 1992 1994 1993 1992
------------------------------- ----------- ----------- ---------- ----------- ----------- -----------

Plant Hatch
Unit No. 1 84% 76% 95% 85% 77% 95%
Unit No. 2 78 75 70 79 75 70
Plant Vogtle
Unit No. 1 86 85 96 86 86 96
Unit No. 2 91 87 80 91 87 80
Plant Wansley
Unit No. 1 92 88 92 62 71 76
Unit No. 2 88 90 92 58 73 77
Plant Scherer
Unit No. 1 97 88 95 64 36 17
Unit No. 2 85 95 100 60 37 29
<FN>
------------------------

(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.

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. However, with
the acquisition of lower cost low-sulfur coal from the western United States,
utilization of Scherer Units No. 1 and No. 2 was higher in 1994. Oglethorpe's
management anticipates continued higher utilization of Scherer Units No. 1 and
No. 2 in the future.

FUEL 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. As of February 28, 1995, there was a 70-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, 1995, the coal stockpile at Plant Scherer contained a 39-day supply based on
nameplate rating. During 1994 Plant Scherer was converted to burn both
sub-bituminous and bituminous coals, and a separate stockpile of sub-bituminous
coal was built in addition to the stockpile of bituminous coal.

The Scherer ownership and operating agreements were amended in 1993 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. Pursuant to the
amendments, Oglethorpe implemented separate dispatch in 1994. Oglethorpe intends
to continue to use GPC as its agent for fuel procurement. The co-owners have
negotiated similar amendments to the Plant Wansley Operating Agreement. Upon
approval by RUS, Oglethorpe expects to implement separate dispatch at Plant
Wansley as well.

To 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 231 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.

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

GPC, as operating agent, has the responsibility to procure nuclear fuel
for Plants Hatch and 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, 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 Plants Hatch and
Vogtle. The services to be provided by DOE are scheduled to begin in 1998;
however, the DOE has stated that permanent nuclear waste storage facilities will
not be available by that date, and it is 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, alternative methods of spent fuel storage will be needed.
One option available is expansion of spent fuel storage at the plant sites. (See
"Environmental and Other Regulations" herein 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
--------------------
1994 1993
--------- ---------

SOURCES OF ENERGY:
Owned or Leased Generation..................... 16,924,038 14,575,920
Purchased -- GPC............................... 2,632,039 5,198,356
-- Others............................ 1,749,048 2,422,459
---------- ----------
Total Sources........................ 21,305,125 22,196,735
---------- ----------
---------- ----------

DISTRIBUTION OF ENERGY:
Members........................................ 16,285,127 16,253,283
Non-Members -- GPC............................. 2,140,526 3,432,542
-- Others.......................... 2,067,443 1,617,684
Transmission Losses............................. 812,029 893,226
--------- ---------
Total Distribution................... 21,305,125 22,196,735
---------- ----------
---------- ----------

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 all
units, except for Unit No. 2 of Plant Vogtle, which will expire at the end of
May 1995. For 1994, the GPC Sell-back represented 3% of total energy sales by
Oglethorpe. Capacity and energy revenues from the GPC Sell-back represented 4%
of Oglethorpe's total revenues in 1994.

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 "CO-OWNERS OF THE PLANTS AND THE PLANT AND
TRANSMISSION AGREEMENTS--The Plant Agreements--HATCH, WANSLEY, VOGTLE AND
SCHERER", General--HISTORICAL FACTORS AFFECTING FINANCIAL PERFORMANCE in Item 7
and Note 1 of Notes to Financial Statements in Item 8.)

POWER PURCHASE ARRANGEMENTS

Oglethorpe currently purchases 1,250 MW of capacity and associated energy
from GPC on a take-or-pay basis under the BPSA, which extends through December
31, 2002. The BPSA, along with the Revised and Restated Integrated Transmission
System Agreement (the "ITSA") and the CSA, became effective in 1991. Together
these agreements enabled Oglethorpe to restructure the way it 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 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 one 250 MW Component Block (coal-fired units) effective September 1, 1996
and is currently negotiating a replacement purchase. 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, GPC provides various control-area services to Oglethorpe.
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 provide
Oglethorpe with the capability 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
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 9 of the Financial Statements in Item 8.)

In 1992, Oglethorpe entered into a contract for the purchase of
approximately 300 MW of capacity (subject to change annually by a demonstrated
capacity test) 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. Commercial operation of the facility
began in April 1994. The contract will expire in April 2019. Oglethorpe intends
to use the units for peaking capacity but has the right fully to dispatch the
units.

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 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 1994.

FUTURE POWER RESOURCES

Oglethorpe uses an integrated resource 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 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, 1995, Rocky Mountain was approximately 98% complete. All
units of Rocky Mountain are currently scheduled to be in commercial operation by
the Summer of 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, 1994, Oglethorpe's ownership interest in
Rocky Mountain was approximately 73%. Based on current arrangements,
Oglethorpe's ultimate ownership interest in Rocky Mountain is estimated to
be approximately 75%, with GPC owning the remaining 25%.

OTHER FUTURE RESOURCES

In its current integrated resource plan, Oglethorpe has identified a
potential need for additional peaking capacity in the late 1990s. Oglethorpe has
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. In 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.
Oglethorpe is reviewing the proposals it received in 1994. From the responses
(which proposed almost 26,000 MW of peaking capacity), Oglethorpe has selected a
short list of suppliers that best meet its future capacity needs on the basis of
price, risk, and flexibility. Oglethorpe is negotiating with these companies and
expects to award final contracts in late 1995 or early 1996.

TRANSMISSION AND OTHER POWER SYSTEM ARRANGEMENTS

Oglethorpe owns approximately 2,230 miles of transmission line and 420
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 over 20 utilities and other
power suppliers. 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.)
Oglethorpe has purchased from GPC sufficient entitlement to the interface
between the ITS and TVA to implement the purchases from Big Rivers and EPI.
Oglethorpe regularly buys and sells power in the short-term bulk power market.
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, to provide transmission service to third
parties and to compete in an increasingly competitive market.

FUTURE 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. 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 particulate matter, sulfur oxides and nitrogen oxides
("NOx") 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 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 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 environmental requirements are expected
to be approximately $2.1 million in 1995, $5.9 million in 1996 and $6.7 million
in 1997.

CLEAN AIR ACT

The Clean Air Act seeks to improve the ambient air quality throughout the
United States. The acid rain provisions of Title IV require the reduction of
sulfur dioxide and NOx 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. Beginning in 1995, Phase I
affected units become subject to the sulfur dioxide 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 sulfur dioxide during a
calendar year, is transferable and can be bought, sold or banked for use
in the years following its issuance. Oglethorpe expects to achieve
compliance with Phase I 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.

For Phase II, which begins in the year 2000, when total U.S. emissions of
sulfur dioxide will be capped at 8.9 million tons, Oglethorpe could use a
variety of options for sulfur dioxide 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.

NOx regulations implementing the requirements of Title IV have not yet
been finalized. Depending on those NOx rules when finalized, additional
expenditures for pollution control equipment may be incurred.

In general, compliance with the Clean Air Act will require expenditures
for monitoring and permitting, and in some instances may involve increased
operating or maintenance expenses. Capital expenditures of Oglethorpe through
1994 for pollution control equipment needed to comply with the Clean Air Act at
Plant Wansley have been approximately $6.2 million and at Scherer Units No. 1
and No. 2 have been approximately $720,000. The estimated cost of any additional
improvements at Plant Wansley and Scherer Units No. 1 and No. 2 will be
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.

Metropolitan Atlanta is classified as a "serious nonattainment area" with
regard to the ozone ambient air quality standards. Title I of the Clean Air Act,
under which these standards are promulgated, requires the State of Georgia to
conduct specific studies and establish new rules regulating sources of NOx and
volatile organic compounds, to achieve attainment of the standards by 1999 and
to maintain compliance thereafter. As a required first step, Georgia has issued
rules for the application of reasonably available control technology for NOx
emissions. Those regulations, however, did not affect Plant Wansley or Scherer
Units No. 1 and No. 2, which are not in the Atlanta ozone nonattainment area.
Georgia is still performing photochemical grid modeling, however, and as a
result may yet promulgate new Title I rules for power plants in the 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 for Title IV compliance. Title III of the
Clean Air Act Amendments 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 Titles I or III, including new rules under the amended provisions,
cannot now be predicted.

The Clean Air Act requires 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. Although EPA has evaluated the need and decided for now not to
revise the NAAQS for nitrogen dioxides, there is no guarantee that that standard
will not be revised in the future. In addition, EPA is updating the criteria
document and staff paper for ozone, which could lead to a change in the NAAQS
for ozone. EPA is also preparing a criteria document and staff paper for
particulate matter, which could lead to a revision of the NAAQS for particulate
matter. The impact of any change in the ozone, sulfur dioxide, nitrogen dioxides
or particulate matter NAAQS cannot now be determined because the effect of any
change would depend in part on the final ambient standards. Congress is
considering reopening portions of the Clean Air Act for amendment. The impact of
such amendments can not be predicted at this time and will depend on the final
legislation and development of any implementing regulations.

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 financial condition. 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

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 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, the Resource Conservation &
Recovery Act ("RCRA"), the Endangered Species Act ("ESA"), the Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA"), 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, however, could affect many areas of Oglethorpe's
operations. Congress is considering amending the ESA and reauthorizing CERCLA
and perhaps RCRA. Moreover, Congress is considering regulatory reform
legislation that could impact the development and implementation of
environmental regulations. 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 that might be brought
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 services by such
suppliers. It 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.

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

CO-OWNERS OF THE PLANTS

Plants Hatch, Vogtle, Wansley and Scherer Units No. 1 and No. 2 are
co-owned by Oglethorpe, GPC, MEAG and Dalton, and Rocky Mountain is co-owned by
Oglethorpe and GPC. Each such co-owner owns, 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
-------------------------------- -------------------------------- --------------
PLANT PLANT PLANT SCHERER UNITS ROCKY
HATCH VOGTLE WANSLEY NO. 1 & NO. 2 MOUNTAIN(3) TOTAL
-------------- --------------- -------------- -------------- ------------- ------
% MW(1) % MW(1) % MW(1) % MW(1) % MW(1) MW(1)
---- ----- --- ----- --- ----- --- ----- --- ----- -----

Oglethorpe . . 30.0 489 30.0 696 30.0 519 60.0(2) 982 75(4) 636 3,322
GPC. . . . . . 50.1 817 45.7 1,060 53.5 926 8.4 137 25(4) 212 3,152
MEAG . . . . . 17.7 288 22.7 527 15.1 261 30.2 494 -- -- 1,570
Dalton . . . . 2.2 36 1.6 37 1.4 24 1.4 23 -- -- 120
----- ----- ----- ----- ----- ----- ----- ----- --- --- -----
Total. . . . . 100.0 1,630 100.0 2,320 100.0 1,730 100.0 1,636 100 848 8,164
----- ----- ----- ----- ----- ----- ----- ----- --- --- -----
----- ----- ----- ----- ----- ----- ----- ----- --- --- -----
<FN>
-----------------------

(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 by the Summer of 1995.

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

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--
Relationship with GPC".)

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").
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 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 has entered into power sales contracts
with each of 47 cities and one county in the State of Georgia. Such political
subdivisions, located in 39 of the State's 159 counties, collectively serve more
than 250,000 electric customers.

CITY OF DALTON, GEORGIA

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

THE PLANT AGREEMENTS

HATCH, WANSLEY, VOGTLE AND SCHERER

Oglethorpe's rights and obligations with respect to Plants Hatch, Wansley,
Vogtle and Scherer are contained in a number of contracts between Oglethorpe and
GPC and, in some instances, MEAG and Dalton. Oglethorpe is a party to four
Purchase and Ownership Participation Agreements ("Ownership Agreements") under
which it acquired from GPC a 30% undivided interest in each of Plants Hatch,
Wansley and Vogtle, a 60% undivided interest in Scherer Units No. 1 and No. 2
and a 30% undivided interest in those facilities at Plant Scherer intended to be
used in common by Scherer Units No. 1, No. 2, No. 3 and No. 4 (the "Scherer
Common Facilities"). Oglethorpe has also entered into four Operating Agreements
("Operating Agreements") relating to the operation and maintenance of Plants
Hatch, Wansley 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 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 is separately dispatching its ownership share of Scherer Units No. 1
and No. 2. Similar amendments to the Plant Wansley Operating Agreement have been
negotiated and, upon approval of RUS, Oglethorpe expects to dispatch separately
its ownership share in Plant Wansley. (See "THE POWER SUPPLY SYSTEM--Fuel
Supply".) In 1990, the co-owners of Plants Hatch and Vogtle entered into the
NMBA 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 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 the proposed amendments to the Plant Wansley Operating
Agreement are effective, each party will be responsible 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.

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.

(See "THE POWER SUPPLY SYSTEM--Proposed Changes to Nuclear Plant Operating
Arrangements".)

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 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 acquired
a 3% undivided interest in Rocky Mountain, together with a future interest in
the remaining 97% undivided interest. 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 elect to
schedule separately its ownership interest. The Rocky Mountain Operating
Agreement will terminate on the fortieth anniversary of the Completion
Adjustment Date (as defined therein).

AGREEMENTS RELATING TO THE INTEGRATED TRANSMISSION SYSTEM

Oglethorpe and GPC have entered into the ITSA to provide for the
transmission and distribution of electric energy in the State of Georgia, other
than in certain counties, and for bulk power transactions, through use of the
ITS. The ITS, together with transmission system facilities acquired or
constructed 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 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 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 work 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 for Plants
Hatch and Vogtle, the Plant Scherer Managing Board has assumed such
responsibilities for Plant Scherer and an operating committee will assume such
responsibilities for Plant Wansley once the proposed amendments to the Plant
Wansley Operating Agreement are effective. (See "The Plant Agreements--HATCH,
WANSLEY, VOGTLE AND SCHERER" herein.) The Joint Committee Agreement also makes
allowance for the joint planning of future transmission and generation
facilities.

ITEM 2. PROPERTIES

Information with respect to Oglethorpe's properties is set forth under the
caption "THE POWER SUPPLY SYSTEM" included in Item 1 and is incorporated herein
by reference.

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.

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

Not applicable.

PART II

Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Not applicable.

Item 6. SELECTED FINANCIAL DATA
-------------------------------------------------------------------------------

(dollars in thousands)
1994 1993 1992 1991 1990

OPERATING REVENUES:
Sales to Members. . . . . . . . . . . . . . . $ 930,875 $ 899,720 $ 816,000 $ 763,657 $ 710,607
Sales to non-Members . . . . . . . . . . . . 125,207 200,940 268,763 300,293 390,535
----------- ----------- ----------- ----------- -----------
Total operating revenues . . . . . . . . . . 1,056,082 1,100,660 1,084,763 1,063,950 1,101,142
----------- ----------- ----------- ----------- -----------

OPERATING EXPENSES:
Fuel. . . . . . . . . . . . . . . . . . . . . 203,444 176,342 167,288 165,168 209,971
Production . . . . . . . . . . . . . . . . . 132,723 129,972 115,915 130,041 125,506
Purchased power . . . . . . . . . . . . . . . 227,477 271,970 230,510 229,898 213,311
Depreciation and amortization . . . . . . . . 131,056 128,060 126,047 135,152 134,021
Taxes . . . . . . . . . . . . . . . . . . . . 24,741 25,148 19,634 42,422 41,798
Other operating expenses. . . . . . . . . . . 49,234 44,876 50,578 49,373 41,755
----------- ----------- ----------- ----------- -----------
Total operating expenses. . . . . . . . . . . 768,675 776,368 709,972 752,054 766,362
----------- ----------- ----------- ----------- -----------

OPERATING MARGIN . . . . . . . . . . . . . . . . 287,407 324,292 374,791 311,896 334,780
OTHER INCOME, NET . . . . . . . . . . . . . . . 40,795 38,741 45,928 113,441 94,471
NET INTEREST CHARGES . . . . . . . . . . . . . . (305,120) (350,652) (393,247) (396,892) (400,712)
----------- ----------- ----------- ----------- -----------
MARGIN BEFORE CUMULATIVE EFFECT OF CHANGE
IN ACCOUNTING PRINCIPLE . . . . . . . . . . 23,082 12,381 27,472 28,445 28,539
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING
FOR INCOME TAXES . . . . . . . . . . . . . . -- 13,340 -- -- --
----------- ----------- ----------- ----------- -----------
NET MARGIN . . . . . . . . . . . . . . . . . . . $ 23,082 $ 25,721 $ 27,472 $ 28,445 $ 28,539
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

ELECTRIC PLANT, NET:
In service. . . . . . . . . . . . . . . . . . $ 3,980,439 $ 4,054,956 $ 4,122,411 $ 4,196,966 $ 4,268,440
Construction work in progress . . . . . . . . 538,789 450,965 322,628 178,980 102,045
----------- ----------- ----------- ----------- -----------
. . . . . . . . . . . . . . . . . . . . . . . $ 4,519,228 $ 4,505,921 $ 4,445,039 $ 4,375,946 $ 4,370,485
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

TOTAL ASSETS . . . . . . . . . . . . . . . . . . $ 5,348,455 $ 5,323,890 $ 5,359,597 $ 5,246,435 $ 5,200,762
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

CAPITALIZATION:
Long-term debt. . . . . . . . . . . . . . . . $ 4,128,080 $ 4,058,251 $ 4,095,796 $ 4,093,218 $ 4,094,246
Obligation under capital leases . . . . . . . 303,749 303,458 302,061 300,833 299,783
Patronage capital and membership fees . . . . 309,496 289,982 264,261 236,789 217,895
----------- ----------- ----------- ----------- -----------
. . . . . . . . . . . . . . . . . . . . . . . $ 4,741,325 $ 4,651,691 $ 4,662,118 $ 4,630,840 $ 4,611,924
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
PROPERTY ADDITIONS . . . . . . . . . . . . . . . $ 206,345 $ 235,285 $ 232,283 $ 225,021 $ 200,257
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

ENERGY SUPPLY (MEGAWATT-HOURS):
Generated . . . . . . . . . . . . . . . . . . 16,924,038 14,575,920 13,805,683 12,686,323 13,387,572
Purchased . . . . . . . . . . . . . . . . . . 4,381,087 7,620,815 6,233,262 6,915,758 6,198,434
----------- ----------- ----------- ----------- -----------
Available for sale . . . . . . . . . . . . . 21,305,125 22,196,735 20,038,945 19,602,081 19,586,006
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

MEMBER REVENUE PER kWh SOLD . . . . . . . . . . 5.65 CENTS 5.47 CENTS 5.55 CENTS 5.36 CENTS 5.01 CENTS
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------

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

GENERAL
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 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, as of
December 31, 1994, had a balance of $309 million in patronage capital.
Patronage capital constitutes the principal equity of Oglethorpe. Under
Oglethorpe's patronage capital retirement policy, margins are returned to the
Members 30 years after the year in which the margins 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 by the
Rural Utilities Service (RUS), formerly known as the Rural Electrification
Administration (REA).
Oglethorpe's equity ratio (patronage capital and membership fees divided by
total capitalization) increased from 6.2% at December 31, 1993 to 6.5% at
December 31, 1994.

RATES AND FINANCIAL COVERAGE REQUIREMENTS
Oglethorpe has entered into an "all-requirements" wholesale power contract
with each of its Members. Pursuant to such contracts, Oglethorpe is required to
design capacity and energy rates that generate sufficient revenues to recover
all costs as described in such contracts and to establish and maintain
reasonable margins. 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 set
annually and adjusted at mid-year to recover actual fuel and variable operations
and maintenance costs. Rate revisions by Oglethorpe are subject to the approval
of the RUS and, to date, the RUS has not reduced or delayed the effectiveness of
any rate increase proposed by Oglethorpe.
The capacity rate which Oglethorpe used in 1992 through 1994 was based on a
proportional allocation of fixed costs over the previous year's billing demand
for each Member. Consequently, the rate produced capacity revenues (which
included the recovery of margins) which were constant throughout the year and
were virtually unaffected by current year factors. In 1995, management expects a
net increase in fixed costs; however, because of anticipated increases in energy
sales and decreases in fuel costs, average Member revenues (measured in cents
per kilowatt-hour (kWh)) should remain at or near the 1994 level.
As of January 1, 1995, Oglethorpe implemented two additional capacity rate
options in an effort to provide greater flexibility to the Members. These
options allocate fixed costs using billing determinants of the current year.
These rates do not produce constant capacity revenues throughout the year and
introduce some variability and uncertainty as to the level of revenues and
margins to be received. The two new options were selected by 11 Members from
which Oglethorpe receives about 50% of its capacity revenues.
Oglethorpe utilizes 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 RUS Mortgage requires Oglethorpe to
implement rates that are designed to maintain an annual TIER of not less than
1.05. In 1992, as part of a plan to build additional equity, Oglethorpe's Board
of Directors revised its annual net margin goal to be 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.
In addition to the TIER requirement under the RUS Mortgage, Oglethorpe is
also required under the RUS 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. By paying in full or
defeasing certain outstanding pollution control revenue bonds (PCBs), Oglethorpe
could reduce the ADSCR requirement to 1.15. 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 RUS Mortgage (excluding
interest charged to construction).
Oglethorpe has always met or exceeded the TIER, DSC and ADSCR requirements
of the RUS Mortgage. TIER, DSC and ADSCR for the years 1992 through 1994 were as
follows:

-------------------------------------------------------------------------------
1994 1993 1992
-------------------------------------------------------------------------------

TIER 1.07 1.07 1.07
DSC 1.19 1.23 1.22
ADSCR 1.25 1.26 1.25
-------------------------------------------------------------------------------

Historically, by setting rates to meet the TIER goals established by
Oglethorpe's Board, the DSC and ADSCR requirements of the RUS Mortgage have
always been met or exceeded. Based on Oglethorpe's financial projections,
however, TIER levels under the current Board policy may not produce rates
sufficient to meet the current ADSCR requirement in the near

future. In that event, Oglethorpe would have to adjust rates to meet the current
ADSCR requirement or take action to lower the ADSCR requirement by prepaying
certain PCBs as described above.

HISTORICAL FACTORS AFFECTING FINANCIAL PERFORMANCE
Over the past several 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 absorbed into rates additional responsibility for
the cost of its ownership interests in Plant Vogtle Units No. 1 and
No. 2 and Plant Scherer Unit No. 2. The mechanisms used by Oglethorpe to
mitigate the rate impact of absorbing these costs have included both long-term
contractual arrangements with Georgia Power Company (GPC) and Board of Directors
policies that have resulted in the gradual absorption of costs over several
years.
Contractual arrangements with GPC have provided 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 years of operation of such units (GPC Sell-back). The GPC
Sell-back has now expired for all units, except for Plant Vogtle Unit No. 2
which will expire as of May 31, 1995. (See Note 1 of Notes to Financial
Statements.) 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 1994, Oglethorpe exceeded its net margin goal. The Board
adopted resolutions in each of these years requiring that these excess margins
be retained and used to mitigate rate increases associated with Plant Vogtle. In
each year beginning with 1989, a portion of these margins has been 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 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, 1994, Oglethorpe held a balance of approximately $37
million from deferred margins and the voluntary Vogtle Surcharge of one of these
two Members, which will be utilized for future rate mitigation. Oglethorpe's
Board of Directors and the Members intend to utilize these amounts as offsets to
rates charged during 1995 and 1996.

RESULTS OF OPERATIONS
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.
For the period 1992 through 1994, although total revenues have remained
virtually unchanged, the scheduled reduction of the GPC Sell-back has resulted
in the planned decrease of non-Member revenues from GPC of about $126 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 sales to other
utilities and achieved reductions in fixed and operating costs in order to
mitigate the need to recover from the Members costs which were previously
recovered through sales to GPC. The refinancing transactions discussed under
"Liquidity and Capital Resources" herein and other factors have resulted in a
reduction in net interest charges from $393 million in 1992 to $305 million in
1994, or a 22% decrease in fixed costs to be recovered through the capacity
rates.

SALES TO MEMBERS. Revenues from sales to Members increased 3.5% in 1994
compared to 1993 and increased 10.3% in 1993 compared to 1992. These increases
reflect two factors: (1) higher capacity revenues, offset by the pass-through of
savings in energy costs (see discussion of savings in fuel costs under
"Operating Expenses" herein), and (2) increased amounts of energy sold.
As non-Member revenues from GPC have declined, Oglethorpe's Member capacity
revenues are higher reflecting the recovery of the fixed costs which had
previously been recovered from GPC through the GPC Sell-back.
Member energy revenues per kWh declined in 1994 compared to 1993,
reflecting savings in fuel and production costs. The average energy cost
recovered in 1994 was virtually unchanged from the average cost in 1992. Actual
energy costs are passed through to the Members such that energy revenues equal
energy costs.
The following table summarizes the amounts of kWh sold to Members during
each of the past three years:

-------------------------------------------------------------------------------
Kilowatt-hours
(in thousands)
-------------------------------------------------------------------------------

1994 16,285,127
1993 16,253,283
1992 14,466,943
-------------------------------------------------------------------------------

Member sales have been significantly affected by abnormal weather
conditions during the past two years. In 1993, prolonged hot weather boosted
sales, while in 1994 record-breaking rainfall amounts statewide moderated Member
sales.

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 average Member revenues:

-------------------------------------------------------------------------------
Cents per Kilowatt-hour
-------------------------------------------------------------------------------

1994 5.65 CENTS
1993 5.47
1992 5.55
-------------------------------------------------------------------------------

SALES TO 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:

-------------------------------------------------------------------------------
1994 1993 1992
(dollars in thousands)
-------------------------------------------------------------------------------

Plant operating agreements $ 45,392 $106,146 $171,686
Power supply arrangements 26,280 44,904 61,602
Transmission agreements 8,783 13,549 29,586
Other utilities 44,752 36,341 5,889
-------- -------- --------
Total $125,207 $200,940 $268,763
-------- -------- --------
-------- -------- --------
-------------------------------------------------------------------------------

Revenues from sales to non-Members declined in 1994 compared to 1993 and in
1993 compared to 1992. These decreases were primarily attributable to scheduled
reductions in plant operating agreement revenues attributable to the GPC
Sell-back with respect to Plants Vogtle and Scherer.
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 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.
Revenues from sales of this type to GPC were lower in 1994 compared to 1993 and
in 1993 compared to 1992 due to the fact that Oglethorpe retained much of its
share of the output from the Plant Scherer and Wansley units because the lower
average fuel costs made those units more attractive than certain purchased
resources. See the discussion under "Operating Expenses" below of the lower
average fuel costs of the coal-fired generating units in 1994. 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 the above
"automatic" type of sales transaction; however, Oglethorpe did continue to make
other sales to GPC from Plant Scherer in this category. Once the amendments to
the Plant Wansley operating agreement become effective, Oglethorpe will commence
separate dispatch of its ownership interest in that Plant.
The third source of non-Member revenues is payments from GPC for use of the
Integrated Transmission System (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. The higher amount of transmission agreement revenues in 1992
compared to 1994 and 1993 was partially attributable to the receipt by
Oglethorpe 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.
Revenues from other non-Member utilities increased substantially due to a
28% increase in kWh sales in 1994 as compared to 1993 and a 49% increase in kWh
sales in 1993 as compared to 1992. Oglethorpe is continuing to aggressively seek
additional off-system sales opportunities as a means of reducing amounts that
must be recovered from Members.

OPERATING EXPENSES
Oglethorpe's operating expenses decreased 1.0% in 1994 compared to 1993 and
increased 9.4% in 1993 compared to 1992. The slight decrease in operating
expenses in 1994 compared to 1993 was largely due to the decline in purchased
power expenses offset somewhat by the increase in fuel expenses. The total kWh
of energy supplied through generation and purchased power in 1994 was 4% less
than 1993. The increase in operating expenses in 1993 compared to 1992 was
primarily attributable to an 11% increase in kWh sold and higher taxes other
than income taxes.
Generally, over the years 1992 through 1994, the Members have received the
benefit of declining per unit fuel costs of Oglethorpe's generating resources
through the pass-through of lower energy costs. The per unit fuel costs of
Oglethorpe's nuclear and fossil generating resources for the last three years
were as follows:

-------------------------------------------------------------------------------
Cents per Kilowatt-hour
-----------------------
Nuclear Fossil
-------------------------------------------------------------------------------

1994 0.64 CENTS 1.78 CENTS
1993 0.61 1.96
1992 0.66 2.04
-------------------------------------------------------------------------------

Oglethorpe began receiving shipments at Plant Scherer of lower-priced coal
from the mining regions of the western United States in the last quarter of
1993. Due primarily to the use of this lower-priced coal, the per unit fuel cost
for the Plant Scherer units decreased by almost 9% in 1994 from 1993 levels.
Additionally, due to a greater reliance on a favorable spot market for coal, the
per unit fuel cost at Plant Wansley decreased by almost 10% in 1994 compared to
1993. Because of the decline in fuel cost per kWh, the usage of the fossil units
has increased significantly, particularly the Plant Scherer units. Output from
these units was 75% higher in 1994 as compared to 1993 and 61% higher in 1993
than in 1992.
The lower amount of production expenses in 1992 compared to 1994 and 1993
was attributable to a reduced number of nuclear refueling outages in 1992. Two
of Oglethorpe's nuclear units underwent planned outages in 1992, as compared to
three

units in both 1994 and 1993.
The significant increase in 1994 in coal-fired generation (prompted by
declining average fuel costs) as well as declining sales from these coal-fired
resources to GPC pursuant to power supply arrangement (see discussion under
"Operating Revenues" above) have resulted in substantially lower utilization of
purchased power resources. Energy purchases decreased by approximately 43% from
1993 levels. The increase in 1993 in purchased power expenses was the result of
a 22% increase in kWh purchases. This increase was, for the most part,
necessitated by the greater energy needs of the Members (see "Operating Revenues
-- Sales to Members" herein) and by Oglethorpe's increased off-system energy
sales (see "Operating Revenues -- Sales to non-Members" herein).
Property taxes, which constitute the majority of taxes other than income
taxes, were lower in 1992 as compared to 1994 and 1993 as a result of the
favorable resolution of Oglethorpe's property tax appeal with the State of
Georgia for the years 1985 through 1988. The negotiated settlement of this
appeal resulted in a reduction of 1992 property tax expense in the amount of
approximately $7.5 million.

OTHER INCOME
Interest income decreased in 1994 and in 1993 as a result of lower
investment returns and lower average cash balances. In 1992, 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.
In 1994, 1993 and 1992, Oglethorpe's Board of Directors authorized the
retention of approximately $9 million, $5 million and $40 million, respectively,
in excess of the 1.07 TIER margin requirement as deferred margins. The remaining
amounts will be available in 1995 and 1996 to mitigate rate increases.
Amortization of deferred margins for 1994 was set by Oglethorpe's Board of
Directors at $18 million, significantly more than the amount utilized in 1993
but less than the amount utilized in 1992. (See Note 1 of Notes to Financial
Statements for a discussion of deferred margins and amortization of deferred
margins.)

INTEREST CHARGES
Net interest charges declined in 1994 compared to 1993 and in 1993 compared
to 1992. The decrease in interest on long-term debt and capital leases in 1994
was due, for the most part, to the refinancing efforts discussed under
"Liquidity and Capital Resources" herein. Allowance for debt and equity funds
used during construction (AFUDC) increased in 1994 and in 1993 as a result of
increased construction activity at Rocky Mountain. The decrease in other
interest expense in 1994 was primarily due to losses incurred on the sale of
securities contained in the decommissioning fund. (See Note 1 for explanation of
Oglethorpe's accounting for decommissioning gains and losses.) The decrease in
other interest expense in 1993 was primarily due to higher interest expense in
1992 associated with the settlement of the property tax appeal and the federal
income tax case. Additionally, Oglethorpe paid a premium (equal to approximately
one year's interest on these refinanced advances) in 1992 in connection with its
refinancing of FFB advances at reduced rates.

FACTORS AFFECTING FUTURE FINANCIAL PERFORMANCE
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) and related transmission facilities, the cost of adding to
Oglethorpe's existing transmission system, changes in fuel costs, fluctuating
rates of load growth, environmental and other governmental regulations
applicable to Oglethorpe and its suppliers and the completion in 1996 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.
The electric utility industry is also becoming increasingly competitive as
a result of deregulation, competing energy suppliers, technologies and other
factors. The Energy Policy Act of 1992 allows 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 developments at
the Federal Energy Regulatory Commission (FERC) and in 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, improve the management of resources
and respond to the changing environment.
To respond to a more competitive utility environment, Oglethorpe has been
discussing the need for a more flexible power supply arrangement with its
Members. The Oglethorpe Board of Directors has authorized the study of three
options which would alter the existing contractual relationships between
Oglethorpe and the Members. The first is a study of the feasibility of changing
the existing "all-requirements" wholesale power contract to allow a Member to
meet some portion of its future capacity and energy requirements with dispersed
generation. Oglethorpe's analysis indicates some economies may be available to
Oglethorpe and the Members through a small amount of Member-owned dispersed
generation. Dispersed generation units could be installed by the Members to
maintain reliability of electric service during emergencies on a Member's
distribution system or to serve specific customer needs.
The second option is a study of the desirability of changing the existing
wholesale power contract to allow a Member to elect to meet its future power
requirements above current levels either from Member-owned generation, through
purchases from Oglethorpe or from other power suppliers. The Members who select
this option would be responsible for some or all of their future power
requirements, but would be required to continue to purchase capacity and energy
from Oglethorpe's existing plants, committed generating projects and existing
power supply contracts.

The third option involves the development of specific implementation
procedures for the existing bylaw provision that grants a Member the right to
withdraw from membership in Oglethorpe upon satisfying certain conditions. These
conditions include, but are not limited to, satisfying or making adequate
provisions for satisfying the Member's obligations under its wholesale power
contract. Oglethorpe is considering a contract by which a Member could withdraw
if they continued to purchase all capacity and related energy from Oglethorpe's
existing plants, committed generating projects and existing power supply
contracts.
The Board of Directors will review the findings of the studies and
determine what changes, if any, to make in the existing wholesale power
contracts. Any changes would have to be approved by Oglethorpe's Board of
Directors and RUS. New contracts would have to be executed by each Member
desiring such changes.
The results of the studies and any action Oglethorpe and the Members might
take based thereon cannot be predicted at this time. However, assuming all three
options are made available to the Members, one or more Members may choose to
pursue each option. Under any of these three options, the Members must maintain
responsibility for their current obligations to Oglethorpe. Therefore,
Oglethorpe's future revenues associated with the Members' current obligations
would be unaffected. However, to the extent the Members choose to secure their
projected load growth from sources other than Oglethorpe, the growth in
Oglethorpe's revenues would decrease as would the related expenses.
Cobb EMC, Snapping Shoals EMC, and Walton EMC, three Members of Oglethorpe
representing a significant portion of Oglethorpe's future load growth, have
reported that they are considering withdrawing from membership in Oglethorpe.
They have also reported that they have initiated a feasibility study of, among
other things, separating from Oglethorpe by acquiring their pro rata shares of
Oglethorpe's assets and either paying or assuming their corresponding portions
of Oglethorpe's indebtedness. The RUS Administrator has advised Oglethorpe and
the three Members that RUS does not believe the asset acquisition approach is
feasible and suggested the parties focus on the three options described above.
Likewise, Oglethorpe's analysis indicates a lack of feasibility of the asset
acquisition concept, and, accordingly, the Oglethorpe Board of Directors has not
directed management to study this alternative.

LIQUIDITY AND CAPITAL RESOURCES
In the past, Oglethorpe, like most other G&Ts, has obtained the majority of
its long-term financing from RUS-guaranteed loans funded by the Federal
Financing Bank (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 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, 1994. Expenditures for property
additions during 1994 amounted to approximately $206 million, of which $33
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 1997, including AFUDC:

-------------------------------------------------------------------------------
CAPITAL EXPENDITURES
(DOLLARS IN THOUSANDS)
Rocky General
Year Generation (1) Transmission Mountain (2) Plant Total
-------------------------------------------------------------------------------

1995 $72,897 $38,377 $54,442 $11,453 $177,169
1996 79,968 41,021 895 2,978 124,862
1997 82,133 42,508 924 3,107 128,672

-------- -------- ------- ------- --------
Total $234,998 $121,906 $56,261 $17,538 $430,703
-------- -------- ------- ------- --------
-------- -------- ------- ------- --------
<FN>

(1) Consists of capital expenditures required for replacements and additions to
facilities in service, compliance with environmental regulations, and nuclear
fuel reloads.

(2) Includes additions to Rocky Mountain after its in-service date, but does not
include any amounts which may be paid as final adjustments to contractors.

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

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, 1994, Rocky Mountain was approximately 98% complete and
Oglethorpe's investment in the project was $499 million. The current schedule
anticipates commercial operation by the Summer of 1995. Oglethorpe is financing
its share of Rocky Mountain from the proceeds of an RUS-guaranteed loan funded
through the FFB. As of December 31, 1994, $422 million had been advanced under
this loan commitment and $285 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. 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 requirement of at least 1.0
and that the RUS 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. Oglethorpe's management believes that the total project cost will
come in considerably under budget and the amounts remaining to be drawn under
such loan will be more than adequate to finance completion of the project.

Based on its current construction budget, Oglethorpe anticipates that it
will fund all capital expenditures through 1997, other than for Rocky Mountain,
with funds generated from operations and, if necessary, with short-term
borrowings.
Oglethorpe has a commercial paper program under which it may issue
commercial paper not to exceed $300 million outstanding at any one time. The
commercial paper may be used as a source of short-term funds 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 back-up 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, 1994,
Oglethorpe's short-term credit facilities were as follows:

-------------------------------------------------------------------------------
Short-Term Credit Facilities Authorized
Amount
-------------------------------------------------------------------------------

Commercial Paper . . . . . . . . . . . . . . . . . . . . . . $300,000,000
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 $370 million due to
certain restrictions contained in the CFC and Trust Company Bank line of credit
agreements. As of December 31, 1994, 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% of the outstanding principal amount of the
variable rate refunding bonds issued. 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
termination of the forward interest rate swap transactions, (ii) cash, (iii)
United States government securities, and (iv) accounts receivable due within 30
days, less (b) monetary obligations due within 30 days. As of December 31, 1994,
Oglethorpe had approximately $390 million of such liquidity available to meet
this requirement.
Oglethorpe's scheduled maturities of long-term debt over the next five
years total $481 million. Of this amount, $376 million, or 78%, relates to the
repayment of RUS and FFB debt.

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 PCB and FFB debt. Since the first transaction was completed in
June 1992, Oglethorpe has refinanced $1.1 billion in PCB debt and $1.1 billion
in FFB debt and has prepaid another $105 million in FFB debt. Included in these
amounts are 1994 refinancings of $375 million of PCB debt and $795 million of
FFB debt (see Note 5 of Notes to Financial Statements). The net result of the
1994 transactions was to reduce the average interest rate on total long-term
debt from 7.94% at December 31, 1993 to 7.07% at December 31, 1994. The average
interest rate was further reduced to 6.82% as of January 31, 1995 as a result of
a $285 million FFB debt refinancing and a prepayment of an additional $30
million in FFB debt. The refinancings completed since the program began will
result in total estimated savings in gross interest costs for 1995 in excess of
$80 million.

MISCELLANEOUS
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.
Currently, Oglethorpe is subject to the provisions of Statement of
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 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 utility plant, and write down the assets to their fair value. See Note
1 of Notes to Financial Statements for additional information.
The staff of the SEC 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 agreed to review the
accounting for nuclear decommissioning costs. If current electric utility
industry accounting practices for such decommissioning are changed, these
changes could, among other things, impact the amount of annual provisions for
decommissioning. Oglethorpe's management does not believe that this or other
changes, if required, would have an adverse effect on results of operations due
to its 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.
Financial Accounting Standards Board Statement No. 115, "Accounting for
Certain Investments in Debt and Equity Securities," was adopted by Oglethorpe in
1994 and had no material effect on the results of operations.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO FINANCIAL STATEMENTS

PAGE
----

Statements of Revenues and Expenses, For the Years Ended
December 31, 1994, 1993 and 1992. . . . . . . . . . . . . . . . . 33
Statements of Patronage Capital, For the Years Ended
December 31, 1994, 1993 and 1992. . . . . . . . . . . . . . . . . 33
Balance Sheets, As of December 31, 1994 and 1993 . . . . . . . . . . . 34
Statements of Capitalization, As of December 31, 1994 and 1993 . . . . 36
Statements of Cash Flows, For the Years Ended
December 31, 1994, 1993 and 1992. . . . . . . . . . . . . . . . . 37
Notes to Financial Statements. . . . . . . . . . . . . . . . . . . . . 38
Report of Management . . . . . . . . . . . . . . . . . . . . . . . . . 48
Report of Independent Public Accountants . . . . . . . . . . . . . . . 48

STATEMENTS OF REVENUES AND EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992

---------------------------------------------------------------------------------------------------------
(dollars in thousands)
1994 1993 1992

OPERATING REVENUES (NOTE 1):
Sales to Members. . . . . . . . . . . . . . . . . . . . $ 930,875 $ 899,720 $ 816,000
Sales to non-Members. . . . . . . . . . . . . . . . . . 125,207 200,940 268,763
---------- ---------- ----------
TOTAL OPERATING REVENUES . . . . . . . . . . . . . . . . . . 1,056,082 1,100,660 1,084,763
---------- ---------- ----------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . 203,444 176,342 167,288
Production. . . . . . . . . . . . . . . . . . . . . . . 132,723 129,972 115,915
Purchased power (Note 9). . . . . . . . . . . . . . . . 227,477 271,970 230,510
Power delivery . . . . . . . . . . . . . . . . . . . . 16,965 14,286 17,804
Sales, administrative and general . . . . . . . . . . . 32,269 30,590 32,774
Depreciation and amortization . . . . . . . . . . . . . 131,056 128,060 126,047
Taxes other than income taxes . . . . . . . . . . . . . 24,741 23,328 15,668
Income taxes (Note 1) . . . . . . . . . . . . . . . . . -- 1,820 3,966
---------- ---------- ----------
TOTAL OPERATING EXPENSES . . . . . . . . . . . . . . . . . . 768,675 776,368 709,972
---------- ---------- ----------
OPERATING MARGIN . . . . . . . . . . . . . . . . . . . . . . 287,407 324,292 374,791
---------- ---------- ----------

OTHER INCOME (EXPENSE):
Interest income . . . . . . . . . . . . . . . . . . . . 10,518 20,316 29,218
Gain on sale of debt service reserve fund securities. . -- -- 3,884
Amortization of deferred gains (Notes 2 and 6). . . . . 9,985 12,532 12,486
Amortization of proceeds from sale of income tax
benefits (Note 6) . . . . . . . . . . . . . . . . . 8,102 8,102 8,102
Amortization of deferred margins (Note 1) . . . . . . . 18,072 4,138 35,973
Deferred margins (Note 1) . . . . . . . . . . . . . . . (9,287) (5,083) (40,464)
Co-owner inventory settlement . . . . . . . . . . . . . -- -- (4,827)
Allowance for equity funds used during
construction (Note 1) . . . . . . . . . . . . . . . 2,907 2,278 1,377
Other . . . . . . . . . . . . . . . . . . . . . . . . . 498 (3,542) 179
---------- ---------- ----------
TOTAL OTHER INCOME . . . . . . . . . . . . . . . . . . . . 40,795 38,741 45,928
---------- ---------- ----------

INTEREST CHARGES:
Interest on long-term debt and capital leases . . . . . 329,738 367,439 392,454
Other interest . . . . . . . . . . . . . . . . . . . . 3,856 8,539 17,049
Allowance for debt funds used during construction
(Note 1). . . . . . . . . . . . . . . . . . . . . . . . (36,113) (29,988) (20,255)
Amortization of debt discount and expense . . . . . . . 7,639 4,662 3,999
---------- ---------- ----------
NET INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . 305,120 350,652 393,247
---------- ---------- ----------
MARGIN BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE . . . . . . . . . . . . . . . . . 23,082 12,381 27,472
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR
INCOME TAXES . . . . . . . . . . . . . . . . . . . . . -- 13,340 --
---------- ---------- ----------
NET MARGIN . . . . . . . . . . . . . . . . . . . . . . . . . $ 23,082 $ 25,721 $ 27,472
---------- ---------- ----------
---------- ---------- ----------

STATEMENTS OF PATRONAGE CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992

---------------------------------------------------------------------------------------------------------
(dollars in thousands)
1994 1993 1992

Patronage capital and membership fees -- beginning
of year (Note 1) . . . . . . . . . . . . . . . . . . . . $ 289,982 $ 264,261 $ 236,789
Net margin . . . . . . . . . . . . . . . . . . . . . . . . . 23,082 25,721 27,472
Unrealized loss on available-for-sale securities,
net of income taxes (Note 3). . . . . . . . . . . . . . (3,568) -- --
--------- --------- ---------
Patronage capital and membership fees--end of year . . . . . $ 309,496 $ 289,982 $ 264,261
--------- --------- ---------
--------- --------- ---------

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

BALANCE SHEETS
DECEMBER 31, 1994 AND 1993

----------------------------------------------------------------------------------------------------
(dollars in thousands)
ASSETS 1994 1993

ELECTRIC PLANT (NOTES 1, 2 AND 6):
In service . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 5,100,299 $ 5,047,739
Less: Accumulated provision for depreciation. . . . . . . . . . . (1,231,818) (1,110,296)
----------- ----------
3,868,481 3,937,443

Nuclear fuel, at amortized cost . . . . . . . . . . . . . . . . . 105,683 110,177
Plant acquisition adjustments, at amortized cost . . . . . . . . 6,275 7,336
Construction work in progress . . . . . . . . . . . . . . . . . . 538,789 450,965
----------- ----------
4,519,228 4,505,921
----------- ----------

INVESTMENTS AND FUNDS (NOTES 1, 3 AND 4):
Bond, reserve and construction funds, at market . . . . . . . . . 64,163 110,390
Decommissioning fund, at market . . . . . . . . . . . . . . . . . 59,164 56,911
Investment in associated organizations, at cost . . . . . . . . . 17,371 19,123
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- 486
----------- ----------
140,698 186,910
----------- ----------

CURRENT ASSETS:
Cash and temporary cash investments, at cost (Note 1) . . . . . . 190,642 244,173
Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . 90,998 82,274
Inventories, at average cost (Note 1) . . . . . . . . . . . . . . 95,076 86,468
Prepayments and other current assets . . . . . . . . . . . . . . 14,857 14,763
----------- ----------
391,573 427,678
----------- ----------

DEFERRED CHARGES:
Premium and loss on reacquired debt, being amortized (Note 5) . . 161,889 91,981
Deferred amortization of Scherer leasehold (Note 2) . . . . . . . 80,132 71,559
Discontinued projects, being amortized (Note 6) . . . . . . . . . 26,342 18,314
Deferred debt expense, being amortized . . . . . . . . . . . . . 20,936 21,527
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,657 --
----------- ----------
296,956 203,381
----------- ----------
$ 5,348,455 $ 5,323,890
----------- ----------
----------- ----------

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

------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)

EQUITY AND LIABILITIES 1994 1993

CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Patronage capital and membership fees (Note 1) . . . . . . . . . . . . . . . . . . . $ 309,496 $ 289,982
Long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,128,080 4,058,251
Obligation under capital leases (Note 2). . . . . . . . . . . . . . . . . . . . . . . 303,749 303,458
---------- ----------
4,741,325 4,651,691
---------- ----------
CURRENT LIABILITIES:
Long-term debt due within one year . . . . . . . . . . . . . . . . . . . . . . . . . 90,086 78,644
Deferred margins and Vogtle surcharge to be refunded within one year (Note 1) . . . . 21,476 20,103
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52,921 62,186
Accrued interest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 100,010 108,702
Accrued and withheld taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,566 9,401
Energy cost billed in excess of actual (Note 1) . . . . . . . . . . . . . . . . . . . 2,125 11,456
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18,177 40,234
---------- ----------
286,361 330,726
---------- ----------

DEFERRED CREDITS AND OTHER LIABILITIES:
Gain on sale of plant, being amortized (Note 2) . . . . . . . . . . . . . . . . . . . 63,209 65,550
Gain on sale of Scherer common facilities, being amortized (Note 6) . . . . . . . . . -- 7,644
Sale of income tax benefits, being amortized (Note 6) . . . . . . . . . . . . . . . . 58,236 66,838
Accumulated deferred income taxes (Note 1). . . . . . . . . . . . . . . . . . . . . . 65,510 65,510
Deferred margins and Vogtle surcharge (Note 1). . . . . . . . . . . . . . . . . . . . 15,568 27,757
Decommissioning reserve (Note 1) . . . . . . . . . . . . . . . . . . . . . . . . . . 96,291 90,476
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21,955 17,698
---------- ----------
320,769 341,473
---------- ----------

COMMITMENTS AND CONTINGENCIES (NOTES 2, 6, 8 AND 9)
$5,348,455 $5,323,890
---------- ----------
---------- ----------

STATEMENTS OF CAPITALIZATION
DECEMBER 31, 1994 AND 1993

------------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
1994 1993

LONG-TERM DEBT (NOTE 5):
Mortgage notes payable to the Federal Financing Bank (FFB) at interest rates varying from
5.79% to 10.78% (average rate of 7.61% at December 31, 1994) due in quarterly
installments through 2023. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,161,550 $ 3,040,767

Mortgage notes payable to the Rural Utilities Service (RUS) at an interest rate of
5% due in monthly installments through 2021. . . . . . . . . . . . . . . . . . . . . . . . . 23,467 23,927

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
Term bonds, 6.80%, due 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- 16,700

- Series 1982
Serial bonds, 10.20% to 10.60%, due serially through 1997 . . . . . . . . . . . . . . . . . 16,135 23,195

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

- Series 1984B
Serial bonds, 9.75% to 10.50%, due serially through 2000 . . . . . . . . . . . . . . . . . . -- 11,530

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

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

-Series 1992A
Adjustable tender bonds, 3.00% to 4.00%, due 2025 . . . . . . . . . . . . . . . . . . . . . 216,925 216,925

Serial bonds, 4.25% to 6.80%, due serially from 1994 through 2012. . . . . . . . . . . . . . 139,240 143,710

- Series 1993
Serial bonds, 2.90% to 5.25%, due serially from 1995 through 2013. . . . . . . . . . . . . . 39,090 --

- Series 1993A
Adjustable tender bonds, 4.95%, due 2016 . . . . . . . . . . . . . . . . . . . . . . . . . . 199,690 199,690

- Series 1993B
Serial bonds, 2.90% to 5.05%, due serially from 1995 through 2008. . . . . . . . . . . . . . 155,610 --

- Series 1994
Serial bonds, 4.90% to 7.125%, due serially from 1996 through 2015. . . . . . . . . . . . . 10,690 --
Term bonds, 7.15% due 2021 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11,550

- Series 1994A
Adjustable tender bonds, 4.95%, due 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . 122,740 --

- Series 1994B
Serial bonds, 4.90% to 6.45%, due serially from 1996 through 2005. . . . . . . . . . . . . . 13,720 --

National Bank for Cooperatives (CoBank) notes payable:
- Headquarters note payable: $5.4 million fixed at 7.40% through April 1995, $0.2 million
fixed at 7.20%-7.35% to April 1995; due in quarterly installments through
January 1, 2009. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,549 5,938
- Transmission note payable: fixed at 7.40% through April 1995; due in bimonthly
installments through November 1, 2018 . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,279 2,296
- Transmission note payable: fixed at 7.25% through April 1995; due in bimonthly
installments through September 1, 2019 . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,697 8,751
----------- -----------
4,219,062 4,143,114

Less: Unamortized debt discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (896) (6,219)
----------- -----------
Total long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,218,166 4,136,895

Less: Amount due within one year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (90,086) (78,644)
----------- -----------
TOTAL LONG-TERM DEBT, EXCLUDING AMOUNT DUE WITHIN ONE YEAR . . . . . . . . . . . . . . . . . . . . . . 4,128,080 4,058,251

OBLIGATION UNDER CAPITAL LEASES (NOTE 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 303,749 303,458

PATRONAGE CAPITAL AND MEMBERSHIP FEES (NOTE 1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . 309,496 289,982
----------- -----------
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 4,741,325 $ 4,651,691
----------- -----------
----------- -----------

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

STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992

-----------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
1994 1993 1992

CASH FLOWS FROM OPERATING ACTIVITIES:
Net margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 23,082 $ 25,721 $ 27,472
-------- -------- --------
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 . . . . . . . . . . . . . . . . . . . 193,351 180,221 188,285
Interest on decommissioning reserve . . . . . . . . . . . . . . . . 1,291 7,356 5,443
Amortization of deferred gains . . . . . . . . . . . . . . . . . . . (9,985) (12,532) (12,486)
Deferred margins and amortization of deferred margins . . . . . . . (8,785) 945 4,491
Amortization of proceeds from sale of income tax benefits. . . . . . (8,102) (8,102) (8,102)
Allowance for equity funds used during construction. . . . . . . . . (2,907) (2,278) (1,377)
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . -- 1,625 2,459
Gain on sale of bond fund investments . . . . . . . . . . . . . . . -- -- (3,884)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (13) (13) (3,066)

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 . . . . . . . . . . . . . . . . . . . . . . . . . . (8,724) (7,128) 371
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . (8,608) 7,172 (1,670)
Prepayments and other current assets . . . . . . . . . . . . . . (94) 2,369 (3,043)
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . (10,569) (2,349) 1,106
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . (8,692) 49,379 (1,238)
Accrued and withheld taxes . . . . . . . . . . . . . . . . . . . (7,835) 5,741 (14,505)
Energy cost billed in excess of actual . . . . . . . . . . . . . (9,331) (17,862) 29,318
Other current liabilities . . . . . . . . . . . . . . . . . . . (24,124) 15,542 (7,532)
-------- -------- --------
Total adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 86,873 206,746 174,570
-------- -------- --------
NET CASH PROVIDED BY OPERATING ACTIVITIES . . . . . . . . . . . . . . . . . . . 109,955 232,467 202,042
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (206,345) (235,285) (232,283)
Increase in decommissioning fund . . . . . . . . . . . . . . . . . . . . . . (3,502) (8,990) (6,841)
Net proceeds from bond, reserve and construction funds . . . . . . . . . . . 42,660 53,574 15,957
Decrease in investment in associated organizations . . . . . . . . . . . . . 1,752 786 1,213
Decrease (increase) in other short-term investments . . . . . . . . . . . . -- 66,165 (66,165)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- 158 (158)
-------- -------- --------
NET CASH USED IN INVESTING ACTIVITIES . . . . . . . . . . . . . . . . . . . . . (165,435) (123,592) (288,277)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Debt proceeds, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 523,518 232,675 579,938
Debt payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (517,530) (369,962) (554,029)
Patronage capital retirements . . . . . . . . . . . . . . . . . . . . . . . -- -- (9,551)
Return of Vogtle surcharge . . . . . . . . . . . . . . . . . . . . . . . . . (2,031) (1,600) (5,085)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,008) (1,439) (144)
-------- -------- --------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES . . . . . . . . . . . . . . 1,949 (140,326) 11,129
-------- -------- --------
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS . . . . . . . . . (53,531) (31,451) (75,106)

CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR . . . . . . . . . . . . 244,173 275,624 350,730
-------- -------- --------

CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR . . . . . . . . . . . . . . . $ 190,642 $ 244,173 $275,624
-------- -------- --------
-------- -------- --------
CASH PAID FOR:
Interest (net of amounts capitalized) . . . . . . . . . . . . . . . . . . . $ 304,882 $ 289,255 $ 388,117
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . -- 1,658 43

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

NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992
-------------------------------------------------------------------------------
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
a. BASIS OF ACCOUNTING
Oglethorpe Power Corporation (Oglethorpe) follows generally accepted
accounting principles and the practices prescribed in the Uniform System of
Accounts of the Federal Energy Regulatory Commission (FERC) as modified and
adopted by the Rural Utilities Service (RUS), formerly known as the Rural
Electrification Administration (REA).

b. 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
Sales 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 end of each
month.
For the year ended December 31, 1994, revenues from Cobb EMC and Jackson
EMC, two of Oglethorpe's Members, accounted for 11% and 10.5% of Oglethorpe's
total revenues, respectively. In 1993, Cobb EMC accounted 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 1995 1994 1993 1992
-------------------------------------------------------------------------------

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

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

Plant Vogtle,
Unit No. 2 4/30 8/30 11/30 14/30
-------------------------------------------------------------------------------

Pursuant to these sell-back agreements and to other contractual
arrangements with GPC, revenues from GPC accounted for approximately 8%, 15%,
and 24% of Oglethorpe's total revenues in 1994, 1993, and 1992, 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 1994,
1993 and 1992 were as follows:

-------------------------------------------------------------------------------
1994 1993 1992
-------------------------------------------------------------------------------

Steam production 2.47% 2.66% 2.66%
Nuclear production 2.84% 2.83% 2.74%
Hydro production 2.00% 2.00% 2.00%
Other production 2.42% 1.09% 1.09%
Transmission 2.75% 2.75% 2.75%
Distribution 2.88% 2.88% 2.88%
General 2.00-20.00% 2.00-17.00% 2.00-17.00%
-------------------------------------------------------------------------------

e. NUCLEAR DECOMMISSIONING
Oglethorpe's portion of the costs of decommissioning co-owned nuclear
facilities is estimated as of December 31, 1994 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 223,000 299,000 302,000 419,000
------------------------------------------------------------------------------------------------------

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 1994, 1993 and 1992 was
$5,948,000, $5,948,000 and $5,984,000, respectively. In developing the amount
of the annual provision for 1994, the escalation rate was assumed to be 4% and
return on trust assets was assumed to be 8%. For 1995, the escalation rate is
assumed to be 3.5% and return on trust assets is 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 non-radioactive
portions of its nuclear facilities. The amounts which will ultimately be used to
decommission the non-radioactive portions of Oglethorpe's nuclear plants are
classified as cash and temporary cash investments on the accompanying balance
sheets. With respect to these "internally" funded amounts, imputed interest
earnings are calculated based on average current investment rates and are
applied to the decommissioning reserve balance and charged to interest expense.
Similarly, 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 and imputed on the internally funded amount is offset by the
recognition of interest expense such that there is no effect on Oglethorpe's net
margin.

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 1994, 1993 and 1992 amounted to $55,229,000, $49,647,000 and
$55,804,000, 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 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 a remaining nuclear fuel asset of approximately
$17,500,000, which is being amortized to nuclear fuel expense over the next
13 years. Oglethorpe has also recorded, net of sell-back, an obligation to DOE
which approximated $14,000,000 at December 31, 1994.

g. 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.
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. 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.

h. 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 1994, 1993 and 1992 is shown
as follows:

-------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1994 1993 1992
-------------------------------------------------------------------------------

Current
Federal $ -- $ -- $ --
State -- 195 1,507
---------- --------- ----------
-- 195 1,507
---------- --------- ----------

Deferred
Federal -- 1,820 4,127
State -- (195) (1,668)
---------- --------- ----------
-- 1,625 2,459
---------- --------- ----------
Income taxes charged
to operations $ -- $ 1,820 $ 3,966
---------- --------- ----------
---------- --------- ----------
-------------------------------------------------------------------------------

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:

-------------------------------------------------------------------------------
1994 1993 1992
-------------------------------------------------------------------------------

Statutory federal income tax rate 35.0% 35.0% 34.0%
Patronage exclusion (35.4%) (35.1%) (21.6%)
Other .4% 0.1% 0.7%
Effect of increase in statutory rate 0.0% 12.8% 0.0%
----- ----- -----
Effective income tax rate 0.0% 12.8% 13.1%
----- ----- -----
----- ----- -----
-------------------------------------------------------------------------------

The components of the net deferred tax liabilities as of December 31, 1994
and 1993 were as follows:

-------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1994 1993
-------------------------------------------------------------------------------

DEFERRED TAX ASSETS
Net operating losses $ 451,543 $ 428,227
Member loss carryforwards 366,417 374,327
Tax credits 252,701 252,701
Accounting for safe harbor leases 98,746 102,886
Patronage exclusions available 80,190 70,804
Accrued nuclear decommissioning expense 38,644 29,324
Accounting for asset dispositions 34,448 38,381
Other 18,061 23,040
------------ ------------
1,340,750 1,319,690
Less: Valuation allowance (252,701) (252,701)
------------ ------------
1,088,049 1,066,989
------------ ------------

DEFERRED TAX LIABILITIES
Depreciation (1,062,233) (1,068,396)
Accounting for debt extinguishment (61,003) (34,114)
Other (30,323) (29,989)
------------ ------------
(1,153,559) (1,132,499)
------------ ------------
Net deferred tax liabilities $ (65,510) $ (65,510)
------------ ------------
------------ ------------
-------------------------------------------------------------------------------

As of December 31, 1994, Oglethorpe has federal tax net operating loss
carryforwards (NOLs) 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 17,817
2003 652 253,665
2004 55,669 114,285
2005 189 213,080
2006 -- 209,009
2007 -- 86,779
2008 -- 94,927
2009 -- 87,836
----------- -----------
$ 252,701 $ 1,077,398
----------- -----------
----------- -----------
-------------------------------------------------------------------------------

Based on Oglethorpe's historical taxable transactions and the timing of the
reversal of existing temporary differences, it is more likely than not that
Oglethorpe's future taxable income will be sufficient to realize the benefit of
these NOLs before their respective expiration dates. However, as reflected in
the above valuation allowance, it is more likely than not that the tax credits
will not be utilized before expiration.
During 1992, 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
-------------------------------------------------------------------------------

Excess of tax over book depreciation $16,524

Difference in accounting for debt
extinguishment 6,956

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

Difference in accounting for safe
harbor leases 6,022

Adjustments to book accrued liabilities 3,514

Accrued nuclear decommissioning expense (558)

Difference in recognition of cost of
discontinued project (532)

Other (67)

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

i. 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.
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 1994 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 RUS,
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
1994 and will be returned in 1995 and 1996. A summary of deferred margins and
Vogtle Surcharge as of December 31, 1994 and 1993 is as follows:

-------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1994 1993
-------------------------------------------------------------------------------

DEFERRED MARGINS
1985-91 $ 125,088 $ 125,088
1992 40,464 40,464
1993 5,083 5,083
1994 9,287 --
-------- --------
179,922 170,635

VOGTLE SURCHARGE
1986-87 36,613 36,613
-------- --------
Subtotal 216,535 207,248
Less: Amounts returned in:
1989-91 (112,592) (112,592)
1992 (41,058) (41,058)
1993 (5,738) (5,738)
1994 (20,103) --
-------- --------
37,044 47,860

Less: Current portion (21,476) (20,103)
-------- --------
Long-term balance* $ 15,568 $ 27,757
-------- --------
-------- --------
<FN>

* The portion relating to amounts provided voluntarily by two of Oglethorpe's
Members was approximately $3,320,000 of the balance at December 31, 1994.
-------------------------------------------------------------------------------

j. CASH AND TEMPORARY CASH INVESTMENTS
Oglethorpe considers all temporary cash investments purchased with a
maturity of three months or less to be cash equivalents.

k. 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, 1994 and 1993, fossil fuels inventories were $24,225,000 and
$16,202,000, respectively. Inventories for spare parts at December 31, 1994 and
1993 were $70,851,000 and $70,266,000, respectively.

l. ENERGY COST BILLED IN EXCESS OF ACTUAL
Oglethorpe's wholesale power rate sets forth the manner in which energy
costs are to be recovered from its Members. The rate in effect for 1994 and 1993
provided that an energy rate be determined based 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 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. The offset to this adjustment is a
payable to or receivable from Members for overcollected or undercollected energy
costs. The rate further provides that any cumulative overcollection or
undercollection for the previous six-month period be utilized to adjust
projected costs for the next six-month period. Therefore, the amounts owed to
Members as of December 31, 1994 and 1993 will be and have been utilized to
reduce Member billings in 1995 and 1994, respectively.

m. 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 credited to Members through the
rate-making process. The following regulatory assets and liabilities were
reflected on the accompanying balance sheets as of December 31, 1994 and 1993:

-------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1994 1993
-------------------------------------------------------------------------------

Premium and loss on reacquired debt $161,889 $ 91,981
Deferred amortization of Scherer leasehold 80,132 71,559
Discontinued projects 26,342 18,314
Other regulatory assets 7,657 --
Sale of income tax benefits (58,236) (66,838)
Deferred margins and Vogtle Surcharge (37,044) (47,860)
Energy costs billed in excess of actual (2,125) (11,456)
-------- --------
$178,615 $ 55,700
-------- --------
-------- --------
-------------------------------------------------------------------------------

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 to
their fair value.

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

2. 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, 1994 are as follows:

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

1995 $ 36,016
1996 38,142
1997 35,239
1998 37,302
1999 37,890
2000-2021 644,564
----------
Total minimum lease payments 829,153

Less: Amount representing interest (525,404)
----------
Present value of net minimum lease payments $ 303,749
----------
----------
-------------------------------------------------------------------------------

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
9.60%. As of December 31, 1994, the variable interest rates of the debt of the
remaining lessor ranged from 5.93% to 7.50% for an average rate of 7.02%.
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 its 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 is such that amortization of
the Scherer Unit No. 2 leasehold calculated in this manner is 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.
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. 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 adjustments to the tax benefits
claimed by this lessor in connection with its purchase and ownership of an
undivided interest in Scherer Unit No. 2. 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 four lessors. Oglethorpe's
potential indemnification liability in this event is estimated to be
approximately $1,400,000 as of December 31, 1994.

3. FAIR VALUE OF FINANCIAL INSTRUMENTS:
A detail of the estimated fair values of Oglethorpe's financial instruments
as of December 31, 1994 and 1993 is as follows:

------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1994 1993
Fair Fair
Cost Value Cost Value
------------------------------------------------------------------------------------------

Cash and temporary
cash investments:
Commercial paper $ 156,192 $ 156,192 $ 218,321 $ 218,321
Repurchase agreement 14,087 14,087 25,549 25,549
Certificates of deposit 20,000 20,000 -- --
Cash and money market
securities 363 363 303 303
---------- ---------- ---------- ----------
Total $ 190,642 $ 190,642 $ 244,173 $ 244,173
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------

Bond, reserve and
construction funds:
U. S. Government
securities $ 57,141 $ 53,573 $ 57,622 $ 59,247
Repurchase agreements 10,590 10,590 52,768 52,768
---------- ---------- ---------- ----------
Total $ 67,731 $ 64,163 $ 110,390 $ 112,015
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------

Decommissioning fund:
U. S. Government
securities $ 36,668 $ 35,513 $ 40,182 $ 39,694
Corporate bonds 4,548 4,388 8,669 8,932
Equity securities 8,605 8,707 -- --
Asset-backed securities 3,754 3,672 -- --
Cash and money market
securities 6,884 6,884 8,060 8,060
---------- ---------- ---------- ----------
Total $ 60,459 $ 59,164 $ 56,911 $ 56,686
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Long-term debt $4,128,080 $4,107,751 $4,058,251 $4,512,469
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
Interest rate swap $ -- $ 6,148 $ -- $ --
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
------------------------------------------------------------------------------------------

The contractual maturities of debt securities available for sale at
December 31, 1994, regardless of their balance sheet classification, are as
follows:

-------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1994
Fair
Cost Value
-------------------------------------------------------------------------------

Due within one year $ 32,292 $ 31,916
Due after one year through five years 48,810 47,065
Due after five years through ten years 21,940 19,367
Due after ten years 9,659 9,388
-------- --------
$112,701 $107,736
-------- --------
-------- --------
-------------------------------------------------------------------------------

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 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. Oglethorpe entered into the swap arrangements
for the purpose of securing a fixed rate lower than otherwise would have been
available from other financing arrangements. 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, 1994 was 4.95%). With respect to the fall 1994
transaction, the notional principal was $122,740,000 and the fixed swap rate is
6.01% (the variable rate at December 31, 1994 was 4.95%). 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, 1994 was $6,148,000. 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, 1994 were $234,000 and $5,050,000, respectively. For
1994, proceeds from sales of available-for-sale securities totaled $291,852,000.
Gross realized gains andlosses from these 1994 sales were $1,099,000 and
$4,776,000, respectively. In accordance with the provisions of the Statement,
the amounts classified as bond, reserve and construction funds and
decommissioning fund on the accompanying balance sheets are carried at amortized
cost as of December 31, 1993.
Investments in associated organizations were as follows at December 31,
1994 and 1993:

-------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1994 1993
-------------------------------------------------------------------------------

National Rural Utilities
Cooperative Finance Corp. $ 13,476 $ 13,476
National Bank for Cooperatives 3,690 5,546
Other 205 101
--------- ---------
Total $ 17,371 $ 19,123
--------- ---------
--------- ---------
-------------------------------------------------------------------------------

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,
1994 and 1993, substantially all of the funds were invested in U.S. Government
securities.

5. LONG-TERM DEBT:
Long-term debt consists of mortgage notes payable to the United States of
America acting through the FFB and the 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 security for
the CoBank headquarters note; substantially all of the owned tangible and
certain of the intangible assets of Oglethorpe are pledged as security for the
FFB and RUS 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.

Oglethorpe currently has ten RUS-guaranteed FFB notes of which $3,161,550,000
and $3,040,767,000 were outstanding at December 31, 1994 and 1993, respectively,
with rates ranging from 5.79% to 10.78%.
In March 1993, Oglethorpe entered into two forward interest rate swap
arrangements obligating Oglethorpe to sell $199,690,000 of variable rate
refunding bonds in 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 by Oglethorpe, have been used in January 1994 and January 1995,
respectively, to refund certain pollution control revenue bonds previously
issued. At December 31, 1994, Oglethorpe accounted for the pending January 1995
retirement of $130,965,000 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 1994.
In connection with the two swap transactions, Oglethorpe recorded redemption
premiums which, combined with unamortized transaction costs, totaled
approximately $38,000,000. This amount has been reported as a deferred charge on
the balance sheets and is being amortized over the life of the related new
bonds.
In January and February 1994, Oglethorpe completed note modifications
pursuant to which it repriced $590,909,000 and $203,641,000, respectively, of
FFB advances. In connection with such modification, Oglethorpe paid premiums of
$50,745,000 and $13,089,000, respectively. These amounts are reported as
deferred charges on the balance sheets and will be amortized over 22 years, the
longest remaining life of the subject advances.
In February 1994, Oglethorpe completed a current refunding transaction
whereby $194,700,000 of fixed rate pollution control revenue bonds were issued.
The proceeds of this transaction were used to retire $204,785,000 of existing
bonds.
In December 1994, Oglethorpe completed a current refunding transaction
whereby $35,960,000 of fixed rate pollution control revenue bonds were issued.
The proceeds of this transaction were used to retire $39,605,000 of existing
bonds. These transactions resulted in the payment of redemption premiums, which
have been combined with unamortized transaction costs and total $12,745,000.
This amount has been reported as a deferred charge on the balance sheet and is
being amortized over the life of the related bonds.
The proceeds from the December 1994 current refunding were held in debt
service reserve funds until the retirement of the bonds occured in January 1995.
At December 31, 1994, Oglethorpe accounted for the pending retirement as an
in-substance defeasance. Therefore, the cash held in debt service reserve funds,
bonds payable, and premium on reacquired debt are stated as though the event of
retiring the refunded bonds had occurred in 1994.
In January 1995, Oglethorpe prepaid two FFB advances totaling $29,940,000 of
principal plus a premium equal to one year's interest of $3,163,000. The premium
will be reported as a deferred charge on the balance sheet and will be amortized
over 22 years, the remaining life of the prepaid advances.
In January 1995, Oglethorpe refinanced $284,759,000 of FFB advances. In
connection with this refinancing, a premium of $44,870,000 was incurred. This
premium was financed by adding the amount to the outstanding balances of the
refinanced advances for a total refunding debt of $329,629,000. Additionally, a
fee of $1,122,000 was paid in cash for the ability to refinance. The combined
premium and fee of $45,992,000 will be reported as a deferred charge on the
balance sheets and will be amortized over the remaining life of the refinanced
advances. Oglethorpe has the option to set the maturities for each advance for a
term as short as three months. The intitial maturities chosen for these advances
ranged from three months to one year.
The annual interest requirement for 1995, based upon all debt outstanding at
December 31, 1994, will be approximately $305,000,000.
Maturities for the long-term debt through 1999 are as follows:

-------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1995 1996 1997 1998 1999
-------------------------------------------------------------------------------

FFB and RUS $ 71,258 $ 66,229 $ 74,702 $ 79,907 $ 83,880
CoBank 468 478 489 502 516
1982 Bonds 3,410 6,050 6,675 -- --
1992A Bonds 4,640 4,840 5,070 5,330 5,615
1992 Bonds -- -- -- 2,085 2,240
1993A Bonds -- -- -- 2,265 2,410
1993B Bonds 9,330 9,535 9,810 6,490 6,695
1993 Bonds 980 855 875 900 935
1994B Bonds -- 1,245 1,335 550 1,465
1994 Bonds -- 325 330 350 370
-------- -------- -------- -------- --------
Total $ 90,086 $ 89,557 $ 99,286 $ 98,379 $104,126
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
-------------------------------------------------------------------------------

Oglethorpe has a commercial paper program under which it may issue
commercial paper not to exceed a $300,000,000 balance outstanding at any time.
The commercial paper may be used as a source of short-term funds and is not
intended 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 (Trust Company) acts as agent. As of December 31, 1994 and 1993, no
commercial paper was outstanding.
Oglethorpe has arranged for uncommitted short-term lines of credit with
CoBank and CFC and a committed line of credit with Trust Company. 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 amount that can be outstanding
under these lines of credit and the commercial paper program at any one time
totals $370,000,000 due to certain restrictions contained in the CFC and Trust
Company line of credit agreements. No balance was outstanding on any of these
three lines of credit at either December 31, 1994 or 1993.

6. ELECTRIC PLANT AND RELATED AGREEMENTS:
Oglethorpe and GPC have entered into agreements providing for the purchase
and subsequent joint operation of certain of GPC's electric generating plants
and transmission facilities. A summary of Oglethorpe's plant investments and
related accumulated depreciation as of December 31, 1994 is as follows:

-------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) Accumulated
Plant Investment Depreciation
-------------------------------------------------------------------------------

IN-SERVICE
Owned property
Vogtle Units No. 1 & No. 2
(NUCLEAR -- 30% OWNERSHIP) $ 2,777,466 $ 524,066
Hatch Units No. 1 & No. 2
(NUCLEAR -- 30% OWNERSHIP) 513,198 183,895
Wansley Units No. 1 & No. 2
(FOSSIL -- 30% OWNERSHIP) 166,229 81,541

Scherer Unit No. 1
(FOSSIL -- 60% OWNERSHIP) 427,162 174,621
Tallassee (Harrison Dam)
(HYDRO -- 100% OWNERSHIP) 9,277 1,463
Wansley (COMBUSTION TURBINE --
30% OWNERSHIP) 3,665 1,044
Transmission and distribution
plant 791,314 159,415
Other 112,905 31,027

Property under capital lease
Scherer Unit No. 2
(FOSSIL -- 60% LEASEHOLD) 299,083 74,746
----------- -----------
TOTAL IN-SERVICE $ 5,100,299 $ 1,231,818
----------- -----------
----------- -----------

CONSTRUCTION WORK IN PROGRESS
Rocky Mountain
(HYDRO -- 73.4%
OWNERSHIP*) $ 498,832
Generation improvements 18,908
Transmission and distribution
plant 19,699
Other 1,350
-----------
TOTAL CONSTRUCTION WORK IN PROGRESS $ 538,789
-----------
-----------
<FN>
* Estimated ownership percentage as of December 31, 1994. Ownership percentage
at project completion is expected to be approximately 75%.
-------------------------------------------------------------------------------

In 1988, Oglethorpe acquired from GPC an undivided ownership interest in
the Rocky Mountain Project, a pumped storage hydroelectric facility (Rocky
Mountain). Under the Rocky Mountain agreements, Oglethorpe assumed
responsibility for construction of the facility, which was commenced by GPC.
Under the agreements, GPC retained its current investment in Rocky Mountain. 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 that the ownership
interests of Oglethorpe and GPC in Rocky Mountain at project completion will be
approximately 75% and 25%, respectively. Rocky Mountain is subject 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
by the summer of 1995. Rocky Mountain was approximately 98.1% complete as of
December 31, 1994.
Oglethorpe is financing its share of Rocky Mountain from the proceeds of an
RUS-guaranteed loan funded through the FFB. As of December 31, 1994, a total of
approximately $285,000,000 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 RUS 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.
Oglethorpe is engaged in a continuous construction program and, as of
December 31, 1994, estimates property additions (including capitalized interest)
to be approximately $177,000,000 in 1995, $125,000,000 in 1996 and $129,000,000
in 1997, 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 determined that the Pickens County Pumped Storage
Hydroelectric Project was 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 $16,905,000 are reflected as deferred charges on the accompanying
balance sheets. Oglethorpe's Board of Directors has authorized that these
project costs be amortized and fully recovered through future rates over a
period of 15 years beginning in 1992.
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 will write off the accumulated
project costs in excess of the current value of the land purchased. These
project costs of $9,437,000 have been reclassified from electric plant in
service to deferred charges on the accompanying balance sheets. Oglethorpe's
Board of Directors has authorized that these project costs be amortized and
fully recovered through future rates over a period of 15 years beginning in
1995.
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 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. 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.
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. EMPLOYEE BENEFIT PLANS:
Oglethorpe has a noncontributory defined benefit pension plan covering
substantially all employees. Oglethorpe's pension cost was approximately
$1,262,000 in 1994, $1,038,000 in 1993 and $362,000 in 1992. For 1992, pension
cost was reduced by a $539,000 net gain from a plan curtailment. The plan
curtailment resulted from a workforce reduction undertaken in the second quarter
of 1992. 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 pension cost recognized in 1994, 1993 and 1992 is shown as
follows:

-------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1994 1993 1992
-------------------------------------------------------------------------------

Pension cost was comprised of the
following
Service cost -- benefits earned
during the year $ 1,084 $ 884 $ 854
Interest cost on projected
benefit obligation 714 617 535
Actual return on plan assets 387 (698) (424)
Net amortization and deferral (911) 247 (64)
Net gain from a plan
curtailment (12) (12) (539)
-------- -------- --------
Net pension cost $ 1,262 $ 1,038 $ 362
-------- -------- --------
-------- -------- --------
-------------------------------------------------------------------------------

The plan's funded status in Oglethorpe's financial statements as of
December 31, 1994 and 1993 were as follows:

-------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1994 1993
-------------------------------------------------------------------------------

Actuarial present value of accumulated
plan benefits
Vested $ 5,281 $ 5,237
Nonvested 380 407
-------- --------
$ 5,661 $ 5,644
-------- --------
-------- --------

Projected benefit obligation $ (9,276) $ (9,920)
Plan assets at fair value 7,282 6,911
--------- ---------
Projected benefit obligation in
excess of plan assets (1,994) (3,009)
Unrecognized net loss (gain) from
past experience different from
that assumed and effects
of changes in assumptions (861) 390
Prior service cost not yet recognized
in net periodic pension cost 598 693
Unrecognized net asset at transition
date being recognized over
19 years (133) (145)
--------- ---------
Pension accrual $ (2,390) $ (2,071)
--------- ---------
--------- ---------
-------------------------------------------------------------------------------

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 8.5% and 5.0% in 1994, and 7.5% and 5.5% in 1993, respectively.
The expected long-term rate of return on plan assets was 8% in 1994 and 1993,
and the discount rate used in determining the pension expense was 7.5% in 1994
and 8.5% in 1993.
Oglethorpe has a contributory employee thrift plan covering substantially
all employees. Employee contributions to the plan may be invested in one or more
of three funds. The employee may contribute, subject to IRS limitations, up to
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 $565,000 in 1994, $503,000 in 1993
and $503,000 in 1992.

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 $8,060,000
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 under NEIL II and NEIL III, which provide insurance to
cover decontamin-ation, debris removal and premature decommissioning as well as
excess property damage to nuclear generating facilities for an additional
$2,250,000,000 for losses in excess of the $500,000,000 NML coverage described
above. Under the NEIL 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 $14,260,000.
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 $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 $93,810,000 per incident, but not more than $11,830,000 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 $3,320,000.
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 purchase 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 December 31, 2002, 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.
Oglethorpe has a contract with Hartwell Energy Limited Partnership for the
purchase of approximately 300 MW of capacity for a 25-year period commencing in
April 1994.
Oglethorpe has entered into a short-term seasonal power purchase agreement
with Florida Power Corporation. Under the agreement, Oglethorpe will purchase 50
MW of capacity on a take-or-pay basis for 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, 1994, 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:

1995 $ 153,270
1996 148,735
1997 138,243
1998 145,248
1999 144,261
-------------------------------------------------------------------------------

Oglethorpe's power purchases from these agreements amounted to
approximately $182,965,000 in 1994, $192,059,000 in 1993 and $192,321,000 in
1992.
Oglethorpe has entered into an agreement with Alabama Electric Cooperative
to sell 100 MW of capacity for the period June 1998 through December 2005.

10. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial information for 1994 and 1993 is as follows:

-------------------------------------------------------------------------------
First Second Third Fourth
(DOLLARS IN THOUSANDS) Quarter Quarter Quarter Quarter
-------------------------------------------------------------------------------

1994
Operating revenues $267,618 $263,035 $266,818 $258,611
Operating margin 81,882 75,704 68,087 61,734
Net margin 20,184 13,511 4,386 (14,999)

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)
-------------------------------------------------------------------------------

Oglethorpe's business is influenced by seasonal weather conditions. The
negative net margin for the fourth quarter of 1994 was primarily attributable to
the deferral of excess margins. The negative net margin for the fourth quarter
of 1993 was attributable to the deferral of excess margins and to the incurrence
of certain nonrecurring expenses. For a discussion of the amounts of excess
margins deferred, see Note 1.

REPORT OF MANAGEMENT

The management of Oglethorpe Power Corporation has prepared this report and
is responsible for the financial statements and related information. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
Oglethorpe maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions. Limitations exist in any system of
internal control based upon the recognition that the cost of the system should
not exceed its benefits. Oglethorpe believes that its system of internal
accounting control, together with the internal auditing function, maintains
appropriate cost/benefit relations.
Oglethorpe's system of internal controls is evaluated on an ongoing basis
by its qualified internal audit staff. The Corporation's independent public
accountants (Arthur Andersen LLP) also consider certain elements of the internal
control system in order to determine their auditing procedures for the purpose
of expressing an opinion on the financial statements.
Arthur Andersen LLP also provides an objective assessment of how well
management meets its responsibility for fair financial reporting. Management
believes that its policies and procedures provide reasonable assurance that
Oglethorpe's operations are conducted with a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations, and cash flows
of Oglethorpe Power Corporation.

T. D. Kilgore
President and Chief Executive Officer

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, 1994 and 1993 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, 1994. These financial statements are the responsibility of
Oglethorpe's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits 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 audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Oglethorpe Power Corporation
as of December 31, 1994 and 1993 and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles.
As explained in Note 3 of notes to financial statements, effective January
1,1994, Oglethorpe Power Corporation changed its method of accounting for
certain investments in debt and equity securities. As explained in Note 1 of
notes to financial statements, effective January 1, 1993, Oglethorpe changed its
method of accounting for income taxes.

Arthur Andersen LLP
Atlanta, Georgia,
February 24, 1995.

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

None.

PART III

Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

(a) IDENTIFICATION OF DIRECTORS:

Oglethorpe is governed by a Board of 39 Directors, 13 of whom are elected
each year for a three-year term. Each of the 39 Members nominates one Director
who must also be on the Member's Board of Directors. 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. 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, age 69, 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. Warnock is the President of Altamaha EMC and a Director of
Georgia Electric Membership Corporation ("GEMC").

James D. Musgrove--Alternate Director, age 48, is the General Manager of
Altamaha EMC. 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 49, 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 77, 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. Mr. Martin is President of Canoochee EMC. 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 65, 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 77, 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 53, 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 Director of the Georgia Cooperative
Council and a Director of Carrollton Federal Bank, F.S.B. in Carrollton,
Georgia.

CENTRAL GEORGIA EMC

D. A. Robinson, III--Director, age 54, 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 present term will expire in March 1995. He serves as
Secretary-Treasurer of Central Georgia EMC.

George L. Weaver--Alternate Director, age 47, 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 Vice President of the
Board of Directors of Federated Rural Electric Insurance Corporation in Shawnee
Mission, Kansas and Chairman of the Board of Directors of Southeastern Data
Cooperative. Mr. Weaver is also Chairman of the Butts County Industrial
Development Authority and Vice Chairman of the West Central Georgia Private
Industry Council. He serves on the Advisory Board of NationsBank of Georgia,
N.A.

COASTAL EMC

James E. Estes--Director, age 59, has served on the Board of Directors of
Oglethorpe since March 1982, with his present term to expire in March 1997. 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 44, 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 1997.

COBB EMC

Larry N. Chadwick--Director, age 54, is the owner of Chadwick's Hardware in
Woodstock, Georgia. He has served on the Board of Directors of Oglethorpe since
July 1989, with his present term to expire in March 1995. He is Chairman of the
Board of Cobb EMC.

Dwight Brown--Alternate Director, age 49, is President and Chief Executive
Officer of Cobb EMC. He previously served as Vice President of Engineering and
Operations for Cobb EMC. He has served as an Alternate Director of Oglethorpe
since October 1993, with his present term to expire in March 1995.

COLQUITT EMC

Simmie King--Director, age 51, is the owner and operator of a farm. 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 47, 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.

COWETA-FAYETTE EMC

W. F. Farr--Director, age 82, 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 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 52, 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.

EXCELSIOR EMC

Vacant--Director

Gary T. Drake--Alternate Director, age 46, 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 1997. 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 63, has served on the Board of Directors
of Oglethorpe since June 1992, with his present term to expire in March 1997.
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 59, 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
1997. He is currently a member of the Planning and Construction Committee of
Oglethorpe and Chairman of the GEMC/Oglethorpe External Affairs Committee.

GRADY EMC

Donald C. Cooper--Director, age 64, 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 47, 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 58, 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 58, 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 59, 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 62, 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 1997. He is currently a member of the
Planning and Construction Committee and the Wholesale Power Contract Oversight
Committee of Oglethorpe. He also was a U.S. Postal Service Rural Carrier for 30
years.

Grooms Johnson--Alternate Director, age 65, 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 1997. 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 43, 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 Chairman and past Vice Chairman of the Finance
Committee of Oglethorpe. Mr. Crenshaw was Office Manager of Irwin EMC from 1974
to 1988.

JACKSON EMC

E. L. McLocklin--Director, age 82, 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 51, 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 a
member of the Finance Committee. Mr. Pugh is also a Director of the First
National Bank of Jackson County in Jefferson, Georgia.

JEFFERSON EMC

Sam Rabun--Director, age 63, 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 50, 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 President
of the GEMC Workers' Compensation Fund.

LAMAR EMC

E. J. Martin, Jr.--Director, age 67, 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 1997. 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 44, 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 1997.

LITTLE OCMULGEE EMC

Jim M. Knight--Director, age 59, is owner and manager of Knight Farms. He
has served on the Board of Directors of Oglethorpe since April 1994, with his
present term to expire in March 1997. Mr. Knight is also a Director of Little
Ocmulgee EMC.

A. Arnold Horton--Alternate Director, age 48, 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. Mr. Horton is a
member of Oglethorpe's Planning and Construction Committee. He has served as
the Alternate Director of Oglethorpe since March 1993, with his present term to
expire in March 1997.

MIDDLE GEORGIA EMC

Ronnie Fleeman--Director, age 60, 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
Oglethorpe Human Resources Management Committee.

Charles Hugh Richardson--Alternate Director, age 41, 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 59, 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 51, 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 46, 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 1997. Mr. Martin is the President of Ocmulgee EMC.

Dennis Grenade--Alternate Director, age 54, 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
1997. He is a member of the Planning & Construction Committee.

OCONEE EMC

John B. Floyd, Jr.--Director, age 52, has served on the Board of Directors
of Oglethorpe since March 1980, with his present term to expire in March 1996.
He is the Vice Chairman of the Board of Oconee EMC and is a Director of CFC.

Preston L. Johnson--Alternate Director, age 60, 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. He
is currently a member of the Oglethorpe Finance Committee.

OKEFENOKE RURAL EMC

Steve Rawl, Sr.--Director, age 48, 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 1997. He is also a
Director of GEMC.

W. Don Holland--Alternate Director, age 44, 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 1997. 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 72, 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 42, 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 68, 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 1997. 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 59, 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 1997. He is a member
of the Operations Committee of Oglethorpe.

RAYLE EMC

J.M. Sherrer--Director, age 59, 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 1997.

Wayne Poss--Alternate Director, age 49, 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 1997. He is a
member of the GEMC/Oglethorpe External Affairs Committee.

SATILLA RURAL EMC

Jack D. Vickers--Director, age 77, 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 1997.

R. Lehman Lanier--Alternate Director, age 75, is President and Chief
Executive Officer of Satilla Rural EMC. He has served as an Alternate Director
of Oglethorpe since September 1974, and his present term expires in March 1997.
He is a member of the Operations Committee of Oglethorpe. He is also a Director
of Southeastern Data Cooperative, Inc.

SAWNEE EMC

C. W. Cox, Jr.--Director, age 67, 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 1997.

Michael A. Goodroe--Alternate Director, age 38, 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 1997. He is a member of
the Oglethorpe Finance Committee.

SLASH PINE EMC

Johnnie Crumbley--Director, age 72, 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 60, 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 62, is a self-employed wallpapering
contractor. He has served on the Board of Directors of Oglethorpe since 1990.
His present term expires in March 1997.

J. E. Robinson--Alternate Director, age 75, is President, Chief 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 1997.
Mr. Robinson is also a Director of the First National Bank of Newton County.

SUMTER EMC

Bob Jernigan--Director, age 67. 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 45, is President and Chief
Executive Officer of Sumter EMC. He was appointed General Manager of Sumter EMC
in 1984. The General Manager title was changed to President/CEO in 1994. 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 48, 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 47, 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 68, 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 46, 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 69, 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. Mr. Woodruff is currently a member of the
Oglethorpe Human Resources Management Committee. He is also a Director of GEMC.

Wayne Livingston--Alternate Director, age 43, has been the Executive Vice
President and General Manager of Troup EMC since August 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 78, 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.

Walter E. Hammond--Alternate Director, age 63, is General Manager of Upson
County EMC. He has served as an Alternate Director of Oglethorpe since 1978,
and his present term will expire in March 1995.

WALTON EMC

Hendrix B. Wiley, Jr., Age 50, is a retired dairy farmer. He has served on
the Board of Directors of Oglethorpe since August 1994, with his present term to
expire in March 1995. Mr. Wiley is also a director of Walton EMC.

D. Ronnie Lee--Alternate Director, age 46, 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 63, 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 65, 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 53, 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 his present term to expire in
March 1995. He is currently the Chairman of the Executive Committee of
Oglethorpe and a member of the Oglethorpe Human Resources Management Committee.
He was previously a member of the Operations Review Committee of Oglethorpe.
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
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 Chairman of the Board, age 64, has served as a
principal executive officer of Oglethorpe since March 1993. He has served as a
member of Oglethorpe's Executive Committee and on the Board of Directors of
Oglethorpe since December 1988. His present term will expire in March 1995. He
was previously a member of the Power Planning and Technical Advisory Committee
of Oglethorpe. He is also the past President 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 55, has served as
Secretary-Treasurer of Oglethorpe since March 1989. He has served as an
Alternate Director of Oglethorpe since 1975, with his present term to expire in
March 1995. He is currently a member of the Executive Committee. He previously
served on Oglethorpe's Operations Review Committee and Finance Committee.
Mr. Dean has been General Manager/Chief Executive Officer of Amicalola EMC since
1974. Prior to his employment with Amicalola EMC, he was Controller of Pickens
General Hospital. Currently, he is on the Board of Directors of Southeastern
Data Cooperative, Inc., Crescent Bank & Trust Company, CoBank, and GEMC Workers'
Compensation Fund. Mr. Dean has a BA degree in Accounting from the University of
Georgia.

T. D. Kilgore, President and Chief Executive Officer, age 47, 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 served as Executive Vice President of GEMC from December
1991 to June 1992. He has served as President and Chief Executive Officer of
GEMC from June 1992 until the present. Mr. Kilgore has over 20 years of
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.
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 BS degree in mechanical engineering from
the University of Alabama, where he has been recognized as a Distinguished
Engineering Fellow, and an ME degree in industrial engineering from Texas A&M.

The senior executives assisting Mr. Kilgore, their areas of responsibility
and a brief summary of their experience are as follows:

David L. Self, Senior Vice President and Group Executive, System
Operations, age 66, has served as an executive of Oglethorpe since August 1991
(from August 1991 to November 1991, as Senior Vice President, Power Supply; from
November 1991 to February 1994, Senior Vice President, Operations; and since
February 1994, as Senior Vice President and Group Executive, Generation).
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 has a BS degree from Saint Mary's College
in California.

Clarence Mitchell, Vice President and Group Executive, Generation, age 41,
has served as an executive of Oglethorpe since January 1995. Prior to that
time, Mr. Mitchell served as Assistant to the Senior Vice President for
Generation from February 1994 to December 1994; Manager of Corporate Planning
from September 1992 to January 1994; Manager of Construction from January 1992
to August 1992; Program Director of Technical Services (environmental, survey
and mapping, land acquisition and R&D) from January 1989 to December 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. Mitchell spent four years as a field engineer with General
Electric Company and worked various installation and maintenance projects
related to coal, nuclear, gas and oil-fired generation. Mr. Mitchell has an MS
degree in Management from Georgia State University, a BS degree in Mechanical
Engineering from Georgia Institute of Technology and a BS degree in
Interdisciplinary Science from Morehouse College. Mr. Mitchell is presently the
Oglethorpe representative on both the Nuclear Managing Board and the Plant
Scherer Managing Board. For information about the Managing Boards see
"CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS -- The Plant
Agreements" in Item 1.

Wylie H. Sanders, Vice President and Group Executive, Transmission, age 58,
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. Mr. Sanders 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. Mr.
Sanders is a member of the Board of Trustees of Southern Tech Foundation, Inc.

Nelson G. Hawk, Vice President and Group Executive, Marketing, age 45,
joined Oglethorpe in February 1994 after almost 24 years of electric utility
experience. Prior to coming to Oglethorpe, he held various management positions
with Florida Power & Light Company and related subsidiaries, including as
Director of Regulatory Affairs at Florida Power & Light from October 1993 to
January 1994; as Director of Market Planning from July 1991 to September 1993;
and as Director of Strategic Business and President of FPL Enersys Services,
Inc. (a utility subsidiary providing energy services to commercial/industrial
customers) from April 1989 to June 1991. Mr. Hawk has a BS degree in Electrical
Engineering from Georgia Institute of Technology and an MBA degree from Florida
International University.

W. Clayton Robbins, Senior Vice President and Group Executive, Support
Services, age 48, 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 December 1989 to December 1991.
Before coming to Oglethorpe, Mr. Robbins spent 17 years with the
Stearns-Catalytic World Corporation and various subsidiaries, including 13 years
in management positions responsible for Human Resources, Information Systems,
Contracts, Insurance, Accounting, and Project Controls. Mr. Robbins has a BA
degree in Business Administration from the University of North Carolina at
Charlotte.

Eugen Heckl, Senior Vice President and Chief Financial Officer, age 60, has
served as an executive of Oglethorpe since March 1975 (from March 1975 to July
1986, as senior finance and accounting executive; 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 over 30 years of
experience, including ten years as a consultant and auditor to electric
utilities with Arthur Andersen & Co. and two years as Secretary-Treasurer of
Davis Brothers, Inc. Mr. Heckl is a Certified Public Accountant in Georgia and
has a BS degree in accounting from Samford University

and an MBA degree from Emory University. Mr. Heckl has served as a Director of
the GEMC Federal Credit Union since 1983, and as its Chief Financial Officer
since 1984.

G. Stanley Hill, Senior Vice President and Staff Executive, age 59, has
served as an executive of Oglethorpe since October 1975 (from October 1975 to
November 1988, as Director of Planning, Director of Power Supply and Planning,
Division Manager, Power Supply and Engineering, Division Manager, Engineering,
Senior Vice President, Planning and System Operations; 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 and Staff Executive, 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.

Item 11. EXECUTIVE COMPENSATION

SUMMARY COMPENSATION TABLE

The following table sets forth for Oglethorpe's President and Chief
Executive Officer and the four most highly compensated senior executives all
compensation paid or accrued for services rendered in all capacities during the
years ended December 31, 1994, 1993 and 1992. 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 are
targeted below the market valuations for similar positions and remain fairly
stable unless the job content changes.

ANNUAL
NAME AND COMPENSATION ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS(2) COMPENSATION
------------------ ---- -------- ---------- ------------

T. D. Kilgore 1994 $224,997 $ 0 $ 6,758(1)
President and Chief Executive Officer 1993 211,250 0 7,652
1992 195,000 0 6,585

David L. Self 1994 147,833 10,476 9,117(1)
Sr. Vice President and 1993 135,000 12,143 8,229
Group Executive, System Operations 1992 131,800 18,286 7,177

Eugen Heckl 1994 142,114 13,919 7,600(1)
Sr. Vice President and Chief 1993 142,114 12,228 7,221
Financial Officer 1992 142,114 19,135 6,194

W. Clayton Robbins 1994 140,366 11,946 4,986(1)
Sr. Vice President and 1993 128,000 12,461 4,582
Group Executive, Support Services 1992 131,021 16,245 4,648

G. Stanley Hill 1994 140,000 10,883 5,619(1)
Sr. Vice President and Staff Executive, 1993 140,000 12,580 7,001
External Affairs 1992 140,000 18,195 6,461
______________________
<FN>
(1) Includes contributions made in 1994 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. Kilgore, Self, Heckl, Robbins and
Hill of $5,344, $2,805, $4,300, $4,179 and $3,523, respectively; and insurance
premiums paid on term life insurance on behalf of Messrs. Kilgore, Self, Heckl,
Robbins and Hill of $1,414, $6,312, $3,300, $807 and $2,096, respectively.

(2) Mr. Kilgore is not a participant in the incentive compensation program.
His compensation is governed solely by the Board of Directors.

PENSION PLAN TABLE

YEARS OF CREDITED SERVICE
---------------------------------------
AVERAGE COMPENSATION 15 20 25
-------------------- ------ ------ ------

$ 50,000. . . . . . . . . . . . . . . . . . . . . $12,958 $17,277 $21,596
75,000. . . . . . . . . . . . . . . . . . . . . 20,458 27,277 34,096
100,000. . . . . . . . . . . . . . . . . . . . . 27,958 37,277 46,596
125,000. . . . . . . . . . . . . . . . . . . . . 35,458 47,277 59,096
150,000 or more. . . . . . . . . . . . . . . . . 42,958 57,277 71,596

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 1994. 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, 1994, 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 . . . . . . . . . . . . . . . . . . . . . 9
Mr. Self. . . . . . . . . . . . . . . . . . . . . . . 6
Mr. Heckl . . . . . . . . . . . . . . . . . . . . . . 18
Mr. Robbins . . . . . . . . . . . . . . . . . . . . . 8
Mr. Hill. . . . . . . . . . . . . . . . . . . . . . . 18

COMPENSATION OF DIRECTORS

Oglethorpe pays its Directors a per diem fee of $200 for meetings attended
or $50 for meetings conducted by conference call. Additionally, Oglethorpe
reimburses its Directors for out-of-pocket expenses incurred in attending a
meeting. Alternate Directors serving as a Director at any meeting receive
neither the per diem payment nor the expense reimbursement to which a Director
is entitled. The Member of which the Alternate Director is the manager receives
reimbursement for the Alternate Director's out-of-pocket expenses.

The Chairman of the Board is also paid at least one day's per diem of $200
each month for time involved in carrying out his official duties in addition to
the regularly scheduled Board Meeting.

COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION

W. F. Farr, J. Calvin Earwood, Ronnie Fleeman, Willis T. Woodruff and Robert
A. Reeves serve as members of the Oglethorpe Human Resources Management
Committee which functions as Oglethorpe's compensation committee. J. Calvin
Earwood has served as an executive officer of Oglethorpe since 1984 and has
served as the Chairman of the Board since 1989.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Not applicable.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Oglethorpe has recently considered a residential marketing program to
increase awareness and understanding of energy conservation measures, including
the use of energy efficient heating, cooling and water heating systems, and to
obtain marketing research data that will be used to develop and refine future
marketing programs that meet the particular needs of residential customers.
Under this marketing program that Oglethorpe is considering, each Oglethorpe
Director and Alternate Director electing to participate may receive at a reduced
cost or no cost, a geothermal heating, cooling and water heating system or air
source heat pump, an electric water heater and waste heat recovery unit. In
addition, each participant may receive various energy efficient "weatherization"
services including upgraded insulation. Participants will agree to the
installation of a meter at their residences that will provide Oglethorpe data
including the amount of energy being used at a particular time. The
participants will also be surveyed as to their comfort and satisfaction with the
equipment. Depending upon the equipment and services actually received by each
participant, the cost of the program will be approximately $5,000-$12,000 per
participant.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

PAGE

(a) LIST OF DOCUMENTS FILED AS A PART OF THIS REPORT.

(1) FINANCIAL STATEMENTS (Included under "Item 8. Financial
Statements and Supplementary Data")

Statements of Revenues and Expenses, For the Years
Ended December 31, 1994, 1993 and 1992 . . . . . . . . . . . 33
Statements of Patronage Capital, For the Years Ended
December 31, 1994, 1993 and 1992 . . . . . . . . . . . . . . 33
Balance Sheets, As of December 31, 1994 and 1993. . . . . . . 34
Statements of Capitalization, As of December 31, 1994
and 1993 . . . . . . . . . . . . . . . . . . . . . . . . . . 36
Statements of Cash Flows, For the Years Ended December
31, 1994, 1993 and 1992. . . . . . . . . . . . . . . . . . . 37
Notes to Financial Statements . . . . . . . . . . . . . . . . 38
Report of Management. . . . . . . . . . . . . . . . . . . . . 48
Report of Independent Public Accountants. . . . . . . . . . . 48

(2) FINANCIAL STATEMENT SCHEDULES

None Applicable

(3) EXHIBITS

NUMBER DESCRIPTION
------ -----------

*3(i) -- 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) -- Bylaws of Oglethorpe as amended November 8, 1993. (Filed as
Exhibit 3.2 to the Registrant's Form 10-Q for the quarterly
period ended September 30, 1993, File No. 33-7591.)

*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 as Exhibit 4.2 to the Registrant's Form S-1
Registration Statement, File No. 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, 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.)

*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.)

*4.7(a) -- Amended and Consolidated Loan Contract dated as of June 1,
1984 between Oglethorpe and the United States of America, as
amended and supplemented, together with eleven 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) -- Amendments, dated October 17, 1986, and January 9, 1987, 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(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. (Filed as
Exhibit 4.7(j) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1993, File No. 33-7591.)

4.7(k) -- Amendment, dated August 31, 1994, to Amended and
Consolidated Loan Contract dated as of June 1, 1984 between
Oglethorpe and the United States of America.

*4.8.1(a) -- Mortgage and Security Agreement made by Oglethorpe to United
States of America dated 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) -- 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 Agreement made by and among Oglethorpe, Mortgagor,
and United States of America and Trust Company Bank, 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
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. (Filed as Exhibit
4.8.11 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1993, File No. 33-7591.)

4.8.12 -- 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, 1994.

++4.9.1 -- Loan Agreement, dated as of October 1, 1992, between
Development Authority of Monroe County and Oglethorpe
relating to Development Authority of Monroe County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Scherer
Project), Series 1992A.

++4.9.2 -- 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.

++4.9.3 -- 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(a) -- First Amended and Restated Letter of Credit Reimbursement
Agreement, dated as of June 1, 1992, 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.

+4.10.4(b) -- First Amendment to First Amended and Restated Letter of
Credit Reimbursement Agreement, dated September 15, 1993,
between Oglethorpe and Credit Suisse.

+4.10.4(c) -- Second Amendment to First Amended and Restated Letter of
Credit Reimbursement Agreement, dated August 1, 1994,
between Oglethorpe and Credit Suisse.

+++4.11.1 -- Loan Agreement, dated as of December 1, 1992, between
Development Authority of Burke County and Oglethorpe
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1993A.

+++4.11.2 -- 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.

+++4.11.3 -- 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.

+++4.11.4 -- 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.

+++4.11.5 -- 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.

+4.11.6 -- Standby Bond Purchase Agreement, dated as of November 30,
1993, as amended by First Amendment to Standby Bond Purchase
Agreement, dated October 1, 1994, between Oglethorpe and The
Industrial Bank of Japan, Limited relating to Development
Authority of Burke County Adjustable Tender Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1993A.

+4.11.7 -- 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.

*4.12.1 -- Loan Agreement, Loan No. T-840901, between Oglethorpe and
Columbia Bank for Cooperatives, dated as of September 14,
1984. (Filed as Exhibit 4.14.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October
9, 1986.)

*4.12.2 -- Promissory Note, Loan No. T-840901, in the original
principal amount of $8,995,000 from Oglethorpe to Columbia
Bank for Cooperatives, dated as of November 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, between Oglethorpe and
Columbia Bank for Cooperatives, dated as of December 30,
1983. (Filed as Exhibit 4.16.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October
9, 1986.)

*4.13.2 -- Promissory Note, Loan No. T-831222, in the original
principal amount of $2,376,000 from Oglethorpe to Columbia
Bank for Cooperatives, dated as of June 1, 1984. (Filed as
Exhibit 4.16.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)

*4.14.1 -- 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 -- 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 -- 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 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 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, 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.)

*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 the
Registrant's Form S-1 Registration Statement, File No. 33-
7591, filed on October 9, 1986.)

*10.5.2 -- 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.)

*10.5.3 -- 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) -- Wholesale Power Contract dated September 5, 1974, between
Oglethorpe and Planters 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 Wholesale Power Contracts,
and an additional 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) -- Amended and Consolidated Wholesale Power Contract, dated as
of December 1, 1988, between Oglethorpe and Planters
Electric Membership Corporation and all schedules thereto,
and the Amended and Consolidated Supplemental Agreement,
dated December 1, 1988, between Oglethorpe and Planters
Electric Membership Corporation, together with a Schedule
identifying 37 other substantially identical Wholesale Power
Contracts, and an additional

Wholesale Power Contract that is not substantially
identical. (Filed as Exhibit 10.10(a) to the Registrant's
Form 10-K for the fiscal year ended December 31, 1988, File
No. 33-7591.)

*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-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.)

*10.12 -- 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 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 10-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.)

*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 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.)

*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 -- Subsidiary of Oglethorpe (not included because the
subsidiary does not constitute a "significant subsidiary"
under Rule 1-02(v) of Regulation S-X).

27.1 -- Financial Data Schedule (for SEC use only)

----------

* Incorporated herein by reference.

+ Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this document is not
filed herewith, however the registrant hereby agrees that such
documents will be provided to the Commission upon request.

++ For the reason stated in footnote (+), this document and eight
other substantially identical documents are not filed as exhibits
to this Registration Statement.

+++ For the reason stated in footnote (+), this document and another
substantially identical document are not filed as exhibits to this
Registration Statement.

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 FORM 8-K.

No reports on Form 8-K were filed by Oglethorpe for the quarter ended
December 31, 1994.

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 30th day of
March, 1995.

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

By: /s/ J. CALVIN EARWOOD
-----------------------------------------
J. Calvin EARWOOD, CHAIRMAN OF THE BOARD

PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.

SIGNATURE TITLE DATE

/s/ J. CALVIN EARWOOD Chairman of the Board, March 30, 1995
------------------------ Director (Principal Executive
J. CALVIN EARWOOD Officer)

/s/ T. D. KILGORE President and Chief Executive March 30, 1995
------------------------ Officer (Principal Executive
T. D. KILGORE Officer)

/s/ JOHN S. DEAN, SR. Secretary-Treasurer (Principal March 30, 1995
------------------------ Financial Officer)
JOHN S. DEAN, SR.

/s/ EUGEN HECKL Senior Vice President and Chief March 30, 1995
------------------------ Financial Officer (Principal
EUGEN HECKL Financial Officer)

/s/ LARRY N. BROWNLEE Controller March 30, 1995
------------------------ (Principal Accounting Officer)
LARRY N. BROWNLEE

/s/ JMON WARNOCK Director March 30, 1995
------------------------
JMON WARNOCK

/s/ CHARLES R. FENDLEY Director March 30, 1995
------------------------
CHARLES R. FENDLEY

/s/ GEORGE C. MARTIN Director March 30, 1995
------------------------
GEORGE C. MARTIN

/s/ J. G. MCCALMON Director March 30, 1995
------------------------
J. G. MCCALMON

/s/ D. A. ROBINSON, III Director March 30, 1995
------------------------
D. A. ROBINSON, III

/s/ JAMES E. ESTES Director March 30, 1995
------------------------
JAMES E. ESTES

/s/ LARRY N. CHADWICK Director March 30, 1995
------------------------
LARRY N. CHADWICK

/s/ SIMMIE KING Director March 30, 1995
------------------------
SIMMIE KING

/s/ W. F. FARR Director March 30, 1995
------------------------
W. F. FARR

/s/ GARY T. DRAKE Alternate Director March 30, 1995
------------------------
GARY T. DRAKE

/s/ JEFF S. PIERCE, JR. Director March 30, 1995
------------------------
JEFF S. PIERCE, JR.

/s/ DONALD C. COOPER Director March 30, 1995
------------------------
DONALD C. COOPER

/s/ HERBERT CHURCH Director March 30, 1995
------------------------
HERBERT CHURCH

/s/ MAC F. OGLESBY Director March 30, 1995
------------------------
MAC F. OGLESBY

/s/ BENNY W. DENHAM Director March 30, 1995
------------------------
BENNY W. DENHAM

/s/ E. L. MCLOCKLIN Director March 30, 1995
------------------------
E. L. MCLOCKLIN

/s/ SAM RABUN Director March 30, 1995
------------------------
SAM RABUN

/s/ E. J. MARTIN, JR. Director March 30, 1995
------------------------
E. J. MARTIN, JR.

/s/ JIM KNIGHT Director March 30, 1995
------------------------
JIM KNIGHT

/s/ RONNIE FLEEMAN Director March 30, 1995
------------------------
RONNIE FLEEMAN

/s/ D. LAMAR COOPER Director March 30, 1995
------------------------
D. LAMAR COOPER

/s/ BARRY H. MARTIN Director March 30, 1995
------------------------
BARRY H. MARTIN

/s/ JOHN B. FLOYD, JR. Director March 30, 1995
------------------------
JOHN B. FLOYD, JR.

/s/ STEVE RAWL, SR Director March 30, 1995
------------------------
STEVE RAWL, SR.

/s/ JAMES GRUBBS Director March 30, 1995
------------------------
JAMES GRUBBS

/s/ SAMMY M. JENKINS Director March 30, 1995
------------------------
SAMMY M. JENKINS

/s/ J. M. SHERRER Director March 30, 1995
------------------------
J. M. SHERRER

/s/ JACK D. VICKERS Director March 30, 1995
------------------------
JACK D. VICKERS

/s/ C. W. COX, JR. Director March 30, 1995
------------------------
C. W. COX, JR.

/s/ JOHNNIE CRUMBLEY Director March 30, 1995
------------------------
JOHNNIE CRUMBLEY

/s/JARNETT W. WIGINGTON Director March 30, 1995
------------------------
JARNETT W. WIGINGTON

/s/ BOB JERNIGAN Director March 30, 1995
------------------------
BOB JERNIGAN

/s/ C. WILLARD MIMS Director March 30, 1995
------------------------
C. WILLARD MIMS

/s/ JAMES E. DOOLEY Director March 30, 1995
------------------------
JAMES E. DOOLEY

/s/ WILLIS T. WOODRUFF Director March 30, 1995
------------------------
WILLIS T. WOODRUFF

/s/ HUBERT HANCOCK Director March 30, 1995

--------------------------
HUBERT HANCOCK

/s/ HENDRIX WILEY Director March 30, 1995
--------------------------
HENDRIX WILEY

/s/ W. W. ARCHER Director March 30, 1995
--------------------------
W. W. ARCHER

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.