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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
------------------------
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, 1995
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)
<TABLE>
<S> <C>
GEORGIA 58-1211925
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
POST OFFICE BOX 1349 30085-1349
2100 EAST EXCHANGE PLACE (Zip Code)
TUCKER, GEORGIA
(Address of principal executive offices)
</TABLE>
<TABLE>
<S> <C>
Registrant's telephone number, including area code: (770) 270-7600
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: NONE
</TABLE>
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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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<PAGE>
OGLETHORPE POWER CORPORATION
1995 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
<TABLE>
<CAPTION>
ITEM PAGE
---- ----
<S> <C> <C>
PART I
1 Business ............................................................... 1
Oglethorpe Power Corporation ......................................... 1
The Members of Oglethorpe ............................................ 8
The Power Supply System .............................................. 11
Co-Owners of the Plants and the Plant and Transmission Agreements .... 21
2 Properties ............................................................. 25
3 Legal Proceedings ...................................................... 25
4 Submission of Matters to a Vote of Security Holders .................... 25
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters .. 26
6 Selected Financial Data ................................................ 26
7 Management's Discussion and Analysis of Financial Condition
and Results of Operations ............................................. 27
8 Financial Statements and Supplementary Data ............................ 35
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure .............................................. 53
PART III
10 Directors and Executive Officers of the Registrant ..................... 53
11 Executive Compensation ................................................. 65
12 Security Ownership of Certain Beneficial Owners and Management ......... 67
13 Certain Relationships and Related Transactions ......................... 67
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K ....... 68
</TABLE>
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SELECTED DEFINITIONS
When used herein the following terms will have the meanings indicated below:
<TABLE>
<CAPTION>
TERM MEANING
---- -------
<S> <C>
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.
EPMI Enron Power Marketing, Inc.
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
GSOC Georgia System Operations Corporation
GTC Georgia Transmission Corporation
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
</TABLE>
ii
<PAGE>
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 427
full-time and 39 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 2.6 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 1995, the aggregate SEPA allocation
to the Members was 542 megawatts ("MW") plus associated energy, representing
approximately 11% of total Member peak demand and approximately 5% 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".)
PROPOSED RESTRUCTURING
For some time, Oglethorpe and the Members have been discussing various
options to provide the Members greater flexibility for meeting their power
supply needs in an increasingly competitive utility environment. These
discussions led to a restructuring plan approved by Oglethorpe's Board of
Directors in December 1995 to divide Oglethorpe into three specialized
companies to respond to increasing competition in the electric industry
and to settle certain issues confronting Oglethorpe and the Members,
including several Members' previously stated intention to withdraw from
membership in Oglethorpe in order to gain more flexibility. The December
plan proposed the creation of a new transmission company and a new system
operations company and Oglethorpe's retention of the generation business.
Oglethorpe's Board believes there are significant potential benefits to
the Members of having the transmission business and the system operations
business operated in
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separate companies. Among the principal benefits is that the Members' freedom
to choose among power suppliers, including Oglethorpe, for their future growth
would be enhanced.
The current target date for full implementation of the
restructuring is January 1, 1997. As a preliminary step, Georgia
Transmission Corporation (An Electric Membership Corporation) ("GTC") has
been incorporated for future use as the transmission company and Georgia
System Operations Corporation ("GSOC") has been incorporated as a Georgia
non-profit corporation for future use as the system operations company. On
March 29, 1996, the Boards of Oglethorpe, GTC and GSOC approved an agreement
(the "Restructuring Agreement") which sets forth the terms and conditions on
which the restructuring and related changes would occur. The Restructuring
Agreement contemplates that Oglethorpe would operate primarily as a power
supply company, but initially would retain economic development, marketing and
service functions.
Oglethorpe would transfer its transmission business, including its
existing transmission assets, to GTC. GTC would thereafter own and operate
the transmission system and provide transmission services to the Members,
Oglethorpe and third parties. (See Note 6 of Notes to Financial Statements
in Item 8 for a summary of Oglethorpe's investments in electric plant,
including transmission and distribution plant.) The purchase price for the
transmission business would be equal to the sum of (1) the higher of: (a) the
appraised fair market value of such business as determined by an independent
appraiser, or (b) Oglethorpe's net book value for the transmission assets,
plus (2) the value of certain deferred charges. If the appraised value of
the transmission business exceeds Oglethorpe's net book value for the
transmission assets by more than 5%, GTC's Board would have to approve the
payment of any resulting purchase price. The purchase price would be paid by
GTC's assumption of a portion of Oglethorpe's long-term secured debt and by
cash obtained through third party borrowing.
Oglethorpe would transfer its system operations business, consisting of
its operations center and related computer and dispatch equipment, to GSOC.
GSOC would thereafter own and operate the operations center and provide system
operation services to the Members, Oglethorpe, GTC and third parties.
Oglethorpe also plans to implement a new governance structure when: (a)
it receives a favorable ruling from the Internal Revenue Service that such
structure would not affect Oglethorpe's status for federal income tax purposes
as a corporation operating on a cooperative basis, and (b) a new rate
schedule which allocates to each Member responsibility for a specified
percentage of all costs of Oglethorpe's existing resources becomes legally
binding and effective. It is contemplated that the new governance structure
would become effective at the same time as the restructuring, although it is
possible that it could become effective independent of the restructuring.
The new governance structure provides for a board of directors consisting of
six directors elected from the Members, four independent outside directors and
Oglethorpe's President and Chief Executive Officer, rather than Oglethorpe's
current 39-member board which is comprised of directors nominated by each
Member. To be elected, the new directors must be nominated by a committee
composed of a representative from each Member whose vote would be weighted in
accordance with the number of retail customers served by such Member and then
elected by a vote of the Members on a one-member, one-vote basis.
In adopting the Restructuring Agreement, Oglethorpe's Board recommended
to the Members that they become members of GTC and GSOC and that they join with
Oglethorpe, GTC and GSOC in executing an agreement (the "Member Agreement")
as to those matters contemplated in the Restructuring Agreement that directly
involve the Members in their capacities as separate corporations. The Member
Agreement will specify the form of transmission contracts and system
operation contracts to be signed by the Members. The Member Agreement will
also provide, subject to the approval of the Rural Utilities Service ("RUS"),
formerly known as the Rural Electrification Administration, that Oglethorpe
and each Member executing the Member Agreement would execute a new wholesale
power contract to govern the purchase and sale of power between Oglethorpe
and each such Member. Each Member signing the new wholesale power contract
would have a choice as to whether or not to participate in future power supply
projects sponsored by Oglethorpe. Such Members would be free to own
generation directly and to engage in purchases and sales with other power
suppliers. To the extent such Members
2
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choose to satisfy their projected load growth from sources other than
Oglethorpe, the growth in Oglethorpe's revenues from the sale of power would
decrease but the growth in related expenses also would decrease.
Members agreeing to the new wholesale power contracts would have the
option to have energy and reserves priced on a pooled basis or to schedule
their capacity and associated energy separately at prices based on the cost
of production. GSOC would administer the new power pool contemplated by the
new wholesale power contracts and would implement the separate schedules for
Members electing that option. Under the power pool, Oglethorpe resources and
any Member-procured resources would be committed to economic dispatch (pooled)
for the benefit of all pool participants. The power pool arrangement also would
allow the participants to pool resource reserves.
In connection with the restructuring, Oglethorpe plans to adopt 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 generally would require the withdrawing
Member either to affirm its obligations under its then-existing wholesale
power contract or to assign its rights and obligations under such wholesale
power contract to another party with a credit rating meeting certain
specified requirements. Withdrawal by a Member would continue to be
conditioned upon approval by RUS.
The restructuring is subject to a number of conditions, including (1)
implementation of Oglethorpe's new governance structure, (2) execution of the
Member Agreement by the Members, execution of new wholesale power
contracts by Oglethorpe and the Members, and execution of the transmission
contracts and system operation contracts specified in the Member Agreement,
(3) RUS approval of new wholesale power contracts and the restructuring,
(4) governmental, lender and other third party consents, authorizations,
waivers, orders and approvals, (5) receipt by GTC and GSOC of certain capital
contributions by the Members and (6) assurances from rating agencies that the
ratings on Oglethorpe's outstanding fixed rate PCBs would not be lowered as a
result of the restructuring and that such rating agencies would assign to any
comparable bonds issued by GTC the same or better credit rating as assigned
to Oglethorpe's fixed rate PCBs. Most of these conditions may be waived by
Oglethorpe's Board, subject to RUS approval in certain instances.
The restructuring is expected to take the remainder of 1996 to complete,
although limited aspects of the restructuring may become effective sooner if
specific conditions set forth in the Restructuring Agreement are met. In
light of the significant conditions that must be satisfied, including RUS and
other governmental and third-party approvals and assurances and receipt of
various agreements from the Members, Oglethorpe cannot predict the actual timing
of or the ultimate likelihood of full implementation of the restructuring or
governance changes. Until implementation of the restructuring, Oglethorpe
will continue its current operations, and until satisfaction of the conditions
applicable to the new governance structure, Oglethorpe will continue under
its existing governance structure.
MEMBER DEMAND AND ENERGY REQUIREMENTS
The following table shows the aggregate peak demand and energy
requirements of the Members for the years 1993 through 1995 and also shows
the amounts of such requirements supplied by Oglethorpe and SEPA. For the
years 1993 through 1995, demand and energy requirements increased at an
average annual compound growth rate of 6.4% and 5.9%, respectively.
3
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<TABLE>
<CAPTION>
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)
--------- ------------- ----------- ---------- ------------- -----------
<S> <C> <C> <C> <C> <C> <C>
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
1995 4,850 4,308 542 19,403,703 18,442,153 961,550
</TABLE>
______________________
(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 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 1995, Cobb EMC and Jackson EMC accounted for approximately 11.3% and
10.4% of Oglethorpe's total revenues, respectively.
SEASONAL VARIATIONS
The demand for energy by the Members is influenced by seasonal weather
conditions. Historically, Oglethorpe's peak demand occurs during the months
of June through September. (See "Electric Rates" herein.) Energy revenues
track energy costs as they are incurred and also fluctuate month to month.
Capacity revenues reflect the recovery of Oglethorpe's fixed costs which do
not vary significantly from month to month; therefore, the capacity revenues
are billed and recognized in equal monthly amounts.
DEMAND MANAGEMENT
Oglethorpe and the Members have implemented various demand management
programs. The program goal, developed in conjunction with Oglethorpe's
integrated resource planning process, 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 also resulted in an increase in off-peak sales. (See "THE
POWER SUPPLY SYSTEM--Future Power 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
SunTrust Bank, Atlanta, formerly known as Trust Company Bank ("SunTrust"), as
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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 1995, 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 1996. (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", "Results of Operations--FACTORS AFFECTING FUTURE
FINANCIAL PERFORMANCE" and "Proposed Restructuring" 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 levels, which is based on a shift to a market-driven environment from a
regulated one. Significant legislative developments and regulatory
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 "Proposed Restructuring" herein and "THE
POWER SUPPLY SYSTEM--General", "--Future Power Resources" and
"--Environmental and Other Regulations".)
5
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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 1995,
Oglethorpe derived 6% 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 most were constructed and are now operated by GPC. Oglethorpe
completed the construction of and is now the primary owner 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",
"--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 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.
For fiscal year 1996, the Congress set the level of funding for the 100%
guarantee program at $300 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. For fiscal year 1997, the
Administration's budget proposal to Congress calls for a level of $400
million for the guarantee program. 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.
For a number of years, RUS has been re-evaluating its regulatory and
lending relationship with its borrowers through what it has described as a
comprehensive rule-making project. RUS has said 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 loan contract for distribution borrowers. RUS has not, however,
pursued finalization of the new form of wholesale power contract earlier
proposed. RUS has adopted a new standard form of mortgage for distribution
borrowers.
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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. While no formal notice has been issued by RUS, RUS has
advised borrowers informally that it will for the present use a case-by-case
approach to power supply borrower mortgage reform and member credit support.
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.
7
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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 2.6 million people. The
Members serve a region covering approximately 40,000 square miles, which is
approximately 70% of the land area of Georgia served by the owners of the
ITS, encompassing 150 of the State's 159 counties. Sales by the Members in
1995 amounted to approximately 18.2 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 1995. The Members are the principal
suppliers for the power needs of rural Georgia. While the Members do not
serve any major cities, portions of their service territories are in close
proximity to urban areas and are experiencing substantial growth due to the
expansion of urban areas, including metropolitan Atlanta, into suburban areas
and the growth of suburban areas into neighboring rural areas. The Members
have experienced average annual compound growth rates from 1993 through 1995
of 4.0% in number of consumers, 5.9% in MWh sales and 6.3% 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 continues to
increase annually. 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 are approached by other parties interested
in purchasing their systems. Some of the Members have been approached in the
past by third parties indicating an interest in purchasing their systems. The
Wholesale Power 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
8
<PAGE>
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, Mitchell EMC, Troup EMC and Walton EMC in
1995, and Cobb EMC in 1996 prepaid their RUS indebtedness and are no longer
RUS borrowers. It is likely that other Members will also pursue this option.
Each of these Members now have financial and other requirements under their
loan documents with the National Rural Utilities Cooperative Finance
Corporation ("CFC") and, for Troup EMC, with CoBank also.
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 1995, the aggregate SEPA allocation to the Members was 542 MW plus
associated energy, representing approximately 11% of total Member peak demand
and
9
<PAGE>
approximately 5% 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. An order was sought from FERC requiring the provision of
these services at just and reasonable rates; however, SEPA and The Southern
Company have continued negotiations in an effort to reach agreement.
During 1995, legislative proposals were made that would have resulted in
the privatization of several of the federal power marketing administrations,
in particular SEPA. Ultimately, no proposal for the privatization of the
power marketing administrations was included in the final budget proposal.
The President's Budget for fiscal year 1997 does not include any proposals to
privatize the federal power marketing administrations. The ultimate outcome
of this issue 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 2% loan program and
substituted a new program, the interest rates for which are based on rates
being paid on municipal bonds with comparable maturities. Certain borrowers
with either low consumer density or higher-than-average rates and
lower-than-average consumer income are eligible for a 5% loan program. The
future cost, availability and amount of RUS direct and guaranteed loans
cannot be predicted.
A number of Members have recently prepaid their RUS indebtedness and are
no longer RUS borrowers. Other Members may also pursue this option. (See
"Rate Regulation of Members" herein.) For further information regarding the
RUS program, see "OGLETHORPE POWER CORPORATION--Relationship with RUS".
10
<PAGE>
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. 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 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".)
<TABLE>
<CAPTION>
OGLETHORPE'S
SHARE OF NAME- COMMERCIAL LICENSE
PERCENTAGE PLATE CAPACITY OPERATION EXPIRATION
TYPE OF FUEL INTEREST(1) (MW) DATE DATE
------------ ----------- --------------- ---------- ----------
<S> <C> <C> <C> <C> <C>
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(2)
Unit No. 2 Coal 30 259.5 1978 N/A(2)
Combustion Turbine Oil 30 14.8 1980 N/A(2)
Plant Scherer (near Forsyth)
Unit No. 1 Coal 60 490.8 1982 N/A(2)
Unit No. 2 Coal 60 490.8 1984 N/A(2)
Tallassee (near Athens) Hydro 100 2.1 1986 2023
Rocky Mountain Pumped Storage
(near Rome) Hydro 74.61 632.5 1995 2027
-------
Total Ownership 3,335.0
-------
-------
</TABLE>
______________________
(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) 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.
Oglethorpe owns or leases 1,500.6 MW of coal-fired capacity, 1,185 MW of
nuclear-fueled capacity, 632.5 MW of pumped storage hydroelectric capacity,
14.8 MW of oil-fired combustion turbine capacity and 2.1 MW of conventional
hydroelectric capacity.
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
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<PAGE>
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:
<TABLE>
<CAPTION>
EQUIVALENT AVAILABILITY(1) CAPACITY FACTOR(2)
-------------------------- ------------------
Unit 1995 1994 1993 1995 1994 1993
- ---- ---- ---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C> <C>
Plant Hatch
Unit No. 1 .......... 98% 84% 76% 100% 85% 77%
Unit No. 2 .......... 75 78 75 75 79 75
Plant Vogtle
Unit No. 1 .......... 98 86 85 98 86 86
Unit No. 2 .......... 89 91 87 90 91 87
Plant Wansley
Unit No. 1 .......... 90 92 88 56 62 71
Unit No. 2 .......... 89 88 90 56 58 73
Plant Scherer(3)
Unit No. 1 .......... 95 97 88 73 64 36
Unit No. 2 .......... 97 85 95 85 60 37
Rocky Mountain(4)
Unit No. 1 .......... 83 N/A N/A 16 N/A N/A
Unit No. 2 .......... 92 N/A N/A 15 N/A N/A
Unit No. 3 .......... 92 N/A N/A 16 N/A N/A
</TABLE>
______________________
(1) Equivalent Availability is a measure of the percentage of time that a unit
was available to generate if called upon, adjusted for periods when the
unit is partially derated from the "maximum dependable capacity" rating.
(2) Capacity Factor is a measure of the output of a unit as a percentage of
the maximum output, based on the "maximum dependable capacity"
rating, over the period of measure.
(3) Prior to 1994, Plant Scherer operated in peaking service due to its higher
cost fuel supply. Oglethorpe's efforts to reduce Plant Scherer's fuel
costs in recent years have made the units more economical to operate,
resulting in higher capacity factors.
(4) Rocky Mountain Commercial Operation Dates: Unit 1 - July 24, 1995;
Unit 2 - June 19, 1995; Unit 3 - June 1, 1995. This information was
calculated beginning from the commercial operation date for each unit.
As a pumped storage plant, Rocky Mountain primarily operates in
peaking service.
The nuclear refueling cycle for Plants Hatch and Vogtle exceeds twelve
months. Therefore, in some calendar years the units at these plants are not
taken out of service for refueling, resulting in higher levels of equivalent
availability and capacity factor.
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<PAGE>
FUEL SUPPLY
Coal for Plant Wansley is purchased under a long-term contract, which is
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 29, 1996, there was a 33-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 29, 1996, the coal stockpile at Plant Scherer contained a 21-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
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<PAGE>
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:
<TABLE>
<CAPTION>
MWh
--------------------------
1995 1994
---------- ----------
<S> <C> <C>
SOURCES OF ENERGY:
Owned or Leased Generation ....... 18,402,839 16,924,038
Purchased -- GPC ............... 2,711,203 2,632,039
-- Others ............ 3,027,431 1,749,048
---------- ----------
Total Sources .............. 24,141,473 21,305,125
---------- ----------
DISTRIBUTION OF ENERGY:
Members .......................... 18,442,153 16,285,127
Non-Members -- GPC ............. 2,195,012 2,140,526
-- Others .......... 2,520,462 2,067,443
Transmission Losses .............. 983,846 812,029
---------- ----------
Total Distribution ......... 24,141,473 21,305,125
---------- ----------
</TABLE>
The sales to GPC were made under the GPC Sell-back (as herein defined)
and the Coordination Services Agreement (the "CSA"). The purchases from GPC
were made under the Block Power Sale Agreement (the "BPSA") and the CSA.
GPC SELL-BACK
Pursuant to the contractual arrangements with GPC, Oglethorpe had an
obligation to sell to GPC, and GPC had 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"). As of May 31, 1995, the GPC Sell-back expired in accordance
with its terms for all units. For 1995, energy sales from the GPC Sell-back
represented less than 1% of total sales by Oglethorpe. Capacity and energy
revenues from the GPC Sell-back represented 1% of Oglethorpe's total revenues
in 1995.
As GPC's entitlement to capacity and energy under the GPC Sell-back
decreased, Oglethorpe's increased entitlement to the output of each unit was
used to serve its own requirements. The increased costs thereof are
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 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,
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<PAGE>
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, 2003. 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 two 250 MW Component Blocks (coal-fired units)
effective September 1, 1996 and September 1, 1997 respectively, and is
currently evaluating replacement purchases. 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 could 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 Notes to Financial Statements in Item 8.)
Oglethorpe also has a contract to purchase approximately 300 MW of
capacity with Hartwell Energy Limited Partnership ("Hartwell"), a partnership
owned 50% by Destec Energy, Inc. and 50% by American National Power, Inc., a
subsidiary of National Power, PLC, through April 2019. Oglethorpe intends to
use the units for peaking capacity but has the right to dispatch the units
fully.
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<PAGE>
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
0.3% of Oglethorpe's energy requirements for the Members in 1995.
EPMI POWER PURCHASE AND SALE
As a means of reducing the cost of power provided to the Members,
Oglethorpe and Enron Power Marketing, Inc. ("EPMI") entered into a power
supply swap agreement effective January 4, 1996 through April 30, 1996.
Pursuant to such agreement, EPMI must provide all the energy necessary to
meet the Members requirements at a favorable fixed rate, and Oglethorpe is
required to sell to EPMI at cost, subject to certain limitations, all energy
available from Oglethorpe's total power resources. Under the agreement,
Oglethorpe still maintains the responsibility of operating the power supply
system and continues to dispatch the generating resources to ensure system
reliability.
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.
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. While Oglethorpe is still considering some of these proposals,
it continues to pursue other options to keep the Members power cost as low as
possible.
On February 7, 1996, Oglethorpe issued another request for proposals.
This RFP did not seek a specific amount of power; instead, it requested
proposals for meeting the combined power needs of the Members with term
options ranging from two to 15 years. Action is anticipated by Oglethorpe's
Board of Directors during April, with implementation of a new arrangement as
soon thereafter as possible.
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.
TRANSMISSION AND OTHER POWER SYSTEM ARRANGEMENTS
Oglethorpe owns approximately 2,267 miles of transmission line and 426
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
16
<PAGE>
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.
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 pollutants, such as particulate matter, sulfur oxides
and nitrogen oxides ("NO(x)") into the air and discharges of other pollutants,
including heat, into waters of the United States. Oglethorpe is also subject
to Federal, State and local waste disposal requirements 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 $1.0 million in 1996, $3.6 million in 1997 and
$1.4 million in 1998.
CLEAN AIR ACT
The Clean Air Act ("Act") seeks to improve air quality throughout the United
States. The acid rain provisions of the Act require the reduction of sulfur
dioxide and NO(x) emissions from affected units, including coal-fired electric
power facilities. The sulfur dioxide reductions required by the Act will be
achieved in two phases. Phase I addresses specific generating units named in
the Act. Both units of Plant Wansley are "affected units" under Phase I.
Scherer Units No. 1 and No. 2 are not "affected units" under Phase I but are
"affected units" under Phase II. Beginning in 1995, Phase I affected units
became subject to the 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
comply with Phase I requirements through the use of its allowances coupled
with switching to lower sulfur coal, a compliance strategy that has required
some equipment upgrades at Plant Wansley and may result in unused allowances
that can be banked for future use.
17
<PAGE>
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.
Although some NO(x) regulations implementing the requirements of the Act
have been finalized, there remains the possibility that other regulations
could be imposed. For example, EPA recently proposed lowering the NO(x)
emission standard for boiler types such as those found at Scherer Units No. 1
and No. 2. Whether those regulations will be finalized and in what form is not
known. Depending on the NO(x) rules when finalized, additional expenditures
for pollution control equipment may be incurred.
In general, compliance with the Act will continue to require expenditures
for monitoring and permitting, and in some instances may involve increased
operating or maintenance expenses. Capital expenditures of Oglethorpe through
1995 for pollution control equipment needed to comply with the Act at Plant
Wansley have been approximately $7,200,000 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 remains
dependent upon the chosen compliance plan and may be affected by future plan
amendments and/or future regulations. In addition, the final capital cost of
improvements and any effect on operating costs will be determined by the
compliance plan as finally implemented and any applicable regulatory changes.
Metropolitan Atlanta is classified as a "serious nonattainment area" with
regard to the ozone ambient air quality standards. The Act, under which these
standards are promulgated, requires the State of Georgia to conduct specific
studies and establish new rules regulating sources of NO(x) 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 NO(x) 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 rules for power plants in the State. Plant Wansley is near the
nonattainment area while Plant Scherer is located further away. The results of
these studies and new rules could require NO(x) controls more stringent than
those now required under the acid rain provisions of the Act for compliance.
Portions of Subchapter I of the Act require that several studies be conducted
regarding the health effects of power plant emissions of certain hazardous
air pollutants. The studies will be used in making decisions on whether
additional controls of these pollutants are necessary. The effect of any of
these potential regulatory changes under the Act, including new rules under the
amended provisions, cannot now be predicted.
The Act also 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). If a new short-term NAAQS for sulfur dioxide were
imposed, it might require numerous power plants to install emission controls,
perhaps in addition to any required under the acid rain provisions of the 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 certainty that that standard will not be revised in the
future. In addition, EPA has finalized a criteria document and is updating a
staff paper for ozone, which could lead to a change in the NAAQS for ozone.
EPA is also updating 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 developed.
Although Oglethorpe's management is currently unable to determine the
overall effect that compliance with requirements under the 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 Act may also
require increased capital or operating
18
<PAGE>
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 reauthorization of the Clean Water Act. If that
occurs, Oglethorpe's operations could be affected. However, the full impact
of any reauthorization cannot now be determined and will depend on the
specific changes to the statute, as well as to any implementing state or
federal regulations that might be promulgated.
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"), the
Emergency Planning and Community Right to Know Act, the Georgia Hazardous
Site Response 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. Although compliance with new environmental legislation could have a
significant impact on Oglethorpe,
19
<PAGE>
those impacts cannot be fully determined at this time and would depend in
part on the final legislation and the development of implementing regulations.
The scientific community, regulatory agencies and the electric utility
industry are continuing to examine the issues of global warming and the
possible health effects of electromagnetic fields. While no definitive
scientific conclusions have been reached regarding these issues, it is
possible that new laws or regulations pertaining to these matters could
increase the capital and operating costs of electric utilities, including
Oglethorpe or entities from which Oglethorpe purchases power. In addition,
the potential for liability exists from lawsuits alleging damages from
electromagnetic fields.
ENERGY POLICY ACT
The Energy Policy Act allows for increased competition among wholesale
electric suppliers and increased access to transmission 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. 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. In March 1995, FERC issued a proposed rule
implementing the open access provisions of the Energy Policy Act. The Chair
of FERC has publicly predicted a final rule before mid-1996. Although
RUS-financed cooperatives will not be subject to all provisions of the FERC
rule, they will be subject to FERC orders to provide transmission on just and
reasonable terms and conditions.
A significant outgrowth of the Energy Policy Act is the rapid increase of
power marketers. Power marketers are FERC-regulated public utilities that
sell under "market-based" rates. Power marketers rely heavily on
transmission access to buy and sell power across several systems. (See "EPMI
Power Purchase and Sale" and "Future Power Resources" herein.)
20
<PAGE>
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.)
<TABLE>
<CAPTION>
Nuclear Coal-Fire Pumped Storage
-------------------------- ---------------------------- --------------
Plant Plant Plant Scherer Units Rocky
Hatch Vogtle Wansley No. 1 & No. 2 Mountain Total
------------ ------------ ------------ --------------- -------------- -----
% MW(1) % MW(1) % MW(1) % MW(1) % MW(1) MW(1)
----- ----- ----- ----- ----- ----- -------- ----- ------ ----- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
Oglethorpe .. 30.0 489 30.0 696 30.0 519 60.0(2) 982 74.61 633 3,319
GPC ......... 50.1 817 45.7 1,060 53.5 926 8.4 137 25.39 215 3,155
MEAG ........ 17.7 288 22.7 527 15.1 261 30.2 494 -- -- 1,570
Dalton ...... 2.2 36 1.6 37 1.4 24 1.4 23 -- -- 120
----- ----- ----- ----- ----- ----- -------- ----- ------ ----- -----
Total........ 100.0 1,630 100.0 2,320 100.0 1,730 100.0 1,636 100.00 848 8,164
----- ----- ----- ----- ----- ----- -------- ----- ------ ----- -----
----- ----- ----- ----- ----- ----- -------- ----- ------ ----- -----
</TABLE>
______________________
(1) Based on nameplate ratings.
(2) Oglethorpe leases its interest in Scherer Unit No. 2 pursuant to long-term
net leases.
GEORGIA POWER COMPANY
GPC is a wholly owned subsidiary of The Southern Company, a registered
holding company under the Public Utility Holding Company Act, and is engaged
primarily in the generation and purchase of electric energy and the
transmission, distribution and sale of such energy within the State of
Georgia at retail in over 600 communities (including Athens, Atlanta,
Augusta, Columbus, Macon, Rome and Valdosta), as well as in rural areas, and
at wholesale to Oglethorpe, MEAG and three municipalities. GPC is the
largest supplier of electric energy in the State of Georgia. (See "OGLETHORPE
POWER CORPORATION--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 48 cities and one county in the State of Georgia. Such
political subdivisions, located in 39 of the State's 159 counties,
collectively serve approximately 270,000 electric customers.
21
<PAGE>
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, 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
22
<PAGE>
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 its fuel costs and for variable Operating Costs in proportion
to the net energy output for its ownership interest, while responsibility for
fixed Operating Costs will continue to be equal to the percentage undivided
ownership interest which is owned or leased in such unit. GPC is required to
furnish budgets for Operating Costs, fuel plans and scheduled maintenance
plans subject to, in the case of Scherer Units No. 1 and No. 2, certain
limited rights of the Participants to disapprove such budgets proposed by GPC
and to substitute alternative budgets.
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"), Oglethorpe initially acquired a 3%
undivided interest in Rocky Mountain which interest increased as Oglethorpe
expended funds to complete construction of Rocky Mountain. The final
ownership percentages for Rocky Mountain are Oglethorpe 74.61% and GPC
25.39%. In connection with this acquisition, Oglethorpe and GPC also entered
into the Rocky Mountain Pumped Storage Hydroelectric Project Operating
Agreement (the "Rocky Mountain Operating Agreement").
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 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. Oglethorpe and GPC have each elected to schedule
separately their respective ownership interests. The Rocky Mountain
Operating Agreement will terminate in 2035.
23
<PAGE>
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.
24
<PAGE>
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.
25
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Not applicable.
ITEM 6. SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
...............................................................................................................
(dollars in thousands)
1995 1994 1993 1992 1991
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES:
Sales to Members ................ $ 1,030,797 $ 930,875 $ 899,720 $ 816,000 $ 763,657
Sales to non-Members............. 118,764 125,207 200,940 268,763 300,293
----------- ----------- ----------- ----------- -----------
Total operating revenues ........ 1,149,561 1,056,082 1,100,660 1,084,763 1,063,950
----------- ----------- ----------- ----------- -----------
OPERATING EXPENSES:
Fuel............................. 219,062 203,444 176,342 167,288 165,168
Production....................... 133,858 132,723 129,972 115,915 130,041
Purchased power.................. 264,844 227,477 271,970 230,510 229,898
Depreciation and amortization.... 139,024 131,056 128,060 126,047 135,152
Taxes............................ 27,561 24,741 25,148 19,634 42,422
Other operating expenses......... 56,535 49,234 44,876 50,578 49,373
----------- ----------- ----------- ----------- -----------
Total operating expenses......... 840,884 768,675 776,368 709,972 752,054
----------- ----------- ----------- ----------- -----------
OPERATING MARGIN................... 308,677 287,407 324,292 374,791 311,896
OTHER INCOME, NET.................. 33,710 40,795 38,741 45,928 113,441
NET INTEREST CHARGES............... (320,129) (305,120) (350,652) (393,247) (396,892)
----------- ----------- ----------- ----------- -----------
MARGIN BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE... 22,258 23,082 12,381 27,472 28,445
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING FOR INCOME TAXES...... -- -- 13,340 -- --
----------- ----------- ----------- ----------- -----------
NET MARGIN......................... $ 22,258 $ 23,082 $ 25,721 $ 27,472 $ 28,445
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
ELECTRIC PLANT, NET:
In service....................... $ 4,436,009 $ 3,980,439 $ 4,054,956 $ 4,122,411 $ 4,196,966
Construction work in progress.... 35,753 538,789 450,965 322,628 178,980
----------- ----------- ----------- ----------- -----------
$ 4,471,762 $ 4,519,228 $ 4,505,921 $ 4,445,039 $ 4,375,946
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
TOTAL ASSETS....................... $ 5,438,536 $ 5,346,330 $ 5,323,890 $ 5,359,597 $ 5,246,435
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
CAPITALIZATION:
Long-term debt................... $ 4,207,320 $ 4,128,080 $ 4,058,251 $ 4,095,796 $ 4,093,218
Obligation under capital leases.. 296,478 303,749 303,458 302,061 300,833
Patronage capital and membership
fees............................ 338,891 309,496 289,982 264,261 236,789
----------- ----------- ----------- ----------- -----------
$ 4,842,689 $ 4,741,325 $ 4,651,691 $ 4,662,118 $ 4,630,840
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
PROPERTY ADDITIONS................. $ 138,921 $ 206,345 $ 235,285 $ 232,283 $ 225,021
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
ENERGY SUPPLY (MEGAWATT-HOURS):
Generated........................ 18,402,839 16,924,038 14,575,920 13,805,683 12,686,323
Purchased........................ 5,738,634 4,381,087 7,620,815 6,233,262 6,915,758
----------- ----------- ----------- ----------- -----------
Available for sale............... 24,141,473 21,305,125 22,196,735 20,038,945 19,602,081
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
MEMBER REVENUE PER KWH SOLD........ 5.53CENTS 5.65CENTS 5.47CENTS 5.55CENTS 5.36CENTS
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
</TABLE>
26
<PAGE>
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, 1995, had a balance
of $339 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. (See "Proposed Restructuring"
below regarding a special patronage capital distribution contemplated in
connection with the proposed restructuring.) Any distributions of patronage
capital are subject to the discretion of the Board of Directors and the
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 6.5% at December 31, 1994 to 7.0% at
December 31, 1995.
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 1993 and 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,
Oglethorpe implemented two additional capacity rate options in an effort to
provide greater flexibility to the Members. These options allocated fixed
costs using billing determinants of the current year. These rates produced
differing monthly amounts of capacity revenues throughout the year and
introduced some variability and uncertainty as to the level of revenues and
margins to be received. Due to extreme weather conditions and other factors,
the new rates options produced $2.5 million of revenues in excess of budgeted
amounts. Such amounts will be returned to the Members in 1996.
Under an interim rate mechanism, effective from January 1, 1996 to April
30, 1996, each Member has an assigned share of responsibility for fixed costs
based on an agreed-upon allocation. Under this approach, capacity costs will
be collected in equal monthly amounts. In connection with the approval on
March 29, 1996 of a Restructuring Agreement (discussed below under "Proposed
Restructuring"), Oglethorpe's Board extended the interim rate mechanism
through the end of 1996, subject to rate changes that might be adopted in
connection with a new long-term power supply arrangement (discussed below
under "Results of Operations--FACTORS AFFECTING FUTURE FINANCIAL
PERFORMANCE"). The Restructuring Agreement contemplates that a new rate
schedule would be effective for 1997 which would implement on a long-term
basis the assignment of responsibility for fixed costs based on historical
demand factors. In 1996, management expects a net increase in fixed costs
due to absorbing a full year's costs of the Rocky Mountain pumped storage
hydroelectric facility (Rocky Mountain); however, because of anticipated
increases in energy sales and decreases in energy costs, average Member
revenues (measured in cents per kilowatt-hour (kWh)) should remain at or near
the 1995 level.
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. Oglethorpe's Board of Directors set an annual net margin
goal to be the amount required to produce a TIER of 1.07 in 1993 through
1995. The net margin goal for 1996 is also a 1.07 TIER.
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
27
<PAGE>
(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 1993
through 1995 were as follows:
<TABLE>
<CAPTION>
1995 1994 1993
---- ---- ----
<S> <C> <C> <C>
TIER 1.07 1.07 1.07
DSC 1.21 1.19 1.23
ADSCR 1.27 1.25 1.26
</TABLE>
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 current 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 set rates to meet the
current ADSCR requirement or take action to lower the ADSCR requirement by
prepaying or defeasing certain PCBs as described above.
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
Financial Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation". Oglethorpe has recorded regulatory assets and
liabilities related to its generation and transmission operations. In 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 of other assets, including utility plant, and write down the plant
assets to their fair value. See Note 1 of Notes to Financial Statements for
additional information.
The staff of the Securities and Exchange Commission has questioned
certain of the current accounting practices of the electric utility industry
regarding the recognition, measurement and classification of decommissioning
costs for nuclear generating facilities in financial statements of electric
utilities. In response to these questions, the Financial Accounting
Standards Board has issued an Exposure Draft of a proposed Statement on
"Accounting for Certain Liabilities Related to Closure or Removal of
Long-Lived Assets". The proposed Statement would require the recognition of
the entire obligation for decommissioning at its present value as a liability
in the financial statements. Rate-regulated utilities would also recognize a
regulatory asset for differences in the timing of recognition of the costs of
decommissioning for financial reporting and rate-making purposes.
Oglethorpe's management does not believe that this proposed Statement 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.
RESULTS OF OPERATIONS
HISTORICAL FACTORS AFFECTING FINANCIAL PERFORMANCE
Over the past three years, Oglethorpe's Members have absorbed into rates
additional responsibility for the cost of its ownership interests in Plant
Scherer Unit No. 2 and Plant Vogtle Units No. 1 and No. 2. These generating
units were placed in commercial operation in 1984, 1987, and 1989,
respectively. Oglethorpe has utilized both long-term contractual
arrangements with Georgia Power Company (GPC) and margin and rates mechanisms
to allow for a gradual absorption of costs over several years. In addition,
Oglethorpe is utilizing margin and rates mechanisms to mitigate the impact of
absorbing the costs of Rocky Mountain which was placed in service during June
and July 1995.
Contractual arrangements with GPC 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 seven to ten years of operation of such units (GPC
Sell-back). As of May 31, 1995, the GPC Sell-back has expired for all units.
(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
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 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 1995, 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 and, subsequently, with Rocky Mountain. 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.) As of
December 31, 1995, Oglethorpe held a balance of approximately $32 million
from deferred margins which will be utilized in 1996 for rate mitigation as
the annual costs of Rocky Mountain are absorbed.
28
<PAGE>
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 1993 through 1995, although total revenues have varied
slightly, the scheduled reduction of the GPC Sell-back has resulted in the
planned decrease of non-Member revenues from GPC of about $96 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 "Financial Condition--REFINANCING TRANSACTIONS" below have
resulted in a reduction in gross interest charges from $367 million in 1993
to $318 million in 1995, or a 13% decrease in that fixed cost component of
the capacity rates.
SALES TO MEMBERS. Revenues from sales to Members increased 10.7% in 1995
compared to 1994 and increased 3.5% in 1994 compared to 1993. 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
capacity revenues in 1995 were also affected by additional fixed costs
related to the commercial operation of Rocky Mountain in June 1995.
Member energy revenues per kWh declined 7.6% in 1995 compared to 1994 and
6.9% in 1994 compared to 1993, reflecting savings in fuel and production
costs. The 1995 decline in revenues per kWh also reflects lower average
purchased power costs. 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:
<TABLE>
<CAPTION>
(IN THOUSANDS) KILOWATT-HOURS
-------------------------------
<S> <C>
1995 18,442,153
1994 16,285,127
1993 16,253,283
</TABLE>
Member sales have been significantly affected by abnormal weather
conditions during the past three years. In 1995 and 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:
<TABLE>
<CAPTION>
CENTS PER KILOWATT-HOUR
-----------------------
<S> <C>
1995 5.53 CENTS
1994 5.65
1993 5.47
</TABLE>
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:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1995 1994 1993
- -------------------------------------------------------------
<S> <C> <C> <C>
Plant operating agreements $ 10,096 $ 45,392 $106,146
Power supply arrangements 43,226 26,280 44,904
Transmission agreements 12,614 10,974 15,763
Other utilities 52,828 42,561 34,127
-------- -------- --------
Total $118,764 $125,207 $200,940
</TABLE>
Revenues from sales to non-Members declined in 1995 compared to 1994 and
in 1994 compared to 1993. 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
higher in 1995 compared to 1994 and lower in 1994 compared to 1993. In 1995,
Oglethorpe retained less of its share of the output from Plant Wansley units
because the added cost associated with emission allowances made those units
less attractive than certain purchased resources. The lower 1994 revenues
were 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. Emission
allowances for Plant Wansley were not required in 1994. See the discussion
under "OPERATING EXPENSES" herein of the lower average fuel costs of the
coal-fired generating units in 1995 and 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
29
<PAGE>
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 primarily 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 change in revenues for
1995 through 1993 resulted from normal variations of Oglethorpe's investment
percentages and its use of the system.
Revenues from other non-Member utilities increased substantially due to a
22% increase in kWh sales in 1995 as compared to 1994 and a 28% increase in kWh
sales in 1994 as compared to 1993. Oglethorpe is continuing to aggressively
seek additional off-system sales opportunities as a means of reducing amounts
that must be recovered from Members. See "FACTORS AFFECTING FUTURE FINANCIAL
PERFORMANCE" herein regarding Oglethorpe's 1996 short-term power swap
arrangement which committed Oglethorpe's total power resources under a single
contractual arrangement, and regarding Oglethorpe's consideration of a similar
power supply swap arrangement for a longer term basis.
OPERATING EXPENSES
Oglethorpe's operating expenses increased 9.4% in 1995 compared to 1994
and decreased 1.0% in 1994 compared to 1993. The increase in operating
expenses in 1995 compared to 1994 was primarily attributable to a 13.0%
increase in kWh sold to Members and non-Members. In addition, depreciation
and amortization, sales, and administrative and general expenses were also
higher. 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.
Generally, over the years 1993 through 1995, 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 are as follows:
<TABLE>
<CAPTION>
CENTS PER KILOWATT-HOUR
-------------------------
NUCLEAR FOSSIL
---------- ----------
<S> <C> <C>
1995 0.59 CENTS 1.74 CENTS
1994 0.64 1.78
1993 0.61 1.96
</TABLE>
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. The use of lower-priced western coal combined with a greater
reliance on a favorable spot market for coal resulted in a per unit fuel cost
decrease for Plant Scherer of 13% in 1995 from 1993 levels. Because of the
decline in fuel cost per kWh at Plant Scherer, the usage of the units
increased significantly. Output from Plant Scherer was 23% higher in 1995
compared to 1994 and 75% higher in 1994 compared to 1993. Oglethorpe
retained significantly less of its output from Plant Wansley in 1995 compared
to 1994 primarily as a result of higher costs associated with the emission
allowances requirement. In 1994 compared to 1993, the per unit fuel cost at
Plant Wansley decreased by almost 10% and thus, Oglethorpe retained more of
its output. The decrease in per unit fuel costs resulted from a greater
reliance on a favorable spot market for coals.
Purchased power cost increased by 16% in 1995 compared to 1994 and
decreased 16% in 1994 compared to 1993. In 1995, the 13% higher kWh sales,
including the increased Member sales and sales to GPC pursuant to power
supply arrangement (see discussion under "OPERATING REVENUES" herein)
resulted in higher utilization of purchased power resources. Energy
purchases increased 31% in 1995 compared to 1994.
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 resulted in
substantially lower utilization of purchased power resources. Energy
purchases decreased by approximately 43% from 1993 levels.
Purchased power expense for 1993 through 1995 reflect the cost of
capacity and energy purchases under various long-term power purchase
agreements. These long-term agreements have, in some cases, take-or-pay
minimum energy requirements. For 1993 through 1995, Oglethorpe utilized its
energy from these purchase power agreements in excess of the take-or-pay
requirements. Oglethorpe's power purchases from these agreements amounted to
approximately $207 million in 1995, $182 million in 1994 and $192 million in
1993. For a discussion of the power purchase agreements, see Note 9 of Notes
to Financial Statements.
The increase in depreciation and amortization in 1995 is due to the
commercial operation of Rocky Mountain in June.
Sales, administrative and general expenses increased in 1995 primarily as
a result of increased marketing efforts in support of Oglethorpe's Members.
OTHER INCOME
Interest income increased in 1995 compared to 1994 due to higher earnings
from the decommissioning trust fund. In 1994, interest income decreased
compared to 1993 as a result of lower average investment balances.
In 1995, 1994 and 1993, Oglethorpe's Board of Directors authorized the
retention of approximately $14 million, $9 million and $5 million,
respectively, in excess of the 1.07 TIER margin requirement as deferred
margins. The remaining amount at December 31, 1995 of $32 million will be
available in 1996 to mitigate rate increases. Amortization of deferred
margins for 1995 was $16 million, slightly less than the amount utilized in
1994 but significantly more than the amount utilized in 1993. (See Note 1 of
Notes to Financial Statements for a discussion of deferred margins and
amortization of deferred margins.) The decrease in
30
<PAGE>
amortization of deferred gains resulted from the completion of amortization in
September 1994 of a gain on the sale of Plant Scherer common facilities. (Also
see Note 1 of Notes of Financial Statements for a discussion of the sale.)
INTEREST CHARGES
Net interest charges increased in 1995 compared to 1994 and decreased
significantly in 1994 compared to 1993. The continued decrease in gross
interest on long-term debt and capital leases in 1995 and 1994 was due to the
refinancing efforts discussed under "Financial Condition--REFINANCING
TRANSACTIONS" below. Allowance for debt and equity funds used during
construction (AFUDC) decreased in 1995 compared to 1994 as a result of the
three units of Rocky Mountain becoming commercially operable in June and July
1995. The change in other interest expense in 1995 was due to gains received
on the sale of securities contained in the decommissioning trust fund,
whereas, the decrease in 1994 was primarily due to losses incurred on the
sale of securities contained in the decommissioning trust fund. (See Note 1
of Notes to Financial Statements for explanation of Oglethorpe's accounting
for decommissioning gains and losses.)
FACTORS AFFECTING FUTURE FINANCIAL PERFORMANCE
Future Member rates will be affected by such factors as the annualized
fixed costs relating to 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. Also, see "Proposed Restructuring" below for a
discussion of Oglethorpe's proposed restructuring.
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 legislative developments and regulatory
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.
As a means of reducing the cost of power provided to the Members, on
January 3, 1996, Oglethorpe entered into a power supply swap agreement with
Enron Power Marketing, Inc. (EPMI). The agreement, effective January 4, 1996
through April 30, 1996, requires EPMI to sell to Oglethorpe at a favorable
fixed cost all the energy needed to serve the Members (approximately 5.2
million MWh). Pursuant to the agreement, Oglethorpe is required to sell to
EPMI at cost, subject to certain limitations, all available energy from
Oglethorpe's total power resources. EPMI has the option to market any excess
energy that remains from Oglethorpe's total power resources.
On February 7, 1996, Oglethorpe issued a Request for Proposals (RFP) to
selected bidders for a long-term power supply arrangement. This RFP did not
seek a specific amount of power; instead, it requested proposals for meeting
the combined power needs of the Members with term options ranging from two to
15 years. Action is anticipated by Oglethorpe's Board of Directors during
April, with implementation of a new arrangement as soon thereafter as possible.
FINANCIAL CONDITION
GENERAL
The principal changes in Oglethorpe's financial condition in 1995 were
additions of $599 million to gross utility plant and a decrease in the cost
of capital achieved through the refinancing or prepayment of $336 million of
long-term debt during 1995 and an additional $89 million in January 1996.
The average interest rate on long-term debt decreased from 7.07% at December
31, 1994 to 6.60% at January 31, 1996.
CAPITAL REQUIREMENTS
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
listed below because of factors such as changes in business conditions,
fluctuating rates of load growth, environmental requirements, design changes
and rework required by regulatory bodies, delays in obtaining necessary
Federal and other regulatory approvals, construction delays, and cost of
capital, equipment, material and labor. The table below indicates
Oglethorpe's estimated capital expenditures through 1998:
CAPITAL EXPENDITURES
(DOLLARS IN THOUSANDS)
<TABLE>
<CAPTION>
GENERAL
YEAR GENERATION(1) TRANSMISSION(2) PLANT AFUDC(3) TOTAL
- -----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1996 $60,640 $ 44,795 $ 4,499 $3,466 $113,400
1997 60,682 39,004 4,000 2,428 106,114
1998 56,703 40,564 4.000 2,086 103,353
-------- -------- ------- ------ --------
Total $178,025 $124,363 $12,499 $7,980 $322,867
-------- -------- ------- ------ --------
-------- -------- ------- ------ --------
</TABLE>
(1) Consists of capital expenditures required for (i) replacements and
additions to facilities in service, (ii) compliance with environmental
regulations, and (iii) nuclear fuel reloads.
(2) If the transmission assets are transferred to a new transmission
corporation, the new transmission corporation, and not Oglethorpe, would be
responsible for the transmission capital expenditures and related AFUDC. (See
"Proposed Restructuring" below)
(3) Allowance for funds used during construction of generation, transmission
and general plant facilities.
31
<PAGE>
In 1988, Oglethorpe acquired from GPC an undivided ownership interest in
Rocky Mountain and assumed responsibility for its construction and operation.
By July 1995, all three units of Rocky Mountain were in-service and
Oglethorpe's investment in the project at December 31, 1995 was $565 million,
including related transmission facilities. Construction of Rocky Mountain's
recreational facilities is still in progress and should be completed in the
summer of 1996. Oglethorpe expects the final project cost to be
approximately $570 million, or more than $130 million under budget.
Oglethorpe financed its share of Rocky Mountain from the proceeds of an
RUS-guaranteed loan funded by the FFB. As of December 31, 1995, $555 million
had been advanced under this loan. Oglethorpe expects to draw the additional
$15 million to close out the project in 1996.
Currently, Oglethorpe does not have any new generation facilities under
construction, and management does not anticipate the need for construction of
any new capacity well into the future. The System peaking capacity needs
through the early 2000 time frame are expected to be met through purchased
power alternatives. (See discussion of the Member's future power supply
options under "Proposed Restructuring" and Oglethorpe's current request for
proposals under "Results of Operations--FACTORS AFFECTING FUTURE FINANCIAL
PERFORMANCE".)
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $4.5 billion as of December 31, 1995. Expenditures for
property additions during 1995 amounted to $139 million, of which $6 million
was provided from operations. These expenditures were primarily for the
construction of Rocky Mountain and replacements and additions to generation
and transmission facilities.
In addition to the funds needed for capital expenditures, approximately
$541 million will be required over the next five years for sinking fund
requirements and maturities of long-term debt. Of this amount, $424 million,
or 78%, relates to the repayment of RUS and FFB debt.
LIQUIDITY AND SOURCES OF CAPITAL
In the past, Oglethorpe, like most other G&Ts, has obtained the majority
of its long-term financing from RUS-guaranteed loans funded by the FFB.
Oglethorpe has also obtained a substantial portion of its long-term financing
requirements from tax-exempt PCBs.
In addition, Oglethorpe's operations have consistently provided a sizable
contribution to the funding of capital requirements, such that internally
generated funds have provided interim funding or long-term capital for
nuclear fuel reloads, new generation, transmission and general plant
facilities, replacements and additions to existing facilities, and retirement
of long-term debt. Oglethorpe anticipates that it will meet its future
capital requirements through 1998 primarily with funds generated from
operations and, if necessary, with short-term borrowings.
To meet short term cash needs and contingencies, Oglethorpe had
approximately $201 million in cash and temporary cash investments plus $79
million in other short term investments available at the beginning of 1996.
The Corporation also has available credit facilities as follows:
<TABLE>
<CAPTION>
SHORT-TERM CREDIT FACILITIES AUTHORIZED
AMOUNT
- ---------------------------------------------------------
<S> <C>
Commercial Paper.......................... $300,000,000
Committed lines of credit:
SunTrust Bank, Atlanta .................. 30,000,000
Uncommitted lines of credit:
CoBank, ACB.............................. 70,000,000
National Rural Utilities Cooperative
Finance Corporation (CFC)............... 50,000,000
</TABLE>
Under its commercial paper program, Oglethorpe may issue commercial paper
not to exceed $300 million outstanding at any one time. The commercial
paper, which is backed 100% by committed lines of credit provided by a group
of banks, may be used as a source of short-term funds and is not designated
for any specific purpose. Historically, Oglethorpe has not relied on
commercial paper for short-term funding due to the availability of internally
generated funds and has never utilized the backup line of credit.
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 SunTrust Bank and CFC line of credit
agreements. As of December 31, 1995, no commercial paper was outstanding and
there was no outstanding balance on any line of credit.
REFINANCING TRANSACTIONS
Over the past few years, Oglethorpe has implemented a program to reduce its
interest costs by refinancing or prepaying a sizable portion of its
high-interest rate PCB and FFB debt. Since the first transaction was completed
in June 1992, Oglethorpe has refinanced $1.1 billion in PCB debt and $1.2
billion in FFB debt and has prepaid another $105 million in FFB debt. Included
in these amounts are a January 1995 refinancing of $285 million of FFB debt and
prepayment of an additional $30 million of FFB debt, and a December 1995
refinancing of $22 million of PCB debt. (See Note 5 of Notes to Financial
Statements.) The net result of the 1995 transactions was to reduce the average
interest rate on total long-term debt from 7.07% at December 31, 1994 to 6.76%
at December 31, 1995. The average interest rate was further reduced to 6.60%
as of January 31, 1996 as a result of a $89 million FFB debt refinancing. The
refinancings completed since the program began will result in total estimated
savings of $90 million in gross interest expense and $80 million in net
interest expense (net of transaction costs) in 1996.
Oglethorpe's use of financial derivatives are for the purpose of
mitigating business risks and are not used for speculative purposes.
Derivatives have been used on a very limited basis, as discussed below, and
at December 31, 1995, the credit risk for derivatives outstanding was not
material.
To refinance high-interest rate PCBs, Oglethorpe entered into two
interest rate swap transactions with a swap counterparty, AIG
32
<PAGE>
Financial Products Corp. (AIG-FP), which were designed to create a
contractual fixed rate of interest on $322 million of variable rate PCBs.
These transactions were entered into in early 1993 on a forward basis,
pursuant to which $200 million of variable rate PCBs were issued on November
30, 1993 and $122 million of variable rate PCBs were issued on December 1,
1994. Oglethorpe is obligated to pay the variable interest rate that accrues
on these PCBs; however, the swap agreements provide a mechanism for
Oglethorpe to achieve a contractual fixed rate which is lower than Oglethorpe
would have obtained had it issued fixed rate bonds.
Under the swap agreements, Oglethorpe is obligated to make periodic
payments to AIG-FP based on a notional principal amount equal to the
aggregate principal amount of the bonds outstanding during the period and a
contractual fixed rate (Fixed Rate), and AIG-FP is obligated to make periodic
payments to Oglethorpe on a notional principal amount equal to the aggregate
principal amount of the bonds outstanding during the period and a variable
rate equal to the variable rate of interest accruing on the bonds during the
period (Variable Rate). These payment obligations are netted, such that if
the Variable Rate is less than the Fixed Rate, Oglethorpe makes a net payment
to AIG-FP. Likewise, if the Variable Rate is higher than the Fixed Rate,
Oglethorpe receives a net payment from AIG-FP. Thus, although changes in the
Variable Rate affects whether Oglethorpe is obligated to make payments to
AIG-FP or is entitled to receive payments from AIG-FP, the effective interest
rate Oglethorpe pays with respect to the PCBs is not affected by changes in
interest rates. The Fixed Rate for the $200 million of variable rate bonds
issued in 1993 is 5.67% and the Fixed Rate for the $122 million of variable
rate bonds issued in 1994 is 6.01%. For the three years ended December 31,
1993, 1994 and 1995, Oglethorpe has made in connection with both interest
rate swap arrangements combined net swap payments to AIG-FP of $0.6 million,
$6.0 million, and $6.4 million, respectively, totaling $13.0 million for such
three-year period.
The swap arrangements extend for the life of these PCBs. If the swap
arrangements were terminated while the PCBs were still outstanding,
Oglethorpe or AIG-FP may owe the other party a termination payment depending
on a number of factors, including whether the fixed rate then being offered
under comparable swap arrangements is higher or lower than the Fixed Rate.
Under the terms of the swap agreements, AIG-FP has limited rights to
terminate the swaps only upon the occurrence of specified events of default
or a reduction in ratings on Oglethorpe's PCBs without credit enhancement
below investment grade. Oglethorpe estimates that its maximum aggregate
liability for termination payments under both swap arrangements had such
payments been due on December 31, 1995 would have been approximately $52
million. (For additional information about the swap arrangements, see Note 2
of Notes to Financial Statements.)
In connection with these interest rate swap agreements, Oglethorpe is
obligated to maintain minimum liquidity in an amount equal to 25% of the
principal amount of the variable rate refunding bonds outstanding. This
minimum liquidity requirement currently equals $81 million and will decrease
proportionately as such bonds are retired. 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 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, 1995, Oglethorpe had approximately $518 million of such
liquidity available to meet this requirement.
PROPOSED RESTRUCTURING
For some time, Oglethorpe and the Members have been discussing various
options to provide the Members greater flexibility for meeting their power
supply needs in an increasingly competitive utility environment. These
discussions led to a restructuring plan approved by Oglethorpe's Board of
Directors in December 1995 to divide Oglethorpe into three specialized
companies to respond to increasing competition in the electric industry
and to settle certain issues confronting Oglethorpe and the Members,
including several Members' previously stated intention to withdraw from
membership in Oglethorpe in order to gain more flexibility. The December
plan proposed the creation of a new transmission company and a new system
operations company and Oglethorpe's retention of the generation business.
Oglethorpe's Board believes there are significant potential benefits to the
Members of having the transmission business and the system operations
business operated in separate companies. Among the principal benefits is that
the Members' freedom to choose among power suppliers, including Oglethorpe,
for their future growth would be enhanced.
The current target date for full implementation of the
restructuring is January 1, 1997. As a preliminary step, Georgia
Transmission Corporation (An Electric Membership Corporation) (GTC) has been
incorporated for future use as the transmission company and Georgia System
Operations Corporation (GSOC) has been incorporated as a Georgia non-profit
corporation for future use as the system operations company. On March 29,
1996, the Boards of Oglethorpe, GTC and GSOC approved an agreement (the
Restructuring Agreement) which sets forth the terms and conditions on which the
restructuring and related changes would occur. The Restructuring Agreement
contemplates that Oglethorpe would operate primarily as a power supply
company, but initially would retain economic development, marketing and
service functions.
Oglethorpe would transfer its transmission business, including its existing
transmission assets, to GTC. GTC would thereafter own and operate the
transmission system and provide transmission services to the Members,
Oglethorpe and third parties. (See Note 6 of Notes to Financial Statements
for a summary of Oglethorpe's investments in electric plant, including
transmission and distribution plant.) The purchase price for the
transmission business would be equal to the sum of (1) the higher of: (a) the
appraised fair market value of such business as determined by an independent
appraiser, or (b) Oglethorpe's net book value for the transmission assets,
plus (2) the value of certain deferred charges. If the appraised value of
the transmission business exceeds Oglethorpe's net book value for the
transmission assets by more than 5%, GTC's Board would have to approve the
payment of any resulting purchase price. The purchase price would be paid by
GTC's assumption of a portion of
33
<PAGE>
Oglethorpe's long-term secured debt and by cash obtained through third party
borrowing. Oglethorpe also would make a special patronage capital
distribution to the Members which could be used by the Members to
establish equity in and to provide initial working capital to GTC.
Oglethorpe would transfer its system operations business, consisting of
its operations center and related computer and dispatch equipment, to GSOC.
GSOC would thereafter own and operate the operations center and provide system
operation services to the Members, Oglethorpe, GTC and third parties.
Oglethorpe also plans to implement a new governance structure when: (a)
it receives a favorable ruling from the Internal Revenue Service that such
structure would not affect Oglethorpe's status for federal income tax purposes
as a corporation operating on a cooperative basis, and (b) a new rate
schedule which allocates to each Member responsibility for a specified
percentage of all costs of Oglethorpe's existing resources becomes legally
binding and effective. It is contemplated that the new governance structure
would become effective at the same time as the restructuring, although it is
possible that it could become effective independent of the restructuring.
The new governance structure provides for a board of directors consisting of
six directors elected from the Members, four independent outside directors and
Oglethorpe's President and Chief Executive Officer, rather than Oglethorpe's
current 39-member board which is comprised of directors nominated by each
Member. To be elected, the new directors must be nominated by a committee
composed of a representative from each Member whose vote would be weighted in
accordance with the number of retail customers served by such Member and then
elected by a vote of the Members on a one-member, one-vote basis.
In adopting the Restructuring Agreement, Oglethorpe's Board recommended to
the Members that they become members of GTC and GSOC and that they join with
Oglethorpe, GTC and GSOC in executing an agreement (the Member Agreement) as to
those matters contemplated in the Restructuring Agreement that directly involve
the Members in their capacities as separate corporations. The Member Agreement
will specify the form of transmission contracts and system operation contracts
to be signed by the Members. The Member Agreement will also provide, subject to
the approval of RUS, that Oglethorpe and each Member executing the Member
Agreement would execute a new wholesale power contract to govern the purchase
and sale of power between Oglethorpe and each such Member. Each Member signing
the new wholesale power contract would have a choice as to whether or not to
participate in future power supply projects sponsored by Oglethorpe. Such
Members would be free to own generation directly and to engage in purchases and
sales with other power suppliers. To the extent such Members choose to satisfy
their projected load growth from sources other than Oglethorpe, the growth in
Oglethorpe's revenues from the sale of power would decrease but the growth in
related expenses also would decrease.
Members agreeing to the new wholesale power contracts would have the
option to have energy and reserves priced on a pooled basis or to schedule
their capacity and associated energy separately at prices based on the cost
of production. GSOC would administer the new power pool contemplated by the
new wholesale power contracts and would implement the separate schedules for
Members electing that option. Under the power pool, Oglethorpe resources and
any Member-procured resources would be committed to economic dispatch (pooled)
for the benefit of all pool participants. The power pool arrangement also
would allow the participants to pool resource reserves.
In connection with the restructuring, Oglethorpe plans to adopt 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 generally would require the withdrawing
Member either to affirm its obligations under its then-existing wholesale
power contract or to assign its rights and obligations under such wholesale
power contract to another party with a credit rating meeting certain
specified requirements. Withdrawal by a Member would continue to be
conditioned upon approval by RUS.
The restructuring is subject to a number of conditions, including (1)
implementation of Oglethorpe's new governance structure, (2) execution of the
Member Agreement by the Members, execution of new wholesale power contracts
by Oglethorpe and the Members, and execution of the transmission contracts
and system operation contracts specified in the Member Agreement, (3) RUS
approval of new wholesale power contracts and the restructuring, (4)
governmental, lender and other third party consents, authorizations, waivers,
orders and approvals, (5) receipt by GTC and GSOC of certain capital
contributions by the Members and (6) assurances from rating agencies that the
ratings on Oglethorpe's outstanding fixed rate PCBs would not be lowered as a
result of the restructuring and that such rating agencies would assign to any
comparable bonds issued by GTC the same or better credit rating as assigned
to Oglethorpe's fixed rate PCBs. Most of these conditions may be waived by
Oglethorpe's Board, subject to RUS approval in certain instances.
The restructuring is expected to take the remainder of 1996 to complete,
although limited aspects of the restructuring may become effective sooner if
specific conditions set forth in the Restructuring Agreement are met. In
light of the significant conditions that must be satisfied, including RUS
and other governmental and third-party approvals and assurances and receipt
of various agreements from the Members, Oglethorpe cannot predict the actual
timing of or the ultimate likelihood of full implementation of the
restructuring or governance changes. Until implementation of the
restructuring, Oglethorpe will continue its current operations, and until
satisfaction of the conditions applicable to the new governance
structure, Oglethorpe will continue under its existing governance structure.
34
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Statements of Revenues and Expenses, For the Years Ended
December 31, 1995, 1994 and 1993................................. 36
Statements of Patronage Capital, For the Years Ended
December 31, 1995, 1994 and 1993................................. 36
Balance Sheets, As of December 31, 1995 and 1994................... 37
Statements of Capitalization, As of December 31, 1995 and 1994..... 39
Statements of Cash Flows, For the Years Ended December 31, 1995,
1994 and 1993.................................................... 40
Notes to Financial Statements...................................... 41
Report of Management............................................... 51
Reports of Independent Public Accountants.......................... 51
35
<PAGE>
STATEMENTS OF REVENUES AND EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
.........................................................................................................
(dollars in thousands)
1995 1994 1993
<S> <C> <C> <C>
OPERATING REVENUES (NOTE 1):
Sales to Members..................................... $1,030,797 $ 930,875 $ 899,720
Sales to non-Members................................. 118,764 125,207 200,940
---------- ---------- ----------
TOTAL OPERATING REVENUES............................... 1,149,561 1,056,082 1,100,660
---------- ---------- ----------
OPERATING EXPENSES:
Fuel................................................. 219,062 203,444 176,342
Production........................................... 133,858 132,723 129,972
Purchased power (Note 9)............................. 264,844 227,477 271,970
Power delivery....................................... 17,520 16,965 14,286
Sales, administrative and general.................... 39,015 32,269 30,590
Depreciation and amortization........................ 139,024 131,056 128,060
Taxes other than income taxes........................ 27,561 24,741 23,328
Income taxes (Note 3)................................ -- -- 1,820
---------- ---------- ----------
TOTAL OPERATING EXPENSES............................... 840,884 768,675 776,368
---------- ---------- ----------
OPERATING MARGIN....................................... 308,677 287,407 324,292
---------- ---------- ----------
OTHER INCOME (EXPENSE):
Interest income...................................... 18,031 10,518 20,316
Amortization of deferred gains (Notes 1 and 4)....... 2,341 9,985 12,532
Amortization of proceeds from sale of income tax
benefits (Note 1).................................. 8,043 8,102 8,102
Amortization of deferred margins (Note 1)............ 15,959 18,072 4,138
Deferred margins (Note 1)............................ (14,282) (9,287) (5,083)
Allowance for equity funds used during
construction (Note 1).............................. 1,715 2,907 2,278
Other................................................ 1,903 498 (3,542)
---------- ---------- ----------
TOTAL OTHER INCOME..................................... 33,710 40,795 38,741
---------- ---------- ----------
INTEREST CHARGES:
Interest on long-term debt and capital leases........ 317,968 329,738 367,439
Other interest....................................... 12,979 3,856 8,539
Allowance for debt funds used during construction
(Note 1)............................................ (21,114) (36,113) (29,988)
Amortization of debt discount and expense............ 10,296 7,639 4,662
---------- ---------- ----------
NET INTEREST CHARGES................................... 320,129 305,120 350,652
---------- ---------- ----------
MARGIN BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE.................................. 22,258 23,082 12,381
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR
INCOME TAXES ......................................... -- -- 13,340
---------- ---------- ----------
NET MARGIN ............................................ $ 22,258 $ 23,082 $ 25,721
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
STATEMENTS OF PATRONAGE CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
(dollars in thousands)
1995 1994 1993
.........................................................................................................
<S> <C> <C> <C>
Patronage capital and membership fees - beginning
of year (Note 1)..................................... $ 309,496 $ 289,982 $ 264,261
Net margin............................................. 22,258 23,082 25,721
Change in unrealized gain (loss) on available-for-sale
securities, net of income taxes (Note 2)............. 7,137 (3,568) --
--------- --------- ---------
Patronage capital and membership fees-end of year...... $ 338,891 $ 309,496 $ 289,982
--------- --------- ---------
--------- --------- ---------
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
36
<PAGE>
BALANCE SHEETS
DECEMBER 31, 1995 AND 1994
<TABLE>
<CAPTION>
........................................................................................
(dollars in thousands)
ASSETS 1995 1994
<S> <C> <C>
ELECTRIC PLANT (NOTES 1, 4 AND 6):
In service............................................ $ 5,699,213 $ 5,100,299
Less: Accumulated provision for depreciation.......... (1,362,431) (1,231,818)
----------- -----------
4,336,782 3,868,481
Nuclear fuel, at amortized cost....................... 94,013 105,683
Plant acquisition adjustments, at amortized cost...... 5,214 6,275
Construction work in progress......................... 35,753 538,789
----------- -----------
4,471,762 4,519,228
----------- -----------
INVESTMENTS AND FUNDS (NOTES 1 AND 2):
Bond, reserve and construction funds, at market....... 56,511 64,163
Decommissioning fund, at market....................... 74,492 59,164
Investment in associated organizations, at cost....... 15,853 17,371
----------- -----------
146,856 140,698
----------- -----------
CURRENT ASSETS:
Cash and temporary cash investments, at cost (Note 1). 201,151 190,642
Other short-term investments, at market............... 79,165 --
Receivables........................................... 99,559 88,873
Inventories, at average cost (Note 1)................. 82,949 95,076
Prepayments and other current assets.................. 14,325 14,857
----------- -----------
477,149 389,448
----------- -----------
DEFERRED CHARGES:
Premium and loss on reacquired debt, being amortized
(Note 5)............................................. 200,794 161,889
Deferred amortization of Scherer leasehold (Note 4)... 87,134 80,132
Discontinued projects, being amortized (Note 1)....... 24,305 26,342
Deferred debt expense, being amortized................ 21,135 20,936
Other................................................. 9,361 7,657
----------- -----------
342,729 296,956
----------- -----------
$ 5,438,496 $ 5,346,330
----------- -----------
----------- -----------
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE BALANCE SHEETS.
37
<PAGE>
<TABLE>
<CAPTION>
........................................................................................
(dollars in thousands)
EQUITY AND LIABILITIES 1995 1994
<S> <C> <C>
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Patronage capital and membership fees (Note 1)....... $ 338,891 $ 309,496
Long-term debt....................................... 4,207,320 4,128,080
Obligation under capital leases (Note 4)............. 296,478 303,749
----------- -----------
4,842,689 4,741,325
----------- -----------
CURRENT LIABILITIES:
Long-term debt and capital leases due within one
year................................................ 89,675 90,086
Deferred margins and Vogtle surcharge to be
refunded within one year (Note 1)................... 32,047 19,279
Accounts payable..................................... 48,855 52,921
Accrued interest..................................... 91,096 100,010
Accrued and withheld taxes........................... 1,785 1,566
Other current liabilities............................ 18,007 18,177
----------- -----------
281,465 282,039
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Gain on sale of plant, being amortized (Note 4)...... 60,868 63,209
Sale of income tax benefits, being amortized
(Note 1)............................................ 50,194 58,236
Accumulated deferred income taxes (Note 3)........... 65,510 65,510
Deferred margins and Vogtle surcharge (Note 1)....... -- 17,765
Decommissioning reserve (Note 1)..................... 114,049 96,291
Other................................................ 23,721 21,955
----------- -----------
314,342 322,966
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTES 4, 9 AND 10)
$5,438,496 $5,346,330
----------- -----------
----------- -----------
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE BALANCE SHEETS.
38
<PAGE>
STATEMENTS OF CAPITALIZATION
DECEMBER 31, 1995 AND 1994
<TABLE>
<CAPTION>
........................................................................................
(dollars in thousands)
1995 1994
<S> <C> <C>
LONG-TERM DEBT (NOTE 5):
Mortgage notes payable to the Federal Financing
Bank (FFB) at interest rates varying from 5.67% to
10.78% (average rate of 7.19% at December 31,
1995) due in quarterly installments through 2023 ..... $ 3,253,636 $ 3,161,550
Mortgage notes payable to the Rural Utilities
Service (RUS) at an interest rate of
5% due in monthly installments through 2021........... 22,983 23,467
Mortgage notes issued in conjunction with the sale by
public authorities of pollution control revenue bonds:
- Series 1982
Serial bonds, 10.20% to 10.60%, due serially
through 1997......................................... 6,675 16,135
- Series 1992
Term bonds, 7.50% to 8.00%, due 2003 to 2022.......... 92,130 92,130
-Series 1992A
Adjustable tender bonds, 3.25% to 3.95%, due 2025..... 216,925 216,925
Serial bonds, 5.10% to 6.80%, due serially from 1997
through 2012......................................... 129,760 139,240
- Series 1993
Serial bonds, 3.30% to 5.25%, due serially from 1996
through 2013......................................... 38,110 39,090
- Series 1993A
Adjustable tender bonds, 5.15%, due 2016.............. 199,690 199,690
- Series 1993B
Serial bonds, 3.55% to 5.05%, due serially from 1997
through 2008......................................... 136,745 155,610
- Series 1994
Serial bonds, 4.90% to 7.125%, due serially from 1996
through 2015......................................... 10,690 10,690
Term bonds, 7.15% due 2021............................ 11,550 11,550
- Series 1994A
Adjustable tender bonds, 5.05%, due 2019.............. 122,740 122,740
- Series 1994B
Serial bonds, 5.20% to 6.45%, due serially from 1997
through 2005......................................... 12,475 13,720
- Series 1995
Adjustable rate bonds, 3.70% to June 1996, due in
2015................................................. 21,670 --
CoBank, ACB notes payable:
- Headquarters note payable: $5.2 million fixed at
6.85% through July 1996, due in quarterly installments
through January 1, 2009 .............................. 5,159 5,549
- Transmission note payable: fixed at 6.85% through
July 1996; due in bimonthly installments through
November 1, 2018...................................... 2,261 2,279
- Transmission note payable: fixed at 6.45% through
November 1996; due in bimonthly installments through
September 1, 2019..................................... 8,637 8,697
----------- -----------
4,291,836 4,219,062
Less:Unamortized debt discount......................... (832) (896)
----------- -----------
Total long-term debt, net.............................. 4,291,004 4,218,166
Less:Long term debt due within one year................ (83,684) (90,086)
----------- -----------
TOTAL LONG-TERM DEBT, EXCLUDING AMOUNT DUE WITHIN
ONE YEAR............................................... 4,207,320 4,128,080
OBLIGATION UNDER CAPITAL LEASES, LONG TERM (NOTE 4)..... 296,478 303,749
PATRONAGE CAPITAL AND MEMBERSHIP FEES (NOTE 1).......... 338,891 309,496
----------- -----------
TOTAL CAPITALIZATION.................................... $ 4,842,689 $ 4,741,325
----------- -----------
----------- -----------
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
39
<PAGE>
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
<TABLE>
<CAPTION>
....................................................................................................................
(dollars in thousands)
1995 1994 1993
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net margin....................................................... $ 22,258 $ 23,082 $ 25,721
---------- ---------- ----------
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................................. 196,920 193,351 180,221
Interest on decommissioning reserve........................... 9,951 1,291 7,356
Amortization of deferred gains ............................... (2,341) (9,985) (12,532)
Deferred margins and amortization of deferred margins......... (1,677) (8,785) 945
Amortization of proceeds from sale of income tax benefits..... (8,043) (8,102) (8,102)
Allowance for equity funds used during construction........... (1,715) (2,907) (2,278)
Deferred income taxes......................................... -- -- 1,625
Other ........................................................ (13) (13) (13)
Change in net current assets, excluding long-term debt due within
one year and deferred margins and Vogtle surcharge to be
refunded within one year:
Receivables................................................... (10,686) (18,055) (24,990)
Inventories................................................... 12,127 (8,608) 7,172
Prepayments and other current assets.......................... 532 (94) 2,369
Accounts payable.............................................. (4,066) (10,569) (2,349)
Accrued interest.............................................. (8,914) (8,692) 49,379
Accrued and withheld taxes.................................... 219 (7,835) 5,741
Other current liabilities..................................... (169) (24,124) 15,542
---------- ---------- ----------
Total adjustments................................................ 182,125 86,873 206,746
---------- ---------- ----------
NET CASH PROVIDED BY OPERATING ACTIVITIES.......................... 204,383 109,955 232,467
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions............................................... (138,921) (206,345) (235,285)
Activity in decommissioning fund - Purchases..................... (410,597) (297,492) --
- Proceeds...................... 399,077 293,990 --
Activity in bond, reserve and construction funds - Purchases..... (27,762) (498,052) --
- Proceeds...... 39,566 540,712 --
Activity in other short-term investments - Purchases............. (76,180) -- --
Increase in decommissioning fund................................. -- -- (8,990)
Net proceeds from bond, reserve and construction funds........... -- -- 53,574
Decrease in investment in associated organizations............... 1,518 1,752 786
Decrease (increase) in other short-term investments.............. -- -- 66,165
Other............................................................ -- -- 158
---------- ---------- ----------
NET CASH USED IN INVESTING ACTIVITIES.............................. (213,299) (165,435) (123,592)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Debt proceeds, net............................................... 132,874 523,518 232,675
Debt payments.................................................... (108,481) (517,530) (369,962)
Return of Vogtle surcharge....................................... (3,320) (2,031) (1,600)
Other............................................................ (1,648) (2,008) (1,439)
---------- ---------- ----------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES................ 19,425 1,949 (140,326)
---------- ---------- ----------
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS..... 10,509 (53,531) (31,451)
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR........... 190,642 244,173 275,624
---------- ---------- ----------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR................. $ 201,151 $ 190,642 $ 244,173
---------- ---------- ----------
---------- ---------- ----------
CASH PAID FOR:
Interest (net of amounts capitalized)............................ $ 308,797 $ 304,882 $ 289,255
Income taxes..................................................... -- -- 1,658
</TABLE>
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
40
<PAGE>
NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
..............................................................................
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. BUSINESS DESCRIPTION
Oglethorpe Power Corporation (Oglethorpe) is an electric generation and
transmission (G&T) cooperative incorporated in 1974 and headquartered in
suburban Atlanta. Oglethorpe provides wholesale electric service, on a not-for-
profit basis, to 39 of Georgia's 42 Electric Membership Corporations (EMCs).
These 39 electric distribution cooperatives (Members) in turn distribute energy
on a retail basis to more than 2.6 million people across two-thirds of the
State. Oglethorpe is the nation's largest G&T in terms of operating revenues,
assets, kilowatt-hour sales and, through its Members, consumers served.
Oglethorpe supplies energy to the Members from 3,335 megawatts (MW) of owned
or leased generating capacity and purchases the remainder from other power
suppliers. Oglethorpe also has access to over 16,000 miles of transmission line
through its ownership in the statewide Integrated Transmission System.
B. BASIS OF ACCOUNTING
Oglethorpe follows generally accepted accounting principles and the practices
prescribed in the Uniform System of Accounts of the Federal Energy Regulatory
Commission (FERC) as modified and adopted by the Rural Utilities Service (RUS),
formerly known as the Rural Electrification Administration (REA).
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities as of December 31, 1995 and 1994 and the
reported amounts of revenues and expenses for each of the three years ending
December 31, 1995. Actual results could differ from those estimates.
C. PATRONAGE CAPITAL AND MEMBERSHIP FEES
Oglethorpe is organized and operates as a cooperative. The Members paid a
total of $195 in membership fees. Patronage capital is the retained net margin
of Oglethorpe. As provided in the bylaws, any excess of revenue over
expenditures from operations is treated as advances of capital by the Members
and is allocated to each of them on the basis of their electricity purchases
from Oglethorpe.
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.
D. 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.
Pursuant to this policy, the annual net margin goal for 1995, 1994 and 1993 was
the amount required to produce a TIER of 1.07.
The Oglethorpe Board of Directors adopted resolutions annually requiring that
Oglethorpe's net margins for the years 1985 through 1995 in excess of its annual
margin goals be deferred and used to mitigate rate increases associated with
Plant Vogtle and Rocky Mountain. In addition, during 1986 and 1987, Oglethorpe's
wholesale electric rate to its Members provided for a one mill per kilowatt-hour
charge (Vogtle Surcharge), also to be used to mitigate the effect of Plant
Vogtle on rates.
Pursuant to rate actions by Oglethorpe's Board of Directors, specified
amounts of deferred margins and Vogtle Surcharge were returned in 1989
through 1995 and all remaining amounts will be returned in 1996. A summary of
deferred margins and Vogtle Surcharge as of December 31, 1995 and 1994 is as
follows:
<TABLE>
<CAPTION>
...................................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...................................................................................
<S> <C> <C>
DEFERRED MARGINS
1985-92 $ 165,552 $ 165,552
1993 5,083 5,083
1994 9,287 9,287
1995 14,282 --
--------- ---------
194,204 179,922
VOGTLE SURCHARGE
1986-87 36,613 36,613
--------- ---------
Subtotal 230,817 216,535
Less: Amounts returned in:
1989-92 (153,650) (153,650)
1993 (5,738) (5,738)
1994 (20,103) (20,103)
1995 (19,279) --
--------- ---------
32,047 37,044
Less: Current portion (32,047) (19,279)
--------- ---------
Long-term balance $ -- $ 17,765
--------- ---------
--------- ---------
...................................................................................
</TABLE>
E. OPERATING REVENUES
Operating revenues consist primarily of electricity sales pursuant to
long-term wholesale power contracts which Oglethorpe maintains with each of
its Members. These wholesale power contracts obligate each Member to pay
Oglethorpe for capacity and energy furnished in accordance with rates
established by Oglethorpe. Energy furnished is determined based on meter
readings which are conducted at the end of each month.
Revenues from Cobb EMC and Jackson EMC, two of Oglethorpe's Members,
accounted for 11.3% and 10.4% in 1995, and 11.0% and 10.5% in 1994 of
Oglethorpe's total operating
41
<PAGE>
revenues. In 1993, Cobb EMC accounted for 10.3% of Oglethorpe's total operating
revenues.
Sales to non-Members consist partly of revenues from energy sales to non-
Member utilities other than Georgia Power Company (GPC) and partly of capacity
and energy sales to 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 purchased through 1995 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:
<TABLE>
<CAPTION>
...................................................................................
Fractional Part of Capacity and Energy Retained
by GPC during Contract Year Ended May 31
Generating Unit 1996 1995 1994 1993
...................................................................................
<S> <C> <C> <C> <C>
Plant Scherer,
Unit No. 2 -- -- -- 6/60
Plant Vogtle,
Unit No. 1 -- -- 4/30 8/30
Plant Vogtle,
Unit No. 2 -- 4/30 8/30 11/30
...................................................................................
</TABLE>
Pursuant to these sell-back agreements and to other contractual
arrangements with GPC, revenues from GPC accounted for approximately 6%, 8%,
and 15% of Oglethorpe's total operating revenues in 1995, 1994, and 1993,
respectively.
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 1995, 1994 and 1993 amounted to $54,588,000, $55,229,000 and
$49,647,000, 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 $16,200,000, which is being amortized to nuclear fuel
expense over the next 12 years. Oglethorpe has also recorded, net of
sell-back, an obligation to DOE which approximated $13,000,000 at December
31, 1995.
G. NUCLEAR DECOMMISSIONING
Oglethorpe's portion of the costs of decommissioning
co-owned nuclear facilities is estimated as follows:
<TABLE>
<CAPTION>
...................................................................................
(DOLLARS IN THOUSANDS) Hatch Hatch Vogtle Vogtle
Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2
...................................................................................
<S> <C> <C> <C> <C>
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
...................................................................................
</TABLE>
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 1995, 1994 and 1993 was
$4,156,000, $5,948,000 and $5,948,000, respectively. In developing the amount
of the annual provision for 1995 and 1996, the escalation rate was assumed to
be 3.5% and return on trust assets was assumed to be 8%. Oglethorpe accounts
for this provision for decommissioning as depreciation expense with an
offsetting credit to a decommissioning reserve. Oglethorpe's management is of
the opinion that any changes in cost estimates of decommissioning will be
fully recovered in future rates.
In compliance with a Nuclear Regulatory Commission (NRC) regulation,
Oglethorpe maintains an external trust fund to provide for a portion of the cost
of decommissioning its nuclear facilities. The NRC regulation requires funding
levels based on average expected cost to decommission only the radioactive
portions of a typical nuclear facility. Oglethorpe's decommissioning reserve
reflects its obligation to decommission both the radioactive and 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.
42
<PAGE>
H. DEPRECIATION
Depreciation is computed on additions when they are placed in service using
the composite straight-line method. Annual depreciation rates in effect in 1995,
1994 and 1993 were as follows:
<TABLE>
<CAPTION>
...................................................................................
1995 1994 1993
...................................................................................
<S> <C> <C> <C>
Steam production 2.13% 2.47% 2.66%
Nuclear production 2.78% 2.84% 2.83%
Hydro production 2.00% 2.00% 2.00%
Other production 3.75% 2.42% 1.09%
Transmission 2.75% 2.75% 2.75%
Distribution 2.88% 2.88% 2.88%
General 2.00-20.00% 2.00-20.00% 2.00-17.00%
...................................................................................
</TABLE>
I. ELECTRIC PLANT
Electric plant is stated at original cost, which is the cost of the plant
when first dedicated to public service, plus the cost of any subsequent
additions. Cost includes an allowance for the cost of equity and debt funds
used during construction. The cost of equity and debt funds is calculated at
the embedded cost of all such funds. The plant acquisition adjustments
represent the excess of the cost of the plant to Oglethorpe over the original
cost, less accumulated depreciation at the time of acquisition, and are being
amortized over a ten-year period.
Maintenance and repairs of property and replacements and renewals of items
determined to be less than units of property are charged to expense.
Replacements and renewals of items considered to be units of property are
charged to the plant accounts. At the time properties are disposed of, the
original cost, plus cost of removal, less salvage of such property, is charged
to the accumulated provision for depreciation.
J. 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, 1995 and 1994, substantially all of the funds were invested
in U.S. Government securities.
K. CASH AND TEMPORARY CASH INVESTMENTS
Oglethorpe considers all temporary cash investments purchased with a
maturity of three months or less to be cash equivalents. Temporary cash
investments with maturities of more than three months are classified as other
short-term investments.
L. INVENTORIES
Oglethorpe maintains inventories of fossil fuels for its generation plant
and spare parts for certain of its generation and transmission plant. These
inventories are stated at weighted average cost on the accompanying balance
sheets.
At December 31, 1995 and 1994, fossil fuels inventories were $12,296,000
and $24,225,000, respectively. Inventories for spare parts at December 31,
1995 and 1994 were $70,653,000 and $70,851,000, respectively.
M. ENERGY COST RECOVERY
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 1995, 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 included as an increase or decrease to the receivable from
Members. For 1995 and 1994, the rate 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. As of
December 31, 1994, an overcollection of $2,125,000 existed and was utilized
to reduce Member billings in 1995. Due to the new power supply swap agreement
discussed in Note 10, in 1996, energy cost will be collected from Members on
a current basis. As of December 31, 1995, a cumulative undercollection of
$4,237,000 was owed Oglethorpe and will be collected from Members over the
next 12-month period.
N. DEFERRED CHARGES
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 $15,496,000 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 is amortizing the
accumulated project costs in excess of the current value of the land
purchased. The remaining project costs of $8,808,000 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 1995.
43
<PAGE>
O. DEFERRED CREDITS
In April 1982, Oglethorpe sold to three purchasers certain of the income
tax benefits associated with Scherer Unit No.1 and related common facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act
of 1981. Oglethorpe received a total of approximately $110,000,000 from the
safe harbor lease transactions. Oglethorpe 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.
P. 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, 1995 and 1994:
<TABLE>
<CAPTION>
...............................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...............................................................................
<S> <C> <C>
Premium and loss on reacquired debt $200,794 $161,889
Deferred amortization of Scherer leasehold 87,134 80,132
Discontinued projects 24,305 26,342
Other regulatory assets 9,361 7,657
Sale of income tax benefits (50,194) (58,236)
Deferred margins and Vogtle Surcharge (32,047) (37,044)
Energy costs 4,237 (2,125)
-------- --------
$243,590 $178,615
-------- --------
-------- --------
...............................................................................
</TABLE>
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.
Q. PRESENTATION
Certain prior year amounts have been reclassified to conform with current
year presentation.
2. FAIR VALUE OF FINANCIAL INSTRUMENTS:
A detail of the estimated fair values of Oglethorpe's financial
instruments as of December 31, 1995 and 1994 is as follows:
<TABLE>
<CAPTION>
.....................................................................................
(DOLLARS IN THOUSANDS) 1995 1994
FAIR Fair
COST VALUE Cost Value
.....................................................................................
<S> <C> <C> <C> <C>
CASH AND TEMPORARY
CASH INVESTMENTS:
Commercial paper $ 179,055 $ 179,055 $ 156,192 $ 156,192
Repurchase agreement -- -- 14,087 14,087
Certificates of deposit 20,000 20,000 20,000 20,000
Cash and money market
securities 2,096 2,096 363 363
---------- ---------- ---------- ----------
TOTAL $ 201,151 $ 201,151 $ 190,642 $ 190,642
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
OTHER SHORT TERM INVESTMENTS:
Mutual funds $ 76,180 $ 79,165 $ -- $ --
---------- ---------- ---------- ----------
TOTAL $ 76,180 $ 79,165 $ -- $ --
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
BOND, RESERVE AND
CONSTRUCTION FUNDS:
U. S. Government
securities $ 49,348 $ 49,932 $ 57,141 $ 53,573
Repurchase agreements 6,579 6,579 10,590 10,590
---------- ---------- ---------- ----------
TOTAL $ 55,927 $ 56,511 $ 67,731 $ 64,163
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
DECOMMISSIONING FUND:
U. S. Government
securities $ 23,087 $ 23,568 $ 36,668 $ 35,513
Commercial paper 4,036 4,036 -- --
Corporate bonds 5,875 6,073 4,548 4,388
Equity securities 19,514 21,271 8,605 8,707
Asset-backed securities 12,484 12,614 3,754 3,672
Cash and money market
securities 6,937 6,930 6,884 6,884
---------- ---------- ---------- ----------
TOTAL $ 71,933 $ 74,492 $ 60,459 $ 59,164
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
LONG-TERM DEBT $4,207,320 $4,506,925 $4,128,080 $4,107,751
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
INTEREST RATE SWAP$ $ -- $ 52,089 $ -- $ 6,148
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
.....................................................................................
</TABLE>
The contractual maturities of debt securities available for sale at
December 31, 1995 and 1994, regardless of their balance sheet classification,
are as follows:
<TABLE>
<CAPTION>
.............................................................................................
(DOLLARS IN THOUSANDS) 1995 1994
FAIR Fair
COST VALUE Cost Value
.............................................................................................
<S> <C> <C> <C> <C>
Due within one year $ 21,050 $ 21,300 $ 32,292 $ 31,916
Due after one year through five years 37,172 37,452 48,810 47,065
Due after five years through ten years 27,628 27,966 21,940 19,367
Due after ten years 11,523 12,049 9,659 9,388
-------- -------- -------- --------
$ 97,373 $ 98,767 $112,701 $107,736
-------- -------- -------- --------
-------- -------- -------- --------
.............................................................................................
</TABLE>
Oglethorpe uses the methods and assumptions described below to estimate
the fair value of each class of financial instruments. For cash and temporary
cash investments, the carrying amount approximates fair value because of the
short-term maturity of those instruments. The fair value of Oglethorpe's
long-term debt and the swap arrangements is estimated based on the quoted
market prices for the same or similar issues or on the current rates offered
to Oglethorpe for debt of similar maturities.
Under the interest rate swap arrangements, Oglethorpe makes payments to
the counterparty based on the notional principal at a
44
<PAGE>
contractually fixed rate and the counterparty makes payments to Oglethorpe
based on the notional principal at the existing variable rate of the
refunding bonds. The differential to be paid or received is accrued as
interest rates change and is recognized as an adjustment to interest expense.
Oglethorpe entered into the swap arrangements for the purpose of securing a
fixed rate lower than otherwise would have been available to Oglethorpe had
it issued fixed rate bonds. For the Series 1993A notes, the notional
principal was $199,690,000 and the fixed swap rate is 5.67% (the variable
rate at December 31, 1995 and 1994 was 5.15% and 4.95% respectively). With
respect to the Series 1994A notes, the notional principal was $122,740,000
and the fixed swap rate is 6.01% (the variable rate at December 31, 1995 and
1994 was 5.05% and 4.95%, respectively). The notional principal amount is
used to measure the amount of the swap payments and does not represent
additional principal due to the counterparty. The swap arrangements extend
for the life of the refunding bonds, with reductions in the outstanding
principal amounts of the refunding bonds causing corresponding reductions in
the notional amounts of the swap payments. The estimated fair value of
Oglethorpe's liability under the swap arrangements at December 31, 1995 and
1994 was $52,089,000 and $6,148,000, respectively. This amount represents
payment Oglethorpe would pay if the swap arrangements were terminated.
Oglethorpe may be exposed to losses in the event of nonperformance of the
counterparty, but does not anticipate such nonperformance.
Oglethorpe adopted Statement of Financial Accounting Standards No. 115,
"Accounting for Certain Investments in Debt and Equity Securities," as of
January 1, 1994. Under this Statement, investment securities held by
Oglethorpe are classified as either available-for-sale or held-to-maturity.
Available-for-sale securities are carried at market value with unrealized
gains and losses, net of any tax effect, added to or deducted from patronage
capital. Unrealized gains and losses from investment securities held in the
decommissioning fund, which are also classified as available-for-sale, are
directly added to or deducted from the decommissioning reserve.
Held-to-maturity securities are carried at cost. All realized and unrealized
gains and losses are determined using the specific identification method.
Gross unrealized gains and losses at December 31, 1995 were $6,497,000 and
$368,000, respectively. Gross unrealized gains and losses at December 31,
1994 were $234,000 and $5,050,000, respectively. For 1995 and 1994, proceeds
from sales of available-for-sale securities totaled $438,643,000 and
$834,702,000, respectively. Gross realized gains and losses from the 1995
sales were $5,098,000 and $1,308,000,respectively. Gross realized gains and
losses from the 1994 sales were $1,099,000 and $4,776,000, respectively.
Investments in associated organizations were as follows at December 31,
1995 and 1994:
<TABLE>
<CAPTION>
...........................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...........................................................................
<S> <C> <C>
National Rural Utilities
Cooperative Finance Corp. (CFC) $13,476 $13,476
CoBank, ACB 2,132 3,690
Other 245 205
------- -------
Total $15,853 $17,371
------- -------
------- -------
...........................................................................
</TABLE>
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.
3. INCOME TAXES
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 1995, 1994 and 1993 is shown
as follows:
<TABLE>
<CAPTION>
...................................................................................
(DOLLARS IN THOUSANDS) 1995 1994 1993
...................................................................................
<S> <C> <C> <C>
Current
Federal $ -- $ -- $ --
State -- -- 195
----- ----- -------
-- -- 195
----- ----- -------
Deferred
Federal -- -- 1,820
State -- -- (195)
----- ----- -------
-- -- 1,625
----- ----- -------
Income taxes charged
to operations $ -- $ -- $ 1,820
----- ----- -------
----- ----- -------
...................................................................................
</TABLE>
45
<PAGE>
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:
<TABLE>
<CAPTION>
...................................................................................
1995 1994 1993
...................................................................................
<S> <C> <C> <C>
Statutory federal income tax rate 35.0% 35.0% 35.0%
Patronage exclusion (35.6%) (35.4%) (35.1%)
Other 0.6% 0.4% 0.1%
Effect of increase in statutory rate 0.0% 0.0% 12.8%
------ ------ ------
Effective income tax rate 0.0% 0.0% 12.8%
------ ------ ------
------ ------ ------
...................................................................................
</TABLE>
The components of the net deferred tax liabilities as of December 31,
1995 and 1994 were as follows:
<TABLE>
<CAPTION>
...........................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...........................................................................
<S> <C> <C>
DEFERRED TAX ASSETS
Net operating losses $ 538,067 $ 451,543
Member loss carryforwards 342,370 366,417
Tax credits 252,680 252,701
Accounting for safe harbor leases 86,599 98,746
Patronage exclusions available 0 80,190
Accrued nuclear decommissioning expense 45,042 38,644
Accounting for asset dispositions 33,496 34,448
Other 18,277 18,061
----------- -----------
1,316,531 1,340,750
Less: Valuation allowance (252,680) (252,701)
----------- -----------
1,063,851 1,088,049
----------- -----------
DEFERRED TAX LIABILITIES
Depreciation (1,034,153) (1,062,233)
Accounting for debt extinguishment (64,006) (61,003)
Other (31,202) (30,323)
----------- -----------
(1,129,361) (1,153,559)
----------- -----------
Net deferred tax liabilities $ (65,510) $ (65,510)
----------- -----------
----------- -----------
...........................................................................
</TABLE>
As of December 31, 1995, Oglethorpe has federal tax net operating loss
carryforwards (NOLs) and unused general business credits (consisting
primarily of investment tax credits) as follows:
<TABLE>
<CAPTION>
...........................................................................
(DOLLARS IN THOUSANDS)
...........................................................................
Expiration Date Tax Credits NOLs
<S> <C> <C>
1997 $ 11,197 $ --
1998 6,934 --
1999 37,206 --
2000 3,198 --
2001 7,264 --
2002 130,377 146,363
2003 652 253,665
2004 55,663 114,285
2005 189 213,080
2006 -- 209,009
2007 -- 86,779
2008 -- 94,927
2009 -- 96,394
2010 -- 77,967
---------- ----------
$ 252,680 $1,292,469
---------- ----------
---------- ----------
...........................................................................
</TABLE>
Based on Oglethorpe's historical taxable transactions, the timing of the
reversal of existing temporary differences, future income, and tax planning
strategies, it is more likely than not that Oglethorpe's future taxable
income will be sufficient to realize the benefit of 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.
4. CAPITAL LEASES:
In December 1985, Oglethorpe sold and subsequently leased back from four
purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The
gain from the sale is being amortized over the 36-year term of the leases.
The minimum lease payments under the capital leases together with the present
value of net minimum lease payments as of December 31, 1995 are as follows:
<TABLE>
<CAPTION>
...........................................................................
YEAR ENDING DECEMBER 31, (DOLLARS IN THOUSANDS)
...........................................................................
<S> <C>
1996 $ 39,293
1997 35,239
1998 37,302
1999 37,890
2000 37,755
2001-2021 606,809
---------
Total minimum lease payments 794,288
Less: Amount representing interest (491,819)
---------
Present value of net minimum lease payments 302,469
Less: Current portion (5,991)
---------
Long term balance $ 296,478
---------
---------
...........................................................................
</TABLE>
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 9.64%. As of December 31, 1995, the variable interest rates of the
debt of the remaining lessor ranged from 5.93% to 8.05% for an average rate
of 6.99%. 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 was such that amortization of the Scherer Unit No. 2
leasehold calculated in this manner was less than zero. Thereafter, the
scheduled cash rental payments increase
46
<PAGE>
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. In 1994, the IRS issued a revised Notice of
Proposed Adjustments to one of the lessors which reduced the proposed
adjustments. During 1995, this lessor advised Oglethorpe that it had settled
this issue on the basis of the revised Notice of Proposed Adjustments.
Oglethorpe subsequently made a lump sum indemnity payment of $362,000 to the
lessor in order to compensate for the reduction in the lessor's tax benefits
resulting from the sale and leaseback transaction. The IRS has indicated that
it will take consistent positions with the other three lessors. If the IRS's
current positions regarding the sale and leaseback transactions were
ultimately upheld, Oglethorpe would be required to indemnify the other three
lessors. Oglethorpe's indemnification liability to the three lessors is
estimated to be approximately $1,150,000 as of December 31, 1995. This
liability has been reflected on the accompanying balance sheet as of this
date.
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 collateral for the CoBank headquarters note; substantially all of
the owned tangible and certain of the intangible assets of Oglethorpe are
pledged as collateral for the FFB and RUS notes, the 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
$3,253,636,000 and $3,161,550,000 were outstanding at December 31, 1995 and
1994, respectively, with rates ranging from 5.67% to 10.78%.
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 in a non-cash transaction
$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 finance the premium. The combined premium and fee of
$45,992,000 is 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. As of December 31, 1995, the remaining maturities on these
advances ranged from three months to 21 months.
In December 1995, Oglethorpe completed a current refunding transaction
whereby $21,670,000 of fixed rate pollution control revenue bonds were
issued. The proceeds of this transaction were used to retire $21,670,000 of
existing bonds. The unamortized transaction costs related to this transaction
total $287,000. 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 1995, current refunding were held in debt
service reserve funds until the retirement of the bonds occurred in January
1996. At December 31, 1995, 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 1995.
In January 1996, Oglethorpe completed note modifications pursuant to which
it repriced $89,447,000 of FFB advances. In connection with such
modification, Oglethorpe paid a premium of $9,332,000. These amounts will be
reported as deferred charges on the balance sheet, and will be amortized over
22 years, the longest remaining life of the subject advances.
The annual interest requirement for 1996, based upon all debt outstanding
at December 31, 1995, will be approximately $290,000,000.
Maturities for the long-term debt through 2000 are as follows:
<TABLE>
<CAPTION>
...................................................................................
(DOLLARS IN THOUSANDS) 1996 1997 1998 1999 2000
...................................................................................
<S> <C> <C> <C> <C> <C>
FFB and RUS $ 82,026 $ 77,499 $ 82,744 $ 86,743 $ 94,897
CoBank 478 489 502 516 532
1982 Bonds -- 6,675 -- -- --
1992A Bonds -- 5,070 5,330 5,615 5,925
1992 Bonds -- -- 2,085 2,240 2,405
1993A Bonds -- -- 2,265 2,410 2,595
1993B Bonds -- 9,810 6,490 6,695 7,770
1993Bonds 855 875 900 935 1,135
1994A Bonds -- -- -- -- 2,240
1994B Bonds -- 1,335 550 1,465 1,540
1994 Bonds 325 330 350 370 385
Capital Leases 5,991 2,795 5,143 6,240 7,075
-------- -------- -------- -------- --------
Total $ 89,675 $104,878 $106,359 $113,229 $126,499
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
...................................................................................
</TABLE>
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 committed lines of credit provided by a group of banks. As of
December 31, 1995 and 1994, no commercial paper was outstanding.
Oglethorpe has arranged for uncommitted short-term lines of
47
<PAGE>
credit with CoBank and CFC and a committed line of credit with SunTrust Bank,
Atlanta (SunTrust). The CoBank line amounts to $70,000,000; the CFC line
amounts to $50,000,000; and the SunTrust 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 SunTrust line of credit agreements. No
balance was outstanding on any of these three lines of credit at either
December 31, 1995 or 1994.
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, 1995 is as follows:
<TABLE>
<CAPTION>
...................................................................................
(DOLLARS IN THOUSANDS) Accumulated
Plant Investment Depreciation
...................................................................................
<S> <C> <C>
In-service
Owned property
Vogtle Units No. 1 & No. 2
(NUCLEAR - 30% OWNERSHIP) $2,779,362 $ 594,553
Hatch Units No. 1 & No. 2
(NUCLEAR - 30% OWNERSHIP) 516,154 198,082
Wansley Units No. 1 & No. 2
(FOSSIL - 30% OWNERSHIP) 171,453 82,842
Scherer Unit No. 1
(FOSSIL - 60% OWNERSHIP) 429,553 184,513
Rocky Mountain Units No. 1,
No. 2 & No. 3
(HYDRO - 74.6% OWNERSHIP) 549,750 6,203
Tallassee (Harrison Dam)
(HYDRO - 100% OWNERSHIP) 9,282 1,641
Wansley (COMBUSTION TURBINE -
30% OWNERSHIP) 3,665 1,181
Transmission and distribution plant 823,087 176,553
Other 117,794 33,796
Property under capital lease
Scherer Unit No. 2
(FOSSIL - 60% LEASEHOLD) 299,113 83,067
---------- ----------
Total in-service $5,699,213 $1,362,431
---------- ----------
---------- ----------
Construction work in progress
Generation improvements $ 17,021
Transmission and distribution plant 18,258
Other 474
----------
Total construction work in progress $ 35,753
----------
----------
...................................................................................
</TABLE>
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
with the ultimate ownership interests of Oglethorpe and GPC in the facility
based on the ratio of each party's direct construction costs to total project
direct construction costs with certain adjustments.
On June 1, 1995, Unit 3 and the completed Unit Common facilities were
declared to be in commercial operation by Oglethorpe. Unit 2 and Unit 1 were
declared to be in commercial operation on June 19, 1995 and July 24, 1995,
respectively. In accordance with the Rocky Mountain agreements, the final
ownership interests of Oglethorpe and GPC in Rocky Mountain is 74.6% and
25.4%, respectively. The final ownership interests in the project will be
applied to all future capital costs.
Oglethorpe is engaged in a continuous construction program and, as of
December 31, 1995, estimates property additions (including capitalized
interest) to be approximately $113,000,000 in 1996, $106,000,000 in 1997 and
$103,000,000 in 1998, primarily for replacements and additions to generation
and transmission facilities.
Oglethorpe's proportionate share of direct expenses of joint operation of the
above plants is included in the corresponding operating expense captions (e.g.,
fuel, production or depreciation) on the accompanying statements of revenues and
expenses.
7. EMPLOYEE BENEFIT PLANS:
Oglethorpe has a noncontributory defined benefit pension plan covering
substantially all employees. Oglethorpe's pension cost was approximately
$1,954,000 in 1995, $1,262,000 in 1994 and $1,038,000 in 1993. For 1995,
pension cost increased by $912,000 related to termination benefits. The
termination benefits resulted from an early retirement program undertaken in
the fourth quarter of 1995. Plan benefits are based on years of service and
the employee's compensation during the last ten years of employment.
Oglethorpe's funding policy is to contribute annually an amount not less than
the minimum required by the Internal Revenue Code and not more than the
maximum tax deductible amount.
The plan's pension cost recognized in 1995, 1994 and 1993 is shown as
follows:
<TABLE>
<CAPTION>
...................................................................................
(DOLLARS IN THOUSANDS) 1995 1994 1993
...................................................................................
<S> <C> <C> <C>
Pension cost was comprised of the
following
Service cost - benefits earned
during the year $ 913 $ 1,084 $ 884
Interest cost on projected benefit
obligation 742 714 617
Actual return on plan assets (1,889) 387 (698)
Net amortization and deferral 1,288 (911) 247
Net gain from a plan curtailment (12) (12) (12)
------- ------- -------
Net pension cost $ 1,042 $ 1,262 $ 1,038
------- ------- -------
------- ------- -------
...................................................................................
</TABLE>
48
<PAGE>
The plan's funded status in Oglethorpe's financial statements as of December 31,
1995 and 1994 were as follows:
<TABLE>
<CAPTION>
...........................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...........................................................................
<S> <C> <C>
Actuarial present value of accumulated
plan benefits
Vested $ 6,868 $ 5,281
Nonvested 591 380
-------- --------
$ 7,459 $ 5,661
-------- --------
-------- --------
Projected benefit obligation $(12,326) $ (9,276)
Plan assets at fair value 7,760 7,282
-------- --------
Projected benefit obligation in excess of
plan assets (4,566) (1,994)
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions 223 (861)
Prior service cost not yet recognized
in net periodic pension cost 548 598
Unrecognized net asset at transition date
being recognized over 19 years (121) (133)
-------- --------
Pension accrual $ (3,916) $ (2,390)
-------- --------
-------- --------
...........................................................................
</TABLE>
The discount rate and rate of increase in future compensation levels used
in determining the actuarial present value of the projected benefit
obligations shown above were 7.25% and 5.0% in 1995, and 8.5% and 5.0% in
1994, respectively. The expected long-term rate of return on plan assets was
8.5% in 1995 and 8% in 1994 and 1993, and the discount rate used in
determining the pension expense was 8.5% in 1995, 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 $589,000 in 1995,
$565,000 in 1994 and $503,000 in 1993.
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 $7,220,000 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 decontamination, debris removal and premature decommissioning as well
as excess property damage to nuclear generating facilities for an additional
$2,250,000,000 for losses in excess of the $500,000,000 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 $13,980,000.
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
$95,130,000 per incident, but not more than $12,000,000 in any one year.
Oglethorpe participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, Oglethorpe could be subject to a total
maximum assessment of $3,360,000.
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
49
<PAGE>
August 31, 1997. Effective September 1, 1997, Oglethorpe will purchase 750 MW
of capacity through the period ending December 31, 2003, 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, 1995, 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:
<TABLE>
<CAPTION>
...........................................................................
Year Ending December 31, (dollars in thousands)
...........................................................................
<S> <C>
1996 $ 149,835
1997 130,843
1998 119,948
1999 118,061
2000 121,179
...........................................................................
</TABLE>
Oglethorpe's power purchases from these agreements amounted to approximately
$206,641,000 in 1995, $182,965,000 in 1994 and $192,059,000 in 1993.
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. SUBSEQUENT EVENT:
On January 3, 1996, Oglethorpe entered into a power supply swap agreement
with Enron Power Marketing Inc. (EPMI). The agreement, effective January 4,
1996 through April 30, 1996, requires EPMI to sell to Oglethorpe at a fixed
cost all the energy needed to serve the Members (approximately 5.2 million
megawatt-hours). Per the agreement, Oglethorpe is required to sell to EPMI at
cost, subject to certain cost limitations, all energy available from
Oglethorpe's total power resources. EPMI has the option to market any excess
energy that remains from Oglethorpe's total power resources. Oglethorpe is
considering a similar power supply swap for a longer term basis.
In order to provide its Members with greater flexibility for meeting their
power supply needs in an increasingly competitive utility environment, a plan
was approved by Oglethorpe's Board of Directors in December 1995 to divide
Oglethorpe into three specialized companies to respond to increasing
competition in the electric industry and related changes in law and
regulation. The December plan proposed the creation of a new transmission
company that would own and operate the transmission system and provides
services to the Members, and a new systems operations company that would own
and operate the systems operation services for the Members, Oglethorpe and
third parties. Oglethorpe would retain the generation business and would
operate as the power supplier for the Members. Oglethorpe is continuing to
develop and refine the restructuring plan, and subject to receiving
governmental and other third party approvals, the current target date for
full implementation of the restructuring is January 1, 1997.
11. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial information for 1995 and 1994 is as follows:
<TABLE>
<CAPTION>
...........................................................................
First Second Third Fourth
(DOLLARS IN THOUSANDS) Quarter Quarter Quarter Quarter
...........................................................................
<S> <C> <C> <C> <C>
1995
Operating revenues $257,547 $281,228 $317,536 $293,250
Operating margin 68,682 82,048 82,949 74,998
Net margin 8,462 20,292 10,656 (17,152)
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)
...........................................................................
</TABLE>
Oglethorpe's business is influenced by seasonal weather conditions. First
and third quarter 1995 net margins were lower than the same periods of 1994.
Historically, most of Oglethorpe's annual net margin was earned by May 31 of
each year. This pattern of earning occurred because non-Member revenues
declined significantly on June 1 of each year through the end of such year
due to scheduled reductions in capacity sell-back to GPC while monthly fixed
costs recovered from Members remained virtually unchanged throughout the
year. Member capacity revenues reflect recovery in nearly equal monthly
amounts of all budgeted fixed costs plus the annual net margin goal, less
fixed costs projected to be recovered from GPC pursuant to plant operating
agreements. The capacity sell-back arrangement with GPC expired on May 31,
1995. For a discussion of the GPC capacity sell-back arrangement, see Note 1.
The higher net margin for the second quarter 1995 compared to 1994
resulted from unbudgeted savings from the continued capitalization of costs
of Rocky Mountain due to the delay in commercial operation from April 1995 to
June 1995.
The negative net margins for the fourth quarter of 1995 and 1994 were
primarily attributable to the deferral of excess margins. For a discussion of
the amounts of excess margins deferred, see Note 1.
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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 (Coopers & Lybrand L.L.P.) also consider certain elements of the
internal control system in order to determine their auditing procedures for
the purpose of expressing an opinion on the financial statements.
Coopers & Lybrand L.L.P. also provides an objective assessment of how well
management meets its responsibility for fair financial reporting. Management
believes that its policies and procedures provide reasonable assurance that
Oglethorpe's operations are conducted with a high standard of business
ethics. In management's opinion, the financial statements present fairly, in
all material respects, the financial position, results of operations, and
cash 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 sheet and statement of
capitalization of Oglethorpe Power Corporation (a Georgia corporation) as of
December 31, 1995 and the related statements of revenues and expenses,
patronage capital, and cash flows for the year then ended. These financial
statements are the responsibility of Oglethorpe's management. Our
responsibility is to express an opinion on these financial statements based
on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Oglethorpe Power
Corporation as of December 31, 1995 and the results of its operations and its
cash flows for the year then ended in conformity with generally accepted
accounting principles.
Coopers & Lybrand L.L.P.
Atlanta, Georgia,
February 28, 1996.
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REPORT OF INDEPENDENT
PUBLIC ACCOUNTANTS
To the Board of Directors of Oglethorpe Power Corporation:
We have audited the accompanying balance sheet and statement of
capitalization of Oglethorpe Power Corporation (a Georgia corporation) as of
December 31, 1994 and the related statements of revenues and expenses,
patronage capital, and cash flows for each of the two 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 the results of its operations and its
cash flows for each of the two years in the period ended December 31, 1994 in
conformity with generally accepted accounting principles.
As explained in Note 2 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 3 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.
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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. For a discussion of the proposed changes in
Oglethorpe's governance structure in connection with the proposed
restructuring, see "OGLETHORPE POWER CORPORATION-Proposed Restructuring" in
Item 1.
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 70, 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 1998. He is currently a member of the Finance
Committee of Oglethorpe. Mr. Warnock is the President of Altamaha EMC and a
Director of GEMC.
James D. Musgrove--Alternate Director, age 49, 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 1998.
Mr. Musgrove is a Director of Montgomery County Bankshares in Ailey, Georgia.
AMICALOLA EMC
Charles R. Fendley--Director, age 50, 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 1998. 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, age 56, 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.
He has served as an Alternate Director of Oglethorpe since 1975, with his
present term to expire in March 1998. He is currently a member of the
Finance Committee. Mr. Dean previously served on Oglethorpe's Operations
Review Committee and Executive Committee and served as Secretary-Treasurer of
Oglethorpe from March 1989 to March 1995. Currently, he is on the Board of
Directors of GRESCO, Southeastern Data Cooperative, Inc., Crescent Bank &
Trust Company, CoBank, and North Georgia Certified Development Corporation.
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CANOOCHEE EMC
George C. Martin--Director, age 78, 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 1998. From March 1978 to March 1984, he
served as Vice President of Oglethorpe.
Donald F. Kennedy--Alternate Director, age 66, 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 1998. Mr.
Kennedy is also a Director of the Tattnall Bank in Reidsville, Georgia.
CARROLL EMC
J. G. McCalmon--Director, age 78, 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 1999. He currently serves as Vice Chairman
of the Human Resources Management Committee. He is Chairman of the Board of
Carroll EMC. Mr. McCalmon also serves on the Boards of Directors of GEMC,
the Farm Bureau, Carroll County Sales Barn, and the Carroll County Chamber
of Commerce.
Gary M. Bullock--Alternate Director. For a description of Mr.
Bullock's background and experience, see "Identification of Executive
Officers and Senior Executives" below.
CENTRAL GEORGIA EMC
D. A. Robinson, III--Director, age 55, 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 1998.
He is a member of the Transmission Committee. Mr. Robinson serves as
Secretary-Treasurer of Central Georgia EMC.
George L. Weaver--Alternate Director, age 48, 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 1998. He is currently a member of the Finance 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 Chairman of the
Butts County Development Authority; Chairman of the Joint Development
Authority which encompasses Butts, Henry, Lamar, and Spalding Counties; 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 60, has served on the Board of
Directors of Oglethorpe since March 1982, with his present term to expire in
March 1997. He currently serves as Chairman of the Wholesale Power Contract
Oversight Committee and is a member of the Executive Committee. He is also
Vice President of the Board of Directors of Coastal EMC. Mr. Estes operates
Estes Property Management, a commercial real estate management service in
Richmond Hill, Georgia; is President of Ways Company, Inc., a real estate
development company in Richmond Hill, Georgia; and is proprietor of Estes Tax
Service, an income tax service in Richmond Hill, Georgia.
Wayne Collins--Alternate Director, age 45, 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 55, 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 1998.
He is currently a member of the Generation Committee. Mr. Chadwick is
Chairman of the Board of Cobb EMC.
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Dwight Brown--Alternate Director, age 50, 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 1998. Mr. Brown currently serves on the Restructuring Advisory
Committee.
COLQUITT EMC
Simmie King--Director, age 52, 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 1999.
R. L. Gaston--Alternate Director, age 48, 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 1999. Mr. Gaston currently serves on the Restructuring Advisory
Committee.
COWETA-FAYETTE EMC
W. F. Farr--Director, age 83, is a banker. He has served on the
Board of Directors of Oglethorpe since March 1975, with his present term to
expire in March 1998. He is currently a member of the Finance Committee and
previously served as Chairman of the 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, Mr. Farr has been the owner and
President of Pioneer Financial Associates, Inc. in Peachtree City, Georgia.
Michael C. Whiteside--Alternate Director, age 53, has been General
Manager of Coweta-Fayette EMC since August 1983. He previously served as
Administrative Assistant of Coweta-Fayette EMC. He currently serves on the
Marketing Committee and the Restructuring Advisory Committee. Mr. Whiteside
has served as an Alternate Director of Oglethorpe since September 1983, with
his present term to expire in March 1998.
EXCELSIOR EMC
Vacant--Director
Gary T. Drake--Alternate Director, age 47, 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 Generation Committee. Mr. Drake is also a Director
of GEMC.
FLINT EMC
Jeff S. Pierce, Jr.--Director, age 64, has served on the Board of
Directors of Oglethorpe since June 1992, with his present term to expire in
March 1997. He is a member of the Executive Committee. He has served as a
Director of Flint EMC since 1964. Mr. Pierce 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 60, 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 Transmission Committee.
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GRADY EMC
Donald C. Cooper--Director, age 65, 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
1999. He is currently a member of the Generation Committee.
Thomas A. Rosser--Alternate Director, age 48, 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 1999.
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 59, 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 1998. He is currently a member of the Marketing
Committee. Mr. Clower serves on the Boards of Directors of Citizens &
Merchants State Bank and GEMC Workers' Compensation Fund.
HABERSHAM EMC
Ray Meaders--Director, age 72, is the owner and operator of a farm
in Cleveland, Georgia. He has served as Director of Oglethorpe since August
1995, with his present term to expire in March 1999. He is currently a
member of the Marketing Committee. Mr. Meaders is also a Director of
Habersham EMC.
William E. Canup--Alternate Director, age 60, 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 1999.
HART EMC
Mac F. Oglesby--Director, age 63, 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 Marketing Committee and the Wholesale Power
Contract Oversight Committee. Mr. Oglesby was a U.S. Postal Service Rural
Carrier for 30 years.
Grooms Johnson--Alternate Director, age 66, 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 44, 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 1998. He is Chairman and past Vice Chairman of the
Finance Committee and also serves on the Restructuring Advisory Committee.
Mr. Crenshaw was Office Manager of Irwin EMC from 1974 to 1988.
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JACKSON EMC
E. L. McLocklin--Director, age 83, 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 1999. Mr. McLocklin is currently a member of the Marketing Committee.
Randall Pugh--Alternate Director, age 52, 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 1999. He is currently a member of the Finance Committee and the
Restructuring Advisory Committee. Mr. Pugh is also a Director of the First
National Bank of Jackson County in Jefferson, Georgia.
JEFFERSON EMC
Sam Rabun--Director, age 64, 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 1999. He is currently a member of the Executive
Committee. Mr. Rabun is the President of Jefferson EMC.
Kenneth Cook--Alternate Director, age 49, is the Executive Vice
President and General Manager of Jefferson EMC. He has served as the Manager
of Engineering since joining Jefferson EMC in 1986. He was previously
self-employed as a row-crop and livestock farmer. Mr. Cook has served as a
Director of Oglethorpe since February 1996, with his present term to expire
in March 1999. He served on the Board of Directors of Little Ocmulgee EMC
from 1979 to 1986 and on the Board of Directors of Oglethorpe from 1982 to
1986.
LAMAR EMC
E. J. Martin, Jr.--Director, age 68, 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 currently a member of the Human Resources Management Committee. Mr.
Martin is the President of Lamar EMC and a Director of GEMC.
J. Raleigh Henry--Alternate Director, age 45, 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 60, 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 49, is the General
Manager of Little Ocmulgee EMC. He previously served as Manager of
Engineering and Operations and has been with Little Ocmulgee EMC since 1983.
He has served as the Alternate Director of Oglethorpe since March 1993, with
his present term to expire in March 1997. Mr. Horton is a member of the
Transmission Committee.
MIDDLE GEORGIA EMC
Ronnie Fleeman--Director, age 61, is a self-employed land and
timber developer. He has served on the Board of Directors of Oglethorpe
since 1990, with his present term to expire in March 1998.
Charles Hugh Richardson--Alternate Director, age 42, 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 1998.
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MITCHELL EMC
D. Lamar Cooper--Director, age 60, operates a dairy farm. He has
served on the Board of Directors of Oglethorpe since September 1974, with his
present term to expire in March 1999. He is currently a member of the
Generation Committee.
Edward A. Pritchett--Alternate Director, age 49, has served as
General Manager of Mitchell EMC since September 1995. Since that time he has
served as Alternate Director of Oglethorpe, with his present term to expire
in March 1999. Prior to that time, Mr. Pritchett served as Assistant General
Manager, Director of Finance and Administrative Services and Supervisor of
Data Processing for Mitchell EMC.
OCMULGEE EMC
Barry H. Martin--Director, age 47, is a farmer. He has served on
the Board of Directors of Oglethorpe since March 1983, with his present term
to expire in March 1997. Mr. Martin is the President of Ocmulgee EMC.
Dennis Grenade--Alternate Director, age 55, 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, with his present term to
expire in March 1997. He is a member of the Transmission Committee.
OCONEE EMC
John B. Floyd, Jr.--Director, age 53, has served on the Board of
Directors of Oglethorpe since March 1980, with his present term to expire in
March 1999. He is currently a member of the Human Resources Management
Committee. Mr. Floyd is also the Vice Chairman of the Board of Oconee EMC.
Preston L. Johnson--Alternate Director, age 61, 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 1999. He was Secretary-Treasurer of Oglethorpe from September 1974
to March 1984.
OKEFENOKE RURAL EMC
Steve Rawl, Sr.--Director, age 49, 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
currently a member of the Finance Committee.
W. Don Holland--Alternate Director, age 45, 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
Transmission Committee and serves on the Restructuring Advisory Committee and
the Wholesale Power Contract Oversight Committee.
PATAULA EMC
James Grubbs--Director, age 73, 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, with his present term to expire in March 1999. Mr. Grubbs
is a member of the Transmission Committee.
Gary W. Wyatt--Alternate Director, age 43, 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 1999. He currently serves as
Vice-Chairman of the Marketing Committee. Mr. Wyatt previously was
Operations Manager and Assistant Operations Superintendent of Coosa Valley
Electric Cooperative.
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PLANTERS EMC
Sammy M. Jenkins--Director, age 69, 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 was Vice Chairman of the Board
of Oglethorpe from March 1989 to March 1990. Mr. Jenkins currently serves as
Vice-Chairman of the Generation Committee and is a member of the Wholesale
Power Contract Oversight Committee.
Ellis H. Lovett--Alternate Director, age 60, 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 currently a member of the Marketing Committee.
RAYLE EMC
J. M. Sherrer--Director, age 60, 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 50, 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
of Oglethorpe since February 1993, with his present term to expire in March
1997. He is currently a member of the Generation Committee.
SATILLA RURAL EMC
Jack D. Vickers--Director, age 78, 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, with his present term to expire in March 1997.
R. Lehman Lanier--Alternate Director, age 76, is President and
Chief Executive Officer of Satilla Rural EMC. He has served as an Alternate
Director of Oglethorpe since September 1974, with his present term to expire
in March 1997. He is currently a member of the Generation Committee. Mr.
Lanier is also a Director of Southeastern Data Cooperative, Inc.
SAWNEE EMC
C. W. Cox, Jr.--Director, age 68, 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. Mr. Cox is currently a member of the
Finance Committee.
Michael A. Goodroe--Alternate Director, age 39, 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 Transmission Committee.
SLASH PINE EMC
Johnnie Crumbley--Director, age 73, 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 1999. He is also a Director of GEMC.
Edward Teston--Alternate Director, age 61, 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 1999.
SNAPPING SHOALS EMC
Jarnett W. Wigington--Director, age 63, is a self-employed
wallpapering contractor. He has served on the Board of Directors of
Oglethorpe since 1990, with his present term to expire in March 1997.
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Randall G. Meadows--Alternate Director, age 51, is President/Chief
Executive Officer/Manager of Snapping Shoals EMC. He previously served as
Executive Vice President/Chief Operating Officer for Snapping Shoals EMC. He
has served as an Alternate Director of Oglethorpe since August 1995, with his
present term to expire in March 1997. Mr. Meadows currently serves on the
Restructuring Advisory Committee.
SUMTER EMC
Bob Jernigan--Director, age 68, has served as a Director of
Oglethorpe since March 1976, with his present term to expire in March 1999.
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 Transmission Committee.
Mr. Jernigan is the Chairman of the Board of Sumter EMC and a Director of
GEMC.
James T. McMillan--Alternate Director, age 46, 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 1999. Mr. McMillan currently serves
on the Generation Committee.
THREE NOTCH EMC
C. Willard Mims--Director, age 49, is a farmer. He has served on
the Board of Directors since 1991, with his present term to expire in March
1999. Mr. Mims is also a Director of GEMC.
Carlton O. Thomas--Alternate Director, age 48, 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 1999. He
currently serves on the Transmission Committee. Mr. Thomas is also a
Director of First Federal Savings Bank of Southwest Georgia.
TRI-COUNTY EMC
Thomas Noles--Director, age 54, is a pharmacist. He has served on
the Board of Directors of Oglethorpe since September 1995, with his present
term to expire in March 1999.
Carol Robertson--Alternate Director, age 47, 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 1999. Ms. Robertson
currently serves on the Restructuring Advisory Committee.
TROUP EMC
Roy Tollerson, Jr.--Director, age 56, is the owner and operator of
Country Furniture. He has served on the Board of Directors of Oglethorpe
since March 1995, with his present term to expire in March 1998. Mr.
Tollerson is currently a member of the Marketing Committee.
Wayne Livingston--Alternate Director, age 44, 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 1998. Mr. Livingston currently serves on the Restructuring
Advisory Committee.
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UPSON COUNTY EMC
Hubert Hancock--Director, age 79, has been President of the Upson
County EMC for the past 34 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 1998.
Mr. Hancock currently serves on the Executive Committee. Prior to his
involvement with Oglethorpe and Upson County EMC, he 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, and Chairman of Upson County
Hospital Authority.
John H. Brodnax--Alternate Director, age 48, was appointed General
Manager of Upson County EMC in 1995. Prior to that time he served as Office
Manager of Upson County EMC. Mr. Brodnax has served as Alternate Director of
Oglethorpe since 1995, with his present term to expire in 1998.
WALTON EMC
Hendrix B. Wiley, Jr.--Director, age 51, is a retired dairy farmer
and is currently self-employed in real estate. He has served on the Board of
Directors of Oglethorpe since August 1994, with his present term to expire in
March 1998. He currently serves on the Generation Committee. Mr. Wiley is
also a director of Walton EMC.
D. Ronnie Lee--Alternate Director, age 47, 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 1998. Mr. Lee currently serves on
the Restructuring Advisory Committee.
WASHINGTON EMC
W. W. Archer--Director, age 64, 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 1998. He is also a
Director of the Bank of Hancock County in Sparta, Georgia.
Robert S. Moore, Sr.--Alternate Director, age 66, 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
1998. He is currently a member of the Marketing Committee.
(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 54, 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 1998. He is currently the Chairman of the
Executive Committee and a member of the Human Resources Management Committee.
He was previously a member of the Operations Review Committee. From 1965
through 1982, Mr. Earwood was a salesman and part owner of Builders Equipment
Company. Since January 1983, he has been the owner and President of Sunbelt
Fasteners, Inc., which sells specialty tools and fasteners to the 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 65, has served as
a principal executive officer of Oglethorpe since March 1993. He has served
on the Board of Directors of Oglethorpe since December 1988, with
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his present term to expire in March 1998. He is currently the Vice-Chairman
of the Executive Committee and was previously a member of the Power Planning
and Technical Advisory Committee. Mr. Denham is also a Director of Community
National Bank in Ashland, Georgia and a Director of Irwin EMC.
Gary M. Bullock, Secretary-Treasurer, age 54, has served as
Secretary-Treasurer of Oglethorpe since March 1995. He has served as an
Alternate Director of Oglethorpe since June 1978, with his present term to
expire in March 1999. He is currently a member of the Executive Committee
and the Restructuring Advisory Committee and was previously a member of the
Operations Committee. Mr. Bullock is President and Chief Executive Officer
of Carroll EMC. Mr. Bullock is also the Secretary of Southeastern Data
Cooperative, Inc. and serves on the Boards of Directors of the Georgia
Cooperative Council, the Federated Rural Electric Insurance Corporation, and
the Carrollton Federal Bank, F.S.B. in Carrollton, Georgia.
T. D. Kilgore, President and Chief Executive Officer, age 48, 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 October 1995. 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:
Clarence Mitchell, Vice President and Group Executive, Generation,
age 42, 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 59, 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
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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
46, has served as an executive at Oglethorpe since February 1994, responsible
for Market Planning, Economic Development, Commercial/Industrial Marketing
and Pricing, Commercial/Industrial Services, and Residential Marketing.
Prior to coming to Oglethorpe, Mr. Hawk spent almost 24 years with the
Florida Power & Light Company and related subsidiaries, serving as Director
of Regulatory Affairs from October 1993 to January 1994, 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 wide range of utility management experience in
energy management, finance, strategic planning, marketing, system planning,
quality assurance, and distribution engineering. Mr. Hawk is a board member
of the Georgia Electrification Council, Inc. and the Georgia Partnership for
Excellence in Education, and served on the board of directors as well as
President of the National Association of Energy Services Companies (NAESCO),
a national trade association, during the late 1980s. Mr. Hawk is a
registered Professional Engineer in Florida and has a BS degree in Electrical
Engineering from the Georgia Institute of Technology and an MBA degree from
Florida International University.
W. Clayton Robbins, Senior Vice President and Group Executive,
Support Services, age 49, 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
61, 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. Mr. Heckl has elected to retire from
Oglethorpe under the provisions of an early retirement program, effective no
later than September 11, 1996. However, Mr. Heckl may continue to provide
services to Oglethorpe on a contract basis after that date at the discretion
of the President and Chief Executive Officer.
G. Stanley Hill, Senior Vice President, External Affairs, age 60,
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 37 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. Mr. Hill has elected to retire from
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Oglethorpe under the provisions of an early retirement program, effective no
later than September 11, 1996. However, Mr. Hill may continue to provide
services to Oglethorpe on a contract basis after that date at the discretion
of the President and Chief Executive Officer.
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ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth, for Oglethorpe's President and
Chief Executive Officer and the five most highly compensated senior
executives, all compensation paid or accrued for services rendered in all
capacities during the years ended December 31, 1995, 1994 and 1993. 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.
<TABLE>
<CAPTION>
ANNUAL
COMPENSATION
NAME AND ------------------- ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS(2) COMPENSATION
- ------------------ ---- -------- --------- -------------
<S> <C> <C> <C> <C>
T. D. Kilgore 1995 $235,000 $10,000 $6,012(1)
President and Chief Executive Officer 1994 224,997 0 6,758
1993 211,250 0 7,652
David L. Self (3) 1995 145,896 13,410 48,024(1)(3)
Sr. Vice President and 1994 147,833 10,476 9,117
Group Executive, System Operations 1993 135,000 12,143 8,229
Eugen Heckl 1995 142,114 13,174 7,651(1)
Sr. Vice President and Chief 1994 142,114 13,919 7,600
Financial Officer 1993 142,114 12,228 7,221
G. Stanley Hill 1995 140,000 11,088 7,204(1)
Sr. Vice President, External Affairs 1994 140,000 10,883 5,619
1993 140,000 12,580 7,001
W. Clayton Robbins 1995 142,310 10,631 4,716(1)
Sr. Vice President and 1994 140,366 11,946 4,986
Group Executive, Support Services 1993 128,000 12,461 4,582
Nelson G. Hawk (4) 1995 140,000 10,899 4,589(1)
Vice President and Group 1994 116,005 9,620 36,972(4)
Executive, Marketing 1993 N/A N/A N/A
</TABLE>
______________________
(1) Includes contributions made in 1995 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. Kilgore, Self, Heckl, Hill,
Robbins and Hawk of $4,620, $3,034, $4,351, $3,975, $4,393 and $3,789,
respectively; and insurance premiums paid on term life insurance on behalf of
Messrs. Kilgore, Self, Heckl, Hill, Robbins and Hawk of $1,392, $6,641,
$3,300, $3,229, $323 and $800, respectively.
(2) Mr. Kilgore is not a participant in the incentive compensation program.
His compensation is governed solely by the Board of Directors.
(3) Mr. Self elected to retire from Oglethorpe under the provisions of an
early retirement program effective December 22, 1995. His 1995 compensation
includes severance benefits of $30,254 and payment of accrued vacation and
sick benefits of $8,095.
(4) Mr. Hawk joined Oglethorpe in February 1994. Mr. Hawk's 1994
compensation includes a sign-on bonus of $5,000 and relocation costs of
$27,383.
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PENSION PLAN TABLE
<TABLE>
YEARS OF CREDITED SERVICE
---------------------------
AVERAGE COMPENSATION 15 20 25
- -------------------- ------- ------- -------
<S> <C> <C> <C>
$ 50,000...................................... $12,823 $17,097 $21,371
75,000...................................... 20,323 27,097 33,871
100,000...................................... 27,823 37,097 46,371
125,000...................................... 35,323 47,097 58,871
150,000...................................... 42,823 57,097 71,371
175,000...................................... 50,323 67,097 83,871
200,000...................................... 57,823 77,097 96,371
225,000...................................... 65,323 87,097 108,871
250,000...................................... 72,823 97,097 120,000
</TABLE>
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 1995. 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, 1995, the years of credited service under the
Pension Plan for the individuals listed in the Summary Compensation Table are
as follows:
<TABLE>
<CAPTION>
YEARS OF
NAME CREDITED SERVICE
---- ----------------
<S> <C>
Mr. Kilgore.......................................... 10
Mr. Self............................................. 7
Mr. Heckl............................................ 19
Mr. Hill............................................. 19
Mr. Robbins.......................................... 9
Mr. Hawk............................................. 0.8
</TABLE>
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.
EMPLOYMENT CONTRACTS
Effective January 1, 1996, Oglethorpe entered into an employment
agreement with its President and Chief Executive Officer. The term of the
agreement extends to December 31, 1998, with certain automatic annual
extension provisions beyond that date unless either party gives notice of
termination 60 days prior to an extension. Pursuant to the agreement, Mr.
Kilgore's base salary and bonus will be determined by Oglethorpe's Board, with
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annual base salary being at least $240,000. Under the agreement, if
Oglethorpe terminates Mr. Kilgore's employment without cause, he will be
entitled to all salary and benefits he would have received between the date
of termination to the end of the agreement. In addition, if Oglethorpe
terminates Mr. Kilgore's employment without cause or meaningfully reduces his
stated duties or prerogatives within three months prior to or 24 months
subsequent to a Change in Control of Oglethorpe (as defined in the
agreement), a severance payment will be paid in an amount not less than two
times Mr. Kilgore's annual base salary on the date of termination or the date
on which his duties or prerogatives are reduced, whichever is applicable. If
such reduction in duties occurs, Mr. Kilgore will be entitled to severance
regardless whether he is terminated or resigns. If Mr. Kilgore voluntarily
separates himself from Oglethorpe, he will be prohibited from working with a
competitor of Oglethorpe for a period of one year thereafter and will be paid
an amount equal to his then current salary, bonus and benefits for such
period.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
E. J. Martin, Jr., J. Calvin Earwood, John B. Floyd, Jr., and J. G.
McCalmon 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
None.
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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, 1995, 1994 and 1993........................ 36
Statements of Patronage Capital, For the Years Ended
December 31, 1995, 1994 and 1993.............................. 36
Balance Sheets, As of December 31, 1995 and 1994............... 37
Statements of Capitalization, As of December 31, 1995
and 1994...................................................... 39
Statements of Cash Flows, For the Years Ended December 31,
1995, 1994 and 1993........................................... 40
Notes to Financial Statements.................................. 41
Report of Management........................................... 51
Reports of Independent Public Accountants...................... 51
(2) FINANCIAL STATEMENT SCHEDULES
None applicable.
(3) EXHIBITS
Exhibits marked with an asterisk (*) are hereby incorporated by reference
to exhibits previously filed by the Registrant as indicated in parentheses
following the description of the exhibit.
NUMBER DESCRIPTION
- ------ -----------
2.1 (1) -- Restructuring Agreement, dated March 29, 1996, by and among
Oglethorpe, Georgia Transmission Corporation (An
Electric Membership Corporation) and Georgia System Operations
Corporation.
*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).
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*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.)
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*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. (Filed as Exhibit 4.7(k) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1994, File No. 33-7591.)
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*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.)
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*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 21, 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. (Filed as Exhibit 4.8.12 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1994, File No. 33-7591.)
4.9.1 (3) -- Loan Agreement, dated as of October 1, 1992, between Development
Authority of Monroe County and Oglethorpe relating to Development
Authority of Monroe County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Scherer Project), Series 1992A.
4.9.2 (3) -- Note, dated October 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated as
of October 1, 1992, between Development Authority of Monroe
County and Trust Company Bank.
4.9.3 (3) -- Trust Indenture, dated as of October 1, 1992, between Development
Authority of Monroe County and Trust Company Bank, Trustee,
relating to Development Authority of Monroe
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County Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Scherer Project), Series 1992A.
4.10.1 (2) -- 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 (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 (2) -- 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
(2) 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
(2) 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
(2) Reimbursement Agreement, dated August 1, 1994, between Oglethorpe
and Credit Suisse.
4.10.4(d) -- Third Amendment to First Amended and Restated Letter of Credit
(2) Reimbursement Agreement, dated April 15, 1995, between
Oglethorpe and Credit Suisse.
4.11.1 (4) -- Loan Agreement, dated as of December 1, 1992, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Adjustable Tender Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A.
4.11.2 (4) -- Note, dated December 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated as
of December 1, 1992, between Development Authority of Burke
County and Trust Company Bank.
4.11.3 (4) -- Trust Indenture, dated as of December 1, 1992, from Development
Authority of Burke County to Trust Company Bank, as trustee,
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1993A.
4.11.4 (4) -- Interest Rate Swap Agreement, dated as of December 1, 1992, by
and between Oglethorpe and AIG Financial Products Corp. relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A.
4.11.5 (4) -- Liquidity Guaranty Agreement, dated as of December 1, 1992, by
and between Oglethorpe and AIG Financial Products Corp. relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A.
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<PAGE>
4.11.6 (2) -- Standby Bond Purchase Agreement, dated as of December 14, 1995,
between Oglethorpe and Canadian Imperial Bank of Commerce, New
York Agency, relating to Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe
Power Corporation Vogtle Project), Series 1993A.
4.11.7 (2) -- Standby Bond Purchase Agreement, dated as of November 30, 1994,
between Oglethorpe and Credit Local de France, Acting through its
New York Agency, relating to the Development Authority of Burke
County Adjustable Tender Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1994A.
4.12.1 (4) -- Loan Agreement, dated as of December 1, 1995, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1995.
4.12.2 (4) -- Indenture of Trust, dated as of December 1, 1995, between
Development Authority of Burke County and SunTrust Bank, Atlanta,
as trustee, relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1995.
*4.13.1 -- 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.)
*4.13.2 -- 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.)
*4.14.1 -- 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.)
*4.14.2 -- 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.)
*4.15.1 -- Loan Agreement, Loan No. T-830404, between Oglethorpe and
Columbia Bank for Cooperatives, dated as of April 29, 1983.
(Filed as Exhibit 4.18.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.15.2 -- Promissory Note, Loan No. T-830404-1, in the original principal
amount of $9,935,000, from Oglethorpe to Columbia Bank for
Cooperatives, dated as of April 29, 1983. (Filed as Exhibit
4.18.2 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*4.15.3 -- Security Deed and Security Agreement, dated April 29, 1983,
between Oglethorpe and Columbia Bank for Cooperatives. (Filed as
Exhibit 4.18.3 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.1.1(a) -- Participation Agreement No. 2 among Oglethorpe as Lessee,
Wilmington Trust Company as Owner Trustee, The First National
Bank of Atlanta as Indenture Trustee, Columbia Bank for
Cooperatives as Loan Participant and Ford Motor Credit Company as
Owner Participant,
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<PAGE>
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,
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<PAGE>
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
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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.)
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*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
78
<PAGE>
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.)
*10.11(b) -- Letter of Commitment (Firm Power Sale) Under Service Schedule J -
Negotiated Interchange Service between Alabama Electric
Cooperative, Inc. and Oglethorpe, dated March 31, 1994. (Filed
as Exhibit 10.11(b) to the Registrant's Form 10-Q for the quarter
ended June 30, 1994, File No. 33-7591.)
*10.12 -- Oglethorpe Deferred Compensation Plan for Key Employees, as
Amended and Restated January, 1987. (Filed as Exhibit 10.19 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1986, File No. 33-7591.)
*10.13.1 -- Assignment of Power System Agreement and Settlement Agreement,
dated January 8, 1975, by Georgia Electric Membership Corporation
to Oglethorpe. (Filed as Exhibit 10.20.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.13.2 -- Power System Agreement, dated April 24, 1974, by and between
Georgia Electric Membership Corporation and Georgia Power
Company. (Filed as Exhibit 10.20.2 to the 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.)
79
<PAGE>
*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.)
80
<PAGE>
*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).
10.27 (5) -- Master Power Purchase and Sale Agreement between Enron Power
Marketing, Inc. and Oglethorpe, dated as of January 3, 1996.
10.28 (6) -- Employment Agreement between Oglethorpe and T. D. Kilgore, dated
as of December 20, 1995.
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)
_________________
(1) Pursuant to 17 C.F.R. 229.601(b)(2), the schedules and exhibits to this
document are identified on a list of schedules and exhibits included
within this document and are not filed herewith; however the registrant
hereby agrees that such schedules and exhibits will be provided to the
Commission upon request.
(2) Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this document is not filed
herewith; however the registrant hereby agrees that such document will be
provided to the Commission upon request.
(3) For the reason stated in footnote (2), this document and eight other
substantially identical documents are not filed as exhibits to this
Registration Statement.
(4) For the reason stated in footnote (2), this document and another
substantially identical document are not filed as exhibits to this
Registration Statement.
(5) Certain portions of this document have been omitted as confidential and
filed separately with the Commission.
(6) Indicates a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this form pursuant to Item 14(c)
of this report.
All other schedules and exhibits are omitted because of the absence of
the conditions under which they are required or because the required
information is included in the financial statements and related notes to
financial statements.
(B) REPORTS ON FORM 8-K.
No reports on Form 8-K were filed by Oglethorpe for the quarter ended
December 31, 1995.
81
<PAGE>
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 1st day
of April 1996.
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, April 1, 1996
- -------------------------- Director (Principal Executive
J. CALVIN EARWOOD Officer)
/s/ T. D. KILGORE President and Chief Executive April 1, 1996
- -------------------------- Officer (Principal Executive
T. D. KILGORE Officer)
/s/ GARY M. BULLOCK Secretary-Treasurer (Principal April 1, 1996
- -------------------------- Financial Officer)
GARY M. BULLOCK
/s/ EUGEN HECKL Senior Vice President and Chief April 1, 1996
- -------------------------- Financial Officer (Principal
EUGEN HECKL Financial Officer)
/s/ LARRY N. BROWNLEE Controller April 1, 1996
- -------------------------- (Principal Accounting Officer)
LARRY N. BROWNLEE
/s/ JMON WARNOCK Director April 1, 1996
- --------------------------
JMON WARNOCK
/s/ CHARLES R. FENDLEY Director April 1, 1996
- --------------------------
CHARLES R. FENDLEY
/s/ GEORGE C. MARTIN Director April 1, 1996
- --------------------------
GEORGE C. MARTIN
/s/ J. G. MCCALMON Director April 1, 1996
- --------------------------
J. G. MCCALMON
82
<PAGE>
/s/ D. A. ROBINSON, III Director April 1, 1996
- --------------------------
D. A. ROBINSON, III
/s/ JAMES E. ESTES Director April 1, 1996
- --------------------------
JAMES E. ESTES
/s/ LARRY N. CHADWICK Director April 1, 1996
- --------------------------
LARRY N. CHADWICK
/s/ SIMMIE KING Director April 1, 1996
- --------------------------
SIMMIE KING
/s/ W. F. FARR Director April 1, 1996
- --------------------------
W. F. FARR
/s/ GARY T. DRAKE Alternate Director April 1, 1996
- --------------------------
GARY T. DRAKE
/s/ JEFF S. PIERCE, JR. Director April 1, 1996
- --------------------------
JEFF S. PIERCE, JR.
/s/ DONALD C. COOPER Director April 1, 1996
- --------------------------
DONALD C. COOPER
/s/ RAY MEADERS Director April 1, 1996
- --------------------------
RAY MEADERS
/s/ MAC F. OGLESBY Director April 1, 1996
- --------------------------
MAC F. OGLESBY
/s/ BENNY W. DENHAM Director April 1, 1996
- --------------------------
BENNY W. DENHAM
/s/ E. L. MCLOCKLIN Director April 1, 1996
- --------------------------
E. L. MCLOCKLIN
/s/ SAM RABUN Director April 1, 1996
- --------------------------
SAM RABUN
/s/ E. J. MARTIN, JR. Director April 1, 1996
- --------------------------
E. J. MARTIN, JR.
/s/ JIM M. KNIGHT Director April 1, 1996
- --------------------------
JIM M. KNIGHT
/s/ RONNIE FLEEMAN Director April 1, 1996
- --------------------------
RONNIE FLEEMAN
/s/ D. LAMAR COOPER Director April 1, 1996
- --------------------------
D. LAMAR COOPER
83
<PAGE>
/s/ BARRY H. MARTIN Director April 1, 1996
- --------------------------
BARRY H. MARTIN
/s/ JOHN B. FLOYD, JR. Director April 1, 1996
- --------------------------
JOHN B. FLOYD, JR.
/s/ STEVE RAWL, SR. Director April 1, 1996
- --------------------------
STEVE RAWL, SR.
/s/ JAMES GRUBBS Director April 1, 1996
- --------------------------
JAMES GRUBBS
/s/ SAMMY M. JENKINS Director April 1, 1996
- --------------------------
SAMMY M. JENKINS
/s/ J. M. SHERRER Director April 1, 1996
- --------------------------
J. M. SHERRER
/s/ JACK D. VICKERS Director April 1, 1996
- --------------------------
JACK D. VICKERS
/s/ C. W. COX, JR. Director April 1, 1996
- --------------------------
C. W. COX, JR.
/s/ JOHNNIE CRUMBLEY Director April 1, 1996
- --------------------------
JOHNNIE CRUMBLEY
/s/ JARNETT W. WIGINGTON Director April 1, 1996
- --------------------------
JARNETT W. WIGINGTON
/s/ BOB JERNIGAN Director April 1, 1996
- --------------------------
BOB JERNIGAN
/s/ C. WILLARD MIMS Director April 1, 1996
- --------------------------
C. WILLARD MIMS
/s/ THOMAS NOLES Director April 1, 1996
- --------------------------
THOMAS NOLES
/s/ ROY TOLLERSON, JR. Director April 1, 1996
- --------------------------
ROY TOLLERSON, JR.
/s/ HUBERT HANCOCK Director April 1, 1996
- --------------------------
HUBERT HANCOCK
/s/ HENDRIX B. WILEY, JR. Director April 1, 1996
- --------------------------
HENDRIX B. WILEY, JR.
/s/ W. W. ARCHER Director April 1, 1996
- --------------------------
W. W. ARCHER
84
<PAGE>
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.
85
<PAGE>
RESTRUCTURING AGREEMENT
BY AND AMONG
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION
CORPORATION),
GEORGIA TRANSMISSION CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
AND
GEORGIA SYSTEM OPERATIONS CORPORATION
MARCH 29, 1996
<PAGE>
TABLE OF CONTENTS
ARTICLE 1
<TABLE>
<S> <C> <C> <C>
DEFINITIONS . . . . . . . . . . . . . . . 2
1.1 Defined Terms. . . . . . . . . . . . . . . . . . . . . . . . . . . 2
(a) "Business Day". . . . . . . . . . . . . . . . . . . . . . . . 2
(b) "Closing" . . . . . . . . . . . . . . . . . . . . . . . . . . 2
(c) "Closing Conditions". . . . . . . . . . . . . . . . . . . . . 2
(d) "Closing Date". . . . . . . . . . . . . . . . . . . . . . . . 2
(e) "Effective Date". . . . . . . . . . . . . . . . . . . . . . . 2
(f) "Existing Wholesale Power Contracts". . . . . . . . . . . . . 2
(g) "FERC". . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
(h) "FFB" . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
(i) "GSOC Asset Transfer Date". . . . . . . . . . . . . . . . . . 2
(j) "GTC Assumed OPC Debt". . . . . . . . . . . . . . . . . . . . 2
(k) "GTC CoBank Note" . . . . . . . . . . . . . . . . . . . . . . 2
(l) "GTC Credit Suisse Note". . . . . . . . . . . . . . . . . . . 3
(m) "GTC FFB Note(s)" . . . . . . . . . . . . . . . . . . . . . . 3
(n) "GTC Indenture" . . . . . . . . . . . . . . . . . . . . . . . 3
(o) "GTC PCB Assumption Agreements" . . . . . . . . . . . . . . . 3
(p) "GTC RUS Note(s)" . . . . . . . . . . . . . . . . . . . . . . 3
(q) "ITSA". . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
(r) "ITSA O&M Agreement". . . . . . . . . . . . . . . . . . . . . 4
(s) "Joint Committee Agreement" . . . . . . . . . . . . . . . . . 4
(t) "Member Agreement". . . . . . . . . . . . . . . . . . . . . . 4
(u) "New Wholesale Power Contracts" . . . . . . . . . . . . . . . 4
(w) "OPC Bylaw Amendments". . . . . . . . . . . . . . . . . . . . 4
(x) "OPC Closing Date Distribution" . . . . . . . . . . . . . . . 4
(y) "OPC Mortgage". . . . . . . . . . . . . . . . . . . . . . . . 4
(z) "PCB Trustees". . . . . . . . . . . . . . . . . . . . . . . . 5
(aa) "Purchase Price Adjustment" . . . . . . . . . . . . . . . . . 5
(ab) "Purchase Price Adjustment Event" . . . . . . . . . . . . . . 5
(ac) "RUS" . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
(ad) "SEC" . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
(ae) "System Operations Assets". . . . . . . . . . . . . . . . . . 6
(af) "System Operations Business". . . . . . . . . . . . . . . . . 6
(ag) "System Operations Contracts" . . . . . . . . . . . . . . . . 6
(ah) "System Operations Employees" . . . . . . . . . . . . . . . . 6
(ai) "System Operations Functions" . . . . . . . . . . . . . . . . 6
(aj) "System Operations Liabilities" . . . . . . . . . . . . . . . 6
(ak) "Transmission Assets" . . . . . . . . . . . . . . . . . . . . 6
(al) "Transmission Business" . . . . . . . . . . . . . . . . . . . 7
(am) "Transmission Contracts". . . . . . . . . . . . . . . . . . . 7
</TABLE>
i
<PAGE>
<TABLE>
<S> <C> <C> <C>
(an) "Transmission Employees". . . . . . . . . . . . . . . . . . . 7
(ao) "Transmission Functions". . . . . . . . . . . . . . . . . . . 7
(ap) "Transmission Liabilities". . . . . . . . . . . . . . . . . . 7
1.2 Other Definitions. . . . . . . . . . . . . . . . . . . . . . . . . 8
ARTICLE 2
THE RESTRUCTURING. . . . . . . . . . . . . . 8
2.1 The Restructuring and Division of Functions. . . . . . . . . . . . 8
(a) Systems Operations Business . . . . . . . . . . . . . . . . . 8
(b) OPC Closing Date Distribution . . . . . . . . . . . . . . . . 9
(c) Transmission Business . . . . . . . . . . . . . . . . . . . . 9
2.2 New Wholesale Power Contracts. . . . . . . . . . . . . . . . . . . 9
2.3 OPC Closing Date Distribution. . . . . . . . . . . . . . . . . . . 9
(a) Allocation Among Members. . . . . . . . . . . . . . . . . . . 9
(b) Methodology for Charging Each Member's Patronage Account. . . 9
2.4 Acquisition of Transmission Business . . . . . . . . . . . . . . . 9
(a) Purchase and Sale of Transmission Assets. . . . . . . . . . . 10
(b) Assumption of Transmission Liabilities. . . . . . . . . . . . 10
(c) Purchase Price. . . . . . . . . . . . . . . . . . . . . . . . 10
(d) Payment of Purchase Price . . . . . . . . . . . . . . . . . . 11
(e) Transfer of Employees . . . . . . . . . . . . . . . . . . . . 11
(f) Adjustment to Purchase Price Resulting from Certain Events
Subsequent to the Closing Date. . . . . . . . . . . . . . . . 11
(g) Assets Owned in Common. . . . . . . . . . . . . . . . . . . . 11
2.5 Transmission Contracts . . . . . . . . . . . . . . . . . . . . . . 12
2.6 Transfer of System Operations Business . . . . . . . . . . . . . . 12
(a) Purchase and Sale of System Operations Assets . . . . . . . . 12
(b) Assumption of System Operations Liabilities . . . . . . . . . 12
(c) Purchase Price. . . . . . . . . . . . . . . . . . . . . . . . 13
(d) Security Agreement. . . . . . . . . . . . . . . . . . . . . . 13
(e) Transfer of Employees . . . . . . . . . . . . . . . . . . . . 13
2.7 System Operations Services . . . . . . . . . . . . . . . . . . . . 13
2.8 Change of OPC Name . . . . . . . . . . . . . . . . . . . . . . . . 14
2.9 Provision of Administrative Services . . . . . . . . . . . . . . . 14
2.10 Office Space Leases. . . . . . . . . . . . . . . . . . . . . . . . 14
2.11 Employee Benefit Plans . . . . . . . . . . . . . . . . . . . . . . 14
(a) Amendments To Be Adopted. . . . . . . . . . . . . . . . . . . 14
(c) Plans Covered . . . . . . . . . . . . . . . . . . . . . . . . 15
(d) Right to Terminate Sponsorship. . . . . . . . . . . . . . . . 15
2.12 Further Assurances . . . . . . . . . . . . . . . . . . . . . . . . 15
</TABLE>
ii
<PAGE>
ARTICLE 3
<TABLE>
<S> <C> <C> <C>
OPC GOVERNANCE MATTERS. . . . . . . . . . . . . 15
3.1 New OPC Governance . . . . . . . . . . . . . . . . . . . . . . . . 15
(a) Conditions to Full Implementation of Governance Changes . . . 16
(b) Possible Modifications. . . . . . . . . . . . . . . . . . . . 16
3.2 Interim Governance . . . . . . . . . . . . . . . . . . . . . . . . 16
ARTICLE 4
REPRESENTATIONS AND WARRANTIES OF OPC. . . . . . . . . 16
4.1 Organization and Qualification, Etc. . . . . . . . . . . . . . . . 16
4.2 Authorization, Etc . . . . . . . . . . . . . . . . . . . . . . . . 17
4.3 Non-Contravention. . . . . . . . . . . . . . . . . . . . . . . . . 17
4.4 Governmental Consents, Etc . . . . . . . . . . . . . . . . . . . . 17
ARTICLE 5
REPRESENTATIONS AND WARRANTIES OF GTC AND GSOC. . . . . . . 18
5.1 Organization and Qualification, Etc. . . . . . . . . . . . . . . . 18
5.2 Authorization, Etc . . . . . . . . . . . . . . . . . . . . . . . . 18
5.3 Non-Contravention. . . . . . . . . . . . . . . . . . . . . . . . . 18
5.4 Governmental Consents, Etc . . . . . . . . . . . . . . . . . . . . 19
ARTICLE 6
ADDITIONAL COVENANTS AND AGREEMENTS . . . . . . . . . 19
6.1 Conduct of Business. . . . . . . . . . . . . . . . . . . . . . . . 19
6.2 Interim Cost Allocations . . . . . . . . . . . . . . . . . . . . . 19
6.3 HSR Act Filings. . . . . . . . . . . . . . . . . . . . . . . . . . 19
6.4 Consents, Authorizations, Etc. . . . . . . . . . . . . . . . . . . 20
(a) OPC Closing Date Distribution . . . . . . . . . . . . . . . . 20
(b) New Wholesale Power Contracts . . . . . . . . . . . . . . . . 20
(c) Release from OPC Mortgage . . . . . . . . . . . . . . . . . . 20
(d) GTC Assumption Documents. . . . . . . . . . . . . . . . . . . 20
(e) Transmission Contracts. . . . . . . . . . . . . . . . . . . . 20
(f) GSOC Matters. . . . . . . . . . . . . . . . . . . . . . . . . 20
(g) System Operations Contracts . . . . . . . . . . . . . . . . . 21
(h) Other Matters Contemplated Hereby . . . . . . . . . . . . . . 21
6.5 IRS Ruling . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
6.6 Access; Confidentiality. . . . . . . . . . . . . . . . . . . . . . 21
(a) Access. . . . . . . . . . . . . . . . . . . . . . . . . . . . 21
(b) Confidentiality . . . . . . . . . . . . . . . . . . . . . . . 21
6.7 Expenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
</TABLE>
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<PAGE>
<TABLE>
<S> <C> <C> <C>
6.8 Publicity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
6.9 Actions to Avoid and Notices of, Breaches of Representations and
Warranties . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22
6.10 Additional Agreements. . . . . . . . . . . . . . . . . . . . . . . 22
ARTICLE 7
CLOSING CONDITIONS. . . . . . . . . . . . . . 22
7.1 Closing Conditions . . . . . . . . . . . . . . . . . . . . . . . . 22
(a) Governance Changes. . . . . . . . . . . . . . . . . . . . . . 23
(b) Member Agreement. . . . . . . . . . . . . . . . . . . . . . . 23
(c) RUS Approvals . . . . . . . . . . . . . . . . . . . . . . . . 23
(d) Hart-Scott-Rodino . . . . . . . . . . . . . . . . . . . . . . 23
(e) PUHCA Matters . . . . . . . . . . . . . . . . . . . . . . . . 23
(f) Federal Power Act Matters . . . . . . . . . . . . . . . . . . 24
(g) No Injunction, Etc. . . . . . . . . . . . . . . . . . . . . . 24
(h) Other Consents, Authorizations, Etc . . . . . . . . . . . . . 24
(i) Representations and Warranties; Compliance With Covenants
and Obligations . . . . . . . . . . . . . . . . . . . . . . . 24
(j) Confirmation of Ratings . . . . . . . . . . . . . . . . . . . 24
(k) New Wholesale Power Contracts . . . . . . . . . . . . . . . . 24
(l) Capital Contributions to GTC. . . . . . . . . . . . . . . . . 25
(m) Appraised Value of Transmission Business. . . . . . . . . . . 25
(n) Transmission Contracts. . . . . . . . . . . . . . . . . . . . 25
(o) Capital Contributions to GSOC . . . . . . . . . . . . . . . . 25
(p) System Operations Contracts . . . . . . . . . . . . . . . . . 25
(q) State Tax Matters . . . . . . . . . . . . . . . . . . . . . . 25
(r) Opinions of Counsel and Certified Resolutions . . . . . . . . 25
7.2 Waiver of Conditions . . . . . . . . . . . . . . . . . . . . . . . 25
ARTICLE 8
CLOSING . . . . . . . . . . . . . . . . 25
8.1 Closing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25
8.3 Deliveries at or prior to GSOC Asset Transfer Date . . . . . . . . 26
ARTICLE 9
TERMINATION AND ABANDONMENT . . . . . . . . . . . 26
9.1 Termination and Abandonment. . . . . . . . . . . . . . . . . . . . 26
(a) By Mutual Action. . . . . . . . . . . . . . . . . . . . . . . 27
(b) By OPC. . . . . . . . . . . . . . . . . . . . . . . . . . . . 27
9.2 Procedure for Termination. . . . . . . . . . . . . . . . . . . . . 27
9.3 Effect of Termination. . . . . . . . . . . . . . . . . . . . . . . 27
</TABLE>
iv
<PAGE>
ARTICLE 10
<TABLE>
<S> <C> <C> <C>
MISCELLANEOUS. . . . . . . . . . . . . . . 27
10.1 No Survival of Representations and Warranties. . . . . . . . . . . 27
10.2 Dispute Resolution and Arbitration . . . . . . . . . . . . . . . . 27
(a) Arbitration Procedures. . . . . . . . . . . . . . . . . . . . 28
(b) Arbitration Decision. . . . . . . . . . . . . . . . . . . . . 28
10.3 Specific Performance, Etc. . . . . . . . . . . . . . . . . . . . . 28
10.4 Waiver . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28
10.5 Notices. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
10.6 Counterparts; Facsimile Delivery . . . . . . . . . . . . . . . . . 29
10.7 Headings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29
10.8 Amendment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
10.9 Severability . . . . . . . . . . . . . . . . . . . . . . . . . . . 30
10.10 Miscellaneous . . . . . . . . . . . . . . . . . . . . . . . . 30
</TABLE>
v
<PAGE>
LIST OF SCHEDULES AND EXHIBITS
SCHEDULES
<TABLE>
<S> <C>
Schedule 1.1(ae) System Operations Assets
Schedule 1.1(ai) System Operations Functions
Schedule 1.1(aj) Certain System Operations Liabilities
Schedule 1.1(ap) Certain Transmission Liabilities
Schedule 2.3 Methodology for Determining OPC Closing Date
Distribution and Members' Closing Date Patronage
Capital
Schedule 2.4(d)(i) Debt Allocation Formula
Schedule 4.3 OPC Non-Contravention Exceptions
Schedule 5.3 GTC and GSOC Non-Contravention Exceptions
EXHIBITS
Exhibit A Draft of GTC PCB Indemnity Agreement between OPC and GTC
Exhibit B Draft of GTC PCB Assumption Agreement between GTC and the
PCB Trustees
Exhibit C Form of GTC Indenture
Exhibit D Draft of System Operations Contract between GSOC and OPC
Exhibit E Draft of System Operations Contract between GSOC and GTC
</TABLE>
vi
<PAGE>
LIST OF CERTAIN DEFINED TERMS
DEFINED IN SECTIONS OTHER THAN SECTION 1.1
<TABLE>
<CAPTION>
Term Section
- ---- -------
<S> <C>
Additional OPC Contract 4.2
Additional GSOC Contract 5.2
Additional GTC Contract 5.2
Agreement Preamble
Applicable Additional Contract 6.4
Closing 8.1
Confidential Material 6.6(b)
Employee Benefit Plan 2.11(c)
GSOC Preamble
GSOC Assumed RUS Note 2.6(c)
GSOC Purchase Money Note 2.6(c)
GSOC Security Agreement 2.6(d)
GTC Preamble
GTC Assumed OPC Deferred Charges 2.4(c)
HSR Act 4.4
IRS Ruling 3.1
Members Preamble
OPC Preamble
OPC Closing Date Distribution 2.3
Representatives 6.6(b)
</TABLE>
vii
<PAGE>
RESTRUCTURING AGREEMENT
This is a Restructuring Agreement (this "Agreement"), dated as of March 29,
1996, by and among Oglethorpe Power Corporation (An Electric Membership
Generation & Transmission Corporation) ("OPC"), Georgia Transmission Corporation
(An Electric Membership Corporation) ("GTC") and Georgia System Operations
Corporation ("GSOC").
BACKGROUND STATEMENT
Since its formation, OPC has provided generation, transmission and
ancillary and other related services for the 39 electric membership cooperatives
that are members of OPC (the "Members") in order to satisfy the Members'
requirements for power. Because of the increasing competition occurring in the
electric industry and related changes in law and regulation, OPC and the Members
have determined that it is in their mutual best interests to restructure OPC to
provide greater flexibility for the future and to settle certain issues and
controversies confronting OPC and the Members, as contemplated by a Statement of
Agreement, dated November 21, 1995, among representatives of OPC and certain
Members named therein, as approved by the OPC Board of Directors on December 4,
1995.
This Agreement sets forth the terms and conditions on which the
restructuring and related changes will occur. Among other things, the
restructuring will separate OPC's "Transmission Business" and its "System
Operations Business" (as such terms are defined below) from OPC's generation
business and any other retained business; OPC will transfer the Transmission
Business to GTC and the System Operations Business to GSOC.
The Boards of Directors of OPC, GTC and GSOC have approved this Agreement,
a separate "Member Agreement" (as defined in Section 1.1), the restructuring and
all other transactions and matters contemplated by this Agreement and by the
Member Agreement. The Board of Directors of OPC also has recommended to the
Members that they join OPC, GTC and GSOC in executing the Member Agreement and
thereby agree among themselves and with OPC, GSOC and GTC as to those matters
contemplated hereby and thereby that directly involve the Members in their
capacities as separate corporations.
AGREEMENT
In consideration of the mutual representations, warranties, covenants and
agreements contained herein, the parties agree as follows:
<PAGE>
ARTICLE 1
DEFINITIONS
1.1 Defined Terms. For the purposes of this Agreement, the following
terms, whether singular or plural, shall have the meanings set forth below:
(a) "BUSINESS DAY" shall mean any day on which both: (i) OPC is open
for business, and (ii) commercial banks in the City of Atlanta and in the City
of New York are not authorized or required to close.
(b) "CLOSING" shall have the meaning specified in Section 8.1.
(c) "CLOSING CONDITIONS" shall mean all of the conditions set forth
in Article 7 of this Agreement.
(d) "CLOSING DATE" shall mean the date on which the Closing occurs
pursuant to Article 8 of this Agreement.
(e) "EFFECTIVE DATE" shall mean (i) January 1, 1997 or (ii) such
other date as the parties may mutually agree.
(f) "EXISTING WHOLESALE POWER CONTRACTS" shall mean the contracts,
dated as of December 1, 1988, between OPC and each Member pursuant to which the
Members currently purchase power and transmission services from OPC.
(g) "FERC" shall mean the Federal Energy Regulatory Commission.
(h) "FFB" shall mean the Federal Financing Bank, which is an
instrumentality and wholly owned corporation of the United States of America.
(i) "GSOC ASSET TRANSFER DATE" shall mean the date on which the
System Operations Assets are sold and transferred to GSOC and GSOC assumes
certain System Operations Liabilities, as provided in Section 2.6.
(j) "GTC ASSUMED OPC DEBT" shall mean that portion of OPC's
indebtedness that GTC assumes pursuant to the GTC CoBank Note, the GTC Credit
Suisse Note, the GTC FFB Note(s), the GTC RUS Note(s) and the GTC PCB Assumption
Agreements.
(k) "GTC COBANK NOTE" shall mean a note in the form required by
CoBank pursuant to which GTC will assume, and replace OPC as an obligor with
respect to, that portion of OPC's indebtedness to CoBank outstanding as of the
Effective Date that the parties have agreed to treat as part of the payment of
the purchase price pursuant to Section 2.4(d)(i).
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<PAGE>
(l) "GTC CREDIT SUISSE NOTE" shall mean a note in the form required
by Credit Suisse pursuant to which GTC will assume, and replace OPC as an
obligor with respect to, that portion of OPC's indebtedness to Credit Suisse
outstanding as of the Effective Date that the parties have agreed to treat as
part of the payment of the purchase price pursuant to Section 2.4(d)(i).
(m) "GTC FFB NOTE(S)" shall mean the note(s) in the form required by
FFB pursuant to which GTC will assume, and replace OPC as an obligor with
respect to, that portion of OPC's indebtedness to the FFB outstanding as of the
Effective Date that the parties have agreed to treat as part of the payment of
the purchase price pursuant to Section 2.4(d)(i).
(n) "GTC INDENTURE" shall mean an Indenture based on the form
attached hereto as Exhibit C, with such changes as may be agreed to by GTC and
RUS prior to Closing, or any other form of real and personal property security
document(s) as GTC and RUS shall mutually agree upon, pursuant to which GTC will
pledge, and grant security title to and a security interest in, substantially
all of the Transmission Assets to secure the GTC FFB Note(s), the GTC RUS
Note(s), the GTC CoBank Note, the GTC Credit Suisse Note and the GTC PCB
Assumption Agreements.
(o) "GTC PCB ASSUMPTION AGREEMENTS" shall mean collectively the
indemnity agreement between GTC and OPC and the assumption agreements between
GTC and the PCB Trustees based on the drafts attached hereto as Exhibits A and
B, respectively, as such drafts may be revised from time to time and, when they
become available, the final forms of such agreements as may be mutually agreed
upon by OPC and GTC in the case of Exhibit A or by GTC and the PCB Trustees in
the case of Exhibit B (in each case with the approval of RUS) prior to Closing,
pursuant to which GTC will agree to assume the obligation to pay that portion of
OPC's pollution control debt secured under the OPC Mortgage (and related
obligations under swap agreements and other hedging transactions) that the
parties have agreed to treat as part of the payment of the purchase price
pursuant to Section 2.4(d)(i).
(p) "GTC RUS NOTE(S)" shall mean the note(s) in the form required by
RUS pursuant to which GTC will assume, and replace OPC as an obligor with
respect to, that portion of OPC's indebtedness to RUS outstanding as of the
Effective Date that the parties have agreed to treat as part of the payment of
the purchase price pursuant to Section 2.4(d)(i).
(q) "ITSA" shall mean the Revised and Restated Integrated
Transmission System Agreement, dated as of November 12, 1990, between OPC and
Georgia Power Company.
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<PAGE>
(r) "ITSA O&M AGREEMENT" shall mean the Transmission Facilities
Operation and Maintenance Contract between Georgia Power Company and OPC, dated
as of June 9, 1986.
(s) "JOINT COMMITTEE AGREEMENT" shall mean the Joint Committee
Agreement, dated as of August 27, 1976, among Georgia Power Company, OPC,
Municipal Electric Authority of Georgia and the City of Dalton, Georgia, as
amended by the First Amendment thereto, dated as of June 19, 1978.
(t) "MEMBER AGREEMENT" shall mean the Member Agreement based on the
draft presented to and approved by the OPC Board of Directors at their March 29,
1996 meeting, as such draft may be revised from time to time and, when it
becomes available, such Member Agreement in final form as executed and delivered
by and among the Members that become parties thereto, OPC, GTC and GSOC (as it
may be amended and supplemented thereafter), pursuant to which the Members that
become parties thereto shall agree with each other and with OPC, GSOC and GTC as
to the matters contemplated by this Agreement that directly involve the Members
in their capacities as separate corporations and as to such other matters that
may be otherwise mutually agreed upon by OPC, GSOC, GTC and the Members affected
by the particular terms or matters involved.
(u) "NEW WHOLESALE POWER CONTRACTS" shall mean the Amended and
Restated Wholesale Power Contracts based on the draft presented to and approved
by the OPC Board of Directors at their March 29, 1996 meeting, as such draft may
be revised from time to time and, when they become available, such contracts in
final form as executed and delivered between OPC and the Members that enter into
such contracts.
(v) "NET BOOK VALUE" of any assets shall mean at any given time the
amount, net of depreciation, at which such assets are recorded on the books of
the owner of such assets.
(w) "OPC BYLAW AMENDMENTS" shall mean the amendments to OPC's Bylaws
in the form adopted by the OPC Member Representatives at their March 29, 1996
annual meeting, subject to the conditions set forth in Section 3.1(a), as such
Bylaw amendments may be amended pursuant to Section 3.1(b).
(x) "OPC CLOSING DATE DISTRIBUTION" shall mean the distribution to be
made by OPC on the Closing Date, as contemplated by Section 2.3.
(y) "OPC MORTGAGE" shall mean the Consolidated Mortgage and Security
Agreement, dated as September 1, 1994, by and among OPC, the United States of
America, acting through the Administrator of the RUS, CoBank, ACB, as successor
in interest to National Bank for Cooperatives, Credit Suisse, acting by and
through its New York Branch, and SunTrust Bank, as successor to Trust Company
Bank (as trustee under certain pollution control bond indentures), as
mortgagees, either as originally executed or as the same may
4
<PAGE>
from time to time be supplemented, modified, amended, renewed, extended or
consolidated, or any alternate mortgage, deed to secure debt, deed of trust,
trust indenture or other security instrument entered into by OPC as a
substitute or replacement for such mortgage, which secures equally and ratably
the payment of principal of and interest on the obligations thereunder and
creates a lien on substantially all of the real and tangible personal property
of OPC in favor of such mortgagees and/or additional and/or substitute
mortgagees or secured parties.
(z) "PCB TRUSTEES" shall mean SunTrust Bank, acting as trustee under
the several pollution control bond indentures identified in the OPC Mortgage.
(aa) "PURCHASE PRICE ADJUSTMENT" shall mean: (A) 75% of that amount,
if any, by which (i) the consideration received by GTC for any sale, lease or
exchange of any part or all of the Transmission Assets constituting a Purchase
Price Adjustment Event exceeds the amount paid to OPC for such Transmission
Assets, or (ii) the value of the Transmission Assets reflected in the
consideration received by GTC or its Members in any merger or consolidation of
GTC or any other disposition or reduction of the Members' capital interests
constituting a Purchase Price Adjustment Event exceeds the amount paid to OPC
for such Transmission Assets, in each case (i) and (ii) net of taxes and other
expenses attributable to the transaction MINUS (B) any Purchase Price Adjustment
previously paid with respect to such Transmission Assets.
(ab) "PURCHASE PRICE ADJUSTMENT EVENT" shall mean the consummation by
GTC or one or more Members of GTC of any one or more transactions after the
Closing Date and prior to the fifth anniversary of the Effective Date (or
thereafter if consummated pursuant to a binding contract entered into after the
Closing Date and prior to the fifth anniversary of the Effective Date) pursuant
to which: (i) GTC sells, leases or exchanges 20% or more, in the aggregate
(measured based on Net Book Value at the time of the transaction or during the
time of any series of related transactions), of the Transmission Assets, or
merges or consolidates with another entity, or (ii) any Member or Members of
GTC, in a transaction or series of transactions involving any party which is not
one of the 39 Members of OPC as of the Effective Date, dispose of or in any
other manner reduce the capital interests in GTC of those entities constituting
the Members in GTC as of the Effective Date (tested separately based on both the
dollar value of such Members' capital interests and the percentage such Members'
capital interests represent of the total GTC capital interests, in each case at
the time of the transaction or during any series of related transactions).
(ac) "RUS" shall mean the Rural Utilities Service, as successor to the
Rural Electrification Administration, which is an agency of the United States
Department of Agriculture, or any governmental agency succeeding to its powers
and functions.
(ad) "SEC" shall mean the Securities and Exchange Commission.
5
<PAGE>
(ae) "SYSTEM OPERATIONS ASSETS" shall mean the computers, other
equipment, equipment leases, and other property of OPC identified on Schedule
1.1(ae) as constituting the System Operations Assets, as such Schedule may be
amended by OPC and GSOC, all of which assets are used to perform the System
Operations Functions.
(af) "SYSTEM OPERATIONS BUSINESS" shall mean the performance of the
System Operations Functions and the use and ownership of and rights to the
System Operations Assets and shall include the System Operations Liabilities.
(ag) "SYSTEM OPERATIONS CONTRACTS" shall mean the contracts based on
the drafts attached hereto as Exhibits D and E to be entered into between GSOC
and OPC and between GSOC and GTC, and the contracts to be entered into between
GSOC and any Member desiring to receive separate scheduling services from GSOC
pursuant to such a contract, based on the draft which was presented to and
approved by the OPC Board of Directors at their March 29, 1996 meeting, in each
case as such drafts may be revised from time to time, and when they become
available, such contracts in final form executed and delivered between the
parties thereto.
(ah) "SYSTEM OPERATIONS EMPLOYEES" shall mean those individuals so
designated by the President and Chief Executive Officer of OPC.
(ai) "SYSTEM OPERATIONS FUNCTIONS" shall mean scheduling, dispatch and
control area services, including the following functions: (i) real-time
optimization and reliability (generation desk); (ii) power delivery (SCADA
desk); (iii) interface management (transmission desk); (iv) data management,
energy accounting and transaction billing; (v) coordinated system operations
planning and compliance management; (vi) pool administration, planning,
reporting and governance; and (vii) operation services; all as more fully
described in the System Operations Functions summary attached hereto as Schedule
1.1(ai).
(aj) "SYSTEM OPERATIONS LIABILITIES" shall mean (i) the obligations
assumed by GSOC from OPC under the leases identified on Schedule 1.1(aj) as such
obligations exist as of the GSOC Asset Transfer Date; and (ii) OPC's obligations
relating to the System Operations Employees which are identified on Schedule
1.1(aj), as such obligations exist as of the Effective Date.
(ak) "TRANSMISSION ASSETS" shall mean all assets of OPC of every kind
and description and wherever located, which, as of the Effective Date, (A) are
properly classified as transmission assets under accounts 350 to 397 of the
System of Accounts as prescribed by RUS in effect on the Effective Date, or (B)
qualify for treatment as "Transmission Facilities" under the ITSA or (C) are
shown on OPC's books as of the Effective Date as transmission assets, plus the
warehouse facility located in Conyers, Georgia and all inventories contained
therein, all claims and rights under work in progress, contracts (including the
right to provide transmission services to the Members in the manner
6
<PAGE>
contemplated by the Transmission Contracts), leases, licenses or other
agreements (whether governmental or private) and rights in condemnation
proceedings and other litigation matters (including by way of counterclaim), in
each case, used in or otherwise relating to its Transmission Business; provided,
however, that the Transmission Assets shall not include: (i) any accounts
receivable of OPC; (ii) any of the real property, buildings and fixtures
constituting OPC's headquarters facility or, except as the parties may
mutually agree, any equipment (except the types expressly specified above),
furniture and other personal property located at OPC's headquarters facility
(subject to OPC's obligations under Section 2.10 to enter into certain office
space leases); (iii) any books or records (subject to OPC's obligations to
provide access and copies pursuant to Section 6.6); (iv) any assets which OPC
owns as a tenant in common with others (except to the extent otherwise provided
by the third sentence of Section 2.4(g)); or (v) any step-up substation
transformers located at generation facilities. For all purposes of this
Agreement, including all provisions relating to the Purchase Price Adjustment,
"Transmission Assets" shall be limited to the assets acquired or to be acquired
by GTC from OPC effective as of the Effective Date.
(al) "TRANSMISSION BUSINESS" shall mean the performance of the
Transmission Functions and the use and ownership of and rights to the
Transmission Assets and shall include the Transmission Liabilities.
(am) "TRANSMISSION CONTRACTS" shall mean the contracts based on the
draft presented to and approved by the OPC Board of Directors at its March 29,
1996 meeting, as such draft is revised from time to time and, when they become
available, the final versions of such contracts, as executed and delivered
between GTC and OPC (the "OPC Transmission Contracts") and between GTC and each
Member (the "Member Transmission Contracts").
(an) "TRANSMISSION EMPLOYEES" shall mean those individuals so
designated by the President and Chief Executive Officer of OPC.
(ao) "TRANSMISSION FUNCTIONS" shall mean (i) the planning, licensing,
design, construction, acquisition, completion, renewal, addition, replacement,
modification and disposal of the transmission facilities included in the
Transmission Assets; (ii) the management, control, operation and maintenance of
such transmission and related facilities; (iii) the planning and procurement of
additional transmission capacity and administration of any contracts related
thereto; (iv) the marketing and disposition of excess facilities and excess
transmission capacity; (v) the performance of obligations and exercise of rights
under the ITSA, the ITSA O&M Agreement, the Joint Committee Agreement and the
Transmission Contracts; (vi) the financing and refinancing of the Transmission
Business Assets; and (vii) related activities, but shall not include the System
Operations Functions.
(ap) "TRANSMISSION LIABILITIES" shall mean (i) all obligations, taxes
and liabilities of every kind and nature, known or unknown, contingent or
otherwise, that exist as of the Effective Date and are primarily related to the
Transmission Business or the
7
<PAGE>
Transmission Employees; and (ii) that portion of OPC's costs, expenses and
other liabilities (except for the OPC Closing Date Distribution) incurred in
effecting the transactions and actions contemplated hereby that corresponds to
the portion of OPC's debt assumed pursuant to Section 2.4(d)(i); provided,
however, that any obligations or liabilities otherwise covered by clause (i)
above shall not be included as Transmission Liabilities to the extent OPC's
President and Chief Executive Officer determines that it would not be in the
best interests of the parties to so include them and so notifies GTC at least
10 Business Days prior to Closing. Without in any way limiting the foregoing,
but subject to the foregoing proviso, the Transmission Liabilities shall include
any and all costs, expenses, obligations and liabilities incurred in connection
with or otherwise relating to any litigation described on Schedule 1.1(ap) and
not paid prior to the Effective Date. Notwithstanding the foregoing,
Transmission Liabilities shall not include: (A) the GTC Assumed OPC Debt; (B)
any taxes or accounts payable to the extent they arise from the conduct of the
Transmission Business prior to the Effective Date; (C) any taxes of any kind
imposed on OPC by reason of the consummation of the transactions contemplated by
this Agreement; (D) or any taxes imposed on any Members of OPC.
1.2 OTHER DEFINITIONS. Certain other terms are defined elsewhere in this
Agreement and have the meanings so indicated. A List of Certain Defined Terms
immediately following the Table of Contents has been included for the
convenience of the parties to assist in locating such definitions, but such list
shall not affect the interpretation of this Agreement.
ARTICLE 2
THE RESTRUCTURING
2.1 THE RESTRUCTURING AND DIVISION OF FUNCTIONS. On the terms and
conditions set forth herein, the Transmission Business and the System Operations
Business shall be separated from OPC's other business functions, assets and
liabilities (including those relating to the generation of power). OPC shall
retain all of its business functions, assets and liabilities that are not being
sold to and assumed by GTC or GSOC.
(a) SYSTEMS OPERATIONS BUSINESS.
(i) As soon as all required approvals have been obtained and the
conditions contained in Section 7.1(e) and (f) have been satisfied or waived,
and without waiting for the Closing of the other transactions contemplated
hereby, the Systems Operations Assets and Liabilities shall be transferred and
sold to and assumed by GSOC, as contemplated by and subject to the provisions
contained in Section 2.6.
(ii) At the Closing, OPC shall transfer to GSOC the System
Operations Employees to the extent contemplated by Section 2.6(e), and GSOC
shall begin
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providing System Operations Functions and related services pursuant
to the System Operations Contracts, as contemplated by Section 2.7.
(b) OPC CLOSING DATE DISTRIBUTION. At the Closing, OPC shall effect
the OPC Closing Date Distribution contemplated by Section 2.3.
(c) TRANSMISSION BUSINESS. At the Closing, the Transmission Business
shall be transferred and sold to and assumed by GTC, as contemplated by Section
2.4. GTC shall begin providing the Transmission Functions and related services
pursuant to the Transmission Contracts, as contemplated by Section 2.5.
2.2 NEW WHOLESALE POWER CONTRACTS. To facilitate the restructuring,
including the transfer of the Transmission Business to GTC, OPC shall seek to
execute and deliver at or before Closing a New Wholesale Power Contract with
each Member pursuant to the Member Agreement. Commencing as of the Effective
Date, provided that RUS approval has been obtained, each New Wholesale Power
Contract shall govern the purchase and sale of power between OPC and each
respective Member party to such New Wholesale Power Contract.
2.3 OPC CLOSING DATE DISTRIBUTION. On the Closing Date, OPC shall make a
special patronage capital distribution to (or at the direction of) its Members
in an aggregate amount determined using the methodology set forth on Schedule
2.3 (the "OPC Closing Date Distribution").
(a) ALLOCATION AMONG MEMBERS. The OPC Closing Date Distribution
shall be made to (or at the direction of) the Members based on allocation
percentages determined by dividing each Member's patronage capital in OPC on the
Closing Date by the total of all Members' patronage capital in OPC on the
Closing Date.
(b) METHODOLOGY FOR CHARGING EACH MEMBER'S PATRONAGE ACCOUNT. For
purposes of charging each Member's patronage account, such distribution shall be
allocated on a proportional basis to each annual period for which any portion of
such Member's total patronage capital has been allocated.
2.4 ACQUISITION OF TRANSMISSION BUSINESS. At the Closing, the
Transmission Business shall be transferred by OPC to GTC in a complete and bona
fide liquidation of OPC's Transmission Business. The parties shall cooperate
with one another in taking such actions and making such adjustments as shall be
appropriate to cause the economic consequences of such actions and changes to be
effective, to the maximum extent feasible and reasonable, as of the Effective
Date. The parties acknowledge and agree that the precise identity of certain of
the Transmission Assets and the Transmission Liabilities, as well as the amount
of the purchase price, initially and preliminarily will be based on OPC's
projected financial statements and records as of December 31, 1996, but shall be
subject to adjustment when OPC's actual financial statements and records as of
December 31, 1996
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become available in final form. The parties shall cooperate with each other in
taking such actions as shall be appropriate to effect and reflect such
adjustments.
(a) PURCHASE AND SALE OF TRANSMISSION ASSETS. At the Closing,
effective as of the Effective Date, OPC shall sell, convey, transfer, assign and
deliver to GTC, and GTC will receive and accept, all of the Transmission Assets.
At the Closing, OPC shall deliver to GTC limited warranty deeds conveying to GTC
all of OPC's right, title and interest in and to the real property included in
the Transmission Assets, subject to the reservation by OPC of a nonexclusive
easement to use such property in any way that does not interfere with GTC's use
of such property to conduct the Transmission Business, and all bills of sale,
endorsements, assignments and other good and sufficient instruments of
conveyance and transfer as shall be effective to vest in GTC all of OPC's right,
title and interest in and to all other Transmission Assets. At the Closing, OPC
will take such other steps as may be reasonably required to put GTC in actual
possession and operating control of the Transmission Assets and Transmission
Business. From time to time after the Closing, at GTC's request and expense but
without further consideration, OPC will execute and deliver such other
instruments of conveyance and transfer and take such other actions as GTC
reasonably may require to vest more effectively in GTC, and to put GTC in
possession of, the Transmission Assets, subject to the above mentioned easement
reserved by OPC.
(b) ASSUMPTION OF TRANSMISSION LIABILITIES. At the Closing,
effective as of the Effective Date, GTC shall execute and deliver to OPC and to
such other persons and entities as may be appropriate all such assumptions of
liability, endorsements, acknowledgments of assignment, and such other
instruments as shall be effective to evidence and effect GTC's assumption and
agreement to pay, perform and discharge all Transmission Liabilities.
(c) PURCHASE PRICE. The purchase price for the transfer of the
Transmission Business shall be the sum of:
(i) The appraised fair market value of such business as
determined by an independent appraiser selected by OPC; provided, however, that:
(A) if the appraised fair market value of the Transmission Assets included
within the Transmission Business is less than OPC's Net Book Value for the
Transmission Assets, then the purchase price for such assets shall be OPC's Net
Book Value for such assets, and (B) if the preliminary appraised fair market
value of the Transmission Business as determined prior to Closing exceeds OPC's
Net Book Value for the Transmission Assets by more than 5%, then GTC's payment
of such excess must be approved by GTC's Board of Directors; PLUS
(ii) That portion of OPC's deferred charges relating to OPC's
debt secured under the OPC Mortgage which is determined in accordance with the
allocation formula set forth on Schedule 2.4(d)(i) (the "GTC Assumed OPC
Deferred Charges").
For purposes of the Closing, the purchase price shall be determined on a
preliminary basis using an appraisal based on OPC's projected financial
statements and records as of
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December 31, 1996. Not later than March 15, 1997, a final appraisal, based on
OPC's actual financial statements and records as of December 31, 1996 shall be
prepared by the same appraiser that prepared the preliminary appraisal and shall
be used to determine the final purchase price, but no further approval by GTC's
Board of Directors shall be required under clause (i)(B) above to the extent
the final appraised fair market value of the Transmission Business exceeds OPC's
Net Book Value for the Transmission Assets by more than 5%.
(d) PAYMENT OF PURCHASE PRICE. Such purchase price shall be paid:
(i) By GTC's assumption at the Closing Date, effective as of the
Effective Date (as evidenced and effected by delivery of the GTC Indenture, the
GTC FFB Note(s), the GTC RUS Note(s), the GTC CoBank Note, the GTC Credit Suisse
Note and the GTC PCB Assumption Agreements) of that portion of OPC's debt
secured under the OPC Mortgage which is determined by the allocation formula set
forth on Schedule 2.4(d)(i), along with certain related obligations under swap
agreements and other hedging transactions; and
(ii) The balance due based on the preliminary appraisal available
prior to Closing shall be paid in cash by wire transfer on the Closing Date and
any additional payment due from GTC (or any refund by OPC of a portion of the
initial payment due to GTC) based on the final appraisal obtained after Closing
shall be paid by the party owing such amount in cash by wire transfer within 10
Business Days after receipt of the final appraisal.
(e) TRANSFER OF EMPLOYEES. As of the Effective Date, OPC will
terminate the employment of all Transmission Employees of OPC. GTC shall
immediately thereupon have the right to employ such employees upon such terms
and conditions as GTC shall determine. For any such employees so hired, the
provision of any benefits under the "Employee Benefit Plans" (as hereinafter
defined) shall be pursuant to Section 2.11. This paragraph (e) does not and
shall not be construed to create any rights (of continued employment or
otherwise) in any employee or any other third party.
(f) ADJUSTMENT TO PURCHASE PRICE RESULTING FROM CERTAIN EVENTS
SUBSEQUENT TO THE CLOSING DATE. Upon the occurrence of any Purchase Price
Adjustment Event, the purchase price for the Transmission Assets purchased from
OPC pursuant to this Agreement, as determined pursuant to Section 2.4(c) of this
Agreement, shall be increased by an amount equal to the Purchase Price
Adjustment. The Purchase Price Adjustment, if any, shall be paid to OPC by GTC
(or any successor entity) in cash within 90 days after the occurrence of the
applicable Purchase Price Adjustment Event.
(g) ASSETS OWNED IN COMMON. Any asset that would be a Transmission
Asset but for the exclusion of assets owned in common under clause (iv) of the
definition of Transmission Assets in Section 1.1 shall be the subject of a lease
or other agreement between OPC and GTC pursuant to which, from and after the
Effective Date and for mutually agreed consideration from GTC to OPC, GTC shall
have the right to use, possess
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and operate such assets as fully as may be permitted by the terms of any
agreements relating to the common ownership of such assets. Any such lease or
other agreement shall be upon such terms as OPC and GTC shall agree. If OPC
is permitted by the terms of any agreements relating to the common ownership of
such assets and by any necessary consents, waivers or other actions of the other
co-owner(s) of such assets to transfer OPC's interest in the title to such
assets, then such assets, to the extent of OPC's interest therein, shall be
treated as part of the Transmission Assets. Nothing in this Section 2.4(g) shall
affect the exclusion from Transmission Assets of step-up substation transformers
located at generation facilities.
2.5 TRANSMISSION CONTRACTS. At or before the Closing, GTC shall seek to
execute and deliver Member Transmission Contract(s) with each Member pursuant to
the Member Agreement, and GTC and OPC shall execute and deliver OPC Transmission
Contract(s), pursuant to which GTC shall provide the Transmission Functions and
related services to the Members and to OPC.
2.6 TRANSFER OF SYSTEM OPERATIONS BUSINESS. As soon as all required
approvals have been obtained and the conditions contained in Sections 7.1(e) and
(f) have been satisfied or waived (which may be earlier, but no later, than the
Closing), OPC and GSOC shall mutually determine the GSOC Asset Transfer Date on
which the System Operations Assets shall be transferred and sold to GSOC and
GSOC shall assume the System Operations Liabilities.
(a) PURCHASE AND SALE OF SYSTEM OPERATIONS ASSETS. On the GSOC Asset
Transfer Date, OPC shall sell, convey, transfer, assign and deliver to GSOC, and
GSOC will receive and accept, all of the System Operations Assets, subject to
the continuing lien of the OPC Mortgage. On the GSOC Asset Transfer Date, OPC
shall deliver to GSOC all such bills of sale, endorsements, assignments and
other good and sufficient instruments of conveyance and transfer as shall be
effective to vest in GSOC all of OPC's title to and interest in the System
Operations Assets, subject to the continuing lien of the OPC Mortgage. On the
GSOC Asset Transfer Date, OPC will take such other steps as may be reasonably
required to put GSOC in actual possession and operating control of the System
Operations Assets and System Operations Business. From time to time thereafter,
at GSOC's request and expense but without further consideration, OPC will
execute and deliver such other instruments of conveyance and transfer and take
such other actions as GSOC reasonably may require to vest more effectively in
GSOC, and to put GSOC in possession of, the System Operations Assets, subject to
the continuing lien of the OPC Mortgage. OPC and GSOC will enter into
appropriate agreements to permit OPC such use of the System Operations Assets as
it may require prior to the Closing Date.
(b) ASSUMPTION OF SYSTEM OPERATIONS LIABILITIES. On the GSOC Asset
Transfer Date, GSOC shall execute and deliver to OPC all such assumptions of
liability, endorsements, acknowledgments of assignment, and such other
instruments as shall be effective to evidence and effect GSOC's assumption and
agreement to pay, perform and discharge all System Operations Liabilities.
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(c) PURCHASE PRICE. The purchase price for the System Operations
Assets shall be the Net Book Value of such assets. Such purchase price shall be
paid on the GSOC Asset Transfer Date:
(i) By GSOC's assumption of OPC's obligations under that certain
Note from OPC, dated January 1, 1984, in the original principal amount of
$5,543,000, which is payable to RUS (as successor to the Rural Electrification
Administration) and has a final maturity of May 31, 2019, as such obligations
exist on the GSOC Asset Transfer Date, which assumption shall be evidenced by
GSOC's execution and delivery of a promissory note or other assumption document
in the form required by RUS (the "GSOC Assumed RUS Note"); and
(ii) By GSOC's execution and delivery to OPC of a purchase money
note (the "GSOC Purchase Money Note") for the portion of the purchase price in
excess of: (A) the balance due under the GSOC Assumed RUS Note and (B) any
capital leases assumed as part of the System Operations Liabilities.
The GSOC Assumed RUS Note and the GSOC Purchase Money Note shall contain such
terms and conditions as RUS shall approve (with the concurrence of OPC in the
case of the GSOC Purchase Money Note). In lieu of assuming OPC's obligations
under the note identified in clause (i) above, GSOC, at its option, may pay such
portion of the purchase price for the System Operations Assets by making a cash
payment and/or increasing the amount of the GSOC Purchase Money Note, by an
aggregate amount equal to the principal amount that would have been assumed
under such note.
(d) SECURITY AGREEMENT. GSOC's obligations under the GSOC Assumed
RUS Note and the GSOC Purchase Money Note shall be secured under a Security
Agreement covering all property of GSOC in favor of RUS and OPC (the "GSOC
Security Agreement"). The GSOC Security Agreement shall contain such terms and
conditions as RUS shall approve.
(e) TRANSFER OF EMPLOYEES. As of the Effective Date, OPC will
terminate the employment of all System Operations Employees of OPC. GSOC shall
immediately thereupon have the right to employ such employees upon such terms
and conditions as GSOC shall determine. For any such employees so hired, the
provision of any benefits under the Employee Benefit Plans shall be pursuant to
Section 2.11. This paragraph (e) does not and shall not be construed to create
any rights (of continued employment or otherwise) in any employee or any other
third party.
2.7 SYSTEM OPERATIONS SERVICES. At or before the Closing, GSOC and OPC
shall execute and deliver a Systems Operations Contract based on the draft
attached hereto as Exhibit D; GSOC and GTC shall execute and deliver a System
Operations Contract based on the draft attached hereto as Exhibit E; and GSOC
shall execute and deliver a System Operations Contract based on the draft to be
attached as an Exhibit to the Member Agreement with each Member desiring to
receive separate scheduling services from GSOC
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pursuant to such a contract, as contemplated by the Member Agreement, in each
case as such drafts may be modified by mutual agreement of the parties thereto.
Effective as of the Effective Date, GSOC shall begin providing the System
Operations Functions and related services pursuant to the System Operations
Contracts.
2.8 CHANGE OF OPC NAME. Promptly following the Closing Date, OPC's name
shall be changed to "Oglethorpe Power Corporation (An Electric Membership
Corporation)." OPC shall execute and file the appropriate documents with the
Georgia Secretary of State to effect such name change.
2.9 PROVISION OF ADMINISTRATIVE SERVICES. At or before the Closing, OPC
and GTC shall execute and deliver an administrative services contract, and OPC
and GSOC shall execute and deliver an administrative services contract, both
substantially in the form recommended by OPC's President and Chief Executive
Officer, subject to such changes as the parties thereto may mutually agree upon.
Effective as of the Effective Date, OPC shall begin providing to GTC and GSOC
pursuant to the administrative services contracts the administrative services
specified therein.
2.10 OFFICE SPACE LEASES. At or before the Closing, OPC and GTC shall
execute and deliver an office space lease, and OPC and GSOC shall execute and
deliver an office space lease, both substantially in the form recommended by
OPC's President and Chief Executive Officer, subject to such changes as the
parties thereto may mutually agree upon. Effective as of the Effective Date,
OPC shall begin leasing office space to GTC and GSOC pursuant to the office
space leases.
2.11 EMPLOYEE BENEFIT PLANS. As soon as practical after the Closing Date,
OPC shall amend its "Employee Benefit Plans," as hereinafter defined, to permit
the Employee Benefit Plans to be jointly sponsored by OPC, GTC, GSOC and any
other employer acceptable by OPC. Each such Employee Benefit Plan shall be a
single plan, with all plan assets available to pay benefits to participating
employees of any sponsoring employer.
(a) AMENDMENTS TO BE ADOPTED. Each such Employee Benefit Plan shall
be amended: (i) to credit employees of OPC, GTC, GSOC and any other sponsoring
employer with service with, and compensation paid by, OPC, GTC, GSOC or any
other sponsoring employer; (ii) to authorize the Board of Directors of OPC to
appoint the plan administrator of such plan; and (iii) to authorize the Board of
Directors of OPC to amend such plans, provided that any amendment that
materially increases the benefit cost to GTC, GSOC or any other sponsoring
employer shall be subject to the approval of the Board of Directors of GTC, the
Board of Directors of GSOC or the governing body of such other sponsoring
employers, which approval may not be unreasonably withheld by such Board of
Directors or other governing body.
(b) ALLOCATION OF COSTS. The benefit and administrative cost of each
such Employee Benefit Plan shall be allocated among OPC, GTC, GSOC and every
other sponsoring employer, in a manner determined by the actuary or contract
administrator then
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engaged by OPC on behalf of the plan, so as to most equitably allocate such
costs, including extraordinary one time costs, to the employer whose employees
are covered by the Plan; provided, however, in the case of employee health care
costs, such costs shall be allocated among OPC, GTC, GSOC and every other
sponsoring employer so as to most equitably spread the risk of adverse claim
experience among all such sponsoring employers in proportion to the number of
participating employees employed by such sponsoring employers.
(c) PLANS COVERED. For purposes of this Section 2.11, "Employee
Benefit Plan" shall include the following plans currently sponsored by OPC: (i)
the Retirement Income Plan; (ii) the Retirement Savings Plan; (iii) the Health
Insurance Plan; (iv) the Flexible Spending Account Plan; (v) the Long Term
Disability Plan; (vi) the Group Life Insurance Plan; (vii) the Deferred
Compensation Plan for Key Employees; and (viii) the Business Travel Accident
Insurance Plan.
(d) RIGHT TO TERMINATE SPONSORSHIP. OPC, GTC or GSOC may terminate
its sponsorship of any Employee Benefit Plan upon 90 days advance written notice
to the other parties.
2.12 FURTHER ASSURANCES. If at any time after the Closing Date for GTC or
after the GSOC Asset Transfer Date for GSOC, any further assignments or
assurances are necessary or desirable to vest or to perfect or confirm of record
in GTC or GSOC OPC's title to any property or right included in the Transmission
Assets or the System Operations Assets, respectively (subject to the easement
reserved by OPC pursuant to Section 2.4(a)), or to evidence and effect the
assumption by GTC or GSOC of the Transmission Liabilities or the System
Operations Liabilities, respectively, or otherwise to carry out the provisions
of this Agreement, the officers of OPC, GTC and GSOC are hereby authorized and
empowered on behalf of such respective corporations, in the name of and on
behalf of the appropriate corporation, to execute and deliver any and all things
necessary or proper to vest or to perfect or confirm OPC's title to such
property or rights in GTC or GSOC (subject to the aforementioned easement) or to
evidence and effect such assumption by GTC or GSOC, and otherwise to carry out
the purposes and provisions of this Agreement.
ARTICLE 3
OPC GOVERNANCE MATTERS
3.1 NEW OPC GOVERNANCE. Subject to satisfaction of the conditions
specified below prior to the full implementation of the governance changes
contemplated by the OPC Bylaw Amendments, OPC shall take appropriate steps on a
timely basis to elect a new Board of Directors in accordance with the OPC Bylaw
Amendments and to implement the new governance structure contemplated by the OPC
Bylaw Amendments.
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(a) CONDITIONS TO FULL IMPLEMENTATION OF GOVERNANCE CHANGES. The
terms of the individuals elected as the new Board of Directors of OPC pursuant
to the OPC Bylaw Amendments shall commence, and the other governance changes
contemplated by the OPC Bylaw Amendments shall be fully and unconditionally
implemented, only on the Effective Date (or if earlier, on the fifth Business
Day following satisfaction or waiver of the following conditions) and shall be
conditioned upon satisfaction of all of the following conditions (or waiver by
the existing OPC Board of Directors of either or both of the conditions
contained in paragraphs (i) and (ii), provided that any waiver of the condition
in paragraph (ii) is also approved by RUS):
(i) A ruling from the Internal Revenue Service (the "IRS
Ruling") shall have been received to the effect that the adoption and
implementation of the OPC Bylaw Amendments and the New Wholesale Power Contracts
will not affect OPC's status for federal income tax purposes as a corporation
operating on a cooperative basis; and
(ii) Either a New Wholesale Power Contract, including Rate
Schedule A, shall have become effective for each Member or an OPC rate schedule
which allocates to each Member responsibility for the fixed percentage of all
costs of OPC's existing resources as provided in Exhibit 1 to Appendix 1 of Rate
Schedule A to the New Wholesale Power Contracts shall have otherwise become
legally binding and effective as to each Member.
(b) POSSIBLE MODIFICATIONS. If any changes in the governance
provisions contemplated by the OPC Bylaw Amendments are required in order to
obtain the IRS Ruling, OPC and the Members may develop changes that are mutually
acceptable to OPC, the Members and the IRS. Any such modification to the OPC
Bylaw Amendments may be adopted only by the requisite vote of the Members
prescribed by applicable law and by OPC's Bylaws.
3.2 INTERIM GOVERNANCE. Until the terms of the individuals elected as the
new OPC Board of Directors commence and the other governance changes
contemplated by the OPC Bylaw Amendments are fully implemented in accordance
with Section 3.1(a), the existing Board of Directors of OPC shall continue to
serve as the directors of OPC.
ARTICLE 4
REPRESENTATIONS AND WARRANTIES OF OPC
OPC represents and warrants to, and agrees with, GTC and GSOC as follows:
4.1 ORGANIZATION AND QUALIFICATION, ETC. OPC is an electric membership
corporation duly organized, validly existing and in good standing under the laws
of the State of Georgia and has the corporate power and authority to own its
properties and assets and to carry on its business as it is now being conducted.
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4.2 AUTHORIZATION, ETC. OPC has the corporate power and authority to
execute and deliver this Agreement and each additional contract which this
Agreement contemplates will be executed and delivered by OPC (each such contract
being referred to as an "Additional OPC Contract") and to consummate the
transactions and actions contemplated hereby on the part of OPC. The execution
and delivery by OPC of this Agreement and each Additional OPC Contract and the
consummation by OPC of the transactions and actions contemplated on its part
hereby have been duly authorized by the Board of Directors of OPC, and the
Members of OPC have adopted the OPC Bylaw Amendments. This Agreement has been
duly executed and delivered by OPC and is a valid agreement of OPC, enforceable
against OPC in accordance with its terms, subject to (a) bankruptcy, insolvency
and other laws of similar import, (b) principles of equity and (c) applicable
public policy.
4.3 NON-CONTRAVENTION. Except as may be indicated on Schedule 4.3 or as
otherwise contemplated by this Agreement, the execution and delivery by OPC of
this Agreement and each Additional OPC Contract and the consummation of the
transactions and actions contemplated hereby, do not and will not: (a) violate
any provision of the Articles of Incorporation or Bylaws of OPC; (b) violate, or
result (with the giving of notice or the lapse of time or both) in a violation
of any provision of, or result in the acceleration of or entitle any party to
accelerate (whether after the giving of notice or lapse of time or both) any
obligation under, or result in the creation or imposition of any lien, charge,
pledge, security interest or other encumbrance upon any of the property of OPC
pursuant to any provision of, any mortgage, lien, lease, agreement, license,
instrument, law, ordinance, regulation, order, arbitration award, judgment or
decree to which OPC is a party or by which OPC is bound; (c) violate or conflict
with any other restriction of any kind or character to which OPC is subject or
by which any assets of OPC may be bound; or (d) constitute an event permitting
termination of any mortgage, lien, lease, agreement, license or instrument to
which OPC is a party, in each case, if such violation, acceleration, entitlement
to accelerate, creation or imposition of a lien, charge, pledge, security
interest or other encumbrance, conflict, or event would, when taken together
with all such other violations, accelerations, entitlements to accelerate,
creations and impositions of liens, charges, pledges, security interests and
other encumbrances, conflicts, and events, affect materially and adversely the
business of OPC or OPC's ability to consummate the transactions and actions
contemplated by this Agreement.
4.4 GOVERNMENTAL CONSENTS, ETC. Except for the RUS approvals contemplated
by Section 7.1(c), the IRS Ruling contemplated by Section 3.1(a), any filings
and other coordination with the SEC and FERC contemplated by Sections 7.1(e) and
(f), and any filings that may be required with the Federal Trade Commission and
the Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act
of 1976, as amended (the "HSR Act"), no consent, authorization, order or
approval, or filing or registration with, any governmental commission, board or
other regulatory body is required to be made or obtained by OPC for or in
connection with the execution and delivery by OPC of this Agreement and each
Additional OPC Contract and the consummation by OPC of the transactions and
actions contemplated hereby, if the failure to make such filing or registration
or to obtain such consent, authorization, order or approval would have a
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material and adverse effect on OPC or on OPC's ability to consummate the
transactions and actions contemplated by this Agreement.
ARTICLE 5
REPRESENTATIONS AND WARRANTIES OF GTC AND GSOC
GTC and GSOC each represents and warrants to, and agrees with, OPC and each
other as follows, each such corporation making each representation and warranty
severally as to itself only:
5.1 ORGANIZATION AND QUALIFICATION, ETC. GTC is an electric membership
corporation duly organized, validly existing and in good standing under the laws
of the State of Georgia. GSOC is a non-profit corporation duly organized,
validly existing and in good standing under the laws of the State of Georgia.
Each such corporation has the corporate power and authority to own the
properties and assets it will own following the Closing Date (or following the
GSOC Asset Transfer Date in the case of GSOC) and to carry on its business as it
will be conducted following the Closing Date.
5.2 AUTHORIZATION, ETC. Such corporation has the corporate power and
authority to execute and deliver this Agreement and each additional contract
which this Agreement contemplates will be executed and delivered by GTC or GSOC,
as the case may be (each such contract being referred to as an "Additional GTC
Contract" or an "Additional GSOC Contract," respectively) and to consummate the
transactions and actions contemplated hereby on the part of such corporation.
The execution and delivery by such corporation of this Agreement and each
Additional GTC Contract or each Additional GSOC Contract, as the case may be,
and the consummation by such corporation of the transactions and actions
contemplated on its part hereby have been duly authorized by the Board of
Directors of such corporation. This Agreement has been duly executed and
delivered by such corporation and is a valid agreement of such corporation,
enforceable against such corporation in accordance with its terms, subject to
(a) bankruptcy, insolvency and other laws of similar import, (b) principles of
equity and (c) applicable public policy.
5.3 NON-CONTRAVENTION. Except as may be indicated on Schedule 5.3 or as
otherwise contemplated by this Agreement, the execution and delivery by such
corporation of this Agreement and each Additional GTC Contract or Additional
GSOC Contract, as the case may be, and the consummation of the transactions and
actions contemplated hereby, do not and will not: (a) violate any provision of
the Articles of Incorporation or Bylaws of such corporation; (b) violate, or
result (with the giving of notice or the lapse of time or both) in a violation
of any provision of, or result in the acceleration of or entitle any party to
accelerate (whether after the giving of notice or lapse of time or both) any
obligation under, or result in the creation or imposition of any lien, charge,
pledge, security interest or other encumbrance upon any of the property of such
corporation pursuant to any provision of, any mortgage, lien, lease, agreement,
license, instrument, law, ordinance, regulation, order,
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arbitration award, judgment or decree to which such corporation is a party or
by which such corporation is bound; (c) violate or conflict with any other
restriction of any kind or character to which such corporation is subject or
by which any assets of such corporation may be bound; or (d) constitute an
event permitting termination of any mortgage, lien, lease, agreement, license
or instrument to which such corporation is a party, in each case, if such
violation, acceleration, entitlement to accelerate, creation or imposition of
a lien, charge, pledge, security interest or other encumbrance, conflict, or
event would, when taken together with all such other violations, accelerations,
entitlements to accelerate, creations and impositions of liens, charges,
pledges, security interests and other encumbrances, conflicts, and events,
affect materially and adversely the business of such corporation or such
corporation's ability to consummate the transactions and actions contemplated
by this Agreement.
5.4 GOVERNMENTAL CONSENTS, ETC. Except for the RUS approvals contemplated
by Section 7.1(c), the IRS Ruling contemplated by Section 3.1(a), any filings
and other coordination with the SEC and FERC contemplated by Sections 7.1(e) and
(f), and any filings that may be required with the Federal Trade Commission and
the Department of Justice under the HSR Act, no consent, authorization, order or
approval, or filing or registration with, any governmental commission, board or
other regulatory body is required to be made or obtained by such corporation for
or in connection with the execution and delivery by such corporation of this
Agreement and each Additional GTC Contract or Additional GSOC Contract, as the
case may be, and the consummation by such corporation of the transactions and
actions contemplated hereby, if the failure to make such filing or registration
or to obtain such consent, authorization, order or approval would have a
material and adverse effect on such corporation or on such corporation's ability
to consummate the transactions and actions contemplated by this Agreement.
ARTICLE 6
ADDITIONAL COVENANTS AND AGREEMENTS
6.1 CONDUCT OF BUSINESS. OPC covenants that during the period from the
date hereof to the Closing Date, it shall conduct its operations in the ordinary
and usual course of business, except as otherwise provided in or contemplated by
this Agreement.
6.2 INTERIM COST ALLOCATIONS. Subject to any subsequent amendments or
other changes by OPC's Board of Directors (and all necessary approvals thereof),
the interim rate, OPC-15i, approved and adopted by OPC's Board of Directors at
its meeting on December 4, 1995 and currently applicable under the Existing
Wholesale Power Contracts, shall continue in effect in accordance with its terms
until the earlier of the Effective Date or December 31, 1996.
6.3 HSR ACT FILINGS. Following the execution of this Agreement, the
applicable parties shall make appropriate filings as may be required, if any,
with the Federal Trade
19
<PAGE>
Commission and the Department of Justice under the HSR Act, with respect to the
transactions contemplated by this Agreement. In connection with any such
filings, each such party shall, in cooperation with each other, and from time
to time thereafter, make all such further filings and submissions, and take
such further actions, as may be required in connection therewith. Each party
shall furnish the other all information in its possession necessary for
compliance by the other with the provisions of this section. No party shall
withdraw any such filing or submission prior to the termination of this
Agreement without the written consent of each other party required to file
under the HSR Act.
6.4 CONSENTS, AUTHORIZATIONS, ETC. Each party hereto will use its
reasonable efforts to obtain all consents, authorizations, waivers, orders and
approvals from any governmental commission, board or other regulatory body, and
to make all related filings and registrations, which may be necessary or
desirable in connection with the consummation of any of the transactions and
actions contemplated by this Agreement and by each additional contract which
this Agreement contemplates will be executed by such party (each such contract
applicable to a respective party being referred to as an "Applicable Additional
Contract"). Each party also will use its reasonable efforts to obtain all
consents, authorizations, waivers and approvals from any non-governmental third
party which may be necessary or desirable in connection with the consummation of
the transactions and actions contemplated by this Agreement and by each
Applicable Additional Contract. Each party will cooperate fully with the other
parties in assisting them to obtain such consents, authorizations, waivers,
orders and approvals that the other parties are required to obtain or make.
Without in any way limiting the foregoing, the parties shall use their
reasonable efforts to obtain the approval of RUS to all of the following (as
well as the approvals and related actions by FFB, CoBank, Credit Suisse and the
PCB Trustees necessary to implement the matters referenced in subsections (c)
and (d)):
(a) OPC CLOSING DATE DISTRIBUTION. The OPC Closing Date Distribution
contemplated by Section 2.3;
(b) NEW WHOLESALE POWER CONTRACTS. The New Wholesale Power
Contracts;
(c) RELEASE FROM OPC MORTGAGE. Appropriate instruments to release
from the OPC Mortgage and to permit the transfer by OPC to GTC of the
Transmission Business;
(d) GTC ASSUMPTION DOCUMENTS. The GTC PCB Assumption Agreements, the
GTC Indenture, the GTC FFB Note(s), the GTC RUS Note(s), the GTC CoBank Note and
the GTC Credit Suisse Note;
(e) TRANSMISSION CONTRACTS. The Transmission Contracts between GTC
and the Members and GTC and OPC;
(f) GSOC MATTERS. The transfer to GSOC of the System Operations
Business and the assumption by GSOC of the GSOC Assumed OPC Debt;
20
<PAGE>
(g) SYSTEM OPERATIONS CONTRACTS. The System Operations Contracts
between GSOC and GTC, GSOC and OPC, and GSOC and any Members desiring to obtain
separate scheduling services from GSOC; and
(h) OTHER MATTERS CONTEMPLATED HEREBY. Such other transactions,
actions and contracts contemplated by this Agreement to the extent OPC
determines that approval by the RUS of such matters is necessary.
6.5 IRS RULING. OPC shall use its reasonable efforts to obtain a
favorable tax ruling of the Internal Revenue Service meeting the requirements of
Section 3.1(a).
6.6 ACCESS; CONFIDENTIALITY.
(a) ACCESS. Prior to and following the Closing Date, GTC and GSOC
shall continue to have access to the premises, books and records, officers and
employees of OPC at reasonable hours and the right to copy all books and records
relating to the Transmission Business and the System Operations Business,
respectively, as may be necessary or desirable for the conduct of the
Transmission Business and the System Operations Business, respectively. The
officers of OPC will furnish GTC and GSOC with such financial and operating data
and other information with respect to the Transmission Business and the System
Operations Business as GTC and GSOC may request from time to time.
(b) CONFIDENTIALITY. Except as otherwise required in filings which
any party makes with regulatory entities, any information which any party
provides to the other or to the other's Representatives, whether written or
oral, shall be treated as confidential material (the "Confidential Material"),
except that this shall not apply to information that is generally available to
the public or becomes generally available to the public other than as a result
of a disclosure by the receiving party or its Representatives. For purposes of
this Agreement, the term "Representatives" shall mean a party's directors,
officers, employees, attorneys, accountants, investment bankers, brokers,
bankers and others engaged by such party or intended to be engaged by such party
to advise it regarding the Confidential Material or the transactions
contemplated hereby or to assist in financing the transactions contemplated
hereby and who receive Confidential Material. It is hereby agreed that the
Confidential Material will be used by the receiving party and/or its
Representatives only for purposes of evaluating and facilitating the
transactions contemplated hereby, and that the Confidential Material will be
kept confidential by the receiving party and its Representatives; provided,
however, that (i) any of such information may be disclosed to the receiving
party's Representatives who need to know such information for purposes relating
to the transactions contemplated hereby (it being understood that such
Representatives shall be informed by the receiving party of the confidential
nature of such information and shall be directed by the receiving party to treat
such information confidentially), and (ii) any other disclosure of such
information may be made to which the party providing the information consents in
writing. The provisions of this Section 6.6(b) shall remain in effect for a
period of three years after the date hereof; provided, however, that following
the Effective Date, GTC and GSOC and their respective Representatives shall not
be restricted hereunder with respect
21
<PAGE>
to any information regarding the Transmission Business and the System
Operations Business, respectively.
6.7 EXPENSES. Whether or not the transactions and actions contemplated by
this Agreement are consummated, all costs and expenses (including reasonable
attorneys' and accountants' fees) incurred in connection with this Agreement and
the transactions and actions contemplated hereby shall be paid by the party
incurring such expenses, subject to the obligation of GTC to assume that portion
of OPC's expenses included in the definition of Transmission Liabilities.
6.8 PUBLICITY. Except as otherwise required by law, OPC shall coordinate
any press releases or other public announcements with respect to this Agreement
and the transactions contemplated hereby, and neither GTC nor GSOC shall act
unilaterally in this regard without prior consultation with OPC.
6.9 ACTIONS TO AVOID AND NOTICES OF, BREACHES OF REPRESENTATIONS AND
WARRANTIES. Each party: (a) shall take such actions so that such party's
representations and warranties in this Agreement remain true and correct and
shall not take any action that would cause such representations and warranties
to cease to be true and correct; and (b) shall inform the other parties hereto
promptly of any facts or circumstances that could be reasonably expected to
constitute or result in a breach of any such party's representations and
warranties in this Agreement.
6.10 ADDITIONAL AGREEMENTS. Subject to the terms and conditions herein
provided, each of the parties hereto agrees to use its reasonable efforts to
take, or cause to be taken, all actions and to do, or cause to be done, all
things necessary, proper or advisable under applicable laws or regulations to
consummate and make effective, as soon as reasonably practicable, the
transactions and actions contemplated by this Agreement.
ARTICLE 7
CLOSING CONDITIONS
7.1 CLOSING CONDITIONS. Subject in each case to the rights of OPC (with
the approval of RUS when applicable) to waive (in whole or in part) any
conditions pursuant to Section 7.2, each party's obligation to consummate the
transactions and actions contemplated by this Agreement is subject to the
fulfillment, to the reasonable satisfaction of such party, of each of the
following conditions, prior to or contemporaneously with the Closing; provided,
however, that the full implementation of the OPC Bylaw Amendments and related
governance changes are subject only to the fulfillment (or waiver) of the
conditions contained in Section 3.1(a), and provided further that the transfer
of the System Operations Assets and Liabilities to GSOC is subject only to the
fulfillment (or waiver) prior to or contemporaneously with the GSOC Asset
Transfer Date of the condition that the parties receive such approvals and
consents described below that are specifically applicable
22
<PAGE>
to such transfer of the System Operation Assets and Liabilities and of the
conditions contained in Sections 7.1(e) and (f).
(a) GOVERNANCE CHANGES. The conditions set forth in Section 3.1(a)
shall have been satisfied or waived in accordance with the provisions of Section
3.1(a), the OPC Bylaw Amendments shall have been implemented on a full and
unconditional basis, and the terms of the individuals elected as the new Board
of Directors of OPC pursuant to the OPC Bylaw Amendments shall have commenced.
(b) MEMBER AGREEMENT. The Member Agreement shall have been executed
and delivered by and among all Members, OPC, GTC and GSOC.
(c) RUS APPROVALS. RUS shall have approved:
(i) The OPC Closing Date Distribution;
(ii) The New Wholesale Power Contracts;
(iii) The transfer of the Transmission Business to GTC, the
related release from the OPC Mortgage contemplated by Section 6.4(c) (which
release shall be joined in by the other secured parties under the OPC Mortgage),
the GTC PCB Assumption Agreements, the GTC Indenture, the GTC FFB Note(s), the
GTC RUS Note(s), the GTC CoBank Note, the GTC Credit Suisse Note, the
Transmission Contracts, the transfer of the System Operations Business to GSOC,
the assumption by GSOC of the GSOC Assumed OPC Debt, and the System Operations
Contracts; and
(iv) The other transactions, actions and contracts contemplated
by this Agreement to the extent OPC determines that approval by the RUS of such
matters is necessary.
(d) HART-SCOTT-RODINO. Any applicable waiting period under the HSR
Act shall have expired or been terminated, and no proceeding by the Department
of Justice or the FTC shall be pending or threatened with respect to the
transactions contemplated by this Agreement, which, if determined adversely,
would have a material adverse effect on the financial condition or results of
operations of OPC, GTC or GSOC.
(e) PUHCA MATTERS. A no-action letter shall have been obtained from
the SEC to the effect that none of the members of GTC or GSOC shall be deemed a
public utility holding company within the meaning of the Public Utility Holding
Company Act of 1935, or there shall have otherwise been obtained assurance
satisfactory to OPC that the parties will be exempt from compliance or in
compliance with such Act and related regulations of the SEC.
23
<PAGE>
(f) FEDERAL POWER ACT MATTERS. There shall have been obtained
assurance satisfactory to OPC that the parties will be exempt from compliance or
in compliance with the Federal Power Act and related regulations of FERC.
(g) NO INJUNCTION, ETC. There shall be no judgment, decree,
injunction, ruling or order of any court, governmental department, commission,
agency or instrumentality outstanding against OPC, GTC or GSOC which prohibits,
restricts or delays consummation of the transactions and other actions
contemplated hereby or limits the right of GTC to control in any material
respect the Transmission Business after the Closing or the right of GSOC to
control in any material respect the System Operations Business after the
transfer of such business to GSOC.
(h) OTHER CONSENTS, AUTHORIZATIONS, ETC. In addition to the
approvals described under any of the foregoing provisions of this Section 7.1,
all other consents, authorizations, waivers, orders and approvals of, and
filings and registrations with, any governmental commission, board or other
regulatory body or any non-governmental third party which are required for or in
connection with the execution and delivery by OPC, GTC and GSOC of this
Agreement and each Applicable Additional Contract and the consummation by OPC,
GTC and GSOC of the transactions and actions contemplated hereby shall have been
obtained or made.
(i) REPRESENTATIONS AND WARRANTIES; COMPLIANCE WITH COVENANTS AND
OBLIGATIONS. In the case of each party: (A) the representations and warranties
of each of the other parties contained in this Agreement shall have been true
and correct at the date hereof and also shall be true and correct in all
material respects at and as of the Closing (and, to the extent applicable, at
and as of the GSOC Asset Transfer Date), except for changes contemplated by this
Agreement, with the same force and effect as if made at and as of the Closing
(and, to the extent applicable, at and as of the GSOC Asset Transfer Date); (B)
each of the other parties shall have performed and complied with in all material
respects all agreements and covenants required by this Agreement to be performed
or complied with by it at or prior to the Closing (and, to the extent
applicable, at or prior to the GSOC Asset Transfer Date); and (C) each party
shall have received one or more certificates of the President or other senior
executive officer of each of the other parties certifying, to the best of his or
her knowledge, all of the foregoing effects.
(j) CONFIRMATION OF RATINGS. OPC shall have received confirmation
from two rating agencies then rating OPC's outstanding fixed rate uninsured
pollution control bonds that the ratings assigned by such rating agencies to
such bonds shall not be lowered as a result of the transactions and actions
contemplated hereby. Such rating agencies also shall have provided satisfactory
assurance that they would assign to any comparable bonds issued directly by GTC
the same or higher ratings as those assigned to OPC's fixed rate uninsured
pollution control bonds on the Effective Date.
(k) NEW WHOLESALE POWER CONTRACTS. A New Wholesale Power Contract
shall have become effective for each Member.
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<PAGE>
(l) CAPITAL CONTRIBUTIONS TO GTC. The Members shall have completed
the actions necessary to become Members of GTC and shall have made the capital
contributions to GTC contemplated by the Member Agreement.
(m) APPRAISED VALUE OF TRANSMISSION BUSINESS. If the appraised value
of the Transmission Business determined on a preliminary basis prior to Closing
in accordance with Section 2.4(c) exceeds OPC's Net Book Value for the
Transmission Assets by more than 5%, the Board of Directors of GTC shall have
approved the payment of such appraised value as the purchase price for such
business.
(n) TRANSMISSION CONTRACTS. The Transmission Contracts between GTC
and each Member and OPC shall have become effective.
(o) CAPITAL CONTRIBUTIONS TO GSOC. The Members shall have completed
the actions necessary to become Members of GSOC and shall have made the capital
contributions to GSOC contemplated by the Member Agreement.
(p) SYSTEM OPERATIONS CONTRACTS. The System Operations Contracts
between GSOC and OPC, GSOC and GTC, and GSOC and each Member desiring separate
scheduling services from GSOC shall have become effective.
(q) STATE TAX MATTERS. Satisfactory assurance shall have been
obtained from the Georgia Department of Revenue (or otherwise) that the transfer
of the Transmission Assets from OPC to GTC will be exempt from Georgia sales
tax.
(r) OPINIONS OF COUNSEL AND CERTIFIED RESOLUTIONS. All opinions of
counsel to each Member and all certificates from each Member as to such legal
matters as RUS shall require to be covered by any opinions or certificates and
all certified resolutions evidencing approval of this Agreement and each
Applicable Additional Contract (in the form required by RUS) shall have been
delivered.
7.2 WAIVER OF CONDITIONS. At its option, the Board of Directors of OPC
may waive any or all of the conditions (in whole or in part) contained herein
(except for those contained in Sections 7.1(c) and 7.1(d)); provided, however,
that the conditions contained in Sections 7.1(k), (n) and (p) may not be waived
without the approval of RUS.
ARTICLE 8
CLOSING
8.1 CLOSING. Provided that all of the conditions set forth in Article 7
shall have been satisfied or waived, evidence of the fulfillment or waiver of
such conditions shall be provided, and all documents and payments required to be
delivered or made or otherwise necessary or desirable to consummate the
transactions contemplated hereby shall be
25
<PAGE>
executed and delivered and paid, by the parties hereto to each other at a
closing (the "Closing") to be held at the offices of Sutherland, Asbill &
Brennan, 999 Peachtree Street, N.E., Atlanta, Georgia 30309 at 10:00 a.m.
Eastern time, on January 2, 1997 (or at such other date, time and place as
OPC, GTC and GSOC may mutually agree). If the parties mutually agree to
reschedule the Closing from January 2, 1997 to another date, the parties
also shall cooperate with each other to make and appropriately document all
adjustments as may be necessary or desirable in other dates contained in
this Agreement which relate to the timing of the Closing.
8.2 PRE-CLOSING. The parties hereto shall cooperate with one another and
shall seek the cooperation of the Members so that: (a) a Pre-Closing can occur
at the Atlanta offices of Sutherland, Asbill & Brennan on a date and at a time
to be set by the OPC Board (on or before December 2, 1996 if possible); and (b)
all documents that are a condition to Closing can be executed and delivered at
or before such Pre-Closing, with such delivery being either to each other or to
Sutherland, Asbill & Brennan to be held in escrow until the Closing Date and
then delivered. The parties hereto agree, and the parties shall seek to obtain
each Member's agreement in the Member Agreement, that any document delivered in
escrow to Sutherland, Asbill & Brennan may be delivered on the Closing Date to
the appropriate recipient(s) without further authorization, unless Barrett K.
Hawks or Cada T. Kilgore, III of Sutherland, Asbill & Brennan actually receives
a written notice from the party or Member that executed such document:
indicating that a representation, warranty, certification, opinion or similar
matter in such document is no longer true; setting forth the specific reason why
such document cannot be delivered; and providing a substitute document which
conforms as nearly as possible to the requirements applicable to the original
document.
8.3 DELIVERIES AT OR PRIOR TO GSOC ASSET TRANSFER DATE. Provided that all
applicable conditions to the sale and transfer of the System Operations Assets
and Liabilities have been satisfied or waived, at or prior to the GSOC Asset
Transfer Date (or any mutually agreed date for pre-closing such transaction),
OPC and GSOC shall execute and deliver all documents necessary or desirable to
consummate such transaction and evidence the satisfaction or waiver of
applicable conditions.
ARTICLE 9
TERMINATION AND ABANDONMENT
9.1 TERMINATION AND ABANDONMENT. This Agreement and all transactions and
actions contemplated hereby may be terminated and abandoned in any manner set
forth below at any time prior to the Closing Date, subject to any earlier
implementation of the effectiveness of the OPC governance changes contemplated
by, and effected pursuant to, Article 3 and subject to any earlier completion of
the transfer of the System Operations Assets and Liabilities to GSOC on the GSOC
Asset Transfer Date:
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<PAGE>
(a) BY MUTUAL ACTION. By mutual action of the Boards of Directors of
OPC, GTC and GSOC.
(b) BY OPC. By OPC if any condition set forth in Section 7.1 shall
not have been complied with or performed in any material respect and such non-
compliance or non-performance shall not have been cured or eliminated (or by its
nature cannot be cured or eliminated other than by waiver) on or before March
15, 1997.
9.2 PROCEDURE FOR TERMINATION. The termination and abandonment of this
Agreement and/or any of the transactions and actions contemplated hereby other
than pursuant to mutual action under Section 9.1(a) shall be effective only when
OPC gives written notice, signed by OPC, stating the grounds for such
termination and abandonment, to the other parties.
9.3 EFFECT OF TERMINATION. In the event of the termination and
abandonment of this Agreement and/or any of the transactions and actions
contemplated hereby, no party shall have any liability (regardless of fault or
control) if such termination and abandonment is by mutual action pursuant to
Section 9.1(a), and no party hereto shall have any liability if this Agreement
and/or any of the transactions and actions contemplated hereby are otherwise
terminated or abandoned in accordance with Section 9.1, unless the failure to
consummate or fulfill a condition is within the reasonable control of such
party, in which case the party or parties having such reasonable control shall
continue to be liable hereunder.
ARTICLE 10
MISCELLANEOUS
10.1 NO SURVIVAL OF REPRESENTATIONS AND WARRANTIES. The representations
and warranties of the parties contained herein shall not survive the Closing.
10.2 DISPUTE RESOLUTION AND ARBITRATION. In the event of any disputes
under this Agreement or any other contracts required hereunder to be entered
into and delivered among the parties hereto, the parties involved in such
dispute shall promptly consult with one another and in good faith seek to
resolve the dispute through negotiation. If such dispute cannot be settled
through negotiation, the parties agree to try in good faith to settle the
dispute by mediation under the Commercial Mediation Rules of the American
Arbitration Association, before resorting to arbitration or some other dispute
resolution procedure; provided that a party may not invoke mediation unless it
has provided the other with written notice of the dispute and has attempted in
good faith to resolve such dispute through negotiation. If the parties involved
in such dispute shall not have reached agreement by negotiation or mediation
within 120 days as to the matter in question, then the matter in dispute shall
be submitted to and settled by arbitration in accordance with the Commercial
Arbitration Rules of the American Arbitration Association (subject to the
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<PAGE>
provisions stated below). Notwithstanding the foregoing, any party may seek
immediate equitable relief, without attempting to settle a dispute through
mediation, in any case where such party is entitled to equitable relief by the
terms of this Agreement or otherwise.
(a) ARBITRATION PROCEDURES. The arbitrators shall have the right to
employ experts to assist them in any arbitration proceeding under this Section
and shall have the right to render equitable, as well as other, awards and
relief. Before submitting a list of potential arbitrators to the parties for
their consideration, the American Arbitration Association shall consult with
each party to discuss the applicable qualifications for the proposed
arbitrators. Upon request by the parties involved in the dispute, the American
Arbitration Association shall select a panel of at least three arbitrators, but
if no such request is made by the time the parties comment on any proposed list
of arbitrators, the American Arbitration Association may select a single
arbitrator unless the American Arbitration Association determines that a greater
number of arbitrators is appropriate.
(b) ARBITRATION DECISION. Any decision of the arbitrator(s) shall be
satisfied as provided in the order of the arbitrator(s). If necessary, any such
decision and satisfaction procedure may be enforced by the prevailing party in
any court of record having jurisdiction over the subject matter or over any of
the parties.
10.3 SPECIFIC PERFORMANCE, ETC. The parties hereto acknowledge that the
rights of the other parties to consummate the transactions contemplated hereby
are special, unique, and of extraordinary character, and that, in the event that
any party violates or threatens to violate or fails and refuses to perform any
covenant made by it herein, then the other parties hereto will be without
adequate remedy at law. Therefore, each party agrees, that, in the event it
violates, breaches, threatens to violate or breach, or fails and refuses to
perform any covenant made by it herein, then the other applicable party or
parties hereto, so long as it or they are not in breach hereof, may, in addition
to any remedies at law, institute and prosecute an action in a court of
competent jurisdiction to enforce specific performance of such covenant or seek
any other equitable relief against the defaulting party.
10.4 WAIVER. The failure of any party hereto at any time or times to
require performance of any provisions hereof shall in no manner affect the right
to enforce the same. No waiver by any party of any condition, or the breach of
any term, provision, warranty, representation, agreement or covenant contained
in this Agreement or the other contracts contemplated hereby, whether by conduct
or otherwise, in any one or more instances shall be deemed or construed as a
further or continuing waiver of any such condition or breach or a waiver of any
other condition or of the breach of any other term, provision, warranty,
representation, agreement or covenant herein or therein contained.
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10.5 NOTICES. Any notices or other communications required or permitted
hereunder shall be sufficiently given if either (a) delivered personally or by
courier, (b) transmitted by telecopy mechanism, provided that any notice so
given is also sent for delivery as provided in clause (a) or mailed as provided
in clause (c), or (c) sent by registered or certified mail, postage prepaid,
addressed to each applicable party at the address shown below (or to such other
address or person as any party shall have designated by notice to the other
party):
<TABLE>
<S> <C>
If to OPC: Oglethorpe Power Corporation
2100 East Exchange Place
Tucker, Georgia 30085-1349
Attention: President and
Chief Executive Officer
Fax: (770) 270-7977
If to GTC: Georgia Transmission Corporation
2100 East Exchange Place
Tucker, Georgia 30085-1349
Attention: President
Fax: (770) 270-7977
If to GSOC: Georgia System Operations Corporation
2100 East Exchange Place
Tucker, Georgia 30085-1349
Attention: President
Fax: (770) 270-7977
</TABLE>
Each such notice or other communication shall be effective (i) if given by
telecopy, when transmitted to the applicable number so specified in (or pursuant
to) this Section and an appropriate answerback is received, or (ii) if given by
any other means, when actually received at such address.
10.6 COUNTERPARTS; FACSIMILE DELIVERY. This Agreement may be executed in
two or more counterparts, each of which shall be deemed an original, but all of
which together shall constitute one and the same instrument. Any party may
deliver an executed copy of this Agreement and an executed copy of any documents
contemplated hereby by facsimile transmission to another party except when the
law expressly requires physical delivery with respect to stock certificates or
other special types of documents, and such delivery shall have the same force
and effect as any other delivery of a manually signed copy of this Agreement or
such other document.
10.7 HEADINGS. The headings herein are for convenience of reference only,
do not constitute a part of this Agreement, and shall not be deemed to limit or
affect any of the provisions hereof.
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<PAGE>
10.8 AMENDMENT. This Agreement may be amended at any time by OPC, GTC and
GSOC by written instrument executed by the parties affected by such amendment.
10.9 SEVERABILITY. If any term or other provision of this Agreement is
invalid, illegal or incapable of being enforced by any rule of law or public
policy, all other terms and provisions of this Agreement will nevertheless
remain in full force and effect so long as the economic or legal substance of
the transactions and other actions contemplated hereby is not affected in any
manner adverse to any party hereto. Upon any such determination that any term
or other provision is invalid, illegal or incapable of being enforced, the
parties hereto will negotiate in good faith to modify this Agreement so as to
effect the original intent of the parties as closely as possible in an
acceptable manner to the end that the transactions and other actions
contemplated by this Agreement are consummated to the extent possible.
10.10 MISCELLANEOUS. This Agreement (a) constitutes the entire
agreement and supersedes all prior agreements and understandings, both written
and oral, among the parties, with respect to the subject matter hereof; (b) is
not intended to confer upon any other person any rights or remedies hereunder;
(c) shall not be assigned, by operation of law or otherwise; and (d) shall be
governed in all respects, including validity, interpretation and effect, by the
laws of the State of Georgia except that the Federal Arbitration Act shall
govern any arbitration proceedings.
[Signatures begin on the following page.]
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<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be
duly executed, and their seals affixed, on the date first above written.
<TABLE>
<S> <C>
OPC:
[CORPORATE SEAL] OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION
& TRANSMISSION CORPORATION)
By: /S/ J. CALVIN EARWOOD
-------------------------------------------
Name: J. CALVIN EARWOOD
-------------------------------------------
Title: Chairman of the Board
-------------------------------------------
Attest:
/s/ Gary M. Bullock
- -----------------------------
Name: Gary M. Bullock
-----------------------
Title: Secretary-Treasurer
-----------------------
GTC:
[CORPORATE SEAL] GEORGIA TRANSMISSION CORPORATION
(AN ELECTRIC MEMBERSHIP
CORPORATION)
By: /S/ T. D. KILGORE
-------------------------------------------
Name: T. D. KILGORE
-------------------------------------------
Title: President
-------------------------------------------
Attest:
/s/ Gary M. Bullock
- -----------------------------
Name: Gary M. Bullock
-----------------------
Title: Secretary-Treasurer
-----------------------
GSOC:
[CORPORATE SEAL] GEORGIA SYSTEM OPERATIONS
CORPORATION
By: /S/ T. D. KILGORE
-------------------------------------------
Name: T. D. KILGORE
-------------------------------------------
Title: President
-------------------------------------------
Attest:
/s/ Gary M. Bullock
- -----------------------------
Name: Gary M. Bullock
-----------------------
Title: Secretary-Treasurer
-----------------------
</TABLE>
<PAGE>
EXHIBIT 10.27
MASTER POWER PURCHASE AND SALE AGREEMENT
BETWEEN
ENRON POWER MARKETING, INC.
AND
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION)
Dated as of January 3, 1996
ACKNOWLEDGEMENT REGARDING CONFIDENTIAL INFORMATION:
Oglethorpe Power Corporation (An Electric Generation & Transmission
Corporation) (the "Company") acknowledges that certain confidential information
is contained throughout the Master Power Purchase and Sale Agreement and the
Exhibits attached thereto and therefore such confidential information has been
omitted from the copy filed with this Annual Report on Form 10-K for the fiscal
year ended December 31, 1995, and an asterisk (*) has been inserted indicating
such omission at the exact place in the Agreement and the Exhibits where such
confidential information has been omitted. A copy of this Agreement without any
omission of confidential information has been filed separately with the
Secretary of the Commission as an attachment to a request for confidentiality
with respect to the omitted information.
<PAGE>
MASTER POWER PURCHASE AND SALE AGREEMENT
BETWEEN
ENRON POWER MARKETING, INC.
AND
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION)
TABLE OF CONTENTS PAGE
ARTICLE 1 DEFINITIONS. . . . . . . . . . . . . . . . . . . 2
ARTICLE 2 SCOPE OF AGREEMENT AND TERM. . . . . . . . . . . 2
2.1 Transactions . . . . . . . . . . . . . . . . . . 2
2.2 Confirmations. . . . . . . . . . . . . . . . . . 2
2.3 Effective Date . . . . . . . . . . . . . . . . . 3
ARTICLE 3 TRANSACTIONS . . . . . . . . . . . . . . . . . . 3
3.1 General Obligations of Seller and Buyer. . . . . 3
3.2 Transmission and Scheduling. . . . . . . . . . . 4
3.3 Title and Risk of Loss . . . . . . . . . . . . . 4
3.4 Failure to Deliver or Receive. . . . . . . . . . 4
3.5 Sales by OPC . . . . . . . . . . . . . . . . . . 5
3.6 Sales by EPMI. . . . . . . . . . . . . . . . . . 9
3.7 Transformer and Transmission Loss Adjustments. . 9
3.8 SEPA Energy. . . . . . . . . . . . . . . . . . . 10
3.9 Imbalances and Regulation Deviation Errors . . . 10
3.10 Non-Territorial Contractual Delivery Obligations 11
ARTICLE 4 PRICE. . . . . . . . . . . . . . . . . . . . . . 11
4.1 OPC's Contract Price . . . . . . . . . . . . . . 11
4.2 EPMI's Contract Price. . . . . . . . . . . . . . 11
4.3 Amounts Due to OPC and EPMI. . . . . . . . . . . 11
4.4 Netting of Payment Obligations . . . . . . . . . 14
4.5 Amendments, Modifications of OPC Contracts . . . 15
ARTICLE 5 CONFIDENTIAL INFORMATION . . . . . . . . . . . . 15
5.1 Prior Confidentiality Agreement
Superseded; Authorization to Use
Information . . . . . . . . . . . . . . . . . 15
5.2 Authorized Disclosure. . . . . . . . . . . . . . 15
5.3 Return of Confidential Information . . . . . . . 16
5.4 Right to Remedies. . . . . . . . . . . . . . . . 16
5.5 Georgia Trade Secrets Act. . . . . . . . . . . . 17
ARTICLE 6 RECORDS. . . . . . . . . . . . . . . . . . . . . 17
6.1 Records of Transactions. . . . . . . . . . . . . 17
ARTICLE 7 BILLING AND PAYMENT. . . . . . . . . . . . . . . 17
7.1 Billing Statements . . . . . . . . . . . . . . . 17
7.2 Offset of Payment Obligations. . . . . . . . . . 17
7.3 Payments . . . . . . . . . . . . . . . . . . . . 18
7.4 Audit Rights . . . . . . . . . . . . . . . . . . 18
<PAGE>
7.5 Subsequent Payment Adjustments . . . . . . . . . 18
ARTICLE 8 TAXES. . . . . . . . . . . . . . . . . . . . . . 19
8.1 Seller's Obligation. . . . . . . . . . . . . . . 19
8.2 Buyer's Obligation . . . . . . . . . . . . . . . 19
8.3 Exemption Certificates . . . . . . . . . . . . . 19
ARTICLE 9 INDEMNIFICATION AND REMEDIES . . . . . . . . . . 19
9.1 General Indemnity. . . . . . . . . . . . . . . . 19
9.2 Limitation on Remedies . . . . . . . . . . . . . 19
9.3 Duty to Mitigate . . . . . . . . . . . . . . . . 20
9.4 DISCLAIMER . . . . . . . . . . . . . . . . . . . 20
[ ]*
ARTICLE 10 REPRESENTATIONS AND WARRANTIES . . . . . . . . . 20
10.1 Mutual Representations . . . . . . . . . . . . . 20
10.2 Additional OPC Representations . . . . . . . . . 21
10.3 Additional EPMI Representations. . . . . . . . . 21
10.4 Good Title . . . . . . . . . . . . . . . . . . . 21
10.5 Continuing Representations and Warranties. . . . 22
ARTICLE 11 DEFAULTS AND REMEDIES. . . . . . . . . . . . . . 22
11.1 Events of Default. . . . . . . . . . . . . . . . 22
11.2 Early Termination; Remedies. . . . . . . . . . . 22
11.3 Special Early Termination Right. . . . . . . . . 23
11.4 Failure to Pay . . . . . . . . . . . . . . . . . 23
11.5 Effect of Regulation . . . . . . . . . . . . . . 23
ARTICLE 12 FORCE MAJEURE. . . . . . . . . . . . . . . . . . 24
12.1 Effect of Force Majeure. . . . . . . . . . . . . 24
ARTICLE 13 MISCELLANEOUS. . . . . . . . . . . . . . . . . . 24
13.1 Assignment . . . . . . . . . . . . . . . . . . . 24
13.2 Notices. . . . . . . . . . . . . . . . . . . . . 24
13.3 Applicable Law . . . . . . . . . . . . . . . . . 25
13.4 Survival of Obligations. . . . . . . . . . . . . 25
13.5 Entire Agreement . . . . . . . . . . . . . . . . 25
13.6 No Partnership . . . . . . . . . . . . . . . . . 25
13.7 Amendment. . . . . . . . . . . . . . . . . . . . 25
13.8 Third Parties. . . . . . . . . . . . . . . . . . 25
13.9 Waiver . . . . . . . . . . . . . . . . . . . . . 25
13.10 Character of Transactions. . . . . . . . . . . . 25
13.11 Severability . . . . . . . . . . . . . . . . . . 25
13.12 Interpretation . . . . . . . . . . . . . . . . . 26
13.13 Headings . . . . . . . . . . . . . . . . . . . . 26
13.14 Counterparts . . . . . . . . . . . . . . . . . . 26
EXHIBITS
- --------------------
* Indicates information that has been filed separately with the Secretary of the
Commission as an attachment to a request for confidentiality with respect to the
omitted information.
-ii-
<PAGE>
MASTER POWER PURCHASE AND SALE AGREEMENT
BETWEEN
ENRON POWER MARKETING, INC.
AND
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION)
This Master Power Purchase and Sale Agreement dated as of January
3, 1996 ("Master Agreement," and together with all Transactions, collectively,
this "Agreement"), is entered into by and between Oglethorpe Power Corporation
(An Electric Membership Generation & Transmission Corporation), a corporation
organized and existing under Title 46 of the Official Code of Georgia Annotated
("OPC"), and Enron Power Marketing, Inc., a corporation organized and existing
under the laws of the State of Delaware ("EPMI").
WITNESSETH
WHEREAS, OPC is an electric generation and transmission corporation
which operates on a cooperative basis and which supplies the electric
requirements of the EMCs for the operation of their respective electric
distribution systems pursuant to the EMC Contracts;
WHEREAS, OPC also has entered into OPC Off-System Sales Contracts listed
on Exhibit 3.5.2 and may, subject to the terms of this Agreement, enter into
additional OPC Off-System Sales Contracts with third parties from time to time;
WHEREAS, EPMI is a power marketer authorized by the Federal Energy
Regulatory Commission to purchase and sell electric energy for resale at
negotiated rates pursuant to EPMI's Rate Schedule No. 1 under orders issued in
ENRON POWER MARKETING, INC., 65 FERC PARA 61,305 (1993) and 66 FERC PARA 61,244
(1994);
WHEREAS, OPC desires to purchase Electric Energy in order to supply the
electric requirements of the EMCs pursuant to the terms of the EMC Contracts and
to satisfy its obligations under the OPC Off-System Sales Contracts and, after
soliciting proposals from various potential suppliers and duly evaluating their
proposals, has selected EPMI for such purpose during the Term of this Agreement;
WHEREAS, EPMI desires to purchase Electric Energy from OPC for resale
(i) to OPC at prices consistent with this Agreement and (ii) to third parties at
negotiated prices;
WHEREAS, the Parties believe that their respective objectives can be
achieved if OPC sells to EPMI all of the Electric Energy OPC is obligated to
take or purchase from Must
<PAGE>
Run Resources and offers to sell to EPMI all of the other Electric Energy which
OPC is entitled to take or purchase, as more specifically set forth herein, and
EPMI agrees to supply OPC with Electric Energy it has purchased from OPC or from
other sources;
WHEREAS, the Parties understand and acknowledge that EPMI shall have and
shall use Confidential Information in the course of satisfying its obligations
under, and in implementing the terms and conditions of, this Agreement and the
Parties desire to protect the Confidential Information in accordance with the
provisions of this Master Agreement instead of pursuant to that certain
Confidentiality Agreement entered into by the Parties, dated as of December 8,
1995; and
WHEREAS, EPMI and OPC desire that with respect to the subject matter of
this Agreement, this Agreement shall supersede and replace any and all prior
agreements between them, including that certain Interchange Agreement dated
March 1, 1995, and that certain agreement dated November 17, 1995.
NOW, THEREFORE, in consideration of the premises and mutual covenants
set forth herein, and for other good and valuable consideration, OPC and EPMI
hereby agree as follows:
ARTICLE 1
DEFINITIONS
All capitalized terms used herein and not otherwise defined shall have
the respective meanings set forth in Appendix A hereto.
ARTICLE 2
SCOPE OF AGREEMENT AND TERM
2.1 TRANSACTIONS. The Parties shall enter into Transactions for the
purchase or sale of Electric Energy hereunder. Each Transaction shall be
effectuated and evidenced in accordance with this Master Agreement and shall
constitute a part of this Agreement. The Parties are relying upon the fact that
all Transactions, together with this Master Agreement, shall constitute a single
integrated agreement, and that the Parties would not otherwise enter into any
Transactions. Any conflict between this Master Agreement and a Transaction
shall be resolved in favor of this Master Agreement. This Master Agreement
shall govern all Transactions between the Parties from and after the Effective
Date unless expressly stated otherwise.
2.2 CONFIRMATIONS. Each Transaction shall be effectuated and
evidenced by (i) a recorded telephone conversation between the Parties whereby
an offer and acceptance
-2-
<PAGE>
shall constitute the agreement of the Parties or (ii) a Transaction Agreement
executed by the Parties (including by facsimile or counterparts). The specific
terms to be established and agreed upon by the Parties shall include the Period
of Delivery, the Contract Price, the Delivery Point(s), the Contract Quantity
and such other terms as the Parties shall agree that are not in conflict with
this Master Agreement; PROVIDED, HOWEVER, that the Parties may modify the
Contract Price, Contract Quantity and Delivery Points with respect to the
purchase and sale of Electric Energy pursuant to the terms of this Master
Agreement. EPMI may confirm a Transaction by forwarding to OPC a Confirmation
substantially in the form of Exhibit 2.2 hereto, which shall be executed by OPC
(with any objections noted thereon) and returned to EPMI within two Business
Days or else be deemed correct as sent; PROVIDED, HOWEVER, that failure to send
a Confirmation shall not invalidate any Transaction agreed to by the Parties.
The Parties agree not to contest or assert any defense to the validity or
enforceability of telephonic Transactions entered into in accordance with this
Master Agreement under Laws relating to whether certain agreements are to be in
writing or signed by the Party to be thereby bound, or the authority of any
employee of such Party to enter into a Transaction. Each Party consents to the
recording of its representatives' telephone conversations without any further
notice. All recordings may be introduced into evidence to prove oral agreements
between the Parties.
2.3 EFFECTIVE DATE. This Master Agreement shall become effective on
the date first written above (the "Effective Date"), provided that the delivery
of Electric Energy pursuant to this Master Agreement shall commence at one
minute prior to 12:01 a.m. EPT on January 4, 1996 ("Commencement Date"), and
shall remain in effect until one second prior to 12:00 midnight EPT on April 30,
1996 (the "Termination Date") unless earlier terminated pursuant to this Master
Agreement (the "Term"); PROVIDED, HOWEVER, that all Transactions shall terminate
no later than the Termination Date. The Term may be extended upon terms
mutually agreeable to the Parties and subject to approval of the RUS, if
required. The applicable provisions of this Master Agreement shall continue in
effect after the Termination Date in accordance with Section 13.4 hereof.
ARTICLE 3
TRANSACTIONS
3.1 GENERAL OBLIGATIONS OF SELLER AND BUYER. With respect to each
Transaction, Seller shall sell and deliver, or cause to be delivered, and Buyer
shall receive, or cause to be received, at the Delivery Point(s) the Contract
Quantity, and Buyer shall pay Seller the Contract Price, as adjusted in
accordance with Article 4 hereof. Except as otherwise specifically addressed in
Section 3.7 hereof, Seller
-3-
<PAGE>
shall be responsible for any costs or charges imposed on or associated with the
delivery of the Contract Quantity (including control area services, transmission
losses and loss charges relating to the transmission of the Contract Quantity)
up to the Delivery Point. Except as otherwise specifically addressed in Section
3.7 hereof, Buyer shall be responsible for any costs or charges imposed on or
associated with the Contract Quantity (including control area services,
transmission losses and loss charges relating to the transmission of the
Contract Quantity) at and from the Delivery Point.
3.2 TRANSMISSION AND SCHEDULING. (a) Seller shall arrange and be
responsible for transmission service to the Delivery Point and shall Schedule or
arrange for Scheduling services with its Transmission Providers to deliver the
Contract Quantity to the Delivery Point. Buyer shall arrange and be responsible
for transmission service at and from the Delivery Point and shall Schedule or
arrange for Scheduling services with its Transmission Providers to receive the
Contract Quantity at the Delivery Point. Each Party shall designate authorized
representatives to effect the Scheduling of the Contract Quantity required to be
delivered and received pursuant to a Transaction. Each Party shall promptly
notify the other of any differences between Scheduled quantities and actual
quantities delivered and received.
(b) Notwithstanding the foregoing, with respect to Transactions
involving or relating to transmission service on the ITS, OPC shall be
responsible for transmission service and shall arrange for any Scheduling with
Georgia Power Company in accordance with EPMI's requests. For Delivery Points
which are Points of Interconnection, at EPMI's request OPC shall Schedule [
]* transfer capability of OPC's allocation entitlement at each
interface set forth on Exhibit 3.2.
3.3 TITLE AND RISK OF LOSS. As between the Parties, Seller shall be
deemed to be in exclusive control (and responsible for any damages or injury
caused thereby) of the Contract Quantity prior to the Delivery Point and Buyer
shall be deemed to be in exclusive control (and responsible for any damages or
injury caused thereby) of the Contract Quantity at and from the Delivery Point.
Title to and risk of loss of the Contract Quantity shall transfer from Seller to
Buyer at the Delivery Point.
3.4 FAILURE TO DELIVER OR RECEIVE. (a) Unless excused by Force
Majeure or the failure of Buyer's performance, if Seller fails to deliver, or
cause to be delivered, the Contract Quantity, Seller shall pay Buyer, on the
date payment would otherwise be due, an amount for each MWh of such deficiency
equal to the positive difference, if any, obtained by subtracting (i) the
Contract Price for that portion of the Contract Quantity which was not delivered
from (ii) the Replacement Price.
- ------------------------
* Indicates information that has been filed separately with the Secretary of
the Commission as an attachment to a request for confidentiality with respect to
the omitted information.
-4-
<PAGE>
"Replacement Price" means the price at which Buyer, acting in a commercially
reasonable manner, purchases substitute Electric Energy not delivered by Seller
(plus any additional transmission charges incurred by Buyer, if any, to the
Delivery Point), including, for example, charges incurred by the Buyer in
respect of purchases of Electric Energy pursuant to Section 3.4(c) hereof, or
absent a purchase, the market price for such quantity at the Delivery Point as
determined by Buyer in a commercially reasonable manner.
(b) Unless excused by Force Majeure or the failure of Seller's
performance, if Buyer fails to receive, or cause to be received, the Contract
Quantity, Buyer shall pay Seller, on the date payment would otherwise be due, an
amount for each MWh of such deficiency equal to the positive difference, if any,
obtained by subtracting (i) the Sales Price from (ii) the Contract Price for
that portion of the Contract Quantity which was not received. "Sales Price"
means the price at which Seller, acting in a commercially reasonable manner,
resells the Electric Energy not received by Buyer (less any additional
transmission charges incurred by Seller, if any, from the Delivery Point to the
point of sale), including, for example, charges incurred by Seller in respect of
sales of Electric Energy pursuant to the CSA, or, absent a resale, the market
price for such quantity at the Delivery Point, as determined by Seller in a
commercially reasonable manner.
(c) If the Electric Energy supplied by EPMI in any hour is
less than OPC Load or if the Electric Energy supplied by OPC in any hour is less
than the amount of OPC Energy Properly Requested by EPMI, the deficiency may be
corrected by a purchase by OPC from Georgia Power Company pursuant to the
applicable schedule of the CSA. Unless excused by Force Majeure, the charge for
such purchase shall be borne by OPC if the deficiency is caused by OPC's failure
to make available the OPC Energy that EPMI Properly Requested, or by EPMI if the
deficiency is caused by EPMI's failure to make available from sources other than
OPC Resources the difference between the OPC Load and OPC Energy that EPMI
Properly Requested to be delivered to OPC.
3.5 SALES BY OPC. For each hour of the Term, OPC shall promptly inform
EPMI of the OPC Resources that are available for the delivery of OPC Energy,
including nuclear OPC Resources and other "must run" resources which are listed
on Exhibit 3.5 hereto ("Must Run Resources") and dispatchable resources.
3.5.1 MUST RUN RESOURCES. OPC shall sell and EPMI shall
purchase all of the OPC Energy associated with Must Run Resources that
are available during each hour of the Term. OPC shall use commercially
reasonable efforts to make Must Run Resources available for the
production and sale of OPC Energy to EPMI during the Term, subject
-5-
<PAGE>
to the terms, conditions and limitations, if any, contained in the OPC
Contracts.
3.5.2 DISPATCHABLE OPC RESOURCES. With respect to OPC
Resources other than Must Run Resources, OPC shall offer to sell to EPMI
on an exclusive basis and EPMI shall have the exclusive right, but not
the obligation, to purchase from OPC any OPC Energy that is available
during each hour of the Term; PROVIDED, HOWEVER, that OPC shall be
permitted to make OPC Off-System Sales pursuant to the OPC Off-System
Sales Contracts, which Electric Energy shall be provided to OPC by EPMI
pursuant to Section 3.6 and at the prices set forth in Section 4.2
hereof. OPC shall use commercially reasonable efforts to make such
dispatchable OPC Resources available for the production and sale of OPC
Energy to EPMI during the Term, subject to the terms, conditions and
limitations, if any, contained in the OPC Contracts. EPMI shall effect
the acceptance of an OPC offer pursuant to the first sentence of this
Section 3.5.2 by complying with the procedures set forth in Section 2.2
hereof. Except with respect to the power purchasers under the OPC Off-
System Sales Contracts listed on Exhibit 3.5.2, OPC shall not be
permitted to make off-system sales of Electric Energy during the Term to
parties other than EPMI without the prior consent of EPMI.
3.5.3 OPC CONTRACTS, RESOURCES AND COSTS. OPC shall be
responsible for compliance with the OPC Contracts and shall take such
rights and obligations into consideration when entering into
Transactions to sell Electric Energy to EPMI. Nothing in this Agreement
shall be construed to assign, impose or otherwise transfer any rights or
obligations under such agreements to EPMI and OPC shall retain all of
its rights and obligations, including but not limited to its obligation
to maintain generation and transmission system stability and
reliability. Notwithstanding any other provision of this Agreement, OPC
shall not be required to take any action inconsistent with its rights
and obligations under either the OPC Contracts or the NERC or SERC
guidelines. Nothing in this Agreement shall affect the rights or
obligations of the parties to the EMC Contracts. OPC acknowledges and
agrees that EPMI requires information concerning OPC Contracts, OPC
Resources, OPC Load and Energy Cost in order to satisfy EPMI's
obligations hereunder. OPC has delivered to EPMI the following
information: (i) a list of all OPC Resources and OPC Contracts and any
proposed or pending amendments to the OPC Contracts, which list is
attached as Exhibit 3.5.3(i) hereto; (ii) a statement of the expected
availability and the transformer loss factor of each OPC Resource,
including nuclear generating units, which statement is
-6-
<PAGE>
attached as Exhibit 3.5.3(ii) hereto; and (iii) a schedule of the Energy
Costs expected to apply to Electric Energy produced by each OPC Resource
during the Term ("Forecast Energy Costs"), which schedule is attached as
Exhibit 3.5.3(iii) hereto. OPC hereby agrees to update such information
promptly as new information becomes available to OPC during the Term and
to promptly provide such updated information to EPMI.
3.5.4 SCHEDULING. The Parties agree to adopt procedures to
facilitate EPMI's ability on an hourly basis to purchase OPC Energy.
The Parties shall also establish procedures whereby OPC shall
communicate to EPMI on an hourly basis the availability of, and
estimated Energy Cost for, each OPC Resource, as such availability and
Energy Cost may change from time to time and the projected OPC Load.
Upon communication of such information, EPMI shall Properly Request the
amounts of Electric Energy that EPMI desires to purchase from each such
OPC Resource in excess of its obligation to purchase OPC Energy from
Must Run Resources. In each hour of the Term, OPC shall sell and
deliver, or cause to be delivered, and EPMI shall purchase and receive,
or cause to be received, the sum of (i) OPC Energy that is attributable
to Must Run Resources and (ii) other OPC Energy that EPMI Properly
Requests for purchase during that hour. The Period of Delivery for OPC
Energy purchased by EPMI from OPC Resources other than Must Run
Resources shall be as specified by EPMI. OPC shall be responsible for
Scheduling transmission service as provided in Section 3.2 hereof.
3.5.5 DELIVERY POINTS. EPMI, in its reasonable discretion,
shall specify one or more Delivery Points for the OPC Energy for each
Transaction in which EPMI is Buyer. OPC shall use commercially
reasonable efforts to accommodate Delivery Point designations by EPMI
consistent with OPC's interests and rights in the ITS and the terms,
conditions and limitations, if any, under the OPC Contracts. OPC shall
promptly inform EPMI of any transmission constraints or other
impediments to satisfying EPMI's Delivery Point designations so that
EPMI may notify OPC of appropriate changes to, or the amount of OPC
Energy to be delivered at, such Delivery Points.
3.5.6 DEEMED ENERGY COST IN THE EVENT OF OPC FAILURE TO
DELIVER FROM CERTAIN OPC RESOURCES. In the event that an OPC Resource
is available for the production of OPC Energy during an hour, EPMI
Properly Requests OPC Energy therefrom and, contrary to EPMI's request,
OPC delivers OPC Energy to EPMI from another OPC Resource, then the
Energy Cost for the OPC Energy made
-7-
<PAGE>
available shall be deemed [
]*. The foregoing
provision shall not apply in the event that OPC shall demonstrate
(either before or after the fact) that its failure to deliver OPC Energy
from the OPC Resource Properly Requested by EPMI is or was a direct
result of a reasonable determination made by OPC, acting in good faith
after consultation with EPMI to the extent reasonably practicable, that
failure to comply with EPMI's request was reasonably required to assure
the stability and reliability of OPC's generation and transmission
system; [
]*. OPC shall use commercially
reasonable efforts to provide EPMI with advance notice of possible
transmission constraints, voltage deterioration or similar system events
or occurrences that might result in a prospective failure by, or
inability of, OPC to Schedule or deliver OPC Energy Properly Requested
by EPMI, either as a result of EPMI's request for OPC Energy or
otherwise, such that EPMI, to the extent practicable, shall be able to
select whether to modify the OPC Resources from which it desires to
receive OPC Energy (or the amount thereof) consistent with the
good-faith and reasonable stability or reliability concerns of OPC or,
alternatively, to bear the risk of acquiring OPC Energy from its
originally designated OPC Resource; PROVIDED, HOWEVER, that it is
specifically agreed by the Parties that in the event EPMI affirms its
originally designated request for OPC Energy from a specific OPC
Resource or does not modify its request consistent with the good-faith
and reasonable recommendations of OPC and, as a result thereof, OPC
incurs additional incremental costs that would not have been incurred in
the absence of OPC complying with EPMI's request, such amounts
(including charges under the CSA) shall be reimbursed by EPMI to OPC.
3.5.7 EMISSION ALLOWANCES. At no cost to EPMI, OPC shall
remain responsible for the surrender of all emission allowances required
to operate the Hal B. Wansley Plant (Units 1 and 2) and other jointly-
owned OPC generating resources and to effect the purchase of energy
- ---------------------
* Indicates information that has been filed separately with the Secretary of
the Commission as an attachment to a request for confidentiality with respect to
the omitted information.
-8-
<PAGE>
under the block power purchase and sale agreement between OPC and
Georgia Power Company. EPMI shall not be deemed to have acquired any
sulfur-free generation for use in a reduced utilization plan by reason
of entering into this Agreement.
3.6 SALES BY EPMI. In each hour of the Term, EPMI shall sell and
deliver, or cause to be delivered, and OPC shall purchase and receive, or cause
to be received, an amount of Electric Energy equal to the sum of the OPC Load
and the OPC Off-System Sales in that hour. EPMI's obligation to supply OPC with
Electric Energy for the purpose of serving OPC Load shall be treated as a single
agreement for which no further authorization or request by OPC other than this
Master Agreement shall be required; PROVIDED, HOWEVER, that OPC shall be
responsible for providing certain ongoing load following, Scheduling and related
ancillary services necessary to effect the sales of Electric Energy by EPMI to
OPC.
3.6.1 DELIVERY POINTS. EPMI, in its reasonable discretion,
shall specify one or more Delivery Points for the Electric Energy for
each Transaction in which EPMI is Seller. OPC shall use commercially
reasonable efforts to accommodate Delivery Point designations by EPMI
consistent with OPC's interests and rights in the ITS and the terms,
conditions and limitations, if any, under the OPC Contracts. OPC shall
promptly inform EPMI of any transmission constraints or other
impediments to satisfying EPMI's Delivery Point designations so that
EPMI may notify OPC of appropriate changes to, or the amount of Electric
Energy to be delivered at, such Delivery Points.
3.7 TRANSFORMER AND TRANSMISSION LOSS ADJUSTMENTS.
(a) With respect to Transactions in which EPMI purchases OPC
Energy from an OPC Resource that is a generating plant which interconnects
directly into the ITS, EPMI shall provide for the transformer losses from the
generator to Level B-1. This shall be effected by EPMI's purchase from OPC of
an amount of MWh equal to the MWh that OPC delivers to Level B-1 divided by the
loss factor stated on Exhibit 3.5.3(ii) for that particular OPC Resource.
(b) For purposes of supplying OPC with Electric Energy to
serve OPC Load, EPMI shall provide for transmission losses which shall be
effected by EPMI delivering, or causing to be delivered, to OPC at one or more
Delivery Points an amount of MWh equal to OPC Load divided by 1 minus the ITS
Loss Factor, as determined pursuant to the ITSA, in effect at the time of each
delivery. EPMI shall not be responsible for any other costs or charges imposed
or associated with the delivery of Electric Energy pursuant to this
Section 3.7(b).
-9-
<PAGE>
(c) For purposes of supplying OPC with Electric Energy to
satisfy OPC's Off-System Sales obligations, EPMI shall provide for transmission
losses which shall be effected by EPMI delivering, or causing to be delivered,
to OPC at one or more Delivery Points an amount of MWh equal to OPC Off-System
Sales divided by 0.97.
(d) For purposes of supplying Electric Energy to satisfy
EPMI's sales obligations to third parties that accept delivery on the ITS or for
delivery at Points of Interconnection, EPMI shall provide for transmission
losses which shall be effected by EPMI delivering, or causing to be delivered,
to OPC at one or more Delivery Points on the ITS an amount of MWh equal to the
amount EPMI desires to receive at the Delivery Point divided by 0.97.
(e) For purposes of supplying Electric Energy to permit OPC to
pump water to the upper reservoir at the Rocky Mountain Pumped Storage
Hydroelectric Generating Facility ("Rocky Mountain"), EPMI shall provide for
transmission losses which shall be effected by EPMI delivering, or causing to be
delivered, to OPC at one or more Delivery Points an amount of MWh equal to the
amount delivered to Rocky Mountain divided by 0.97.
Except as set forth in this Section 3.7, EPMI shall not be responsible for other
transmission costs or charges for ancillary services.
3.8 SEPA ENERGY. Each of the EMCs is entitled to an allocation of
hydroelectric power from SEPA, the cost of which is billed directly by SEPA to
each EMC. OPC and EPMI agree that EPMI's obligation to serve the power supply
requirements of OPC pursuant to this Agreement shall be reduced by the SEPA
Energy Scheduled for delivery to the EMCs pursuant to the SEPA Contracts;
PROVIDED, HOWEVER, that OPC shall Schedule delivery of SEPA Energy to the EMCs
as requested by EPMI consistent with the CSA.
3.9 IMBALANCES AND REGULATION DEVIATION ERRORS. (a) The Parties
recognize that the actual OPC Load may vary in any hour even when the OPC Load
has been reasonably forecast by EPMI and Electric Energy has been Scheduled as
Properly Requested by EPMI. Such variances are expected to be accounted for
pursuant to the CSA (which accounts for various types of imbalances and
regulation deviation errors). If such imbalances and regulation deviation
errors occur, EPMI shall pay the additional charges for which OPC is responsible
pursuant to the CSA as a result thereof, and EPMI shall receive the benefit, if
any, of any revenue or credit received by OPC pursuant to the CSA; PROVIDED,
HOWEVER, that OPC shall be solely responsible for, and shall pay for charges,
credits and revenues, if any, resulting from imbalances
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and regulation deviation errors resulting from a failure to supply Electric
Energy as Properly Requested from EPMI.
(b) In the event that OPC determines that there are material
imbalances and regulation deviation errors which are causing problems in
relationships between OPC and Georgia Power Company, OPC shall so notify EPMI,
and the chief executive officers of OPC and EPMI shall meet to establish
procedures to correct such problems.
3.10 NON-TERRITORIAL CONTRACTUAL DELIVERY OBLIGATIONS.
For purposes of supplying Electric Energy to satisfy EPMI's sales obligations to
third parties that accept delivery on the ITS or delivery at Points of
Interconnection, EPMI shall be responsible for and shall pay charges arising
from any Non-Territorial Contractual Delivery Obligations in the event and to
the extent such charges are imposed on and paid by OPC pursuant to the ITSA.
ARTICLE 4
PRICE
4.1 OPC'S CONTRACT PRICE. Subject to Section 4.3 hereof, the Contract
Price for Electric Energy sold by OPC to EPMI shall be the Energy Cost for OPC
Energy that EPMI Properly Requests.
4.2 EPMI'S CONTRACT PRICE. Subject to Section 4.3 hereof, (i) with
respect to sales of Electric Energy by EPMI to OPC relating to OPC Load, the
Contract Price shall be equal to [ ]*, as adjusted pursuant to
Exhibit 4.2 hereto if the ITS Loss Factor is reduced from 4.1931% to 3.7271%
("EPMI Sales Price"), and (ii) with respect to sales of Electric Energy by EPMI
to OPC relating to OPC Off-System Sales, the Contract Price shall be as agreed
to by the Parties (the "EPMI Off-System Sales Price"); PROVIDED, HOWEVER, that
if the ITS Loss Factor is adjusted to be other than 4.1931% or 3.7271%, then
EPMI and OPC agree to promptly negotiate in good faith an acceptable adjustment
to the EPMI Sales Price; and PROVIDED, FURTHER, that with respect to the OPC
Off-System Sales Contracts listed on Exhibit 3.5.2 hereto, EPMI and OPC have
agreed that the Contract Price shall be equal to [
]*.
4.3 AMOUNTS DUE TO OPC AND EPMI. Each month OPC shall charge EPMI an
amount equal to the aggregate Energy Costs attributable to the OPC Energy that
is Properly Requested by EPMI, including amounts, if any, owing under the CSA.
Each month EPMI shall charge OPC an amount equal to the product of (i) the OPC
Load purchased by OPC during the month and (ii) the EPMI Sales Price, PLUS an
amount equal to the product of (i) each OPC Off-System Sales quantity purchased
by OPC from EPMI during the month and (ii) the EPMI Off-System Sales Price
applicable to each
- -------------------
* Indicates information that has been filed separately with the Secretary of
the Commission as an attachment to a request for confidentiality with respect to
the omitted information.
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such OPC Off-System Sale; PROVIDED, HOWEVER, that the amounts so determined
shall be subject to the following adjustments:
4.3.1 AVAILABILITY OF NUCLEAR OPC RESOURCES. (a) The EPMI
Sales Price has been computed based upon certain assumptions relating to
the expected availability of the nuclear OPC Resources during the Term.
Such price assumes cumulative availability (measured in MWh) of
1,055,419 MWh for Plant Hatch (Units 1 and 2 combined) and 1,597,982 MWh
for Plant Vogtle (Units 1 and 2 combined) for such period, as reflected
on Exhibit 4.3.1 hereof. Adjustments to the amounts otherwise due to
EPMI or OPC shall be made to reflect and to take into account any
deviation between the expected availability of Plant Hatch and Plant
Vogtle, respectively, and the actual availability of such nuclear OPC
Resources. If Plant Hatch or Plant Vogtle generates Electric Energy in
excess of the assumed MWh availability, additional amounts (as described
below) shall be payable by EPMI to OPC; alternatively, if Plant Hatch or
Plant Vogtle generates Electric Energy less than the expected MWh
availability, then OPC shall owe additional amounts (as described below)
to EPMI.
(b) If the total actual OPC nuclear generation (in MWh) ("Total
Actual OPC Nuclear Generation") for Plant Hatch or Plant Vogtle,
respectively, shall exceed the total expected OPC nuclear generation (in
MWh) ("Total Expected OPC Nuclear Generation") for the respective
generation facilities ("Excess Generation"), then EPMI shall pay to OPC
an amount equal to the product of: (i) the amount of such Excess
Generation and (ii) [ ]* if the nuclear OPC Resource
that shall have experienced Excess Generation is Plant Hatch and
[ ]* if the nuclear OPC Resource that shall have experienced
Excess Generation is Plant Vogtle. If the Total Actual OPC Nuclear
Generation for Plant Hatch or Plant Vogtle is less than the Total
Expected OPC Nuclear Generation for the respective plants ("Generation
Shortfall"), regardless of whether the Generation Shortfall results from
or is the result of a scheduled or forced outage, a limited load
operating condition or other event or condition that adversely affects
the availability of such nuclear OPC Resource, then OPC shall pay to
EPMI an amount equal to the product of: (i) the Generation Shortfall
and (ii) [ ]* if the nuclear OPC Resource that shall have
suffered a Generation Shortfall is Plant Hatch and [ ]* if the
nuclear OPC Resource that shall have suffered a Generation Shortfall is
Plant Vogtle.
(c) The Total Actual OPC Nuclear Generation for Plant Hatch and
Plant Vogtle shall be compared to the
- -----------------
* Indicates information that has been filed separately with the Secretary of
the Commission as an attachment to a request for confidentiality with respect to
the omitted information.
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Total Expected OPC Nuclear Generation for Plant Hatch and Plant
Vogtle, respectively, computed on a cumulative basis from the
Commencement Date; PROVIDED, HOWEVER, that as set forth on Exhibit 4.3.1
hereof, the differences between the Total Actual OPC Nuclear Generation
and the Total Expected Nuclear Generation at the end of each month
during the Term shall be settled financially between OPC and EPMI on a
monthly basis.
(d) Exhibit 4.3.1 sets forth the intended operation of this
Section 4.3.1, reflecting possible variances in availability (in MWh) on
a month-to-month basis, resulting in payments between the Parties on
account of Excess Generation in certain months and Generation Shortfalls
in others.
4.3.2 DEVIATION FROM FORECAST ENERGY COSTS. As soon as
reasonably practicable after the end of each month, OPC shall compare
the actual average monthly Energy Cost for each of the OPC Resources
with the Forecast Energy Cost for each such OPC Resource as shown on
Exhibit 3.5.3(iii) hereto. If the actual average monthly Energy Cost
exceeds [ ]* of the Forecast Energy Cost for any of the OPC
Resources during the month, then the amount otherwise due EPMI pursuant
to this Section 4.3 shall be increased by an amount equal to the product
of (i) the amount of the actual average monthly Energy Cost of any OPC
Resource in excess of [ ]* of the Forecast Energy Cost of such OPC
Resource for such month and (ii) the Electric Energy Properly Requested
by EPMI from such OPC Resource during such month. No adjustment shall
be made to the extent that the actual average monthly Energy Cost does
not exceed [ ]* of the Forecast Energy Cost for an OPC Resource
during any month. EPMI may, from time to time, provide for the cost of
fuel for the account of OPC in order to permit the owner of Hartwell
Units 1 and 2 ("Hartwell") to produce Electric Energy and, consequently,
no adjustment shall be made to Energy Cost under this Section 4.3.2 for
Hartwell.
4.3.3 FIXED MONTHLY PAYMENTS BY EPMI TO OPC. EPMI shall
pay to OPC an amount equal to the Fixed Monthly Payment for the
applicable month during the Term, as specified on Exhibit 4.3.3 hereof,
which payments shall be payable in accordance with Section 7.3 hereof
without regard to, INTER ALIA, the source of Electric Energy Properly
Requested or purchased by EPMI pursuant to Section 3.5 hereof or the
amount of Electric Energy sold by EPMI to OPC pursuant to Section 3.6
hereof. The Fixed Monthly Payments are intended to pay the estimated
variable operation and maintenance expenses of OPC; PROVIDED, HOWEVER,
that if OPC's actual variable operation and maintenance expenses exceed
the amount of
- --------------------
* Indicates information that has been filed separately with the Secretary of
the Commission as an attachment to a request for confidentiality with respect to
the omitted information.
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<PAGE>
the Fixed Monthly Payments, EPMI shall have no liability with respect to
such excess expenses.
4.3.4 ROCKY MOUNTAIN "TRUE-UP" ADJUSTMENT. On the
Commencement Date and at the end of the Term, OPC shall determine the
water level in the upper reservoir of Rocky Mountain to determine the
estimated megawatt hours of generation in storage in accordance with
Exhibit 4.3.4, column 1 (Upper Reservoir Level Ft.) and column 4
(estimated MWh in Storage Generating). In the event that the beginning
megawatt hours minus the ending megawatt hours is positive, then EPMI
shall pay OPC this difference (in MWh) times the EPMI Sales Price in
effect for the last month of the Term. In the event that the beginning
megawatt hours minus the ending megawatt hours is negative, then OPC
shall pay EPMI an amount equal to this difference (in MWh) times the
EPMI Sale Price in effect for the last month of the Term.
4.3.5 LPMI CONTRACT ADJUSTMENT. Pursuant to Section 4.2
hereof, EPMI has agreed to sell Electric Energy to OPC at a Contract
Price equal to the price at which OPC is obligated to sell Electric
Energy to LPMI pursuant to that certain power purchase and sale
agreement between LPMI and OPC listed on Exhibit 3.5.2 hereto. In
consideration thereof, OPC shall pay to EPMI the sum of [ ]*;
[ ]* of which shall be payable for the month of January and
[ ]* shall be payable for the month of February. Such amounts
shall be credited to EPMI in the form of an offset against the
amounts of the Fixed Monthly Payments due to OPC from EPMI pursuant
to Section 4.3.3 hereof for the months of January and February, 1996.
4.3.6 CERTAIN SALES FOR RESALE. The Parties understand and
agree that the EPMI Sales Price applies to all Electric Energy required
to enable OPC to satisfy its obligations under the EMC Contracts to meet
the requirements of each of the EMCs for the operation of their electric
distribution systems, including serving the "customer choice" customers
which are not situated within the territorial service area of any such
EMC; PROVIDED, HOWEVER, that if, on or after the Effective Date, an EMC
enters into a contract with a customer for the sale of Electric Energy
for resale, the EPMI Sales Price for Electric Energy sold to OPC to
serve such wholesale sale by such EMC shall be adjusted to cover the
actual cost of such Electric Energy. OPC and EPMI shall negotiate to
determine the actual cost of providing such Electric Energy.
4.4 NETTING OF PAYMENT OBLIGATIONS. The Parties shall satisfy their
respective financial obligations to each other by
- -------------
* Indicates information that has been filed separately with the Secretary of
the Commission as an attachment to a request for confidentiality with respect to
the omitted information.
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<PAGE>
netting the amounts due to OPC from EPMI against amounts due to EPMI from OPC
hereunder, subject to the provisions of Section 7.2.
4.5 AMENDMENTS, MODIFICATIONS OF OPC CONTRACTS. The Parties agree and
understand that the EPMI Sales Price is based upon and reflects the OPC
Contracts in effect on the Effective Date and the pending or proposed amendments
thereto, if any, which are listed on Exhibit 3.5.3(i). In the event that
additional amendments or modifications to the OPC Contracts become effective
and, as a result thereof, the economic return anticipated to be derived by EPMI
pursuant to this Agreement would reasonably be expected to be materially and
adversely affected, EPMI and OPC agree to negotiate in good faith modifications
to this Agreement in order to substantially preserve the economic return that
would have been derived by EPMI in the absence of such amendments or
modifications.
ARTICLE 5
CONFIDENTIAL INFORMATION
5.1 PRIOR CONFIDENTIALITY AGREEMENT SUPERSEDED; AUTHORIZATION TO USE
INFORMATION. The Parties expressly agree that that certain Confidentiality
Agreement entered into by the Parties dated as of December 8, 1995,
automatically and immediately and with no further action by the Parties shall
terminate as of the Effective Date of this Master Agreement. OPC expressly
authorizes and grants its consent to EPMI to use Confidential Information,
whether acquired before or after the Effective Date, pertaining to, without
limitation, OPC, OPC Resources, OPC Load, OPC Off-System Sales and the EMCs, for
the purpose of exercising EPMI's rights under this Agreement, including EPMI's
right to buy Electric Energy from OPC or any other person and to sell Electric
Energy to OPC or any other person, whether Electric Energy is produced by or
attributable to OPC Resources or other resources. Each Party agrees that it
shall not disclose Confidential Information whether acquired before or after the
Effective Date, to any third party other than each Party's officers, directors,
employees, advisors or representatives, or each Party's Affiliates (or as to
OPC, the EMCs), their officers, directors, employees, advisors or
representatives who need to know and agree to maintain the confidentiality of
the Confidential Information (collectively, "Representatives") during the Term
and for a period of not more than three (3) years after the Termination Date.
Each Party shall be responsible for any breach of this Agreement by its
Representatives.
5.2 AUTHORIZED DISCLOSURE. Notwithstanding anything contained in this
Article 5, Confidential Information may be disclosed to any governmental,
judicial or regulatory authority requiring such Confidential Information,
provided that: (i) such
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Confidential Information is submitted under applicable provisions, if any, for
confidential treatment by such governmental, judicial or regulatory authority;
(ii) prior to such disclosure, the Party who supplied the information is given
notice of the disclosure requirement so that it may take whatever action it
deems appropriate, including intervention in any proceeding and the seeking of
an injunction to prohibit such disclosure; and (iii) the Party subject to the
governmental, judicial or regulatory authority endeavors to protect the
confidentiality of any Confidential Information to the extent reasonable under
the circumstances and to use its good faith efforts to prevent the further
disclosure of any Confidential Information provided to any governmental judicial
or regulatory authority. In addition to, and without limiting the foregoing,
the Parties agree and understand that EPMI may, in its discretion, seek to
obtain a ruling from or the formal or informal approval of a governmental agency
or agencies, including the Securities and Exchange Commission, with respect to
this Agreement or the effect thereof on certain business activities of EPMI. In
connection therewith, such governmental agency may require EPMI to submit the
Agreement or a description of the terms and conditions thereof to such
governmental agency. OPC hereby consents to the disclosure of such documents or
information to such governmental agencies, provided that EPMI shall request such
governmental agency to keep such submitted information confidential.
5.3 RETURN OF CONFIDENTIAL INFORMATION. Upon (i) the termination of
this Agreement and (ii) the request of a Party, the other Party shall return all
written Confidential Information (including written confirmation of oral
communications) provided by the requesting Party which was stamped
"confidential" and shall not retain any copies of such written Confidential
Information. In the event of such request, all documents, analyses,
compilations, studies or other materials prepared by the returning Party or its
Representatives that contain or reflect Confidential Information (other than
computer archival and backup tapes or archival and backup files (collectively
"Computer Tapes") and billing and trading records (collectively, "Other
Records")) shall be destroyed and no copy thereof shall be retained (such
destruction to be confirmed in writing by a duly authorized officer of the
returning Party). Computer Tapes and Other Records shall be kept confidential
in accordance with the terms of this Agreement.
5.4 RIGHT TO REMEDIES. In the event of an unauthorized disclosure to
a third party, the limitations on remedies contained in Section 9.2 shall not
apply, and in the event of a breach neither Party will have an adequate remedy
at law and accordingly shall, in addition to any other available legal or
equitable remedies, be entitled to an injunction against such breach without any
requirement to post a bond as a condition of such relief.
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5.5 GEORGIA TRADE SECRETS ACT. Except as expressly provided in
Article 5 of this Agreement, including OPC's consent to the use by EPMI of
Confidential Information in its trading operations pursuant to this Agreement,
the rights of the Parties under this Agreement are in addition to and not in
lieu of their rights under Georgia law, including but not limited to the Georgia
Trade Secrets Act of 1990. Nothing in this Article 5 shall be construed as a
waiver on the part of any Party of any privilege or objection of any kind to the
disclosure or use of Confidential Information.
ARTICLE 6
RECORDS
6.1 RECORDS OF TRANSACTIONS. Each Party shall keep such records as may
be needed to afford a clear history of the Scheduled deliveries and Transactions
hereunder. In maintaining such records, OPC and EPMI may rely upon the logs and
other meter information routinely recorded by Transmission Providers or
utilities responsible for coordination of the Transactions.
ARTICLE 7
BILLING AND PAYMENT
7.1 BILLING STATEMENTS. OPC shall deliver to EPMI no later than on the
tenth (10th) day of each month, a statement (the "Statement") setting forth the
amounts of Electric Energy purchased by OPC from EPMI at the applicable EPMI
Sales Price and the respective EPMI Off-System Sales Prices as adjusted pursuant
to Section 4.3, and the amounts of Electric Energy purchased by EPMI from OPC at
the applicable Energy Cost. To the extent that OPC has not yet received or been
able to compile the applicable Energy Cost figures as of such date, OPC may set
forth on such Statement its good-faith estimate of the Energy Cost of an OPC
Resource, PROVIDED that in no event shall such estimate exceed [ ]* of the
corresponding Forecast Energy Cost for such OPC Resource; and PROVIDED, FURTHER,
that OPC shall compile the actual Energy Costs and "true-up" such estimates as
promptly as practicable pursuant to Section 7.5 hereof.
7.2 OFFSET OF PAYMENT OBLIGATIONS. The Parties shall discharge their
obligations to pay through netting, in which case the Party, if any, owing the
greater aggregate amount shall pay to the other Party the difference between the
amounts owed, as set forth in Section 7.3. Each Party reserves to itself all
rights, setoffs, counterclaims and other remedies and defenses, consistent with
Article 9, which such Party has or may be entitled to arising from or out of
this Agreement. All outstanding Transactions and obligations to make payment in
connection therewith or under this Agreement or any other
- ---------------------
* Indicates information that has been filed separately with the Secretary of
the Commission as an attachment to a request for confidentiality with respect to
the omitted information.
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agreement between the Parties may be offset against each other, set-off or
recouped therefrom.
7.3 PAYMENTS. EPMI shall pay to OPC on the tenth (10th) day of each
month of the Term the applicable Fixed Monthly Payment stated on Exhibit 4.3.3,
less the amount set forth in Section 4.3.5 hereof. Other than payments for
Fixed Monthly Payments, all other payments shall be due on or before the later
of the following: (i) the tenth (10th) Business Day after receipt of the
Statement or (ii) the twentieth (20th) day of the month in which the Statement
is received. The Party owing to the other shall render by wire transfer
payments of the amount due for Transactions during the preceding month. Payment
shall be made to the payment address provided in Exhibit 13.2 hereto. If either
Party, in good faith, disputes any part of any statement, it shall provide a
written explanation of the basis for the dispute and pay the portion of such
statement conceded to be correct no later than the due date as calculated in
accordance with the preceding sentence. If any amount disputed is determined to
be due to the other Party, it shall be paid within ten days of such
determination, along with interest calculated at the Interest Rate from the
original due date until the date paid. Absent such a good faith dispute,
overdue payments shall bear interest from, and including, the due date to, but
excluding, the date of payment at a rate equal to the Interest Rate.
7.4 AUDIT RIGHTS. Each Party or any third party representative of a
Party shall have the right, at its sole expense and during normal working hours,
to examine the records of the other Party to the extent reasonably necessary to
verify the accuracy of any statement, charge or computation made pursuant to
this Agreement. If requested, a Party shall provide to the other Party
statements evidencing the quantities of Electric Energy delivered at the
Delivery Point. If any such examination reveals any inaccuracy in any
statement, the necessary adjustments in such statement and the payments thereof
will be promptly made and shall bear interest calculated at the Interest Rate
from the date the overpayment or underpayment was made; PROVIDED, HOWEVER, that
no adjustment for any statement or payment will be made unless objection to the
accuracy thereof was made prior to the lapse of two (2) years from the rendition
thereof; and PROVIDED, FURTHER, that this provision of this Agreement will
survive any termination of this Agreement for a period of two (2) years from the
date of such termination for the purpose of such statement and payment
objections.
7.5 SUBSEQUENT PAYMENT ADJUSTMENTS. The Parties understand that in
certain cases monthly billings will need to be made on an estimated basis,
including with respect to the calculation of Energy Cost for each of the OPC
Resources. Each Party shall cooperate in good-faith with the other Party to
obtain the requisite information and perform the necessary computations so as to
"true-up" any estimated billings promptly.
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ARTICLE 8
TAXES
8.1 SELLER'S OBLIGATION. Seller is liable for and shall pay, or cause
to be paid, or reimburse Buyer if Buyer has paid, all Taxes applicable to a
Transaction arising prior to the Delivery Point(s). If Buyer is required to
remit any such Tax, the amount shall be deducted from any sums becoming due to
Seller. Seller shall indemnify, defend and hold harmless Buyer from any Claims
for such Taxes.
8.2 BUYER'S OBLIGATION. Buyer is liable for and shall pay, cause to be
paid, or reimburse Seller if Seller has paid, all Taxes applicable to a
Transaction arising at and from the Delivery Point(s), including any Taxes
imposed or collected by a taxing authority with jurisdiction over Buyer. Buyer
shall indemnify, defend and hold harmless Seller from any Claims for such Taxes.
8.3 EXEMPTION CERTIFICATES. Either party, upon written request of the
other, shall provide a certificate of exemption or other reasonably satisfactory
evidence of exemption if either Party or a Transaction is exempt from Taxes, and
shall use reasonable efforts to obtain and cooperate with obtaining any
exemption from or reduction of any Taxes. Each Party shall use reasonable
efforts to administer this Agreement and implement the provisions in accordance
with the intent to minimize Taxes.
ARTICLE 9
INDEMNIFICATION AND REMEDIES
9.1 GENERAL INDEMNITY. Subject to Section 9.2 hereof, Seller and Buyer
shall each indemnify, defend and hold harmless the other Party from any Claims
or other losses arising from (i) any act or incident occurring when title to the
Contract Quantity is vested in the indemnifying Party pursuant to Section 3.3
hereof and (ii) any Event of Default.
9.2 LIMITATION ON REMEDIES. THE PARTIES CONFIRM THAT THE EXPRESS
REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE
ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS
REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF
DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR'S LIABILITY SHALL BE
LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW
OR IN EQUITY ARE WAIVED. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY HEREIN
PROVIDED, THE OBLIGOR'S LIABILITY SHALL BE LIMITED TO DIRECT ACTUAL DAMAGES
ONLY, SUCH DIRECT ACTUAL DAMAGES SHALL BE THE SOLE AND EXCLUSIVE REMEDY AND ALL
OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. UNLESS EXPRESSLY
HEREIN PROVIDED, NEITHER PARTY SHALL BE LIABLE FOR
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CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS
OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR IN CONTRACT UNDER
ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE
LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT
REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY
PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR
PASSIVE. TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID HEREUNDER ARE
LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE
TO DETERMINE, OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE
LIQUIDATED DAMAGES CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS.
9.3 DUTY TO MITIGATE. Each Party agrees that it has a duty to mitigate
damages and covenants that it will use commercially reasonable efforts to
minimize any damages it may incur as a result of the other Party's performance
or non-performance of this Agreement.
9.4 DISCLAIMER. EXCEPT AS EXPRESSLY SET FORTH HEREIN, OPC, WITH
RESPECT TO THE SALE OF ELECTRIC ENERGY TO EPMI, AND EPMI, WITH RESPECT TO THE
SALE OF ELECTRIC ENERGY TO OPC, EXPRESSLY NEGATES ANY OTHER REPRESENTATION OR
WARRANTY, WRITTEN OR ORAL, EXPRESS OR IMPLIED, INCLUDING, WITHOUT LIMITATION,
ANY REPRESENTATION OR WARRANTY WITH RESPECT TO CONFORMITY TO MODELS OR SAMPLES,
MERCHANTABILITY, OR FITNESS FOR ANY PARTICULAR PURPOSE.
[ ]*
ARTICLE 10
REPRESENTATIONS AND WARRANTIES
10.1 MUTUAL REPRESENTATIONS. On the date hereof, the Effective Date
and the date of entering into each Transaction, each Party represents and
warrants to the other Party: (i) it is duly organized, validly existing and in
good standing under the laws of the state of its incorporation and, in the case
of EPMI, is doing business as a foreign corporation in the State of Georgia;
(ii) it has all requisite corporate power to own, operate and lease its
properties and carry on its business as now conducted; (iii) it has all
regulatory authorizations, including any required authorization from the Rural
Utilities Service of the United States Department of Agriculture ("RUS"),
necessary for it to legally perform its obligations under this Agreement and
each Transaction; (iv) the execution, delivery and performance of this Agreement
and each Transaction are within its
- ---------------
* Indicates information that has been filed separately with the Secretary of
the Commission as an attachment to a request for confidentiality with respect to
the omitted information.
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powers, have been duly authorized by all necessary action and do not violate any
of the terms or conditions in its governing documents, any contract or other
agreement to which it is a party or any Law applicable to it; (v) each of this
Master Agreement and each Transaction when entered into in accordance with this
Agreement constitutes its legally valid and binding obligation enforceable
against it in accordance with its terms, subject to any Equitable Defenses;
(vi) there are no Bankruptcy Proceedings pending or being contemplated by it or,
to its knowledge, threatened against it; (vii) there are no Legal Proceedings
that would be reasonably likely to materially adversely affect its ability to
perform this Agreement and each Transaction; and (viii) it has knowledge and
experience in financial matters and in the electric industry that enable it to
evaluate the merits and risks of this Agreement and each Transaction.
10.2 ADDITIONAL OPC REPRESENTATIONS. OPC further represents and
warrants that on the date hereof, the Effective Date and the date of entering
into each Transaction: (i) the EMC Contracts are and will be in full force and
effect throughout the Term and will not be amended so as to affect OPC's ability
to perform its obligations under this Agreement; (ii) except as set forth on
Exhibit 3.5.3(ii) hereto, there are no planned outages or other limitations on
the availability of any of the OPC Resources during the Term; (iii) Exhibit
3.5.3(i) hereto sets forth a true and complete list of each OPC Resource and
each material written OPC Contract; (iv) correct and complete copies of the OPC
Contracts listed on Exhibit 3.5.3(i) hereto have previously been delivered to
EPMI by OPC; (v) except as stated on Exhibit 3.5.3(i) hereto, no amendments to
the OPC Contracts are proposed or pending as of the Effective Date that would
affect this Agreement; (vi) each OPC Contract is valid, binding and in full
force and effect and enforceable by or against the respective parties thereto in
accordance with its terms; (vii) OPC has fulfilled, and will continue to fulfill
during the Term, all of its obligations under each OPC Contract; (viii) there
has not occurred any default by OPC or any event which, with the lapse of time
or the giving of notice or both will become a default of OPC under any of the
OPC Contracts; and (ix) OPC is not in arrears in respect of the performance or
satisfaction of the terms or conditions to be performed or satisfied by it under
any of the OPC Contracts, and, to the best knowledge of OPC, no waiver of any of
such terms or conditions has been granted thereunder by any of the parties
thereto.
10.3 ADDITIONAL EPMI REPRESENTATIONS. EPMI further represents and
warrants that it is a power marketer authorized by the FERC to purchase and sell
Electric Energy at negotiated rates pursuant to EPMI's Rate Schedule No. 1 (as
in effect on January 1, 1996) under orders issued in ENRON POWER MARKETING,
INC., 65 FERC PARA 61,305 (1993) and 66 FERC PARA 61,244 (1994).
10.4 GOOD TITLE. Each Party represents and warrants that it will
deliver to the other good title to Electric Energy
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delivered hereunder, free and clear of all liens, claims and encumbrances
arising prior to transfer of title at the Delivery Point.
10.5 CONTINUING REPRESENTATIONS AND WARRANTIES. Each Party covenants
that it will cause these representations and warranties to be true and correct
throughout the term of this Agreement.
ARTICLE 11
DEFAULTS AND REMEDIES
11.1 EVENTS OF DEFAULT. An "Event of Default" shall mean with respect to
a Party ("Defaulting Party"):
11.1.1 The failure by the Defaulting Party to make, when due, any
payment required if such failure is not remedied within five Business Days
after written notice of such failure is given to the Defaulting Party by
the other Party ("Notifying Party"); PROVIDED, that the payment is not the
subject of a good faith dispute as described in Section 7.3 hereof; or
11.1.2 Any representation or warranty made by the Defaulting
Party herein shall prove to have been false or misleading in any material
respect when made or deemed to be repeated; or
11.1.3 The failure by the Defaulting Party to perform any
covenant set forth in this Agreement (other than its obligations to make
any payment or obligations which are otherwise specifically covered in this
Section 11.1 as a separate Event of Default or its obligations to deliver
or receive Electric Energy, a remedy for which is provided in Section 3.4
hereof) and such failure is not excused by Force Majeure or cured within
five Business Days after written notice thereof to the Defaulting Party; or
11.1.4 The Defaulting Party shall be subject to a Bankruptcy
Proceeding.
11.2 EARLY TERMINATION; REMEDIES. If an Event of Default occurs with
respect to a Defaulting Party at any time during the Term, the other party
("Non-Defaulting Party") may, for so long as the Event of Default is continuing,
(i) establish a date (which date shall be between five and ten Business Days
after the Non-Defaulting Party delivers notice to the Defaulting Party) ("Early
Termination Date") on which any or all Transactions selected by it shall
terminate (individually, a "Terminated Transaction" and collectively the
"Terminated Transactions") and (ii) withhold any payments due to the
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Defaulting Party under this Agreement; PROVIDED, HOWEVER, that if the Event of
Default is that the Defaulting Party becomes subject to a Bankruptcy Proceeding,
then all Transactions and this Agreement shall automatically terminate without
notice and without any other action by either Party as if an Early Termination
Date had been immediately declared prior to such Event of Default. Regardless
of whether an Early Termination Date is declared, if an Event of Default shall
have occurred, the Non-Defaulting Party shall be entitled to exercise any remedy
available at law or equity consistent with Article 9 hereof to recover its
damages, including attorneys' fees, resulting from any Event of Default.
11.3 SPECIAL EARLY TERMINATION RIGHT. OPC shall have the right to
terminate this Agreement prior to the end of the Term in the event that EPMI's
failure to supply OPC with Electric Energy sufficient for OPC to service the OPC
Load results in the interruption by Georgia Power Company of the flow of
Electric Energy to the EMCs pursuant to Section 16.3 of the CSA, regardless of
whether and when such condition is subsequently cured; PROVIDED, HOWEVER, that
under no circumstances shall this provision apply if EPMI's failure to supply
Electric Energy or the interruption caused by Georgia Power Company is the
result of Force Majeure or the imposition of a rolling "brownout" or "blackout"
or other similar demand-side management controls or practices employed in the
geographical area. Neither OPC nor EPMI shall have any liability for damages in
the event OPC exercises this early termination right. Notwithstanding the
foregoing, OPC and EPMI each shall remain liable for any amounts on account of
Electric Energy furnished to the other Party prior to the effective date of such
early termination and for any other amounts accrued as of such date. EPMI and
OPC shall agree to a final accounting and settlement of their obligations to
each other as soon as practicable as provided in Section 13.4 hereof.
11.4 FAILURE TO PAY. Notwithstanding any other provision of this
Agreement, if either Party fails to pay the other any amounts when due, the
other Party shall have the right to (i) suspend performance under this Agreement
until such amounts plus interest have been paid and/or (ii) exercise any remedy
available at law or in equity to enforce payment of such amount plus interest;
PROVIDED, HOWEVER, that if the Defaulting Party, in good faith, shall dispute
the amount of any such billing or part thereof and shall pay such amounts as it
concedes to be correct, no suspension shall be permitted.
11.5 EFFECT OF REGULATION. In the event OPC is or becomes regulated by a
federal, state or local regulatory body, and such body shall disallow all or any
portion of any costs incurred or yet to be incurred by OPC under any provision
of this Agreement, such action shall not operate to excuse OPC from performance
of any obligation nor shall such action give rise to
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any right of OPC to any refund or retroactive adjustment of any amounts payable
hereunder.
ARTICLE 12
FORCE MAJEURE
13.1 EFFECT OF FORCE MAJEURE. If either Party is rendered unable by a
Force Majeure to carry out, in whole or part, its obligations hereunder and such
Party gives notice and full details of the event to the other Party as soon as
practicable after the occurrence of the event, then during the pendency of such
Force Majeure but for no longer period, the obligations of the Party affected by
the event (other than the obligation to make payments then due or becoming due
with respect to performance prior to the event) shall be suspended to the extent
required. The Party affected by the Force Majeure shall remedy the Force
Majeure with all reasonable dispatch.
ARTICLE 13
MISCELLANEOUS
13.1 ASSIGNMENT. Neither Party shall assign this Agreement or its rights
hereunder without the prior written consent of the other Party; PROVIDED,
HOWEVER, either Party may, without the consent of the other Party (and without
relieving itself from liability hereunder), (i) transfer, pledge, encumber or
assign this Agreement or the accounts, revenues, or proceeds hereof in
connection with any financing or other financial arrangements, (ii) transfer or
assign this Agreement to an Affiliate of such party, or (iii) transfer or assign
this Agreement to any person or entity succeeding to all or substantially all of
the assets of such Party; PROVIDED, HOWEVER, that in each such case, this
Agreement shall be binding upon any such assignee, such assignee shall agree in
writing to be bound by the terms and conditions hereof and each of the
representations of a Party shall be true with respect to such Party's assignee
as of the effective date of such assignment.
13.2 NOTICES. All notices, requests, statements or payments shall be made
as specified in Exhibit 13.2 hereto. Notices required to be in writing shall be
delivered by letter, facsimile or other documentary form. Notice by facsimile
or hand delivery shall be deemed to have been received by the close of the
Business Day on which it was transmitted or hand delivered (unless transmitted
or hand delivered after close, in which case it shall be deemed received at the
close of the next Business Day). Notice by overnight mail or courier shall be
deemed to have been received two Business Days after it was sent. A Party may
change its address by providing notice of same in accordance herewith.
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13.3 APPLICABLE LAW. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE
PARTIES ARISING OUT OF THIS AGREEMENT SHALL BE GOVERNED BY AND CONSTRUED,
ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF GEORGIA,
WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW.
13.4 SURVIVAL OF OBLIGATIONS. Upon the expiration of the Parties' sale
and purchase obligations under this Agreement, any monies, penalties or other
charges due and owing Seller shall be paid, any corrections or adjustments to
payments previously made shall be determined, and any refunds due Buyer made, as
soon as practicable. All indemnity and confidentiality obligations and audit
rights shall survive the termination of this Agreement. The Parties'
obligations provided in this Agreement shall remain in effect for the purpose of
complying with the provisions of this Section.
13.5 ENTIRE AGREEMENT. This Agreement constitutes the entire agreement
between the Parties relating to the subject matter contemplated by this
Agreement and supersedes all prior agreements, whether oral or written,
including that certain Interchange Agreement between Oglethorpe Power
Corporation and Enron Power Marketing, Inc., dated March 1, 1995.
13.6 NO PARTNERSHIP. Nothing in this Agreement shall ever be deemed to
create or constitute a partnership, joint venture or association between the
Parties, or to impose a trust or partnership duty, obligation or liability on or
with regard to the Parties.
13.7 AMENDMENT. No amendment or modification to this Master Agreement
shall be enforceable unless reduced to writing and executed by both Parties.
13.8 THIRD PARTIES. The provisions of this Agreement shall not impart
rights enforceable by any person or entity not a Party or not a permitted
successor or assignee of a Party bound by this Agreement.
13.9 WAIVER. No waiver by either Party hereto of any one or more defaults
by the other in the performance of any of the provisions of this Agreement or
terms of any Transaction shall be construed as a waiver of any other default or
defaults, whether of a like kind or different nature.
13.10 CHARACTER OF TRANSACTIONS. The sale by OPC to EPMI of OPC Energy
under this Agreement does not constitute either a sale, lease, or the dedication
of ownership of any OPC Resource.
13.11 SEVERABILITY. Any provision declared or rendered unlawful by a
court of law or regulatory agency with jurisdiction over the Parties or deemed
unlawful because of a statutory change
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will not otherwise affect the lawful obligations that arise under this
Agreement.
13.12 INTERPRETATION. The term "including" when used in this Agreement
shall not be considered in any way to be in limitation.
13.13 HEADINGS. The headings used for the Articles herein are for
convenience and reference purposes only.
13.14 COUNTERPARTS. This Master Agreement may be executed in multiple
counterparts to be construed as one effective as of the Effective Date.
IN WITNESS WHEREOF, the Parties hereto have caused this Master
Agreement to be executed by their duly authorized officers and copies delivered
to each Party.
OGLETHORPE POWER CORPORATION
By: /S/ T.D. Kilgore Attest: /S/ Patricia N. Nash
-------------------------- -----------------------------------
Title: President and CEO Title: Assistant Secretary
ENRON POWER MARKETING, INC.
By: /S/ KENNETH D. RICE Attest: /S/ ELAINE V. OVERTURF
------------------------- -----------------------------------
Title: President and Managing Title: Corporate Secretary
Director
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APPENDIX A
All capitalized terms used in this Agreement and not otherwise
defined shall have the respective meanings set forth below, whether singular or
plural.
"Affiliate" means, with respect to any person, any other person
(other than an individual) that directly or indirectly, through one or more
intermediaries, controls, or is controlled by, or is under common control with,
such person. For this purpose, "control" means the direct or indirect ownership
interest of more than fifty (50) percent of the outstanding capital stock or
other equity interests having ordinary voting power.
"Bankruptcy Proceedings" means, with respect to a Party that such
Party (i) makes any general assignment or any general arrangement for the
benefit of creditors, (ii) files a petition or otherwise commences, authorizes
or acquiesces in the commencement of a proceeding or cause of action under any
bankruptcy or similar law for the protection of creditors, or has such a
petition involuntarily filed against it and such petition is not withdrawn or
dismissed within 30 days after such filing, (iii) otherwise becomes bankrupt or
insolvent (however evidenced), or (iv) is unable to pay its debts as they fall
due.
"Business Day" means a day on which the Federal Reserve Member
Banks in New York City are open for business; and a Business Day shall open at
8:00 a.m. and close at 5:00 p.m. local time for each Party's principal place of
business.
"Buyer" means the Party to a Transaction who is obligated to
purchase and receive, or cause to be received, Electric Energy during a Period
of Delivery.
"Claims" means all claims or actions, threatened or filed and
whether groundless, false or fraudulent, that directly or indirectly relate to
the subject matter of an indemnity, and the resulting losses, damages, expenses,
attorneys' fees and court costs, whether incurred by settlement or otherwise,
and whether such claims or actions are threatened or filed prior to or after the
termination of this Agreement.
"Commencement Date" has the meaning specified in Section 2.3
hereof.
"Computer Tapes" has the meaning specified in Section 5.3 hereof.
"Confidential Information" means written data or information (or
an oral communication if the party requesting confidentiality for such oral
communication promptly confirms such communication in writing) which is
privileged, confidential or proprietary or which constitutes a trade secret
under the
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Georgia Trade Secrets Act of 1990, except information which (i) is a matter of
public knowledge at the time of its disclosure or is thereafter published in or
otherwise ascertainable from any source available to the public without breach
of this Agreement, (ii) constitutes information which is obtained from a third
party (who or which is not an Affiliate of one of the Parties hereto) other than
by or as a result of unauthorized disclosure, or (iii) prior to the time of
disclosure had been independently developed by the receiving Party or its
Affiliates not utilizing improper means.
"Confirmation" means a written notice confirming the specific
terms of a Transaction substantially in the form set forth on Exhibit 2.2
hereto.
"Contract Price" means the price in United States dollars (per
MWh) to be paid by Buyer to Seller for the purchase of Electric Energy that is
Scheduled or Properly Requested pursuant to a Transaction.
"Contract Quantity" means the amount of Electric Energy that
Seller agrees to sell and deliver, or cause to be delivered, to Buyer and Buyer
agrees to purchase and receive, or cause to be received, from Seller pursuant to
the terms of a Transaction.
"CSA" means that certain Coordination Services Agreement between
Georgia Power Company and Oglethorpe Power Corporation (An Electric Membership
Generation & Transmission Corporation), dated as of November 12, 1990, as
amended from time to time.
"Defaulting Party" has the meaning specified in Section 11.1
hereof.
"Delivery Point" means any point on the Integrated Transmission
System at which title to Electric Energy passes from Seller to Buyer, including
at any Point of Interconnection as shown on Exhibit 3.2.
"Early Termination Date" has the meaning specified in
Section 11.2 hereof.
"Effective Date" has the meaning specified in Section 2.3 hereof.
"Electric Energy" means energy in the form of electricity
expressed in megawatt-hours (MWh) (or in kilowatt-hours when energy is measured
at the points of delivery to the EMCs).
"EMC" means an electric membership corporation as defined in
Section 46-3-171(3) of the Georgia Electric Membership
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Corporation Act, which is a member of OPC on the Effective Date, as shown on
Exhibit 1.1 hereto.
"EMC Contract" means one of those certain Amended and
Consolidated Wholesale Power Contracts between OPC and an EMC, which contract is
dated as of December 1, 1988, as amended from time to time, pursuant to which
OPC sells and such EMC purchases all Electric Energy required to meet the energy
requirements of its customers for the operation of its system.
"EMC Metering Point" means that certain point at which deliveries
of Electric Energy to each EMC, respectively, are measured and received pursuant
to the EMC Contracts.
"Energy Cost" means the (i) actual cost of fuel (and not any
other costs), in United States Dollars (per MWh), incurred by OPC with respect
to Electric Energy produced by OPC Resources (other than the power contracts
described below in this definition), as determined pursuant to the applicable
OPC Contracts; (ii) the actual cost of fuel and variable operations and
maintenance expenses under the block power purchase and sale agreements with
Georgia Power Company; (iii) the costs described on Exhibit 3.5.3(iii) hereto
with respect to the power purchase agreements with Big Rivers Electric
Corporation and Energy Power, Incorporated; PROVIDED, HOWEVER, that the Energy
Cost with respect to Hartwell shall be deemed to be zero to the extent EPMI
arranges for the delivery of gas at its expense to such plant. The energy cost
associated with pumping water at Rocky Mountain is deemed to be at EPMI's
expense pursuant to Section 4.3.4 of this Agreement.
"EPMI Off-System Sales Price" has the meaning specified in
Section 4.2 hereof.
"EPMI Sales Price" has the meaning specified in Section 4.2
hereof.
"EPT" means Eastern Prevailing Time and refers to the time in
effect in the Eastern Time Zone of the United States, whether Eastern Standard
Time or Eastern Daylight Savings Time.
"Equitable Defenses" means bankruptcy, insolvency, reorganization
and other laws affecting creditors' rights generally, and with regard to
equitable remedies, the discretion of the court before which proceedings to
obtain the same may be pending.
"Event of Default" has the meaning specified in Section 11.1
hereof.
"Excess Generation" has the meaning set forth in Section 4.3.1
hereof.
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"FERC" means the Federal Energy Regulatory Commission or any
successor agency which enforces the Federal Power Act.
"Fixed Monthly Payments" means the fixed monthly amounts
scheduled to be paid to or credited to the account of OPC pursuant to
Section 4.3.3 hereof and which are set forth on Exhibit 4.3.3 hereto.
"Force Majeure" means an event not anticipated as of the
Effective Date, which is not within the reasonable control of the Party (or, in
the case of third party obligations or facilities, the third party) claiming
suspension (the "Claiming Party"), and which by the exercise of due diligence
the Claiming Party is unable to overcome or obtain or cause to be obtained a
commercially reasonable substitute performance therefor. Force Majeure
includes, but is not restricted to: failure of transmission facilities; acts of
God; fire; civil disturbance; labor dispute; labor or material shortage;
sabotage; action or restraint by court order or public or governmental authority
(so long as the Claiming Party has not applied for or assisted in the
application for, and has opposed where and to the extent reasonable, such
government action); PROVIDED, HOWEVER, that neither (i) the loss of Buyer's
markets nor Buyer's inability economically to use or resell Electric Energy
purchased hereunder, nor (ii) the loss or failure of Seller's Electric Energy
supply, nor (iii) Seller's ability to sell Electric Energy to a market at a more
advantageous price, shall constitute an event of Force Majeure. Interruption by
a Transmission Provider shall not be deemed to be Force Majeure unless (i) the
Party contracting with such Transmission Provider shall have made arrangement
with such Transmission Provider for the firm transmission, as defined under the
Transmission Provider's tariff, of the Electric Energy to be delivered or
received hereunder and (ii) such interruption is due to a force majeure as
defined under the Transmission Provider's tariff.
"Forecast Energy Cost" has the meaning specified in Section 3.5.3
hereof, as reflected on Exhibit 3.5.3(iii) hereto.
"Generation Shortfall" has the meaning set forth in Section 4.3.1
hereof.
"Hartwell" has the meaning specified in Section 4.3.2 hereof.
"Integrated Transmission System" or "ITS" means the Transmission
Facilities as defined in the Revised and Restated Integrated Transmission System
Agreement between Oglethorpe Power Corporation (An Electric Membership
Generation & Transmission Corporation) and Georgia Power Company, dated as of
November 12, 1990, as amended from time to time.
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"Interest Rate" means the Prime Rate plus two percent, or the
maximum lawful rate permitted by applicable Law, whichever is less.
"ITS Loss Factor" means the EMC transmission loss factor
determined pursuant to the ITSA applicable to deliveries of Electric Energy from
any point on the ITS to any EMC Metering Point, which loss factor is currently
4.1931%.
"ITSA" means the Revised and Restated Integrated Transmission
System Agreement between Oglethorpe Power Corporation (An Electric Membership
Generation & Transmission Corporation) and Georgia Power Company, dated as of
November 12, 1980, as amended from time to time.
"Law" means any law, rule, regulation, order, writ, judgment,
decree or other legal or regulatory determination by a court, regulatory agency
or governmental authority of competent jurisdiction.
"Legal Proceeding" means any suit, proceeding, judgment, ruling
or order by or before any court or any governmental authority.
"Level B-1" means the high side of the step-up transformer of a
generating plant that is an OPC Resource which interconnects directly into the
ITS.
"LPMI" means LG&E Power Marketing, Inc., the purchaser under that
certain power purchase and sale agreement with OPC which is listed on
Exhibit 3.5.2.
"MWh" means megawatt-hour.
"Must Run Resources" has the meaning specified in Section 3.5
hereof.
"Non-Defaulting Party" has the meaning specified in Section 11.2
hereof.
"NERC" means the North American Electric Reliability Council.
"Notifying Party" has the meaning specified in Section 11.1.1
hereof.
"Non-Territorial Contractual Delivery Obligations" means an
obligation, based on a quantity of capacity, energy, or both, which an ITS
participant is contractually committed to deliver or make available from or
through the ITS to a non-territorial entity, as further defined in the ITSA.
"OPC Contracts" means, as of a particular date, all contracts,
operating procedures and understandings (whether
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written or oral, and if oral, written statements of the terms thereof) in effect
on such date affecting OPC's rights and obligations with respect to OPC
Resources and to the ITS.
"OPC Energy" means all of the available Electric Energy which OPC
owns, purchases or otherwise has a right to take from OPC Resources.
"OPC Load" means, as of a particular hour, the entire Electric
Energy requirements of the EMCs measured at each EMC Metering Point, after
reducing such requirements to reflect the EMCs' aggregate allocation of SEPA
Energy Scheduled for delivery to the EMCs.
"OPC Off-System Sales" means transactions undertaken by OPC
pursuant to the OPC Off-System Sales Contracts.
"OPC Off-System Sales Contracts" means the contracts listed on
Exhibit 3.5.2 and, subject to the consent of EPMI, contracts entered into
between OPC and third parties pursuant to which OPC sells Electric Energy to
such third parties.
"OPC Resource" means the capacity entitlement or other rights
with respect to generating facilities from which, or power purchase contracts,
interchange agreements or other contracts or agreements under which, OPC is
required or has the right to take, purchase or otherwise acquire Electric Energy
during the Term.
"Other Records" has the meaning specified in Section 5.3 hereof.
"Party" and "Parties" mean a party or the parties, respectively,
to this Agreement, including permitted assignees of each pursuant to this
Agreement.
"Period of Delivery" means the period from the date physical
delivery of the Electric Energy is to commence to the date physical delivery is
to terminate pursuant to a Transaction.
"Plant Hatch" means those two nuclear generating facilities (and
associated common facilities) having a rated capacity of 810 MW for Unit 1 and
820 MW for Unit 2.
"Plant Vogtle" means those two nuclear generating facilities (and
associated common facilities) having a rated capacity of 1160 MW for Unit 1 and
1160 MW for Unit 2.
"Point of Interconnection" means any point of interconnection
between the ITS and the transmission facilities of an interconnected utility,
electric cooperative or other transmission owner or operator, as set forth on
Exhibit 3.2.
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"Prime Rate" means for any date, the per annum rate of interest
announced from time to time by Citibank, N.A., as its "prime" rate for
commercial loans, effective for such date as established from time to time by
such bank.
"Properly Requested" or "Properly Requests" means that EPMI has
notified or notifies OPC of specified amounts of OPC Energy that EPMI desires to
purchase from specific OPC Resources at specified times during the Term in
accordance with Section 2.2 hereof; PROVIDED, that all Electric Energy
attributable to Must Run Resources (which EPMI is obligated to purchase pursuant
to Section 3.5.1 hereof) shall be deemed to be Properly Requested for purposes
of this Agreement.
"Regulatory Approvals" means all current and future valid and
applicable Laws, orders, statutes, and regulations of courts or regulatory
bodies (state or federal) having jurisdiction over a Party or any Transaction.
"Replacement Price" has the meaning specified in Section 3.4(a)
hereof.
"Representatives" has the meaning specified in Section 5.1
hereof.
"Rocky Mountain" has the meaning specified in Section 3.7(e)
hereof.
"RUS" has the meaning specified in Section 10.1(iii) hereof.
"Sales Price" has the meaning specified in Section 3.4(b) hereof.
"Scheduling," "Scheduled" or "Schedule" means or relates to the
acts of Seller, Buyer and their designated representatives, including each
Party's Transmission Providers, if applicable, of notifying, requesting and
confirming to each other the quantity of Electric Energy to be delivered hourly
on any given day or days during a Delivery Period at a specified Delivery Point.
"Seller" means the Party to a Transaction who is obligated to
sell and deliver, or cause to be delivered, Electric Energy during a Period of
Delivery.
"SEPA" means the Southeastern Power Administration, a federal
agency of the United States Government.
"SEPA Energy" means the aggregate amount of Electric Energy
Scheduled for delivery to the EMCs pursuant to the SEPA Contracts.
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"SEPA Contracts" means those certain power purchase and sale
agreements between each EMC and SEPA pursuant to which each EMC purchases
Electric Energy from SEPA.
"SERC" means the Southeastern Electric Reliability Council.
"Statement" has the meaning specified in Section 7.1 hereof.
"Taxes" means any or all ad valorem, property, occupation,
severance, generation, first use, conservation, Btu or energy, transmission,
utility, gross receipts, privilege, sales, use, consumption, excise, lease,
transaction, and other or new Taxes, governmental charges, licenses, fees,
permits and assessments, or increases therein, other than taxes based on net
income or net worth.
"Term" has the meaning specified in Section 2.3 hereof.
"Terminated Transaction" has the meaning specified in
Section 11.2 hereof.
"Termination Date" has the meaning specified in Section 2.3
hereof.
"Total Actual Nuclear Generation" shall have the meaning set
forth in Section 4.3.1 hereof.
"Total Expected Nuclear Generation" shall have the meaning set
forth in Section 4.3.1 hereof.
"Transaction" means a particular transaction agreed to by the
Parties relating to the purchase and sale of Electric Energy pursuant to this
Master Agreement.
"Transaction Agreement" means a written agreement executed by the
Parties to form and effectuate a Transaction which agreement may be in
substantially the form set forth on Exhibit 1.2 hereto.
"Transmission Provider" means the entity or entities transmitting
Electric Energy on behalf of Seller or Buyer to or from the Delivery Point(s) in
a particular Transaction.
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EXHIBIT 1.1
ELECTRIC MEMBERSHIP CORPORATIONS
OF
OGLETHORPE POWER CORPORATION
ALTAMAHA EMC
AMICALOLA EMC
CANOOCHEE EMC
CARROLL EMC
CENTRAL GEORGIA EMC
COASTAL EMC
COBB EMC
COLQUITT EMC
COWETA-FAYETTE EMC
EXCELSIOR EMC
FLINT EMC
GRADY EMC
GREYSTONE POWER CORPORATION, AN EMC
HABERSHAM EMC
HART EMC
IRWIN EMC
JACKSON EMC
JEFFERSON EMC
LAMAR EMC
LITTLE OCMULGEE EMC
MIDDLE GEORGIA EMC
MITCHELL EMC
OCMULGEE EMC
OCONEE EMC
OKEFENOKE RURAL EMC
PATAULA EMC
PLANTERS EMC
RAYLE EMC
SATILLA RURAL EMC
SAWNEE EMC
SLASH PINE EMC
SNAPPING SHOALS EMC
SUMTER EMC
THREE NOTCH EMC
TRI-COUNTY EMC
TROUP EMC
UPSON COUNTY EMC
WALTON EMC
WASHINGTON EMC
<PAGE>
EXHIBIT 1.2
FORM OF TRANSACTION AGREEMENT
FOR USE WITH
TRANSACTIONS TO BE EXECUTED UNDER SECTION 2.2(II)
This Transaction Agreement shall form and effectuate the current proposal
between Oglethorpe Power Corporation ("OPC") and Enron Power Marketing, Inc.
("EPMI"), regarding the purchase and sale of Electric Energy under the following
terms and conditions. ________ is to purchase and receive ("Buyer") and
__________ is to sell and deliver ("Seller"). The transaction number is
____________________.
Contract Quantity: __________________________
Delivery Point(s): __________________________
Contract Price: __________________________
Period of Delivery: __________________________
Other: __________________________
__________________________
This Transaction Agreement is being provided pursuant to and in accordance
with Section 2.2(ii) of the Master Power Purchase and Sale Agreement dated
January 3, 1996, in effect between OPC and EPMI, and constitutes part of and is
subject to all of the terms and provisions of the Master Agreement. Terms used
but not defined herein shall have the meanings ascribed to them in the Master
Agreement. Please execute this Transaction Agreement and return an executed
copy to EPMI. Your execution should reflect the appropriate party in OPC who
has the authority to cause OPC to enter into this Transaction. In the event OPC
alters the terms of this Transaction Agreement in any manner, at the option of
EPMI, there will be no Transaction pursuant to this Transaction Agreement.
OGLETHORPE POWER CORPORATION ENRON POWER MARKETING, INC.
By:______________________________ By:______________________________
Title:___________________________ Title:___________________________
Date:____________________________ Date:____________________________
<PAGE>
EXHIBIT 2.2
FORM OF CONFIRMATION
[Date]
[Address]
Attn: ______________
CONFIRMATION LETTER
This Confirmation shall confirm the agreement reached on ________ ___, 1996
between Oglethorpe Power Corporation ("OPC") and Enron Power Marketing, Inc.
("EPMI") regarding the sale/purchase of Electric Energy under the terms and
conditions as follows:
_____________ to purchase and receive ("Buyer"); ______________ to sell and
deliver ("Seller").
Contract Quantity: _______________________
Delivery Point(s): _______________________
Contract Price: _______________________
Period of Delivery: _______________________
Other: _______________________
This Confirmation is being provided pursuant to and in accordance with the
Master Agreement dated January 3, 1996 (the "Master Agreement") between OPC and
EPMI, and constitutes part of and is subject to all of the terms and provisions
of the Master Agreement. Terms used by not defined herein shall have the
meanings ascribed to them in the Master Agreement.
Please confirm that the terms stated herein accurately reflect the agreement
between OPC and EPMI by returning an executed copy of this letter by facsimile
to the sender hereof. Your response should reflect the appropriate party in
your organization who has the authority to enter into this Transaction, and
should be received by the sender hereof no later than _______________.
Notwithstanding the foregoing request that you return this Confirmation, if you
do not return this Confirmation or do not object to this Confirmation within two
Business Days of your receipt of it, you will have accepted and agreed to all of
the terms included herein, including the terms and provisions of the Master
Agreement.
OGLETHORPE POWER CORPORATION ENRON POWER MARKETING, INC.
By:________________________________ By:_______________________________
Title:_____________________________ Title:____________________________
Date:______________________________ Date:_____________________________
<PAGE>
EXHIBIT 3.2
INTERCONNECTION POINTS WITH THE GEORGIA ITS
Alabama Electric Cooperative
Florida Power Corporation
Florida Power & Light Company
Duke Power Company
Jacksonville Electric Authority
South Carolina Electric & Gas Company
South Carolina Public Service Authority
Southern Companies
Tallahassee Electric Department
Tennessee Valley Authority
<PAGE>
EXHIBIT 3.2 (CONTINUED)
OPC ALLOCATION OF
FIRST CONTINGENCY TOTAL TRANSFER CAPABILITY (FCTTC)
UNDER NORMAL OPERATING CONDITIONS
(EFFECTIVE JANUARY - MAY, 1996)
<TABLE>
<CAPTION>
FCTTC (MVA)
INTERFACE WITH GEORGIA ITS TO GEORGIA ITS FROM GEORGIA ITS
- -------------------------- ----------------- ------------------
<S> <C> <C>
Florida 584 841
Sale to GPC 40
Sale to GPC 47 (Tentative)
Sale to Entergy (3/1/96) 25 (Tentative)
-----
729
Alabama Power 730 116
Duke Power 468 556
SC Public Service Authority 42 19
SC Electric and Gas 134 172
Savannah Power 32 0
Gulf Power 0 0
Tennessee Valley Authority 301 310
Purchase from GPC 70
Purchase from GPC 126 (Tentative)
---
497
Alabama Electric Cooperative 17 47
</TABLE>
<PAGE>
EXHIBIT 3.5
OPC RESOURCES(1)
<TABLE>
<CAPTION>
Type of Resource OPC Resources
- ---------------- that are NOT
Must Run Minimum Maximum
Resources (MW) (MW)
--------- ------------------------
<S> <C> <C> <C>
Generating Units Rocky Mountain 1 110.0 212.0
-----------------------
Rocky Mountain 2 110.0 212.0
-----------------------
Rocky Mountain 3 110.0 212.0
-----------------------
Scherer 1(2) 195.0 496.2
-----------------------
Scherer 2(2) 195.0 498.0
-----------------------
Tallassee N/A 2.0
----------------------
Wansley 1 121.0 253.8
-----------------------
Wansley 2 122.0 253.8
-----------------------
Wansley CT N/A 14.8
-----------------------
OPC Resources
that are
Must Run Minimum Maximum
Resources (MW) (MW)
--------- -----------------------
Generating Units Hatch 1 N/A 222.3
-----------------------
Hatch 2 N/A 229.5
-----------------------
Vogtle 1 N/A 348.6
-----------------------
Vogtle 2 N/A 348.6
-----------------------
QF N/A 27
-----------------------
</TABLE>
- ------------------
(1) The figures contained in this Exhibit shall not serve to limit the actual
output available from any OPC Resource.
(2) Scherer minimum could be 330 MW if Georgia Power is not taking electric
energy from its ownership share of the generating facility.
<PAGE>
EXHIBIT 3.5 (CONTINUED)
<TABLE>
<CAPTION>
Other OPC Resources Minimum Maximum
(MW) (MW)
-----------------------
<S> <C> <C> <C>
Purchased Power GPC Block 1(3) 100 215
-----------------------
GPC Block 2(3) 100 215
-----------------------
GPC Block 3(3) 100 215
-----------------------
GPC Block 4(3) 100 215
-----------------------
GPC Block 5(3) 0 107
-----------------------
GPC Block 6(3) 0 108
-----------------------
Big Rivers 25 100
-----------------------
Entergy 25 100
-----------------------
Hartwell 1 67 148
-----------------------
Hartwell 2 67 148
-----------------------
</TABLE>
- -------------------
(3) 100% availability - minimum applies when energy is being scheduled under
the particular block.
<PAGE>
EXHIBIT 3.5.2
POWER PURCHASE AND SALE AGREEMENTS
UNDER WHICH OPC IS OBLIGATED TO SELL ELECTRIC ENERGY
Letter of Commitment to sell power to Alabama Electric Cooperative
beginning January 1, 1996, and extending through December 31, 1996, dated as of
December 15, 1995.
Letter confirming terms and conditions of the Energy Option Agreement
between OPC and LG&E Power Marketing, Inc., dated as of November 10, 1995.(4)
- ------------------------------
(4) Pursuant to Section 4.3.5 of the Agreement, OPC is obligated to pay
[ ]* for the month of January and [ ]* for the month of February
for a total of [ ]* to EPMI, as provided therein, in consideration of
EPMI's agreement to sell Electric Energy to OPC (pursuant to Section 4.2)
to permit OPC to satisfy its obligations under its contract with LG&E Power
Marketing, Inc.
- ------------------------------
* Indicates information that has been filed separately with the Secretary
of the Commission as an attachment to a request for confidentiality with
respect to the omitted information.
<PAGE>
EXHIBIT 3.5.3(i)
OPC RESOURCES AND OPC CONTRACTS
OPC RESOURCE OPERATIONS GOVERNED BY
- ------------ ----------------------
Georgia Power Blocks Block Power Sale Agreement between Georgia Power
Company and OPC, dated as of November 12, 1990.
Letters dated as of December 30, 1992 and
December 8, 1993, extending term of Block Power
Sale Agreement. Letter dated as of August 30,
1994, electing to reduce capacity OPC is obligated
to purchase under Block Power Sale Agreement.
Vogtle, Units 1 & 2 Alvin W. Vogtle Nuclear Units Numbers One and Two
Purchase and Ownership Participation Agreement
among Georgia Power Company, OPC, Municipal
Electric Authority of Georgia and City of Dalton,
Georgia, dated as of August 27, 1976; Amendment,
dated as of January 18, 1977; Amendment Number
Two, dated as of February 24, 1977. Alvin W.
Vogtle Nuclear Units One and Two Operating
Agreement among Georgia Power Company, OPC,
Municipal Electric Authority of Georgia and City
of Dalton, Georgia, dated as of August 27, 1976.
Hatch, Units 1 & 2 Edwin I. Hatch Nuclear Plant Purchase and
Ownership Participation Agreement between Georgia
Power Company and OPC, dated as of January 6,
1975. Hatch Operating Agreement between Georgia
Power Company and OPC, dated as of January 6,
1975.
Scherer, Units 1 & 2 Plant Robert W. Scherer Units Numbers One and Two
Purchase and Ownership Participation Agreement
among Georgia Power Company, OPC, Municipal
Electric Authority of Georgia and City of Dalton,
Georgia, dated as of May 15, 1980; Amendment,
dated as of December 30, 1985; Amendment Number
Two, dated as of July 1, 1986; Amendment Number
Three, dated as of August 1, 1988; Amendment
Number Four, dated as of December 31, 1990. Plant
Robert W. Scherer Units Numbers One and Two
Operating Agreement among Georgia Power Company,
OPC, Municipal Electric Authority of Georgia and
City of Dalton, Georgia, dated as of May 15, 1980;
Amendment, dated as of December 30, 1985;
Amendment Number Two, dated as of December 31,
1990. Plant Scherer Managing Board Agreement
among Georgia Power Company, OPC, Municipal
Electric Authority of Georgia
<PAGE>
EXHIBIT 3.5.3(i) (CONTINUED)
and City of Dalton, Georgia, dated as of
December 31, 1990. Letter of Intent re: Use of
Eastern and Western Coal at Scherer, dated as of
January 16, 1992; Letter Agreement re: Capital
Modifications and Expenditures for the use of
Western Coal at Plant Scherer, dated as of July 7,
1992 (partially executed). Letter Agreement re:
Additional Amendments to the Scherer and Wansley
Agreements, dated as of December 31, 1990.
Wansley, Units 1, 2, & CT Plant Hal B. Wansley Purchase and Ownership
Participation Agreement between Georgia Power
Company and OPC, dated as of March 26, 1976; Plant
Hal Wansley Operating Agreement between Georgia
Power Company and OPC, dated as of March 26, 1976.
Plant Hal Wansley Combustion Turbine Agreement
between Georgia Power Company and OPC, dated as of
August 2, 1982; Amendment dated as of October 20,
1982. Definitive Agreement Concerning Transfer
Units Under Phase I of the Clean Air Act
Amendments, dated as of October 30, 1992.
Tallassee, Units 1 & 2 No Operative Documents.
Big Rivers Purchase Long Term Firm Power Purchase Agreement between
Big Rivers Electric Corporation and OPC, dated as
of December 17, 1990. Letter dated March 12,
1992. Long Term Firm Power Purchase Agreement,
dated as of July 19, 1989, by and between OPC and
Big Rivers Electric Corporation.
Entergy Purchase Unit Capacity and Energy Purchase Agreement
between OPC and Entergy Power, Incorporated, dated
as of October 11, 1990; Amendment, dated as of
September 29, 1992. Letter Agreement Regarding
Offer to Sell Energy, dated as of April 23, 1992;
Amendment, dated as of February 25, 1993.
Hartwell Energy Limited
Partnership Purchase Power Purchase Agreement between OPC and Hartwell
Energy Limited Partnership, dated as of June 12,
1992. Agreement for Purchase of 230KVS Switchyard
and ITS Interconnection Facilities Agreement,
dated as of August 31, 1992.
<PAGE>
EXHIBIT 3.5.3(i) (CONTINUED)
Rocky Mountain Pumped
Storage Resource Rocky Mountain Pumped Storage Hydroelectric
Project Ownership Participation Agreement, dated
as of November 18, 1988, by and between OPC and
Georgia Power Company. Rocky Mountain Pumped
Storage Hydroelectric Project Operating Agreement
by and between OPC and Georgia Power Company,
dated as of November 18, 1988. Pumped Storage
Hydroelectric Project Option Agreement, dated as
of November 18, 1988. Reciprocity Letter
Agreement, dated as of November 18, 1988. Letters
Relating to Rocky Mountain (Title Defects Letter;
Floyd County Prepayment Letter; Letter Re: Other
Commitments; Letter Re: Cost of Construction).
QF Agreements Interconnection Policy of OPC and Members for
Cogeneration and Small Power Producers, dated as
of January, 1994. Agreement for Purchase of Power
between Carroll Electric Membership Corporation
and the Southwire Company, dated as of July 14,
1986; Amendment, dated as of July 11, 1988.
Restated Power Purchase Agreement between OPC,
Carroll EMC, and The Southwire Company dated June
1, 1995. Agreement for Purchase of Power between
Habersham Electric Membership Corporation and
Herschel Webster, dated as of July 26, 1981;
Amendment, dated as of July 8, 1985; Second
Amendment, dated as of June 1993. Agreement for
Purchase of Power from Georgia Waste Systems,
Inc., dated January 1993. Agreement for Purchase
of Power from Southeast Paper Manufacturing Co.,
dated as of February 29, 1988; Amendment, dated as
of November 11, 1991. Agreement for Purchase of
Power from Spartan Mills, dated as of April 6,
1992.
Proposed Amendments Amendment No. 1 to the CSA between GPC and OPC
dated Draft as of November 7, 1995. Proposed sale
of FLA ITS Interface capability to GPC from OPC
dated December 21, 1995. Proposed sale of FLA ITS
Interface capability to Entergy Power Inc. from
OPC dated December 29, 1995. Proposed Amendment
to Plant Hal B. Wansley Operating Agreement among
GPC, OPC, MEAG, and the City of Dalton.
<PAGE>
EXHIBIT 3.5.3(i) (CONTINUED)
OTHER AGREEMENTS
- ----------------
Integrated Transmission
System Agreement Revised and Restated Integrated Transmission
System Agreement between OPC and Georgia Power
Company, dated as of November 12, 1990. ITSA,
Power Sale and Coordination Umbrella Agreement
between OPC and Georgia Power Company, dated as of
November 12, 1990.
Coordination Services Coordination Services Agreement between Georgia
Power Company and OPC, dated as of November 12,
1990.
Transmission O&M Transmission Facilities Operation and Maintenance
Contract between Georgia Power Company and OPC,
dated as of June 9, 1986.
ITS Transfer Capability Purchase of TVA ITS Interface capability from
Municipal Electric Authority of Georgia to OPC
dated December 17, 1990. Purchase of TVA ITS
Interface capability from GPC to OPC dated
November 12, 1990. Sale of FLA ITS Interface
capability to GPC and from OPC dated May 30, 1995.
SEPA SEPA Contract No. 89-00-1501-912 between SEPA and
OPC dated May 28, 1991 and amended in Supplemental
Agreement No. 1 dated November 26, 1991,
Supplemental Agreement No. 2 dated May 23, 1994,
Supplemental Agreement No. 3 dated January 30,
1995. SEPA Contract No. 89-00-1501-916 between
SEPA and OPC dated December 29, 1993 and amended
in Supplemental Agreement No. 1 dated June 17,
1994, Supplemental Agreement No. 2 dated July 28,
1995, Supplemental Agreement No. 3 dated November
24, 1995.
Operating Procedures Rocky Mountain Pumped Storage Hydroelectric Plant
Coordination Procedures Agreement between
Oglethorpe Power Corporation and Georgia Power
Company effective June 1, 1995. Plant Scherer
Units #1 and #2 Dispatch Procedures Rev. 6..
Hartwell Energy Facility Operation and Maintenance
Procedure for Unit Dispatch effective June 6,
1994. Operating Procedures for use between System
Control Center and Rocky Mountain Plant effective
November 18, 1994.
<PAGE>
EXHIBIT 3.5.2
POWER PURCHASE AND SALE AGREEMENTS
UNDER WHICH OPC IS OBLIGATED TO SELL ELECTRIC ENERGY
Letter of Commitment to sell power to Alabama Electric Cooperative
beginning January 1, 1996, and extending through December 31, 1996, dated as of
December 15, 1995.
Letter confirming terms and conditions of the Energy Option Agreement
between OPC and LG&E Power Marketing, Inc., dated as of November 10, 1995.(4)
- ------------------------------
(4) Pursuant to Section 4.3.5 of the Agreement, OPC is obligated to pay
[ ]* for the month of January and [ ]* for the month of February
for a total of [ ]* to EPMI, as provided therein, in consideration of
EPMI's agreement to sell Electric Energy to OPC (pursuant to Section 4.2)
to permit OPC to satisfy its obligations under its contract with LG&E Power
Marketing, Inc.
- ------------------------------
* Indicates information that has been filed separately with the Secretary
of the Commission as an attachment to a request for confidentiality with
respect to the omitted information.
<PAGE>
EXHIBIT 3.5.3(ii)
EXPECTED AVAILABILITY OF EACH OPC RESOURCE
<TABLE>
<CAPTION>
OPC RESOURCE PLANNED OUTAGES DUE TO SCHEDULED FORCED LOSS FACTOR
MAINTENANCE AFFECTING THE TERM OUTAGE RATE
From To
-------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Hatch 1(5) March 20 May 5 7.00% 1.0000
Hatch 2(5) None 7.00% 1.0000
Rocky Mountain Jan. 21 Jan. 22 8.00% .9980
* Unit 1 Apr. 4 Ap. 26
* Unit 2 None 8.00% .9980
* Unit 3 None 8.00% .9980
Scherer 1 None 6.00% .9980
Scherer 2 Feb. 17 March 3 6.00% .9980
Tallassee 1 & 2 None 1.00% .99015
Vogtle 1(5) March 3 Apr. 16 6.00% 1.0000
Vogtle 2(5) None 6.00% 1.0000
Wansley 1 None 6.00% 1.0000
Wansley 2 Jan. 6 Feb. 4 6.00% 1.0000
Wansley CT None 11.00% 1.0000
-------------------------------------------------------------
</TABLE>
(5) Nuclear planned outages exclude ramp down period prior to full
expected planned outages above.
<PAGE>
EXHIBIT 3.5.3(iii)
[ ]*
- ------------------------------
* Indicates information that has been filed separately with the Secretary
of the Commission as an attachment to a request for confidentiality with
respect to the omitted information.
<PAGE>
EXHIBIT 4.2
[ ]*
- ------------------------------
* Indicates information that has been filed separately with the Secretary of
the Commission as an attachment to a request for confidentiality with
respect to the omitted information.
<PAGE>
EXHIBIT 4.3.1
[ ]*
- ---------------------------------
* Indicates information that has been filed separately with the Secretary
of the Commission as an attachment to a request for confidentiality with
respect to the omitted information.
<PAGE>
EXHIBIT 4.3.3
FIXED MONTHLY PAYMENTS
The Fixed Monthly Payments payable by EPMI to OPC are as follows:
January $ [ ]*
February [ ]*
March [ ]*
April [ ]*
--------------
Total $ [ ]*
The Fixed Monthly Payments were computed based upon the estimated variable
O&M expenses of OPC as summarized below.10
Estimated Variable O&M Expenses
(Thousands of Dollars)
<TABLE>
<CAPTION>
OPC RESOURCE January February March April Total
----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Hatch 1 [ ]* [ ]* [ ]* [ ]* [ ]*
Hatch 2 [ ]* [ ]* [ ]* [ ]* [ ]*
Rocky Mountain [ ]* [ ]* [ ]* [ ]* [ ]*
Scherer 1 [ ]* [ ]* [ ]* [ ]* [ ]*
Scherer 2 [ ]* [ ]* [ ]* [ ]* [ ]*
Tallassee [ ]* [ ]* [ ]* [ ]* [ ]*
Vogtle 1 [ ]* [ ]* [ ]* [ ]* [ ]*
Vogtle 2 [ ]* [ ]* [ ]* [ ]* [ ]*
Wansley 1 [ ]* [ ]* [ ]* [ ]* [ ]*
Wansley 2 [ ]* [ ]* [ ]* [ ]* [ ]*
Wansley CT [ ]* [ ]* [ ]* [ ]* [ ]*
----------------------------------------------------------------------
----------------------------------------------------------------------
Total [ ]* [ ]* [ ]* [ ]* [ ]*
----------------------------------------------------------------------
</TABLE>
- ---------------------------
10 No adjustments will be made to the Fixed Monthly Payments regardless of the
actual amount of the variable O&M expenses.
* Indicates information that has been filed separately with the Secretary of
the Commission as an attachment to a request for confidentiality with
respect to the omitted information.
<PAGE>
<TABLE>
<CAPTION>
Upper
Lower Reservior Estimated Estimated
Upper Reservior Volume MW hrs in MW hrs Accumulated Estimated MW hrs
Reservior Level Ft. change in storage change Generation MW hrs Pumping
Level Ft (optimum) Acre Ft Generating Generating Total Pumping to full pool
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
1392 690.5 5991.0 7696.2
1391 691.0 218 5860.4 130.6 130.6 7528.5 167.7
1390 691.6 216 5731.1 129.4 259.9 7362.3 333.9
1389 692.0 216 5601.7 129.4 389.3 7196.1 500.1
1388 692.6 216 5472.3 129.4 518.7 7029.9 666.3
1387 693.1 215 5343.6 128.8 647.4 6864.5 831.7
1386 693.6 214 5215.4 128.2 775.6 6699.8 996.4
1385 694.1 214 5087.2 128.2 903.8 6535.2 1161.0
1384 694.6 213 4959.7 127.6 1031.3 6371.3 1324.9
1383 695.1 212 4832.7 127.0 1158.3 6208.2 1488.0
1382 695.6 212 4705.7 127.0 1285.3 6045.1 1651.1
1381 696.0 212 4578.7 127.0 1412.3 5882.0 1814.2
1380 696.5 210 4453.0 125.8 1538.0 5720.4 1975.8
1379 697.0 210 4327.2 125.8 1663.8 5558.8 2137.4
1378 697.4 210 4201.4 125.8 1789.6 5397.3 2298.9
1377 697.9 209 4076.3 125.2 1914.7 5236.5 2459.7
1376 698.3 208 3951.7 124.6 2039.3 5076.4 2619.8
1375 698.8 208 3827.1 124.6 2163.9 4916.4 2779.8
1374 699.2 208 3702.5 124.6 2288.5 4756.4 2939.8
1373 699.6 206 3579.1 123.4 2411.9 4597.9 3098.3
1372 700.1 206 3455.8 123.4 2535.2 4439.4 3256.8
1371 700.5 206 3332.4 123.4 2658.6 4280.9 3415.3
1370 700.9 205 3209.6 122.8 2781.4 4123.2 3573.0
1369 701.4 204 3087.4 122.2 2903.6 3966.2 3730.0
1368 701.8 204 2965.3 122.2 3025.7 3809.2 3887.0
1367 702.2 204 2843.1 122.2 3147.9 3652.3 4043.9
1366 702.6 202 2722.1 121.0 3268.9 3496.9 4199.3
1365 703.0 202 2601.1 121.0 3389.9 3341.5 4354.7
1364 703.4 202 2480.1 121.0 3510.9 3186.0 4510.2
1363 703.8 201 2359.7 120.4 3631.3 3031.4 4664.8
1362 704.1 200 2240.0 119.8 3751.0 2877.5 4818.7
1361 704.5 200 2120.2 119.8 3870.8 2723.6 4972.6
1360 704.9 200 2000.4 119.8 3990.6 2569.8 5126.4
1359 705.2 184 1890.2 110.2 4100.8 2428.2 5268.0
1358 705.6 184 1780.0 110.2 4211.0 2286.6 5409.6
1357 705.9 183 1670.4 109.6 4320.6 2145.8 5550.4
1356 706.3 182 1561.4 109.0 4429.6 2005.8 5690.4
1355 706.6 182 1452.4 109.0 4538.6 1865.8 5830.4
1354 706.9 180 1344.6 107.8 4646.4 1727.3 5968.9
1353 707.3 180 1236.8 107.8 4754.2 1588.8 6107.4
1352 707.6 180 1129.0 107.8 4862.0 1450.3 6245.9
1351 707.9 178 1022.4 106.6 4968.6 1313.3 6382.9
1350 708.2 178 915.7 106.6 5075.3 1176.4 6519.8
1349 708.5 177 809.7 106.0 5181.3 1040.2 6656.0
1348 708.8 176 704.3 105.4 5286.7 904.8 6791.4
1347 709.1 176 598.9 105.4 5392.1 769.4 6926.8
1346 709.4 174 494.7 104.2 5496.3 635.5 7060.7
1345 709.8 174 390.5 104.2 5600.5 501.6 7194.6
1344 710.0 164 292.3 98.2 5698.7 375.5 7320.7
1343 710.3 164 194.1 98.2 5796.9 249.3 7446.9
1342 710.6 162 97.0 97.0 5894.0 124.6 7571.6
1341 710.9 162 0.0 97.0 5991.0 7696.2
- --------------------------------------------------------------------------------------------------------------------------
-51 20.4 10003 5991.0
- --------------------------------------------------------------------------------------------------------------------------
MW hrs per
Acre ft
0.599 Generating
0.769 Pumping
Conversions Factors
43,580 cu. ft = acre ft
CFS - flow = acre ft per hr
4000 330.6
4100 338.8
4200 347.1
4300 355.4
4400 363.6
4500 371.9
4600 380.2
4700 388.4
4800 396.7
4900 405.0
5000 413.2
5100 421.5
5200 429.8
5300 438.0
5400 446.3
5500 454.5
5600 462.8
5700 471.1
5800 479.3
5900 487.6
6000 495.9
6100 504.1
6200 512.4
6300 520.7
6400 528.9
6500 537.2
</TABLE>
<PAGE>
EXHIBIT 13.2
NOTICES AND PAYMENT
ENRON POWER MARKETING, INC.:
NOTICES AND CORRESPONDENCE PAYMENTS
Enron Power Marketing, Inc. NationsBank of Texas-Dallas
P.O. Box 4428 for Enron Power Marketing, Inc.
Houston, Texas 77210-4428 ABA Routing # 111000012
Attn: Power Contract Account # 375 04609321
Settlement Manager Confirmation: Enron Power Marketing,Inc.
FAX # (713) 646-3421 Credit and Collections
(713) 853-5667
INVOICES
Enron Power Marketing, Inc.
1400 Smith Street
P.O. Box 4428
Houston, Texas 77210-4428
OGLETHORPE POWER CORPORATION:
NOTICES AND CORRESPONDENCE PAYMENTS
2100 East Exchange Place SunTrust Bank, Atlanta
P.O. Box 1349 for Oglethorpe Power Corporation Master
Tucker, Georgia 30085-1349 Account
Attn: Manager, System Control ABA Routing #061-0001-04
FAX# (404) 270-7663 Account # 8800599634
Confirmation: Oglethorpe Power
Corporation
Samantha Cofield
(770) 270-7191
<PAGE>
EXHIBIT 10.28
STATE OF GEORGIA
COUNTY OF DEKALB
EMPLOYMENT AGREEMENT
THIS EMPLOYMENT AGREEMENT, ("Agreement"), is made and entered into this
the 20th day of December, 1995 by and between OGLETHORPE POWER CORPORATION
(an Electric Membership Generation and Transmission Corporation), organized
and existing under Title 46 of the Official Code of Georgia Annotated
("Employer") and T.D. KILGORE, ("Employee");
WITNESSETH:
WHEREAS, Employer is engaged in the business of providing electric
energy and services to its Member Systems;
WHEREAS, the Board of Directors of Employer recognizes that the electric
utility industry is undergoing rapid and unpredictable change;
WHEREAS, Employer believes that the continued availability of Employee's
service is vitally important to Employer's continued corporate growth and
success; and
WHEREAS, Employee desires to formalize his employment with Employer and
to ensure the security of his position.
NOW THEREFORE, in consideration of the promises and other good and
valuable consideration, the parties agree as follows:
the parties agree as follows:
SECTION 1 - EMPLOYMENT
Employer employs Employee and Employee accepts employment upon the terms
and conditions set forth herein.
SECTION 2 - TERM
(a) Subject to the provisions for termination and extension as provided
herein below, the initial term of this Agreement shall begin on January 1,
1996 and shall terminate on December 31, 1998.
(b) Unless earlier terminated by a voluntary resignation by Employee,
termination of Employee by Employer, or action by either the Employee or
Employer pursuant to Section 2(c), the initial three-year term of this
Agreement shall be automatically extended for an additional year on each
anniversary date of the Agreement, beginning with the January 1, 1997
anniversary.
By: JCE TDK
-------- --------
Employer Employee Page 1 of 8
<PAGE>
(c) Unless earlier terminated by a voluntary resignation by Employee,
or termination of Employee by Employer, sixty days prior to each anniversary
date either the Employee or Employer by written notice to the other may elect
not to allow an automatic extension under Section 2(b). Such notice shall be
effective on the date it is either hand-delivered or sent by certified or
registered mail.
(d) In the event the Employee or Employer makes election under Section
2(c) the remaining term of the contract shall remain in full force or effect.
(e) Notwithstanding the language of this Section 2, no extension of
this Agreement shall operate to extend the term of the Agreement past
Employee's 65th birthday on March 11, 2013.
(f) Subject to Section 11, Employee agrees that during the initial
twelve (12) months of this Agreement, and during the first ten (10) months
following an anniversary date at which a one-year extension of the term of
this Agreement has occurred, he will not accept employment from any other
employer.
SECTION 3 - COMPENSATION
For all services rendered by Employee under this Agreement, Employer
shall pay Employee an annual base salary to be determined by its Board of
Directors, but in no event shall the annual base salary be less than Two
Hundred Forty Thousand dollars ($240,000) per year payable in equal
installments on the 15th and last business day of each month. The Board of
Directors of Employer shall meet at least annually for the purpose of
determining Employee's next year's annual base salary based upon the value of
his services as determined by the Board of Directors. At this same meeting,
the Board of Directors shall also consider what, if any, bonus should be paid
to Mr. Kilgore. This paragraph shall not be interpreted to create any
obligation on the part of the Board of Directors of Employer to increase
Employee's base salary or to pay any bonus whatsoever. Both parties to this
Agreement recognize these determinations to be totally within the discretion
of the Board of Directors.
SECTION 4 - DUTIES
Employee shall serve as the President and Chief Executive Officer of
Employer. In this role he shall manage the day-to-day affairs of Employer as
Employer's Chief Executive. Employee shall have such other duties and
responsibilities as from time-to-time may be reasonably assigned to him by
Employer's Board of Directors and are consistent with Employee's role as
Chief Executive Officer.
SECTION 5 - BENEFITS
Employer currently provides to all employees a comprehensive benefits
package including, but not limited to, paid vacation, health and disability
insurance, life insurance and Employer funded pension plan, a 401K plan and
for key employees, a deferred compensation plan. During the term of his
employment, Employee shall be entitled to receive and shall be allowed to
participate in these benefits on the terms and conditions as provided in the
human resources policies and practices of Employer as the same may be
modified from time-to-time by the Board of Directors. Employee
By: JCE TDK
-------- --------
Employer Employee Page 2 of 8
<PAGE>
recognizes that it is within the sole discretion of the Board of Directors to
modify the benefits of Employer from time-to-time and agrees that no claim
will arise against Employer by virtue of the Board of Directors' exercise of
its rights to modify Employer's benefits package for Employee as a member of
Employer's Executive group. Employer specifically grants Employee unlimited
accrual of vacation time not taken.
SECTION 6 - AUTOMOBILE
In addition to the benefits provided under Section 5 above, Employer
shall provide to Employee an automobile for his personal and business use.
Title to said automobile will remain with Employer. Employer will pay all ad
valorem taxes, maintenance, and gas and will provide appropriate insurance
coverage. Employee will bear all cost of personal use consistent with
Internal Revenue Guidelines and corporate policies as the same may exist from
time-to-time.
SECTION 7 - EXPENSES
Employee is authorized to incur reasonable expenses on behalf of
Employer in performing his duties. Such reasonable expenses shall be
promptly paid (or reimbursed as applicable) by Employer.
SECTION 8 - TERMINATION BY EMPLOYER
(a) Employee's employment may be terminated by Employer at any time for
cause upon written notice to Employee. Cause shall exist if Employee
intentionally commits an act or acts of dishonesty which constitute a felony
or job-related misdemeanor, or an act or acts which breach Employee's
fiduciary duties to Employer, and which either: (1) cause intentional or
material harm to Employer; (2) materially and lawfully impair the reputation
of Employer; or (3) materially interfere with the operations of Employer.
Said written notice shall specify with particularity the actions or inactions
constituting cause. Employee shall have the right, but not the obligation,
to appear with or without counsel, as he elects, before Employer's Board of
Directors to respond to any allegation that serves as the basis for the
termination prior to the effective date of termination. The failure of
Employee to make such appearance shall in no way affect or prejudice the
right of either party to arbitrate any dispute under Section 12, below.
Employee shall be given at least ten days actual written notice of the date,
terms and place of such hearing.
(b) In the event of a termination for cause, Employer shall pay
Employee all amounts due which are then accrued but unpaid, within thirty
(30) days after the date of notice. Employer shall have no additional or
further liability to Employee if cause be sustained.
(c) In the event Employee is terminated by Employer without cause, he
shall be entitled to receive, in addition to accrued salary and benefits, all
salary and benefits he would have received between the date of his
termination and the ending date of the Agreement. Employee acknowledges that
the receipt of such compensation is in lieu of any other amounts that he may
be entitled to receive for any reason related to his employment by Employer
and in lieu of any monies he would otherwise be entitled to receive under any
then applicable corporate policy. If Employer terminates Employee's
employment without cause or meaningfully reduces his stated duties or
prerogatives within three (3)
By: JCE TDK
-------- --------
Employer Employee Page 3 of 8
<PAGE>
months prior to or twenty-four (24) months subsequent to a Change in Control
of Employer, the severance payment shall not be less than the amount
equivalent to two times Employee's annual base salary on the date of
termination or the date on which Employee's duties or prerogatives are
reduced, whichever is applicable. If such reduction in duties occurs,
Employee shall be entitled to severance regardless whether he is terminated
or resigns. Said payment must be provided within thirty (30) days from
Employee's last day of employment. As used herein, a "Change in duties
occurs, Employee shall be entitled to severance regardless whether he is
terminated or resigns. Said payment must be provided within thirty (30)
days from Employee's last day of employment. As used herein, a "Change in
Control" occurs if, during any twelve-month period, there is either (1) a
change in ownership of Employer such that owners of the Employer prior to the
twelve-month period cease to constitute at least seventy percent (70%) of the
owners after the twelve-month period; or (2) a change in the Board of
Directors such that the Board Members prior to the twelve-month period cease
to constitute at least fifty percent (50%) of the Directors at the end of the
twelve-month period. However, Employer and Employee agree that a reduction
in the size of the Board of Directors as contemplated by Section 11 below
shall not constitute a Change in Control.
(d) Employee agrees that in the event of a termination without cause,
as a condition precedent to receipt of the monies described under Section
8(b), he will execute a mutual release of all claims (other than vested
benefits) against Employer, its members, affiliates, directors, officers,
agents, employees and attorneys, and VICE VERSA. The Employer's failure to
execute and provide a fully mutual release shall eliminate Employee's duty to
do same, but shall not delay Employer's duty to pay the monies as provided
herein.
SECTION 9 - NOTICE TO EMPLOYER UPON VOLUNTARY RESIGNATION
Employee agrees that should he choose to voluntarily separate himself
from Employer, he will provide Employer with a minimum of sixty (60) days
written notice. Said notice to be provided in accordance with the terms of
this Agreement.
SECTION 10 - COVENANT NOT TO COMPETE
(a) Employee agrees that in the event he voluntarily separates himself
from Employer during the time periods covered by Section 2(f), or after
Employee makes the election under Section 2(c), he will not, for a period of
one (1) year thereafter, unless he obtains prior written consent of the
Chairman of the Board of Employer, which consent shall not be unreasonably
withheld, become an officer, director, contractor, consultant or employee or
in any way be employed with or for any competitor of Employer or any of its
competitor's, affiliates or members. By way of example, and not by way of
limitation, this shall include:
include:
(1) Georgia Power Company;
(2) The Municipal Electric Authority of Georgia;
(3) Dalton Utilities;
(4) National Power PLC; or
(5) Any of the above-named entities' affiliates;
(b) Employee acknowledges that the provisions specified herein
regarding his non-competition are fair and equitable under the circumstances
and agrees that the period for such
By: JCE TDK
-------- --------
Employer Employee Page 4 of 8
<PAGE>
undertaking may be tolled or suspended pursuant to a court order for any
period of time during which he is found by a court of competent jurisdiction
to be in violation of this Section 10. Moreover, Employee acknowledges that
should he be in violation of this Section, Employer shall be entitled to seek
injunctive or monetary relief in a court of competent jurisdiction.
(c) In the event that Employee voluntarily separates himself from
Employer (unless such separation is in violation of Section 2(f)), and
Employer does not provide written consent waiving the provisions of
subsection (a) above, Employer shall provide compensation equivalent to
Employee's salary, most recent bonus, and benefits on the date of the
termination of his employment for the entire period covered by subsection
(a). Such payment shall be made regardless whether Employee obtains
employment which does not violate subsection (a).
SECTION 11 - BOARD OF DIRECTORS
Employer will engage in a good faith effort to reduce the size of
the Board of Directors to fifteen (15) or less. Failure to engage in such
good faith efforts shall permit Employee, at his election by written notice,
to void this entire Agreement immediately. Such notice must be sent pursuant
to Section 13 on or before December 31, 1997.
SECTION 12 - ARBITRATION
Except as otherwise provided in this Agreement, Employer and
Employee hereby consent to the resolution by arbitration of all claims or
controversies for which a court otherwise would be authorized by law to grant
relief, in any way arising out of, relating to or associated with Employee's
employment with Employer or its termination, whether actual, or alleged, that
Employer may have against Employee or that Employee may have against Employer
or against its members, officers, directors, employees or agents in their
capacity as such or otherwise, whether or not such dispute concerns the
formation or terms of this Agreement. Any such arbitration shall be in
accordance with the then procedures of the American Arbitration Association
("AAA"). The arbitration hearing will be held before an experienced
employment arbitrator or panel of such arbitrators licensed to practice law
in the State of Georgia and selected by and in accordance with the rules of
the AAA, as the exclusive remedy for such claim or dispute. The forum for
such arbitration shall be Atlanta, Georgia. The party seeking arbitration of
a dispute, claim or controversy as required by this Section must give
specific written notice of any claim to the other party within twelve (12)
months of the date the party seeking arbitration first has knowledge of the
event giving rise to a claim or dispute; otherwise, the claim shall be void
and deemed waived, even if there is a federal or state statute of limitations
which would have given more time to pursue the claim. Notwithstanding the
foregoing, Employer shall have the right to seek temporary and/or preliminary
injunctive relief in a court of competent jurisdiction to enforce the terms
of Section 10 hereof. The ultimate resolution of the underlying issues in
such litigation, shall, however, be subject to this Agreement by the parties
to resolve any disputes by arbitration as set forth herein. In the event
that Employee prevails in said arbitration or litigation, whether wholly or
in part, he shall be entitled to prompt full reimbursement by Employer of his
legal costs as incurred.
By: JCE TDK
-------- --------
Employer Employee Page 5 of 8
<PAGE>
SECTION 13 - NOTICES
Any notice required or permitted to be given under this Agreement shall
be sufficient if in writing and sent by Certified or Registered Mail to
Employee's residence then on file with Employer, in the case of Employee, or
its principal office at OGLETHORPE POWER CORPORATION, 2100 East Exchange
Place, P.O. Box 1349, Tucker, Georgia 30085-1349, Attention: Chairman of the
Board, in the case of Employer.
SECTION 14 - WAIVER OF BREACH
The waiver of Employer or Employee of a breach of any provision of this
Agreement by Employee or Employer shall not operate or be construed as a
waiver of any subsequent breach by Employee or Employer, respectively.
SECTION 15 - ASSIGNMENT
The rights and obligations of Employer under this Agreement shall inure
to the benefit of and shall be binding upon Employer's successors and assigns.
SECTION 16 - GOVERNING LAW
This Agreement shall be governed by, construed under, performed and
enforced in accordance with the laws of the State of Georgia.
SECTION 17 - EMPLOYEE'S ATTORNEYS' FEES
Employer agrees to reimburse Employee for the attorneys' fees incurred
in obtaining legal advice regarding this Agreement, up to a maximum of
$2,500.00.
SECTION 18 - SEVERABILITY
Should any provision of this Agreement or portion thereof, be ruled
void, invalid, unenforceable or contrary to public policy by any court of
competent jurisdiction, then any remaining portion of such provision and all
other provisions of this Agreement shall survive and be applied and any
invalid or unenforceable portion shall be construed or performed to preserve
as much of the original words, terms, purpose and intent as shall be
permitted by law.
SECTION 19 - COUNTERPARTS
This Agreement shall be executed in duplicate counterparts. Each
counterpart is deemed an original of equal dignity with the other. The
official executing this Agreement on behalf of Employer represents and
warrants that he has full requisite authority to do so.
By: JCE TDK
-------- --------
Employer Employee Page 6 of 8
<PAGE>
SECTION 20 - ENTIRE AGREEMENT
This Agreement sets forth the entire understanding and agreement of
Employer and Employee with respect to the subject of this Agreement. All
courses of dealing, and prior representations, promises, understandings and
agreements, if any, whether oral or written, are suspended by and merged into
this Agreement. No modification of or amendment to this Agreement shall be
binding upon Employer or Employee unless in writing and signed by both
parties hereto. No provision of this Agreement shall be construed against or
interpreted to the advantage or disadvantage of either party by any court,
judicial or other governmental authority by reason of such party having been
deemed to have structured, written, drafted or dictated such provision.
SECTION 21 - CAPTIONS
The brief underlined headings and titles preceding each Section of this
Agreement are for the purpose of section identification, convenience and ease
of reference, and shall be completely disregarded in the construction of this
Agreement.
SECTION 22 - RURAL UTILITIES SERVICE REQUIREMENTS
This Agreement shall not become effective until approved by the Rural
Utilities Service (the "RUS") in accordance with the consolidated Mortgage
and Security Agreement, dated September 1, 1994, by and between OPC, as
Mortgagor, and the 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 Bond Indentures, all as Mortgagees
("Mortgage").
In the event that OPC is in default under the Mortgage and if the RUS
requires termination of the Employee's employment or of this Agreement
notwithstanding any other language in this Agreement, Employer may
immediately upon notice to Employee terminate this Agreement and/or the
employment of the Employee. Termination under this provision shall be deemed
a termination without cause, unless the default is caused by actions of
Employee which permit termination with cause under Section 8(a). In either
case, Employee's right to compensation will be governed by Section 8.
By: JCE TDK
-------- --------
Employer Employee Page 7 of 8
<PAGE>
IN WITNESS WHEREOF, Employer and Employee have caused these presents to
be executed as of the date first stated above.
EXECUTED this 20th day of December, 1995.
/s/ T. D. Kilgore T.D. KILGORE
- ----------------------------- Social Security Number: ###-##-####
/s/ Lynda Clark
- -----------------------------
Witness:
/s/ J. Calvin Earwood OGLETHORPE POWER CORPORATION
- -----------------------------
Title: Chairman of Board
-----------------------
/s/ Julie Martin Witnessed and approved:
- ------------------------------
Witness: /s/ Charles T. Autry
----------------------------------
General Counsel
Oglethorpe Power Corporation
Page 8 of 8
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM
OGLETHORPE POWER CORPORATION'S BALANCE SHEET AS OF DECEMBER 31, 1995
AND RELATED STATEMENTS OF REVENUES AND EXPENSES AND CASH FLOWS FOR THE
PERIOD ENDED DECEMBER 31, 1995 AND IS QUALIFIED IN ITS ENTIRETY BY
REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<BOOK-VALUE> PER-BOOK<F1>
<TOTAL-NET-UTILITY-PLANT> 4,471,762
<OTHER-PROPERTY-AND-INVEST> 146,856
<TOTAL-CURRENT-ASSETS> 477,149
<TOTAL-DEFERRED-CHARGES> 342,729
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 5,438,496
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 338,891
<TOTAL-COMMON-STOCKHOLDERS-EQ> 0
0
0
<LONG-TERM-DEBT-NET> 4,207,320
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 83,684
0
<CAPITAL-LEASE-OBLIGATIONS> 296,478
<LEASES-CURRENT> 5,991
<OTHER-ITEMS-CAPITAL-AND-LIAB> 506,132
<TOT-CAPITALIZATION-AND-LIAB> 5,438,496
<GROSS-OPERATING-REVENUE> 1,149,561
<INCOME-TAX-EXPENSE> 0
<OTHER-OPERATING-EXPENSES> 840,884
<TOTAL-OPERATING-EXPENSES> 840,884
<OPERATING-INCOME-LOSS> 308,677
<OTHER-INCOME-NET> 33,710
<INCOME-BEFORE-INTEREST-EXPEN> 342,387
<TOTAL-INTEREST-EXPENSE> 320,129
<NET-INCOME> 22,258
0
<EARNINGS-AVAILABLE-FOR-COMM> 0
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 54,819
<CASH-FLOW-OPERATIONS> 204,383
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1>$338,891 REPRESENTS TOTAL RETAINED PATRONAGE CAPITAL. THE REGISTRANT IS
A MEMBERSHIP CORPORATION AND HAS NO AUTHORIZED OR OUTSTANDING EQUITY
SECURITIES.
</FN>
</TABLE>
