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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM 10-K
(MARK ONE)
/ /
X/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended DecemberFOR THE FISCAL YEAR ENDED DECEMBER 31, 19931995
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.FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NO. 33-7591
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OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION)
(Exact name of registrant as specified in its charter)
GEORGIA 58-1211925
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
POST OFFICE BOX 1349
2100 EAST EXCHANGE PLACE 30085-1349
2100 EAST EXCHANGE PLACE (Zip Code)
TUCKER, GEORGIA (Zip Code)
(Address of principal executive offices)
Registrant's telephone number, including area code: (404) 270-7600
Securities registered pursuant to Section 12(b) of the
Act: None
Securities registered pursuant to Section 12(g) of the
Act: None
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
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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 ofto such
filing requirements for the past 90 days. YES__X__ NO______Yes _X_ No ____
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]/X/
State the aggregate market value of the voting stock held by nonaffiliates
of the registrant. NoneNONE
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.THE REGISTRANT IS A
MEMBERSHIP CORPORATION AND HAS NO AUTHORIZED OR OUTSTANDING EQUITY SECURITIES.
Documents Incorporated by Reference: NoneNONE
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OGLETHORPE POWER CORPORATION
19931995 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
Item Page
-ITEM PAGE
---- ----
PART I
1 Business . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ................................................................ 1
Oglethorpe Power Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .......................................... 1
The Members of Oglethorpe. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6Oglethorpe ............................................ 8
The Power Supply System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Co-ownersSystem .............................................. 11
Co-Owners of the Plants and the Plant and Transmission Agreements. . . . . . . . . . . . 19Agreements .... 21
2 Properties . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24............................................................. 25
3 Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24Proceedings ...................................................... 25
4 Submission of Matters to a Vote of Security Holders. . . . . . . . . . . . . . . . . . . . 24Holders .................... 25
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . 25Matters .. 26
6 Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25Data ................................................ 26
7 Management's Discussion and Analysis of Financial Condition
and Results of Operations. . . 26Operations ............................................. 27
8 Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . . . 32Data ............................ 35
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure . . . 49.............................................. 53
PART III
10 Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . . 49..................... 53
11 Executive Compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61................................................. 65
12 Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . . 63......... 67
13 Certain Relationships and Related Transactions . . . . . . . . . . . . . . . . . . . . . . 63......................... 67
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . . . 64....... 68
i
SELECTED DEFINITIONS
When used herein the following terms will have the meanings indicated below:
Term Meaning
-TERM MEANING
---- -------
ADSCR Annual Debt Service Coverage Ratio
AFUDC Allowance for Debt and Equity Funds Used During Construction
BPSA Block Power Sale Agreement
CFC National Rural Utilities Cooperative Finance Corporation
CoBank CoBank, ACB, formerly known as the National Bank for Cooperatives
Commission Securities and Exchange Commission
CSA Coordination Services Agreement
Dalton City of Dalton, Georgia
DOE United States Department of Energy
DSC Debt Service Coverage Ratio
EPA United States Environmental Protection Agency
EPI Entergy Power, Inc.
FASB Financial Accounting Standards BoardEPMI 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
REARUS 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
ii
PART I
ItemITEM 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. As
of February 28, 1994, Oglethorpe had 505has approximately 427
full-time and 4339 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. As of
December 31, 1993, theThe Members servedserve approximately 11.1 million electric consumers
(meters) representing a total population of approximately 2.32.6 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"). 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.
MEMBER CONTRACTS
Eachexisting Wholesale Power Contract will remain in effect through the yearContracts
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 1993,1995, the aggregate SEPA allocation
to the Members was 542 megawatts ("MW") plus associated energy, representing
approximately 13%11% of total Member peak demand and approximately 6%5% of total
Member energy requirements. Because theThe 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, such
growth is expected to be served primarily through Oglethorpe's resources.requirements. (See "Member
Demand and Energy Requirements--DISPERSED GENERATION"Requirements" herein and "THE MEMBERS OF OGLETHORPE--Contracts
with SEPA" herein..)
Each Wholesale Power ContractPROPOSED 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
1
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 withoutthey 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 both
Oglethorpe andthe Rural Utilities Service ("RUS"),
formerly known as the Rural Electrification Administration, ("REA"), nothat Oglethorpe
and each Member may
reorganize, consolidateexecuting 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 merge,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
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 sell, leaseto 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 transfer all orto assign its rights and obligations under such wholesale
power contract to another party with a substantial partcredit 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 its assets (or make any agreement therefor), so long asconditions, 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 has notes outstanding to REA and the FFB, without first payingMembers, 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 portionrating 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 any such outstanding notes asthese conditions may be determinedwaived 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 withcannot predict the prior written consentactual timing
of REAor the ultimate likelihood of full implementation of the restructuring or
governance changes. Until implementation of the restructuring, Oglethorpe
will continue its current operations, and otherwise complying with such reasonable
terms asuntil satisfaction of the conditions
applicable to the new governance structure, Oglethorpe and REA may require.
1
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 19911993 through 19931995 and also shows
the amounts of such requirements supplied by Oglethorpe and SEPA. For the
years 19911993 through 1993,1995, demand and energy requirements increased at an
average annual compound growth rate of 8.1%6.4% and 7.3%5.9%, respectively.
3
DEMAND (MW) ENERGY REQUIREMENTS (MWh)
--------------------------------------(MWH)
--------------------------------------- -----------------------------------------
TOTAL TOTAL
REQUIRE- SUPPLIED BY SUPPLIED BY REQUIRE- SUPPLIED BY SUPPLIED BY
MENTS(1) OGLETHORPE(2) SEPA(3) MENTS OGLETHORPE(2) SEPA(3)
----------------- ------------- ----------- ------------------ ------------- -----------
1991 . . . . . . . . . 3,664 3,122 542 15,029,976 14,022,213 1,007,763
1992 . . . . . . . . . 3,865 3,323 542 15,562,495 14,466,943 1,095,552
1993 . . . . . . . . . 4,283 3,736 542 17,313,313 16,253,283 1,060,030
- -------------------------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
______________________
(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".)
Prior to 1993, no Member accounted for 10% or more of Oglethorpe's total
revenues. In 1993, however,1995, Cobb EMC and Jackson EMC accounted for approximately 10%11.3% and
10.4% of Oglethorpe's total revenues.revenues, respectively.
SEASONAL VARIATIONS
Although theThe demand for energy by the Members is influenced by seasonal weather
conditions, Oglethorpe's rate structure is designed to cause capacity
revenues, which include margins, to remain relatively level throughout the year.
Energy revenues, which do not include margins, track energy costs as they are
incurred. Although energy charges, which are based on variable costs, fluctuate
from month to month, capacity charges, which are based on annual peak demands,
do not fluctuate based on a Member's usage during a given year.conditions. Historically, Oglethorpe's peak demand occurs during the months
of June through September. CONSERVATION AND LOAD(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--OTHER FUTURE RESOURCES"Resources".)
DISPERSED GENERATION
Oglethorpe and the Members have been discussing the desire of a number of
the Members to make greater use of dispersed generation units. If permitted by
REA, such units would be used to maintain reliability of electric service during
emergencies on a Member's distribution system, to serve specific customer needs
and otherwise to be available to Oglethorpe to serve the demands of Members on
its system. The installation and use of dispersed generation units by any Member
would be governed by policies and procedures, consistent with the Wholesale
Power Contract, designed to
2
ensure system reliability and prevent any material adverse effect on
Oglethorpe's revenues or on any other Member's power costs.
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,
19931994 (the "REA"RUS Mortgage"), among Oglethorpe, as mortgagor, and the United
States of America acting through the Administrator of REA,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 ("Trust Company"SunTrust"), as
4
trustee under certain pollution control bond indentures identified in the REARUS
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 1993,1995, which amounts will be fully amortized by the end of
1995.1996. (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 industrialcommercial and commercialindustrial loads. (See "THE
MEMBERS OF OGLETHORPE--Service Area and Competition".)
Oglethorpe's rates, as established by its Board of Directors, are
subject to review and approval by REA.RUS. Oglethorpe is required under the REARUS
Mortgage to implement rates designed to maintain a Times Interest Earned
Ratio ("TIER") of not less than 1.05, a Debt Service Coverage Ratio ("DSC")
of not less than 1.0 and an Annual Debt Service Coverage Ratio ("ADSCR") of
not less than 1.25. Oglethorpe has always met or exceeded the TIER, DSC and
ADSCR requirements of the REARUS Mortgage. Oglethorpe's current policy is to
set rates to meet a TIER of 1.07 in 1996. (See "General--RATES"General-RATES AND FINANCIAL
COVERAGE REQUIREMENTS" in Item 7.)
The Wholesale Power Contracts provide that no rate revision shall be
effective unless approved by REA,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, REARUS 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--
OPERATING REVENUES--SALES TO MEMBERS"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 electricityelectric 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 availability and 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, licensing and other delays affecting the construction, operation
and cost of new and existing facilities, and the effects of conservation, energy
management and other governmental regulations on the use of electric energy.regulations.
All of thesethe factors mentioned above present an increasing challenge to
companies in the electric utility industry, including Oglethorpe and the
Members, to reduce costs, and
improve the management of resources.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".)
35
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 1993,1995,
Oglethorpe derived 15%6% of its total revenues from sales to GPC, making GPC one
of Oglethorpe's largest customer.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
iscompleted 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",
"--Future Power Resources--ROCKY MOUNTAIN", "-Transmission"--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"Plants--Georgia Power Company", "--The Plant Agreements", "--Agreements
Relating to the Integrated Transmission System", and "--The Joint Committee
Agreement".
RELATIONSHIP WITH REARUS
Federal loan programs administered by REARUS have provided the principal
source of financing for electric cooperatives. Direct loans from REARUS have
been a major source of funding for the Members, while loans guaranteed by REARUS
and made by the Federal Financing Bank ("FFB") have been a major source of
funding for Oglethorpe. Through provisions of the REARUS Mortgage, REARUS exercises
substantial control and supervision over Oglethorpe in such areas as
accounting, issuingthe 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 REARUS loan and guarantee
programs have been characterized by the imposition of increasingly
problematic terms and conditions and extended delays in access to necessary
funding.
The President's budget forFor fiscal year 1995 proposes to1996, the Congress set the level of funding for the 100%
guarantee program at $275$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 REARUS 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, however, the future cost, availability
and magnitude of REA-guaranteedRUS-guaranteed loans cannot be predicted. See "THE MEMBERS
OF OGLETHORPE-Members'OGLETHORPE--Members' Relationship with REA"RUS" for a discussion of the impact
of the budget proposal on the direct loan program.
REA continues to re-evaluateFor 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. TheRUS has said the purpose of the project
is to improve the credit-worthiness of loans made or guaranteed by REA.RUS. In
addition to adopting new rules regulating policies and procedures for insured
and guaranteed loans and lien accommodations, REARUS 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 in annot, 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.
6
In advance noticenotices of proposed rule-making,rule-makings, RUS also has requested
suggestions for revisions to its standard form of mortgage. Many of
thesemortgage 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 have takencontinue to take many months or years to complete and the
outcome
4
of these various rule-making initiatives, whether others may be
forthcoming, whether any of such rule-making initiatives may achieve the
objectives stated by REA,RUS, or the extent to which such initiatives may affect
Oglethorpe or the Members cannot be predicted.
The Clinton Administration has proposed that the Department of Agriculture,
which includes REA, be reorganized to improve its efficiency. Legislation has
been introduced that would authorize the Secretary of Agriculture to implement
this reorganization. Under the proposed reorganization, the electric and
telephone programs of REA would be included in a new Rural Utilities Service.
The rural development functions of REA would be included in a Rural Business and
Cooperative Development Service. Both agencies would report to an Under
Secretary for Rural Economic and Community Development. Oglethorpe's management
does not believe that the reorganization, if implemented as proposed, will have
a significant adverse effect on it or the Members.
57
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. As of
December 31, 1993, theThe
Members servedserve approximately 11.1 million electric consumers (meters)
representing a total population of approximately 2.32.6 million people. The
Members serve a region covering approximately 40,000 square miles, which is
approximately 70% of the land area of Georgia served by the owners of the
ITS, encompassing 150 of the State's 159 counties. Sales by the Members in
19931995 amounted to approximately 16.218.2 million megawatt-hours ("MWh"), with 74%72%
to residential consumers, 24%26% to commercial and industrial consumers and 2%
to other consumers. No single consumer of any Member constituted more than
1% of the Members' aggregate sales in 1993.1995. 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 19911993 through 19931995
of 4.5%4.0% in number of consumers, 6.9%5.9% in MWh sales and 8.9%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. Thesuppliers;
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.
The territorial assignments underAs referenced above, the Territorial Act are also subject to
an exception that permitsallows the owner of any new
facility located outside of existing municipal limits and having a connected
demand upon initial full operation of 900 kilowatts or greater to receive
electric service from the retail supplier of its choice. The Members, with
Oglethorpe's support, are actively engaged in competition with other retail
electric suppliers for these new 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 increasedgiven Oglethorpe
and the Members the opportunity to develop resources and strategies to
operate in recent years.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
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 REA. TheseRUS or loan documents with other lenders. The RUS mortgages
generally prohibit such distributions unless, after any such distribution,
the Member's total equity will equal at least 40% of its total assets, except
that distributions may be made of up to 25% of the margins and patronage
capital received by the Member in the preceding year. As a general matter,
the Members that borrow from RUS distribute accumulated patronage capital
from time to time subject to their respective financial policies and in
conformity with their respective REARUS mortgages. (See "Members' Relationship
With RUS" herein.)
Oglethorpe is a membership corporation, and the Members are not
subsidiaries of Oglethorpe. Except with respect to the obligations of the
Members under each Member's 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 6
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 REARUS mortgages
of the Members.
RATE REGULATION OF MEMBERS
Through provisions in the loan documents securing loans to the Members,
REARUS exercises control and supervision over the Members that borrow from it in
such areas as: (i) accounting; (ii) borrowings; (iii) rates and charges for
the sale of power; (iv) construction and acquisition of facilities; and (v)
the purchase and sale of power. The individual REARUS mortgages of the Members
require them to design rates with a view to maintaining an average TIER of
not less than 1.50 and an average DSC of not less than 1.25 for the two
highest out of every three successive years.
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 REA,RUS, the
Territorial Act prohibits the Members from unreasonable discrimination in the
setting of rates, charges, service rules or regulations.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 1993,1995, the aggregate SEPA allocation to the Members was 542 MW plus
associated energy, representing approximately 13%11% of total Member peak demand
and
9
approximately 6%5% of total Member energy requirements. (See "OGLETHORPE POWER
CORPORATION-MemberCORPORATION--Member Contracts" and "-Member"--Member Demand and Energy Requirements"
and the table thereunder.)
In September 1993,On December 8, 1994, SEPA issued a Notice of Intent to revise its marketing
policyfinal Power Marketing Policy for the
Georgia-Alabama-SouthGeorgia - Alabama - South Carolina systemSystem of projects, from which
the Members purchase SEPA power.Projects. This policy will
govern the renewal of SEPA's contracts with the Members, which are subjectMembers. 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.
Although Oglethorpe1994, 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 anticipate that such revised policy will resultinclude any proposals to
privatize the federal power marketing administrations. The ultimate outcome
of this issue in a significant change, the final marketing policy and its effect on the Members'
allocations of capacity and energyCongress cannot be predicted with certainty.
MEMBERS' RELATIONSHIP WITH REARUS
Federal loan programs providing direct loans from REARUS to electric
cooperatives have been a major source of funding for the Members. On November 1,
1993,Recent
changes and proposals for further changes have made the President signed into lawdirect 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 which contains significant revisions toeliminated the REAlong-standing 2% loan program utilized byand
substituted a new program, the Members. The Members previously reliedinterest rates for which are based on the 5% insured loan
program, under which the REA Administrator could require that up to 30% of a
borrower's capital needs be obtained from private sources. The 1993 Act provides
for loans to be made at an interest rate equal to thatrates
being paid on municipal bonds with comparable maturities. Certain borrowers
with either (i) low consumer density or (ii) higher than averagehigher-than-average rates and
consumers having lower
than average incomes will have borrowing rates capped at 7%.lower-than-average consumer income are eligible for a 5% loan program. The 1993 Act
continues to make 5% loans available for hardship cases. Loans will also be
available to fund demand-side management and conservation programs. Although the
1993 Act will reduce the Government's cost associated with the REA loan program,
there is no guarantee that further changes in the cost and availability of the
REA lending program will not be made, since the level of funding will remain
subject to the Congressional budget and appropriation processes. The President's
budget proposal for the fiscal year 1995 includes a proposal to replace most of
the "municipal bond rate" program with higher-cost loans made at the cost to the
United States Department of the Treasury. The outcome of this budget proposal
and the
future cost, availability and amount of REARUS 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
REARUS program, see "OGLETHORPE POWER CORPORATION-RelationshipCORPORATION--Relationship with REA"RUS".
7
THIRD-PARTY INTEREST IN MEMBER SYSTEMS
From time to time, utilities may be approached by other utilities or other
parties interested in purchasing their systems. Some of Oglethorpe's Members
have been approached in the past by third parties indicating an interest in
purchasing their systems. The Wholesale Power Contract between Oglethorpe and
each Member provides that no Member may reorganize, consolidate or merge, or
sell, lease or transfer all or a substantial portion of its assets (or make any
agreement therefor), so long as Oglethorpe has notes outstanding to REA and the
FFB, without first paying such portion of any such outstanding notes as may be
determined by Oglethorpe with the prior written consent of REA and otherwise
complying with such reasonable terms and conditions as Oglethorpe and REA may
require. The enforceability of the REA form of wholesale power contract has been
consistently upheld by the courts in several jurisdictions. In addition, REA has
recently stated its policy that it will not encourage or facilitate the buyout
of borrowers by third parties and that it will expect cooperative distribution
utilities to retire a proportionate share of the associated G&T indebtedness and
to pay other appropriate costs and expenses of the G&T as a condition of a
buyout.
Oglethorpe's management is unable to predict what transactions, if any,
might result from the past third-party interest or whether any other proposals
will be made to the Members. Oglethorpe has received an opinion of its counsel
that each of the Wholesale Power Contracts is a valid, binding and enforceable
obligation of each respective Member. Based on this opinion and other factors,
Oglethorpe's management believes that no sale or transfer of Member assets would
have a material adverse effect upon its financial condition or results of
operations.
810
THE POWER SUPPLY SYSTEM
GENERAL
Oglethorpe supplies the current capacity and energy requirements of the
Members from a combination of owned and leased generating plants and power
purchased under long-term contracts with other power suppliers. These
resources are scheduled and dispatched so as to minimize the operating cost
of Oglethorpe's system. In addition, Oglethorpe purchases and sells capacity
and energy in the bulk power market to make the best use of its resources and
thus minimize the cost of capacity and energy delivered to the Members.
The following table sets forth certain information with respect to the
generating facilities in which Oglethorpe currently has ownership or
leasehold interests, all of which are in commercial operation except for Rocky Mountain,
which is under construction.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 construction and operating agent. Oglethorpe is the sole owner of the
Tallassee Project at the Walter W. Harrison Dam ("Tallassee"). (See
"CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--The Plant
Agreements".)
OGLETHORPE'S
SHARE OF NAME- COMMERCIAL LICENSE
PERCENTAGE PLATE CAPACITY OPERATION EXPIRATION
TYPE OF FUEL INTEREST(1) (MW) DATE DATE
------------ ----------- ----------------------------- ---------- ----------
FACILITIES IN SERVICE:
- ----------------------
Plant Hatch (near Baxley)
Unit No. 1 Nuclear 30 243.0 1975 2014
Unit No. 2 Nuclear 30 246.0 1979 2018
Plant Vogtle (near Waynesboro)
Unit No. 1 Nuclear 30 348.0 1987 2027
Unit No. 2 Nuclear 30 348.0 1989 2029
Plant Wansley (near Carrollton)
Unit No. 1 Coal 30 259.5 1976 N/A(3)A(2)
Unit No. 2 Coal 30 259.5 1978 N/A(3)A(2)
Combustion Turbine Oil 30 14.8 1980 N/A(3)A(2)
Plant Scherer (near Forsyth)
Unit No. 1 Coal 60 490.8 1982 N/A(3)A(2)
Unit No. 2 Coal 60 490.8 1984 N/A(3)A(2)
Tallassee (near Athens) Hydro 100 2.1 1986 2023
-------
Total in Service 2,702.5
-------
FACILITIES UNDER CONSTRUCTION:
Rocky Mountain Pumped Storage
(near Rome) Hydro 75(2) 635.974.61 632.5 1995 2027
-------
Total Ownership 3,338.43,335.0
-------
- --------------------------------
______________________
(1) Oglethorpe has an ownership interest in all of the facilities except
Scherer Unit No. 2. The 60% interest in Scherer Unit No. 2 is leased
under leases that expire in 2013, subject to options to renew for a
total of 8.5 years.
(2) Represents Oglethorpe's estimated ownership interest upon completion.
Oglethorpe's ultimate ownership interest is proportional to its investment
in the project relative to GPC's investment. (See "Future Power
Resources--ROCKY MOUNTAIN" herein.)
(3) Coal-fired units and combustion turbines do not operate under operating
licenses similar to those granted to nuclear units by the Nuclear
Regulatory Commission and to hydroelectric plants by the Federal Energy
Regulatory Commission.
9
Upon completion of Rocky Mountain, Oglethorpe will ownowns or leaseleases 1,500.6 MW of coal-fired capacity, 1,185 MW of
nuclear-fueled capacity, an estimated 635.9632.5 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
11
owners to use their combined resources to make deliveries to their respective
consumers, to provide transmission service to third parties and to make
off-system purchases and sales. (See "Transmission and Other Power System
Arrangements" herein and "CO-OWNERS OF THE PLANTS AND THE PLANT AND
TRANSMISSION AGREEMENTS--Agreements Relating to Integrated Transmission
System".)
PLANT PERFORMANCE
The following table sets forth certain operating performance information
of each of the major generating facilities in which Oglethorpe currently has
ownership or leasehold interests, except for Rocky Mountain which is not yet in
commercial operation:interests:
EQUIVALENT AVAILABILITY(1) CAPACITY FACTOR(2)
-------------------------- --------------------
UNIT------------------
Unit 1995 1994 1993 1992 19911995 1994 1993 1992 1991
- ---- ---- ---- ---- ---- ---- ----
Plant Hatch
Unit No. 1 . . . . . . ........... 98% 84% 76% 95% 73%100% 85% 77% 95% 72%
Unit No. 2 . . . . . . ........... 75 70 7478 75 70 7475 79 75
Plant Vogtle
Unit No. 1 . . . . . . ........... 98 86 85 96 7898 86 96 7886
Unit No. 2 . . . . . . ........... 89 91 87 80 9290 91 87 80 92
Plant Wansley
Unit No. 1 . . . . . . ........... 90 92 88 92 8456 62 71 76 64
Unit No. 2 . . . . . . ........... 89 88 90 92 94 73 7756 58 73
Plant SchererScherer(3)
Unit No. 1 . . . . . . ........... 95 97 88 95 9873 64 36 17 25
Unit No. 2 . . . . . . ........... 97 85 95 100 10085 60 37
29Rocky 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
______________________
(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.
Although Plant Scherer is designed for base load operation, it has
primarily operated in peaking service due to the historically higher cost of its
fuel supply (low-sulfur coal under long-term contracts) relative to the cost of
Oglethorpe's other resources. Thus, the capacity factors for Scherer Units No. 1
and No. 2 have been lower than those typical of base loaded units. With the
planned acquisition of lower cost low-sulfur coal and expected increases in
Member sales, Oglethorpe's management anticipates higher utilization of Scherer
Units No. 1 and No. 2 in the future.
1012
FUEL SUPPLY
Coal for Plant Wansley is purchased under a long-term contracts,contract, which areis
estimated to be sufficient to provide the majority of the coal requirements
of Plant Wansley through 1997, with the remainder being provided through spot
market transactions. To comply with the requirements of the Clean Air Act, as
amended (the "Clean Air Act"), Plant Wansley is being modified to burn
low-sulfur coal. As of February 28, 1994,29, 1996, there was a 20-day33-day coal supply
at Plant Wansley based on nameplate rating.
Low-sulfur "compliance" coal for Scherer Units No. 1 and No. 2 is
purchased under long-term contracts and spot market transactions. As of
February 28, 1994,29, 1996, the coal stockpile at Plant Scherer contained a 29-day21-day
supply based on nameplate rating. Further,During 1994, Plant Scherer is beingwas converted
to burn both sub-bituminous and bituminous coals, and a separate stockpile of
sub-bituminous coal is beingwas built in addition to the stockpile of bituminous coal.
The coal supply at Plants Scherer and Wansley is lower than normal due to
(i) higher than expected use of Plant Scherer during the summer of 1993 and the
winter of 1994 because of abnormal temperatures, (ii) transportation
interruptions resulting from severe weather conditions, and (iii) deferred
deliveries because of higher replacement prices due to the United Mine Workers
of America strike. The supply is planned to be replenished as needed and as
competitively priced coal becomes available.
The Scherer ownership and operating agreements were amended effective
Octoberin 1993 to
allow each co-owner (i) to dispatch separately its respective ownership
interest in conjunction with contracting separately for long-term coal
purchases procured by GPC and (ii) to procure separately long-term coal
purchases. Oglethorpe elected to dispatch separately in November 1993. Pursuant to the amendments, GPC is expected to implementOglethorpe implemented separate
dispatch by May 1,in 1994. Oglethorpe intends to continue to use GPC as its agent for
fuel procurement. In anticipationThe 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 115
cars, and Oglethorpe anticipates the acquisition of approximately 350 additional
cars during the next three years for both Plants Scherer and Wansley.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.
The co-owners are
currently negotiating a similar amendment to the Plant Wansley operating
agreement.
For information relating to the impact that the Clean Air Act will have
on Oglethorpe, see "Environmental and Other Regulations" herein.
GPC, as operating agent, has the responsibility to procure nuclear fuel
for PlantPlants Hatch and Plant Vogtle. GPC has contracted with Southern Nuclear
Operating Company ("SONOPCO") to provide nuclear services, including nuclear
fuel procurement. SONOPCO employs both spot purchases and long-term
contracts to satisfy nuclear fuel requirements. The nuclear fuel supply and
related services are expected to be adequate to satisfy current and future
nuclear generation requirements.
Plants Hatch and Vogtle currently have on-site spent fuel storage
capacity. Based on normal operations and retention of all spent fuel in the
reactor, it is anticipated that existing on-site pool capacity would not be
sufficient in 2003 and 2009, respectively, to accept the number of spent fuel
assemblies that would normally be removed from the reactor during a
refueling. Contracts with the Department of Energy ("DOE") have been executed
to provide for the permanent disposal of spent nuclear fuel produced at
PlantPlants Hatch and Plant Vogtle. The services to be provided by DOE are scheduled to
begin in 1998. However,1998; however, the actual yearDOE has stated that these servicespermanent nuclear waste
storage facilities will beginnot be available by that date, and it is uncertain.uncertain
when they will be available. If DOE does not begin receiving the spent fuel
from Plant Hatch in 2003 or from Plant Vogtle in 2009, 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.)
11
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
13
subsidiary of The Southern Company specializing in nuclear services,
currently provides certain operating, maintenance, and other services to GPC
in accordance with the Amended and Restated Nuclear Managing Board Agreement
(the "Amended and Restated NMBA") and the agreements referenced in the
Amended and Restated NMBA. The co-owners have agreed to a Nuclear Operating
Agreement between GPC and SONOPCO, which will be entered into in the event
the NRC approves the application. (See "CO-OWNERS OF THE PLANTS AND THE
PLANT AND TRANSMISSION AGREEMENTS--The Plant Agreements--HATCH, WANSLEY,
VOGTLE AND SCHERER".)
POWER SALES TO AND PURCHASES FROM GPC
A significant portion of Oglethorpe's sales are made to GPC and a
significant portion of Oglethorpe's purchased power is obtained from GPC.
The following table sets forth a summary of Oglethorpe's electric purchases
from and sales to GPC and all other utilities as a group:
MWh
------------------------------
1993 1992--------------------------
1995 1994
---------- ----------
Sources of Energy:
- -----------------SOURCES OF ENERGY:
Owned or Leased Generation . . . . . . . . 14,575,920 13,805,683....... 18,402,839 16,924,038
Purchased -- GPC . . . . . . . . . . . . . 5,198,356 4,669,282............... 2,711,203 2,632,039
-- Others. . . . . . . . . . . . 2,422,459 1,563,980Others ............ 3,027,431 1,749,048
---------- ----------
Total Sources. . . . . . . . . . . 22,196,735 20,038,945Sources .............. 24,141,473 21,305,125
---------- ----------
---------- ----------
Distribution of Energy:
- ----------------------
Members. . . . . . . . . . . . . . . . . . 16,253,283 14,466,943DISTRIBUTION OF ENERGY:
Members .......................... 18,442,153 16,285,127
Non-Members -- GPC . . . . . . . . . . . . 3,432,542 4,621,675............. 2,195,012 2,140,526
-- Others. . . . . . . . . . . 1,617,684 272,314Others .......... 2,520,462 2,067,443
Transmission Losses. . . . . . . . . . . . 893,226 678,013Losses .............. 983,846 812,029
---------- ----------
Total Distribution . . . . . . . . 22,196,735 20,038,945
---------- ----------......... 24,141,473 21,305,125
---------- ----------
The sales to GPC arewere made under the GPC Sell-back (as herein defined)
and the Coordination Services Agreement (the "CSA"). The purchases from GPC
arewere made under the Block Power Sale Agreement (the "BPSA") and the CSA.
GPC SELL-BACK
Pursuant to the contractual arrangements with GPC, Oglethorpe hashad an
obligation to sell to GPC, and GPC hashad 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"). TheAs of May 31, 1995, the GPC Sell-back has expired in accordance
with its terms for Plants Wansley, Hatch and Scherer Units No. 1 and No. 2 and continues to decline
for Plant Vogtle. The GPC Sell-back will expire for Unit No. 1 of Plant Vogtle
at the end of May 1994 and for Unit No. 2 of Plant Vogtle at the end of May
1995.all units. For 1993,1995, energy sales from the GPC Sell-back
represented 6%less than 1% of total energy sales by Oglethorpe. Capacity and energy
revenues from the GPC Sell-back represented 10%1% of Oglethorpe's total revenues
in 1993.1995.
As GPC's entitlement to capacity and energy under the GPC Sell-back
has
decreased, and continues to decrease, Oglethorpe's increased entitlement to the output of each unit has been and will continue to bewas
used to serve its
12
own requirements. The increased costs thereof will beare
recovered through Member rates and through off-system sales transactions.
The historical ability of Oglethorpe to sell power from new units to GPC
under the GPC Sell-back while at the same time purchasing power from GPC
under lower-cost arrangements has
enabled Oglethorpe to moderate the effects of
the higher costs associated with new generating units on Oglethorpe's costs
of service, and therefore on the rates charged the Members. (See "Other Power Purchases" herein, and "CO-OWNERS
OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--The Plant
Agreements--
HATCH,Agreements--HATCH,
14
WANSLEY, VOGTLE AND SCHERER", "General--HISTORICAL FACTORS AFFECTING
FINANCIAL PERFORMANCE" in Item 7 and Note 1 of Notes to Financial Statements
in Item 8.)
The following table sets forth the contractual schedule for the fractional
portion of capacity and energy retained by GPC for the units for which GPC is
currently making GPC Sell-back payments:
CONTRACT YEAR ENDED MAY 31,
---------------------------
OPERATING UNIT 1994 1995 1996
-------------- ---- ---- ----
Vogtle Unit No. 1. . . . . . . . 4/30 -- --
Vogtle Unit No. 2. . . . . . . . 8/30 4/30 --
POWER PURCHASE ARRANGEMENTS
Oglethorpe currently purchases 1,250 MW of capacity and associated energy
from GPC on a take-or-pay basis under the BPSA. The contract expiresBPSA, which extends through
December 31, 2001.2003. The BPSA, along with the Revised and Restated Integrated
Transmission System AgreementsAgreement (the "ITSA") and the CSA, were entered into in 1990 and madebecame effective in
1991 as part of a comprehensive restructuring of1991. Together these agreements enabled Oglethorpe to restructure the way Oglethorpeit
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 by eliminatingof
one or more Component Blocks upon writtenproper notice to GPC. Oglethorpe mayhas given
notice of its intent to reduce up totwo 250 MW with two years'
notice, above 250 to 500 MW with four years' notice, and more than 500 MW with
seven years' notice. Oglethorpe is entitled to extend the purchase of one or
more Component Blocks one additional year at a time under the same notice
conditions.(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 willcould limit Oglethorpe's
ability to compete with GPC for short-term energy transactions requiring less
than one hour's notice. Oglethorpe may elect to establish its own control
area and terminate regulation services under the CSA upon one year's notice
to GPC. Upon such termination, the parties will, if necessary, negotiate new
service schedules and applicable rates. In order to optimize its use of
coordination services, Oglethorpe is currently installing the equipment that
would be necessaryprovide 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".
13
OTHER POWER PURCHASES
Oglethorpe has entered into power purchase contracts with Entergy Power,
Inc. ("EPI") and Big Rivers Electric Corporation ("Big Rivers"), each for the
purchase of 100 MW, extending through June and July 2002, respectively. The EPI
contract is subject to the approval of REA. The
availability of capacity under the EPI contract is dependent on the
availability of two specific generating units available to EPI. The
Tennessee Valley Authority ("TVA") provides the transmission service to
deliver the power from the Big Rivers electric system to the ITS. TVA and
Southern Company Services, as agent for Alabama Power Company and Mississippi
Power Company, provide the transmission service necessary to deliver the
power from EPI to the ITS. (See "Transmission and Other Power System
Arrangements" herein and Note 109 of theNotes 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.
15
In addition to the purchases from GPC, Big Rivers and EPI, Oglethorpe
also purchases small amounts of capacity and energy from "qualifying
facilities" under the Public Utility Regulatory Policies Act of 1978
("PURPA"). Under a waiver order from the Federal Energy Regulatory Commission ("FERC"),FERC, Oglethorpe will make all purchases
the Members would have otherwise been required to make under PURPA and
Oglethorpe was relieved of its obligation to sell certain services to
"qualifying facilities" so long as the Members make those sales. Oglethorpe
provides the Members with the necessary services to fulfill these sale
obligations. Purchases by Oglethorpe from such qualifying facilities provided
0.4%0.3% of Oglethorpe's energy requirements for the Members in 1993.1995.
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 resourcesresource planning process to study
regularly the need for and feasibility of adding additional generation
facilities. This planning process also considers demand-side management
options that could be implemented by the Members as well as off-system sales
of capacity and energy to optimize the use of Oglethorpe's resources.
Oglethorpe's current resources (both
owned or leased generation and purchased power) consist predominately of
resources that can be best used in base-load operation. As a result, all of
Oglethorpe's currently planned resource additions are for peaking capacity. To
further optimize the use of its resources, Oglethorpe is seeking to sell certain
amounts of base capacity and associated energy and to replace it with the
acquisition of peaking capacity when necessary (see "Future Long-Term Power
Sales" herein).
ROCKY MOUNTAIN
Rocky Mountain, which is currently under construction by Oglethorpe, is a
pumped storage hydroelectric facility with no conventional hydroelectric
capability. The facility is designed to consist of three units with a combined
nameplate rating of 847.8 MW at maximum head and a FERC-licensed capacity of 760
MW at minimum head. Under optimal operations, the maximum output of the plant
will decline steadily over a period of approximately eight hours as the upper
reservoir is emptied.
In 1988, Oglethorpe acquired from GPC an undivided ownership interest in
Rocky Mountain. Under the Rocky Mountain ownership arrangement, Oglethorpe, as
agent, is responsible for the design, construction and operation of Rocky
Mountain.
The license issued by FERC for Rocky Mountain expires in 2027. Among other
conditions, the license requires that construction be completed by June 1, 1996.
As of February 28, 1994, Rocky Mountain was approximately 92% complete. Rocky
Mountain is currently scheduled to begin commercial operation in early 1995.
Construction at Rocky Mountain is currently on schedule and under budget.
Under the Ownership Participation Agreement (as hereinafter defined), GPC
has not been required to expend any funds for construction of Rocky Mountain
since December 15, 1988, and is not required to make any additional
contributions. Oglethorpe is required to finance and complete Rocky Mountain.
(See "Liquidity and Capital Resources" in Item 7.) Each party's undivided
interest in Rocky Mountain is equal to the proportion that its respective
investment bears to the total investment in Rocky Mountain (excluding each
party's cost of funds and ad valorem taxes). (See "CO-OWNERS OF THE PLANTS AND
THE PLANT AND TRANSMISSION AGREEMENTS--The Plant
14
Agreements--ROCKY MOUNTAIN".) As of December 31, 1993, Oglethorpe's ownership
interest in Rocky Mountain was approximately 70%. Based on current arrangements,
Oglethorpe's ultimate ownership interest in Rocky Mountain is estimated to be
approximately 75%, with GPC owning the remaining 25%.
Oglethorpe, GPC and certain third parties have had preliminary discussions
regarding alternatives by which Oglethorpe may acquire the output of GPC's
remaining interest in Rocky Mountain. Options being discussed include a
long-term lease or power purchase arrangement with a third party which would
purchase GPC's interest or a purchase of such interest directly by Oglethorpe.
The nameplate rating of GPC's ultimate ownership interest is estimated to be
approximately 212 MW, and if any such transaction is consummated, such output
would satisfy a portion of Oglethorpe's long-term capacity needs. The outcome of
these discussions cannot be determined at this time.
HARTWELL PURCHASE
In 1992, Oglethorpe entered into a contract for the purchase of
approximately 300 MW of capacity with Hartwell Energy Limited Partnership
("Hartwell"), a partnership owned 50% by Destec Energy, Inc. and 50% by American
National Power, Inc., a subsidiary of National Power, PLC. The contract has a
term of 25 years, commencing upon commercial operation, which by contract is
scheduled to be no later than June 1994. Under the contract, Hartwell is
constructing two 150 MW gas-fired turbine generating units on a site near
Hartwell, Georgia. Oglethorpe intends to use the units for peaking capacity but
has the right to dispatch the units fully. If Hartwell misses any of a specified
list of project milestones, Oglethorpe may terminate the contract and, if it so
chooses, purchase the project at fair market value. Hartwell has provided an
irrevocable letter of credit payable to Oglethorpe in the amount of $10,360,000,
which can be drawn upon if the project is not in service by the scheduled date
or as liquidated damages in case of a default by Hartwell. Hartwell has advised
Oglethorpe that it expects to begin deliveries of power to Oglethorpe prior to
June 1994.
OTHER FUTURE RESOURCES
In its current integrated resource plan, Oglethorpe has identified a
potential need for additional peaking capacity in the late 1990s. 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 November 1993, Oglethorpe issued a Requestrequest for Proposalsproposals for the
purchase of up to 600 MW of long-term peaking capacity to be available by
June 1, 1999. Proposals were
due March 29, 1994.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 reserved the rightan agreement to reject anysell 100 MW of base capacity to Alabama
Electric Cooperative beginning June 1, 1998, and all
bids, and should it do so, Oglethorpe may construct that capacity itself.extending through December
31, 2005. Oglethorpe has also agreedsubmitted bids to purchase from Florida Power Corporation 50 MW of
peakingvarious formal and informal
solicitations for capacity during the summer of 1997 and 275 MW of peaking capacity during
the summer of 1998. This purchasesales. Whether any such bid will be successful is
subject to regulatory approval.uncertain.
TRANSMISSION AND OTHER POWER SYSTEM ARRANGEMENTS
As of February 28, 1994, Oglethorpe ownedowns approximately 2,1862,267 miles of transmission line and 404426
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
GPC--POWER PURCHASE ARRANGEMENTS" herein and "CO-OWNERS OF THE PLANTS AND THE
PLANT AND TRANSMISSION AGREEMENTS--Agreements Relating to Integrated
Transmission System".)
In addition to the interconnections available to Oglethorpe through the
ITS, Oglethorpe has interconnection, interchange, transmission and/or
short-term capacity and energy purchase or sale agreements with Alabama Electric
Cooperative, Cajun Electric Power Cooperative, Big Rivers, Seminole Electric
Cooperative, Entergy Services (as agent for the Entergy operating companies),
TVA, Florida Power Corporation, Jacksonville Electric Authority, Tampa Electric
Company, Louisville Gas & Electric Company, Florida Power & Light Company, SEPA,
South Carolina Electric & Gas (subject to approval by FERC), South Carolina
Public Service Authority, Arkansas Electric Cooperative Corporationover 20
utilities and East
Kentucky Power Cooperative.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 (seeCSA. (See "Power Sales to and Purchases from GPC--POWER
PURCHASE ARRANGEMENTS" herein).
15
In addition, Oglethorpe has sold to GPC a portion of its entitlement to the
interface capability between the ITS and the Florida electric system through May
1994.herein.) Oglethorpe has purchased from GPC sufficient
entitlement to the interface between the Integrated Transmission SystemITS and TVA to implement the
purchases from Big Rivers and EPI. Oglethorpe regularly buys and sells power
in the short-term bulk power market. FUTURE LONG-TERM POWER SALES
Oglethorpe has signedThe development of and access to a
Letter of Intentstatewide transmission network and the interconnections with Alabama Electric Cooperative
for the sale of 100 MW of base capacity beginning June 1, 1998,other utilities
are key elements in Oglethorpe's ability to make off-system sales and
extending
through December 31, 2005. This arrangement is subjectpurchases, to the approval of a
definitive agreement by the Boards of Directors of each party. The agreement
would also be subjectprovide transmission service to approval by REA. No assurances can be given that such
definitive agreement will be consummated. Oglethorpe has also submitted bidsthird parties and to various formal and informal solicitations for capacity sales. Whether any such
bid will be successful is uncertain.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 particulates,pollutants, such as particulate matter, sulfur dioxideoxides
and nitrogen oxideoxides ("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 suchthese requirements
could result in the imposition of civil and criminal penalties as well as the
complete shutdown of individual generating units not in compliance. There is
no assurance that the units in operation or under construction will always
remain subject to the regulations currently in effect or will always be in
compliance with future regulations.
Compliance with environmental standards or deadlines will continue to be
reflected in Oglethorpe's capital and operating costs. Oglethorpe's direct
capital costs to achieve compliance with air and water quality control
facilities were approximately $6.5 million in 1993 andenvironmental requirements are
expected to be approximately $3.1$1.0 million in 1994, $4.11996, $3.6 million in 19951997 and
$8.6$1.4 million in 1996.1998.
CLEAN AIR ACT
The Clean Air Act ("Act") seeks to improve the ambient air quality throughout the United
States by the year 2000 and beyond.States. The acid rain provisions of Title IVthe Act require the reduction of sulfur
dioxide and nitrogen oxideNO(x) emissions from affected units, including coal-fired electric
power facilities. The sulfur dioxide reductions required by Title IVthe Act will be
achieved in two phases. Phase I addresses specific generating units named in
the Clean Air Act. Both units of Plant Wansley are "affected units" under Phase I.
Scherer Units No. 1 and No. 2 are not "affected units" under Phase I but are
affected units"affected units" under Phase II. InBeginning 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
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, by the year 2000, usingOglethorpe could use a
"tradeable allowance" plan. Finalvariety 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 sulfur dioxide allocationshas 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 published by Environmental Protection
Agency ("EPA") regulations. Compliancefinalized, 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 Clean Air Act will continue to require expenditures
for monitoring annual permit fees,and permitting, and in some instances may involve increased
operating or maintenance expenses or capitalexpenses. Capital expenditures of Oglethorpe through
1995 for pollution control and continuous monitoring equipment.
Capital improvements, of which Oglethorpe's share is approximately $6.4
million, are in progressequipment needed to comply with the Act at Plant
Wansley. Scheduled to be completed in 1994,
these improvements are designed to bring the plant into compliance with
anticipated requirements for both Phase IWansley have been approximately $7,200,000 and Phase II. Approximately $500,000
in capital improvements, to be completed in 1994, will be made at Plant Scherer.Scherer Units No. 1 and No. 2
have been approximately $720,000. The estimated cost of any additional
improvements at Plant Wansley and Plant Scherer are
16
Units No. 1 and No. 2 remains
dependent upon the chosen compliance plan and may be affected by future plan
amendments andand/or future regulation.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.
Title I ofMetropolitan Atlanta is classified as a "serious nonattainment area" with
regard to the Clean Airozone 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 nitrogen oxideNO(x) and volatile organic
compounds. Thecompounds, 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 must be promulgated by November
1994, with attainment demonstrated by November 1999. Metropolitan Atlanta is
classified as a "serious non-attainment area" with regard tofor power plants in the ozone ambient
air quality standards.State. Plant Wansley is near although not in this non-attainment
area.the
nonattainment area while Plant Scherer is located further away. The results of
these studies and new rules could require nitrogen oxideNO(x) controls more stringent than
those now required under the acid rain provisions of the Act for Title IV compliance.
The Clean
AirPortions of Subchapter I of the Act also requiresrequire that several studies be conducted
regarding the health effects of power plant emissions of certain hazardous
air pollutants. The studies will be used in making decisions on whether
additional controls of these pollutants are necessary. The effect of any of
these potential regulatory changes under Title I,the Act, including new rules under the
amended provisions, cannot now be predicted.
The Clean Air Act also requires the EPA to review all National Ambient Air Quality
Standards ("NAAQS") periodically, revising such standards as necessary. EPA
continues to evaluate the need for a new short-term standard for sulfur oxides
(measured as sulfur dioxide). Preliminary results from an EPA study
indicate thatIf 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 Title IVthe acid rain provisions of the Clean Air Act.
These controls could result in substantial costs to Oglethorpe. Although EPA
is also evaluatinghas evaluated the need and decided for now not to revise the NAAQS for nitrogen
dioxide anddioxides, there is no certainty that that standard will not be updatingrevised in the
future. In addition, EPA has finalized a criteria document usedand is updating a
staff paper for ozone, which could lead to a change in its recent
decision not to revise the NAAQS for ozone.
EPA is not currently formally
revising thealso updating a criteria document and staff paper for particulate matter,
which could lead to a revision of the NAAQS but is gathering information which may be
used in a revision.for particulate matter. The impact
of any change in the ozone, sulfur dioxide, nitrogen dioxidedioxides or particulate
matter NAAQS cannot now be determined because the effect of any change would
depend in part on the final ambient standards.standards developed.
Although Oglethorpe's management is currently unable to determine the
overall effect that compliance with requirements under the Clean Air Act will have on
its operations, it does not believe that any required increases in capital or
operating expenses would have a material effect on its results of operations
or financial condition. Compliance with requirements under the Clean Air Act may also
require increased capital or operating
18
expenses on the part of GPC. Any increases in GPC's capital or operating
expenses may cause an increase in the cost of power purchased from GPC. (See
"Power Sales to and Purchases from GPC--POWER PURCHASE ARRANGEMENTS" herein.)
CLEAN WATER ACT
Oglethorpe is subject to provisions of the Clean Water Act, as amended. As
a result of the 1987 Amendments to the Clean Water Act, the State of Georgia has
amended its State Water Quality Standards to make them more stringent. These
amendments will cause an increase in Oglethorpe's cost to comply. These costs
include capital expenditures for improvements at Plant Scherer to comply with
Georgia's new clean water regulations covering waste water discharge.
Oglethorpe's share of these improvements, completed in early 1994, was
approximately $2 million.
Congress is considering reauthorizingreauthorization 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 17
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 98 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 and("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.
Furthermore,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.
SuchOglethorpe,
19
those impacts cannot be fully determined at this time however, and would depend in
part on any suchthe final legislation and the development of implementing regulations.
The scientific community, regulatory agencies and the electric utility
industry are examiningcontinuing to examine the issues of global warming and the
possible health effects of electric and magneticelectromagnetic 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.
(See "Future Power Resources--OTHER FUTURE RESOURCES" herein.) Unlike purchases from qualifying facilities under PURPA (see
"Other Power Purchases" herein), however, utilities have no statutory
obligation to purchase power from EWGs. Furthermore, EWGs are precluded from
making direct sales to retail electricity customers.
The Energy Policy Act also broadens the authority of FERC to require a
utility to transmit power to or on behalf of other participants in the
electric utility industry, including EWGs and qualifying facilities, but FERC
is precluded from requiring a utility to transmit power from another entity
directly to a retail customer. 18In 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
CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS
CO-OWNERS OF THE PLANTS
Plants Hatch, Vogtle, Wansley and Scherer Units No. 1 and No. 2 are
co-owned by Oglethorpe, GPC, MEAG and Dalton, and Rocky Mountain is co-owned
by Oglethorpe and GPC. Each such co-owner owns, and Oglethorpe owns or
leases, undivided interests in the amounts shown in the following table
(which excludes the Plant Wansley combustion turbine). GPC is the
construction and operating agent for each of these plants, except for Rocky
Mountain for which Oglethorpe is the construction and operating agent. (See
"The Plant Agreements" herein.)
NUCLEAR COAL-FIRED PUMPED STORAGE
------------------------------ --------------------------------Nuclear Coal-Fire Pumped Storage
-------------------------- ---------------------------- --------------
PLANT PLANT PLANT SCHERER UNITS ROCKY
HATCH VOGTLE WANSLEY NO.Plant Plant Plant Scherer Units Rocky
Hatch Vogtle Wansley No. 1 & NO.No. 2 MOUNTAIN(3) TOTAL
------------- ------------- -------------Mountain Total
------------ ------------ ------------ --------------- ----------------------------- -----
% MW(1) % MW(1) % MW(1) % MW(1) % MW(1) MW(1)
---- ----- ---- ----- ---- ----- ---- ----- --------- ----- -------- ----- ------ ----- -----
Oglethorpe . . ... 30.0 489 30.0 696 30.0 519 60.0(2) 982 75(4) 636 3,322
GPC. . . . . . .74.61 633 3,319
GPC ......... 50.1 817 45.7 1,060 53.5 926 8.4 137 25(4) 212 3,15225.39 215 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. . . . . .Total........ 100.0 1,630 100.0 2,320 100.0 1,730 100.0 1,636 100100.00 848 8,164
----- ----- ----- ----- ----- ----- -------- ----- ----- --- --------- ----- -----
----- ----- ----- ----- ----- ----- -------- ----- --- --------- -----
- ------------------------------
______________________
(1) Based on nameplate ratings.
(2) Oglethorpe leases its interest in Scherer Unit No. 2 pursuant to long-term
net leases.
(3) Rocky Mountain is currently under construction and scheduled to be in
commercial operation in early 1995.
(4) Represents Oglethorpe's and GPC's estimated ownership interests upon
completion. (See "The Plant Agreements--ROCKY MOUNTAIN" herein.)
GEORGIA POWER COMPANY
GPC is a wholly owned subsidiary of The Southern Company, a registered
holding company under the Public Utility Holding Company Act, and is engaged
primarily in the generation and purchase of electric energy and the
transmission, distribution and sale of such energy within the State of
Georgia at retail in over 600 communities (including Athens, Atlanta,
Augusta, Columbus, Macon, Rome and Valdosta), as well as in rural areas, and
at wholesale to Oglethorpe, MEAG and three municipalities. GPC is the
largest supplier of electric energy in the State of Georgia. (See "OGLETHORPE
POWER CORPORATION--
RelationshipCORPORATION--Relationship with GPC".)
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 4748 cities and one county in the State of Georgia. Such
political subdivisions, located in 39 of the State's 159 counties,
collectively serve approximately 268,000270,000 electric customers.
1921
CITY OF DALTON, GEORGIA
The City of Dalton, located in northwest Georgia, supplies electric
capacity and energy to consumers in Dalton, and presently serves more than
10,000 residential, commercial and industrial customers.
THE PLANT AGREEMENTS
HATCH, WANSLEY, VOGTLE AND SCHERER
Oglethorpe's rights and obligations with respect to Plants Hatch,
Wansley, Vogtle and Scherer are contained in a number of contracts between
Oglethorpe and GPC and, in some instances, MEAG and Dalton. Oglethorpe is a
party to four Purchase and Ownership Participation Agreements ("Ownership
Agreements") under which it acquired from GPC a 30% undivided interest in
each of Plants Hatch, Wansley and Vogtle, a 60% undivided interest in Scherer
Units No. 1 and No. 2 and a 30% undivided interest in those facilities at
Plant Scherer intended to be used in common by Scherer Units No. 1, No. 2,
No. 3 and No. 4 (the "Scherer Common Facilities"). Oglethorpe has also
entered into four Operating Agreements ("Operating Agreements") relating to
the operation and maintenance of Plants Hatch, Wansley, and Vogtle and Scherer,
respectively. The Operating Agreements and Ownership Agreements relating to
Plants Hatch and Wansley are two-party agreements between Oglethorpe and GPC.
The other Operating Agreements and Ownership Agreements are agreements among
Oglethorpe, GPC, MEAG and Dalton. The parties to each Ownership Agreement
and each Operating Agreement are referred to as "Participants" with respect
to each such agreement.
In 1985, in four separate transactions, Oglethorpe sold its entire 60%
undivided ownership interest in Scherer Unit No. 2 to four separate owner
trusts established by four different institutional investors. (See Note 4 of
Notes to Financial Statements in Item 8.) Oglethorpe retained all of its
rights and obligations as a Participant under the Ownership and Operating
Agreements relating to Scherer Unit No. 2 for the term of the leases. (In
the following discussion, references to Participants "owning" a specified
percentage of interests include Oglethorpe's rights as a deemed owner with
respect to its leased interests in Scherer Unit No. 2.)
The Ownership Agreements appoint GPC as agent with sole authority and
responsibility for, among other things, the planning, licensing, design,
construction, renewal, addition, modification and disposal of Plants Hatch,
Vogtle, Wansley and Scherer Units No. 1 and No. 2 and the Scherer Common
Facilities. Under the Ownership Agreements, Oglethorpe is obligated to pay a
percentage of capital costs of the respective plants, as incurred, equal to
the percentage interest which it owns or leases at each plant. GPC has
responsibility for budgeting capital expenditures subject to, in the case of
Scherer Units No. 1 and No. 2, certain limited rights of the Participants to
disapprove capital budgets proposed by GPC and to substitute alternative
capital budgets.budgets and in the case of Plants Hatch and Vogtle, the right of any
co-owner to disapprove large discretionary capital improvements.
Each Operating Agreement gives GPC, as agent, sole authority and
responsibility for the management, control, maintenance, operation,
scheduling and dispatching of the plant to which it relates. However, as
provided in the recent amendments to the Plant Scherer Ownership and
Operating Agreements, Oglethorpe has elected to dispatchis separately dispatching its ownership
share of Scherer Units No. 1 and No. 2. Similar amendments to the Plant
Wansley Operating Agreement have 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
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.
20
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.
(See "THE POWER SUPPLY SYSTEM--Proposed Changes to Nuclear
Plant Operating Arrangements".)
During the first seven years of Commercial Operation (as defined in the
Operating Agreement for Plant Vogtle) of Plant Vogtle, GPC is entitled to a
declining percentage of Oglethorpe's capacity and energy for all or a portion of
each contract year ending May 31. (See "THE POWER SUPPLY SYSTEM--Power Sales to
and Purchases from GPC--GPC SELL-BACK" and Note 1 of the Financial Statements
in Item 8.) Regardless of the amount of capacity available, GPC is obligated to
pay Oglethorpe monthly for the capacity of each unit to which it is entitled,
if any, an amount derived by a formula set forth in the Operating Agreement
based upon an average of GPC's annual fixed costs and Oglethorpe's annual fixed
costs with respect to each unit. In addition, GPC is responsible for the same
percentage of Oglethorpe's share of the Operating Costs and fuel-related costs
incurred.
The Ownership Agreements and Operating Agreements provide that, should a
Participant fail to make any payment when due, among other things, such
nonpaying Participant's rights to output of capacity and energy would be
suspended.
(See "THE POWER Supply SYSTEM--Proposed Changes to Nuclear Plant
Operating Arrangements".)
TERMS. The Operating Agreement for Plant Hatch will remain in effect
with respect to Hatch Units No. 1 and No. 2 until 2009 and 2012,
respectively. The Operating Agreement for Plant Vogtle will remain in effect
with respect to each unit at Plant Vogtle until 2018. The Operating
Agreement for Plant Wansley will remain in effect with respect to Wansley
Units No. 1 and No. 2 until 2016 and 2018, respectively. The Operating
Agreement for Scherer Units No. 1 and No. 2 will remain in effect with
respect to Scherer Units No. 1 and No. 2 until 2022 and 2024, respectively.
Upon termination of each Operating Agreement, GPC will retain such powers as
are necessary in connection with the disposition of the property of the
applicable plant, and the rights and obligations of the parties shall
continue with respect to actions and expenses taken or incurred in connection
with such disposition.
ROCKY MOUNTAIN
Oglethorpe's rights and obligations with respect to Rocky Mountain are
contained in several contracts between Oglethorpe and GPC, the co-owners of
Rocky Mountain. Pursuant to Rocky Mountain Pumped Storage Hydroelectric
Ownership Participation Agreement, by and between Oglethorpe and GPC (the
"Ownership Participation Agreement"), on December 15, 1988, Oglethorpe initially acquired a 3%
undivided interest in Rocky Mountain together with a futurewhich interest in
the remaining 97% undivided interest.increased as Oglethorpe
expended funds to complete construction of Rocky Mountain. The final
ownership percentages for Rocky Mountain are Oglethorpe 74.61% and GPC
25.39%. In connection with this acquisition, Oglethorpe and GPC also entered
into the Rocky Mountain Pumped Storage Hydroelectric Project Operating
Agreement (the "Rocky Mountain Operating Agreement").
Under the Ownership Participation Agreement, Oglethorpe has responsibility
for financing and completing the construction of Rocky Mountain. As Oglethorpe
expends funds for construction, GPC's ownership interest decreases and
Oglethorpe's ownership interest increases. At all times, each party's undivided
interest in the project is equal to the proportion that its respective
investment bears to the total investment in the project (excluding each party's
cost of funds and ad valorem taxes). Except as described below in respect of the
exercise by GPC of its option to retain a minimum ownership interest, GPC is not
required to expend any funds for construction. GPC's prior investment is
determined in "as-spent" dollars, while Oglethorpe's investment is discounted to
constant 1987 dollars (computed using a semi-annual Handy-Whitman Index).
21
The Ownership Participation Agreement appoints Oglethorpe as agent with
sole authority and responsibility for, among other things, the planning,
licensing, design, construction, operation, maintenance and disposal of Rocky
Mountain. The Ownership Participation Agreement provides that Oglethorpe must
use its reasonable best efforts in accordance with Prudent Utility Practices (as
defined therein) to have Rocky Mountain in commercial operation by June 1, 1996. The Rocky Mountain Operating Agreement gives Oglethorpe, as agent,
sole authority and responsibility for the management, control, maintenance
and operation of Rocky Mountain. In general, each co-owner is responsible
for payment of its respective ownership share of all Operating Costs and
Pumping Energy Costs (as defined in the Rocky Mountain Operating Agreement)
as well as costs incurred as the result of any separate schedule or
independent dispatch. A co-owner's share of net available capacity and net
energy is the same as its respective ownership interest under the Ownership
Participation Agreement. GPC
will schedule and dispatch Rocky Mountain on a continuous economic dispatch
basis, on behalf of itself and Oglethorpe and will notify Oglethorpe in advance
of estimated operating levels, until such time as Oglethorpe may electGPC have each elected to schedule
separately itstheir respective ownership interest.interests. The Rocky Mountain
Operating Agreement will terminate on the fortieth anniversary of the Completion
Adjustment Date (as defined therein).in 2035.
23
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
22
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 if agreed by the
co-owners, an operating
committee would alsowill assume such responsibilities for Plant Wansley.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.
2324
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.
2425
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Not Applicable.applicable.
ITEM 6. SELECTED FINANCIAL DATA
- -----------------------------------------------------------------------------
...............................................................................................................
(dollars in thousands)
1995 1994 1993 1992 1991 1990 1989
- ---------------------------------------------------------------------------------------------------------------------------------
- -
OPERATING REVENUES:
Sales to Members . . . . . . . . . . . . . . . ................. $ 1,030,797 $ 930,875 $ 899,720 $ 816,000 $ 763,657
$ 710,607 $ 631,966
Sales to non-Members . . . . . . . . . . . . . .non-Members............. 118,764 125,207 200,940 268,763 300,293 390,535 367,183
----------- ----------- ----------- ----------- -----------
Total operating revenues . . . . . . . . . . . ......... 1,149,561 1,056,082 1,100,660 1,084,763 1,063,950 1,101,142 999,149
----------- ----------- ----------- ----------- -----------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . .Fuel............................. 219,062 203,444 176,342 167,288 165,168
209,971 180,698
Production . . . . . . . . . . . . . . . . . . .Production....................... 133,858 132,723 129,972 115,915 130,041
125,506 97,266
Purchased power. . . . . . . . . . . . . . . . .power.................. 264,844 227,477 271,970 230,510 229,898
213,311 202,778
Depreciation and amortization. . . . . . . . . .amortization.... 139,024 131,056 128,060 126,047 135,152
134,021 123,614
Taxes. . . . . . . . . . . . . . . . . . . . . .Taxes............................ 27,561 24,741 25,148 19,634 42,422
41,798 31,541
Other operating expenses . . . . . . . . . . . .expenses......... 56,535 49,234 44,876 50,578 49,373 41,755 33,301
----------- ----------- ----------- ----------- -----------
Total operating expenses . . . . . . . . . . . .expenses......... 840,884 768,675 776,368 709,972 752,054 766,362 669,198
----------- ----------- ----------- ----------- -----------
OPERATING MARGIN. . . . . . . . . . . . . . . . .MARGIN................... 308,677 287,407 324,292 374,791 311,896
334,780 329,951
OTHER INCOME, NET . . . . . . . . . . . . . . . .NET.................. 33,710 40,795 38,741 45,928 113,441
94,471 70,297
NET INTEREST CHARGES. . . . . . . . . . . . . . .CHARGES............... (320,129) (305,120) (350,652) (393,247) (396,892) (400,712) (379,820)
----------- ----------- ----------- ----------- -----------
MARGIN BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE. . . . . . . . . . . . . . . . . . . .PRINCIPLE... 22,258 23,082 12,381 27,472 28,445 28,539 20,428
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING FOR INCOME TAXES. . . . . . . . . . .TAXES...... -- -- 13,340 - - - --- --
----------- ----------- ----------- ----------- -----------
NET MARGIN. . . . . . . . . . . . . . . . . . . .MARGIN......................... $ 22,258 $ 23,082 $ 25,721 $ 27,472 $ 28,445 $ 28,539 $ 20,428
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
ELECTRIC PLANT, NET:
In service . . . . . . . . . . . . . . . . . . .service....................... $ 4,436,009 $ 3,980,439 $ 4,054,956 $ 4,122,411 $ 4,196,966
$ 4,268,440 $ 4,275,770
Construction work in progress. . . . . . . . . .progress.... 35,753 538,789 450,965 322,628 178,980 102,045 103,729
----------- ----------- ----------- ----------- -----------
$ 4,471,762 $ 4,519,228 $ 4,505,921 $ 4,445,039 $ 4,375,946 $ 4,370,485 $ 4,379,499
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
TOTAL ASSETS. . . . . . . . . . . . . . . . . . .ASSETS....................... $ 5,438,536 $ 5,346,330 $ 5,323,890 $ 5,359,597 $ 5,246,435 $ 5,200,762 $ 5,288,673
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
CAPITALIZATION:
Long-term debt . . . . . . . . . . . . . . . . .debt................... $ 4,207,320 $ 4,128,080 $ 4,058,251 $ 4,095,796 $ 4,093,218
$ 4,094,246 $ 4,112,892
Obligation under capital leases. . . . . . . . .leases.. 296,478 303,749 303,458 302,061 300,833 299,783 298,929
Patronage capital and membership
fees. . . . . .fees............................ 338,891 309,496 289,982 264,261 236,789 217,895 194,233
----------- ----------- ----------- ----------- -----------
$ 4,842,689 $ 4,741,325 $ 4,651,691 $ 4,662,118 $ 4,630,840 $ 4,611,924 $ 4,606,054
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
PROPERTY ADDITIONS. . . . . . . . . . . . . . . .ADDITIONS................. $ 138,921 $ 206,345 $ 235,285 $ 232,283 $ 225,021 $ 200,257 $ 226,709
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
ENERGY SUPPLY (MEGAWATT-HOURS):
Generated. . . . . . . . . . . . . . . . . . . .Generated........................ 18,402,839 16,924,038 14,575,920 13,805,683 12,686,323
13,387,572 12,079,706
Purchased. . . . . . . . . . . . . . . . . . . .Purchased........................ 5,738,634 4,381,087 7,620,815 6,233,262 6,915,758 6,198,434 5,664,919
----------- ----------- ----------- ----------- -----------
Available for sale . . . . . . . . . . . . . . .sale............... 24,141,473 21,305,125 22,196,735 20,038,945 19,602,081 19,586,006 17,744,625
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
MEMBER REVENUE PER kWh SOLD . . . . . . . . . . . 5.47 cents 5.55 cents 5.36 cents 5.01 cents 4.84 cents
CERTAIN PRIOR YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH CURRENT YEAR
PRESENTATION.KWH SOLD........ 5.53CENTS 5.65CENTS 5.47CENTS 5.55CENTS 5.36CENTS
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
2526
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 its 39 retail
electric distribution cooperatives (Members)the Members on the basis of its electricity purchases
from Oglethorpe. Since its formation in 1974, Oglethorpe has generated a
positive net margin in each year and, as of December 31, 1993,1995, had a balance
of $290$339 million in patronage capital.
Patronage capital constitutes the principal equity of Oglethorpe. As a
means of accumulating additional equity,Under
Oglethorpe's Board of Directors amended
in 1992 the patronage capital retirement policy, for returning margins are returned to the
Members to extend the retirement schedule from 13 years to 30 years after the year in which the margins were generated.are earned. Pursuant to
such policy, no patronage capital would be retired until 2010, at which time
the 1979 patronage capital would be returned. (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 5.7%6.5% at December 31, 19921994 to 6.2%7.0% at
December 31, 1993.1995.
RATES AND FINANCIAL COVERAGE REQUIREMENTS
Oglethorpe's policy is to design its rates to generate sufficient revenues
to recover its Member cost of service and produce net margins at such levels as
Oglethorpe's Board of Directors determines to be consistent with sound financial
practice. Rate revisions by Oglethorpe are subject to the approval of the REA
and, to date, the REA has not reduced or delayed the effectiveness of any rate
increase proposed by Oglethorpe. Oglethorpe has entered into aan "all-requirements" wholesale power
contract with each of its MembersMembers. Pursuant to such contracts, Oglethorpe is
required to design capacity and energy rates that requires rates to be designedgenerate sufficient
revenues to recover all costs as described in such contracts. Oglethorpe's rates include an energy
charge that is set annuallycontracts and adjusted at mid-year to recover actual fuelestablish
and variable operations and maintenance costs.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 REARUS 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 REARUS Mortgage, Oglethorpe is
also required under the REARUS Mortgage to implement rates designed to maintain
a Debt Service Coverage Ratio (DSC) of not less than 1.0 and an Annual Debt
Service Coverage Ratio (ADSCR) of not less than 1.25. 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
(including interest charged to construction). ADSCR is determined by
dividing the sum of Oglethorpe's net margin plus interest on long-term debt
(excluding interest charged to construction) plus depreciation and
amortization (excluding amortization of nuclear fuel and debt discount and
expense) by Oglethorpe's interest and principal payable on long-term debt
secured under the REARUS Mortgage (excluding interest charged to construction).
Oglethorpe has always met or exceeded the TIER, DSC and ADSCR
requirements of the REARUS Mortgage. TIER, DSC and ADSCR for the years 19911993
through 19931995 were as follows:
- -----------------------------------------------------------------------------1995 1994 1993
1992 1991
- --------------------------------------------------------------------------------- ---- ----
TIER 1.07 1.07 1.07
DSC 1.21 1.19 1.23
1.22 1.28
ADSCR 1.261.27 1.25 1.31
- -----------------------------------------------------------------------------1.26
In 1992, as part of a plan to build additional equity, Oglethorpe's Board
of Directors revised its annual net margin goal to be the amount required to
produce a TIER of 1.07 in each year through 1995, 1.08 in 1996, 1.09 in 1997 and
1.10 in 1998 and thereafter.
Historically, by setting rates to meet the TIER goals established by
Oglethorpe's Board, the DSC and ADSCR requirements of the REARUS Mortgage have
always been met or exceeded. Based on Oglethorpe's current financial
projections, however, rates based on theseTIER levels of TIERunder the current Board policy may not
be
sufficient to meet the ADSCR requirement of the REA Mortgage. In that event,produce rates sufficient to meet the current ADSCR requirementsrequirement 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 established.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 severalthree years, the most significant factor affecting
Oglethorpe's financial performance has been the mechanisms Oglethorpe has
utilized to moderate the financial impact of new generating plants. During this
period, Oglethorpe's Members have absorbed much ofinto rates
additional responsibility for the cost of its ownership interests in Plant
VogtleScherer Unit No. 2 and SchererPlant Vogtle Units No. 1 and No. 2. 26
The mechanisms used byThese generating
units were placed in commercial operation in 1984, 1987, and 1989,
respectively. Oglethorpe to mitigate the rate impact of absorbing
these costs have includedhas utilized both long-term contractual
arrangements with Georgia Power Company (GPC) and Board of Directors policies that have resulted in themargin 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 provideprovided that Oglethorpe sell to GPC
and GPC purchase from Oglethorpe a declining percentage of Oglethorpe's
entitlement to the capacity and energy of certain co-owned generating plants
during the initial seven to ten years of operation of such units (GPC
Sell-back). The GPC Sell-back will
expire for Plant Vogtle Unit No. 1 asAs of May 31, 1994, and for Plant Vogtle
Unit No. 2 as of May 31, 1995. The1995, the GPC Sell-back has expired for Scherer Unit No. 1 expired
in May 1991 and for Scherer Unit No. 2, in May 1993.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
has enabled Oglethorpe to moderate the effects of the higher costs associated
with new generating units on Oglethorpe's cost of service and, therefore, on
the rates charged to Members. Furthermore, the GPC Sell-back has enabled
Oglethorpe to obtain the generating capacity needed to serve anticipated
increases in Member loads while minimizing the risks and costs of excess
generating capacity.
Prior to the completion of the first unit of Plant Vogtle in 1987,
Oglethorpe's Board of Directors implemented policies that have resulted in
the gradual absorption of the costs of Plant Vogtle by the Members. In each
of the years 1985 through 1993,1995, Oglethorpe exceeded its net margin goal. The
Board adopted resolutions in each of these years requiring that these excess
margins be deferredretained and used to mitigate rate increases associated with Plant
Vogtle.Vogtle and, subsequently, with Rocky Mountain. In each year beginning with
1989, a portion of these margins has been returned to the Members through
billing credits. (See Note 1 of Notes to Financial Statements.) Furthermore, during 1986 and 1987, Oglethorpe's rates to its Members
included a one mill per kilowatt-hour (kWh) charge (Vogtle Surcharge). The
Vogtle Surcharge represented a pre-collection of charges prior to commercial
operation of Plant Vogtle the effect of which was to mitigate future rate
increases. In addition, two of the Members elected to increase the level of this
charge for their systems during this period.
As of
December 31, 1993,1995, Oglethorpe held a balance of approximately $48$32 million
from deferred margins and the voluntary Vogtle Surcharges to two Members
which will be utilized in 1996 for future rate mitigation. Oglethorpe's Boardmitigation as
the annual costs of Directors and the two Members intend to utilize these amounts as offsets to
rates charged during 1994 and 1995. By the end of 1995, all costs associated
with Plant Vogtle will be included in Member rates.
RESULTS OF OPERATIONSRocky Mountain are absorbed.
28
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 19911993 through 1993,1995, although total revenues have remained virtually unchanged,varied
slightly, the scheduled reduction of the GPC Sell-back has resulted in the
planned decrease of non-
Membernon-Member revenues from GPC of almost $130about $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 and transmission 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 10.3%10.7% in 19931995
compared to 1992,1994 and increased 6.9%3.5% in 19921994 compared to 1991.1993. These increases
reflect two factors: first,(1) higher capacity rates,revenues, offset by the pass-through
of savings in energy costs (see discussion of savings in fuel costs under
"OPERATING EXPENSES" herein);, and second,(2) increased amounts of energy sold.
Concerning the first factor, asAs non-Member revenues from GPC have declined, Oglethorpe has increased rates to Members to recoverOglethorpe'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. Since December 28,
1990, Oglethorpe has placed into effect four rate changes, as set forth below:
- -----------------------------------------------------------------------------
EFFECTIVE DATE RATE CHANGE (1)
- -----------------------------------------------------------------------------
January 1, 1994 -4.5%
January 1, 1993 1.7%
December 27, 1991 8.8%
December 28, 1990 4.8%
(1) After credit for deferred margins. (See Note 1 of Notes to Financial
Statements.)
- -----------------------------------------------------------------------------
Oglethorpe was ableMember
capacity revenues in 1995 were also affected by additional fixed costs
related to implement a rate reduction forthe commercial operation of Rocky Mountain in June 1995.
Member energy revenues per kWh declined 7.6% in 1995 compared to 1994 because the
anticipated additional revenuesand
6.9% in 1994 compared to be derived based on the increase1993, reflecting savings in the
Members' 1993 peak demand more than offset the reductionfuel and production
costs. The 1995 decline in revenues from the
GPC Sell-back.
Oglethorpe's wholesale rate to the Members sets forth the manner in whichper kWh also reflects lower average
purchased power costs. Actual energy costs are to be recovered. Oglethorpe's rate provides that actual energy
costs be passed through to the Members
such that energy revenues equal energy costs.
The following table summarizes the amounts of kilowatt-hourskWh sold to Members during
each of the past three years:
- -----------------------------------------------------------------------------(IN THOUSANDS) KILOWATT-HOURS
(in thousands)
- ------------------------------------------------------------------------------------------------------------
1995 18,442,153
1994 16,285,127
1993 16,253,283
1992 14,466,943
1991 14,022,213
- -----------------------------------------------------------------------------
27
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:
- -----------------------------------------------------------------------------
CENTS/CENTS PER KILOWATT-HOUR
- ----------------------------------------------------------------------------------------------------
1995 5.53 CENTS
1994 5.65
1993 5.47 cents
1992 5.55
1991 5.36
- -----------------------------------------------------------------------------
Oglethorpe is reducing the need to recover from Members the additional
costs resulting from reductions to the GPC Sell-back by increasing revenues from
off-system sales and reducing fixed and operating costs.
In addition to the impact of reductions in GPC Sell-back revenues, future
Member rates will also be affected by such factors as fixed costs relating to
the Rocky Mountain Project, a pumped storage hydroelectric facility (Rocky
Mountain), the cost of adding to Oglethorpe's existing transmission system,
changes in fuel costs, environmental and other governmental regulations
applicable to Oglethorpe and its suppliers and the completion in 1995 of the
amortization of deferred margins. Oglethorpe's future rates will also be
affected by its ability to forecast accurately its future power resource needs
and by its ability to obtain and manage its power resources, including its
purchases and construction of generating capacity and its procurement of coal.
SALES TO NON-MEMBERS. Sales of electric services to non-Members are
primarily made pursuant to three different types of contractual arrangements
with GPC and from off-system sales to other non-Member utilities.
The following table summarizes the amounts of non-Member revenues from
these sources for the past three years:
- -------------------------------------------------------------------------------
1993 1992 1991
(DOLLARS IN THOUSANDS) 1995 1994 1993
- --------------------------------------------------------------------------------------------------------------------------------------------
Plant operating agreements $ 10,096 $ 45,392 $106,146 $171,686 $235,851
Power supply arrangements 43,226 26,280 44,904 61,602 45,662
Transmission agreements 13,549 29,586 17,20312,614 10,974 15,763
Other utilities 36,341 5,889 1,577
------- ------- -------52,828 42,561 34,127
-------- -------- --------
Total $118,764 $125,207 $200,940 $268,763 $300,293
------- ------- -------
------- ------- -------
- -------------------------------------------------------------------------------
Revenues from sales to non-Members declined in 19931995 compared to 1992,1994 and
in 19921994 compared to 1991.1993. 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 or part
of its contractual entitlement to the generation. These revenues
essentially represent reimbursement of costs to Oglethorpe because, under the
operating agreements, Oglethorpe is responsible for its share of fuel costs
any time a unit operates. The greater amountRevenues from sales of such revenuesthis type to GPC were
higher in 19921995 compared to 19931994 and 1991 was largely attributablelower in 1994 compared to GPC's operational decisions causing1993. 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 higher
levelsource of generation atthe above
"automatic" type of sales transaction; however, Oglethorpe did continue to
make other sales to GPC from Plant Scherer in 1992.this
29
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. In addition, beginningThe change in 1991, GPC purchased the right to use
the majorityrevenues for
1995 through 1993 resulted from normal variations of Oglethorpe's shareinvestment
percentages and its use of the interface capability between the ITS
and the Florida electric system through May 1994.
The higher amount of transmission agreement revenuessystem.
Revenues from other non-Member utilities increased substantially due to a
22% increase in 1992kWh sales in 1995 as compared to 19931994 and 1991 was partially attributable to the receipt by Oglethorpea 28% increase in 1992 of
a payment of $10.5 million from GPCkWh
sales in 1994 as a result of adjustments of transmission
income for the years 1990 through 1992.
Other revenues from non-Members increased significantly in 1993 compared to 1992 and 1991. This increase reflects greater revenues from off-system energy
sales.1993. Oglethorpe is continuing to aggressively
seek to makeadditional off-system sales to non-Members.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 19931995 compared to 19921994
and decreased 5.6%1.0% in 19921994 compared to 1991.1993. The increase in operating
expenses in 19931995 compared to 19921994 was primarily attributable to higher productiona 13.0%
increase in kWh sold to Members and non-Members. In addition, depreciation
and amortization, sales, and administrative and general expenses purchased power expenses and taxes other than income taxes.were also
higher. The slight decrease in operating expenses in 19921994 compared to 19911993
was primarilylargely due to declinesthe decline in productionpurchased power expenses depreciationoffset somewhat by
the increase in fuel expenses. The total kWh of energy supplied through
generation and amortization, taxes otherpurchased power in 1994 was 4% less than income
taxes and income taxes.1993.
Generally, over the years 19911993 through 1993,1995, the Members have received
the benefit of declining averageper unit fuel costs of Oglethorpe's generating
resources through the pass-through of lower energy costs. The averageper unit fuel
costs of Oglethorpe's nuclear and fossil generating resources for the last
three years are as follows:
- -------------------------------------------------------------------------------
CENTS/CENTS PER KILOWATT-HOUR
--------------------------------------------
NUCLEAR FOSSIL
- ----------------------------------------------------------------------------------------- ----------
1991 .80 cents 2.08 cents
1992 .66 2.041995 0.59 CENTS 1.74 CENTS
1994 0.64 1.78
1993 .610.61 1.96
- -------------------------------------------------------------------------------
MuchOglethorpe began receiving shipments at Plant Scherer of lower-priced
coal from the mining regions of the reductionwestern United States in averagethe 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 costs was attributable to
Oglethorpe's nuclear units. Fuel savings were particularly significantcost
decrease for Plant Scherer of 13% in 1995 from 1993 levels. Because of the
decline in fuel cost per kWh at Plant Vogtle where average fuel costs declined by 29%Scherer, the usage of the units
increased significantly. Output from Plant Scherer was 23% higher in 19931995
compared to 1991. The
decline was1994 and 75% higher in 1994 compared to 1993. Oglethorpe
retained significantly less of its output from Plant Wansley in 1995 compared
to 1994 primarily due to the lower cost of replacement fuel relative to the
cost of the initial core loading of fuel. These initial fuel supplies were
purchased well in advance of commercial operation of these units
28
and carried a significantly higher amount of capitalized interest than
subsequent fuel reloads. Additionally, as a result of purchases of nuclear fuel
inhigher costs associated with the spot market, Oglethorpe's costs for nuclear fuel in the last three years
have been favorably impacted.
The lower amount of production expenses in 1992emission
allowances requirement. In 1994 compared to 1993, the per unit fuel cost at
Plant Wansley decreased by almost 10% and 1991
was attributable to a reduced numberthus, Oglethorpe retained more of
nuclear refueling outagesits output. The decrease in 1992. Two
of Oglethorpe's nuclear units underwent planned outages in 1992, as compared to
three units in both 1993 and 1991.
The increase in 1993 in purchased power expenses was the result of a 22%
increase in kWh purchases. This increase was, for the most part, necessitated by
the greater energy needs of the Members (see "OPERATING REVENUES - SALES TO
MEMBERS" herein) and by Oglethorpe's increased off-system energy sales (see
"OPERATING REVENUES - SALES TO NON-MEMBERS" herein).
The decline in power delivery expenses from 1991 through 1993 was due to
the lengthening of maintenance cycles, particularly on substation equipment, and
to delays in 1993 by GPC, Oglethorpe's primary transmission maintenance
contractor, in performing authorized work. Additionally, in 1991 Oglethorpe
incurred a transmission charge of $3.8 million resultingper unit fuel costs resulted from a greater
percentage usereliance 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 ITS comparedtake-or-pay
requirements. Oglethorpe's power purchases from these agreements amounted to
its projected percentage of investment.
(This amount was subsequently returned to Oglethorpeapproximately $207 million in 1992. See1995, $182 million in 1994 and $192 million in
1993. For a discussion of transmission income adjustment in 1992 under "OPERATING REVENUES - SALES TO NON-
MEMBERS" herein.)the power purchase agreements, see Note 9 of Notes
to Financial Statements.
The increase in sales, administrative and general expense in 1992 compared
to 1991 was primarily attributable to increases in property insurance for
co-owned plants, expanded marketing programs, and the expenses associated with
one-time payments made to separated employees and to the utilization of
consultants in a workforce reduction undertaken in 1992.
Decreases in depreciation and amortization income taxes and taxes other
than income taxes also contributedin 1995 is due to the
decreasecommercial operation of Rocky Mountain in total operatingJune.
Sales, administrative and general expenses increased in 1992 compared to 1991. These lower expense categories also directly
contributed to the substantial amount of margins earned in excess of the 1992
TIER-based goal. (See the discussion below under "OTHER INCOME" concerning the
disposition of this excess.)
As a result of depreciation studies undertaken by GPC as operating agent in
the fall of 1991, Oglethorpe implemented lower depreciation rates for all
co-owned generating units. The lower rates are1995 primarily due to a plant life
extension program undertaken by GPC for the co-owned units.
Property taxes, which constitute the majority of taxes other than income
taxes, decreased in 1992 as
a result of the favorable resolutionincreased marketing efforts in support of Oglethorpe's property tax appeal with the State of Georgia for the years 1985 through 1988.
The negotiated settlement of this appeal resulted in a reduction of 1992
property tax expense in the amount of approximately $7.5 million.
Income taxes were substantially lower in 1992 compared to 1991 due to
several factors, including lower interest income, less gain in 1992 than in 1991
from the sale of debt service reserve fund securities (see "OTHER INCOME" below)
and increased energy sales to GPC and other utilities. These sales to GPC were
$16 million higher in 1992, and sales to other utilities were $3 million higher.
(See "OPERATING REVENUES - SALES TO NON-MEMBERS" herein.) Oglethorpe deducts
both fixed and variable costs from the revenues from these energy sales which
generated tax losses resulting in lower taxable income from non-Member sales.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
incompared to 1993 and in 1992, as a result of lower average interest rates on investments.investment balances.
In 19921995, 1994 and 1991, Oglethorpe realized the capital
appreciation on securities invested for its debt service reserve funds by
selling investments bearing coupon yields which were higher than prevailing
market rates. The securities sold in 1991 had been held for a number of years
and their average rates were substantially higher than market rates at the time
of the sale. The 1992 gain captured only the capital appreciation resulting
from declining interest rates during the 12 months following the 1991 sale.
In 1993, 1992 and 1991, Oglethorpe's Board of Directors authorized the
retention of approximately $5$14 million, $40$9 million and $12$5 million,
respectively, in excess of the 1.07 TIER margin requirement as deferred
margins. The remaining amountsamount at December 31, 1995 of $32 million will be
available in 1994 and 19951996 to mitigate rate increases. Amortization of deferred
margins for 19931995 was set by Oglethorpe's
Board of Directors at $4$16 million, significantlyslightly less than the amountsamount utilized in
1992 and 1991.1994 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
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 declinedincreased in 19931995 compared to 1992,1994 and decreased
significantly in 19921994 compared to 1991.1993. The continued decrease in gross
interest on long-term debt and capital leases in 19931995 and 1994 was due for the most part, to the
refinancing efforts discussed under "LIQUITY AND CAPITAL RESOURCES" herein."Financial Condition--REFINANCING
TRANSACTIONS" below. Allowance for debt and equity funds used during
construction (AFUDC) increaseddecreased in 1993 and in 19921995 compared to 1994 as a result of increased construction activity atthe
three units of Rocky Mountain.Mountain becoming commercially operable in June and July
1995. The decreasechange in other interest expense in 19931995 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 higher interest expenselosses incurred on the
sale of securities contained in 1992
associated with the settlementdecommissioning 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 property tax appeal and the federal income
tax case. Additionally, Oglethorpe paid a premium in 1992 in connection with
its repricing of Federal Financing Bank (FFB) advances at reduced rates. In
orderannualized
fixed costs relating to modify the FFB advances, Oglethorpe paid a premium equal to
approximately one year's interest on these repriced advances.
LIQUIDITY AND CAPITAL RESOURCES
In the past, Oglethorpe, like most other G&Ts, has obtained the majority of
its long-term financing from REA-guaranteed loans funded by the FFB. Oglethorpe
has
29
also obtained a substantial portion of its long-term financing requirements from
tax-exempt pollution control bonds (PCBs).
In addition, Oglethorpe's operations have consistently provided a sizable
contribution to the financing of construction programs, such that internally
generated funds have provided interim funding or long-term capital for nuclear
fuel reloads, new generation, transmission and general plant facilities, and
replacements and additions to existing facilities.
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $4.5 billion as of December 31, 1993. Expenditures for property
additions during 1993 amounted to approximately $235 million, of which $198
million was provided from operations. These expenditures were primarily for the
construction of Rocky Mountain and replacementsrelated 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 generationgross utility plant and transmission facilities.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 1996, including AFUDC:
- -------------------------------------------------------------------------------1998:
CAPITAL EXPENDITURES
(DOLLARS IN THOUSANDS)
Year Generation(1) Transmission Rocky Mtn.(2) General Total
GENERAL
YEAR GENERATION(1) TRANSMISSION(2) PLANT AFUDC(3) TOTAL
- ------------------------------------------------------------------------------------------------------------------------------------------------------
19941996 $60,640 $ 84,98244,795 $ 60,966 $118,055 $20,384(3) $284,387
1995 85,389 52,319 61,493 5,015 204,216
1996 90,231 53,285 882 3,239 147,6374,499 $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
-------- -------- ------- ------ --------
-------- -------- ------- ------ --------
Total $260,602 $166,570 $180,430 $28,638 $636,240
-------- -------- -------- ------- --------
-------- -------- -------- ------- --------
(1) CONSISTS OF CAPITAL EXPENDITURES REQUIRED FOR REPLACEMENTS AND ADDITIONS
TO FACILITIES IN SERVICE, COMPLIANCE WITH ENVIRONMENTAL REGULATIONS, NUCLEAR
FUEL RELOADS AND THE PURCHASE OF RAILCARS.
(2) INCLUDES RELATED TRANSMISSION FACILITIES AND ADDITIONS, RENEWALS AND
REPLACEMENTS TO ROCKY MOUNTAIN AFTER ITS IN-SERVICE DATE.
(3) CONSISTS PRIMARILY OF DEVELOPMENT COSTS RELATED TO AN ENERGY CONTROL
SYSTEM.
- -------------------------------------------------------------------------------
Based on its current construction budget, Oglethorpe anticipates that it
will fund all(1) Consists of capital expenditures through 1996, other thanrequired for Rocky Mountain,
from operations.(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
In 1988, Oglethorpe acquired from GPC an undivided ownership interest in
Rocky Mountain and assumed responsibility for its construction and operation.
AsBy July 1995, all three units of December 31, 1993, Rocky Mountain was approximately 90% completewere in-service and
Oglethorpe's investment in the project at December 31, 1995 was $414 million.$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 is
financingexpects 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
REA-guaranteedRUS-guaranteed loan funded throughby the FFB. As of December 31, 1993, $2481995, $555 million
had been advanced under this loanloan. 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 $459 million remained availablemanagement 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 drawnmet 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 permanent financingof December 31, 1995. Expenditures for
Rocky Mountain. Oglethorpe intendsproperty additions during 1995 amounted to finance all
direct$139 million, of which $6 million
was provided from operations. These expenditures and capitalized interest associated withwere primarily for the
construction of Rocky Mountain through suchand 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 loan, and management believesdebt.
LIQUIDITY AND SOURCES OF CAPITAL
In the amounts
remaining to be drawn under such loan are more than adequate to completepast, Oglethorpe, like most other G&Ts, has obtained the project. The obligation to advance funds under this loan, however, is subject
to certain conditions, includingmajority
of its long-term financing from RUS-guaranteed loans funded by the requirement that Oglethorpe maintain an
annual TIER of at least 1.0 and that the REA shall not have determined that
there has occurred any material adverse change in the assets, liabilities,
operations or financial condition of Oglethorpe or any circumstances involving
the nature or operation of the business of Oglethorpe. In management's opinion,
no such material adverse change has occurred. The current schedule anticipates
commercial operation in early 1995.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:
SHORT-TERM CREDIT FACILITIES AUTHORIZED
AMOUNT
- ---------------------------------------------------------
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
Under its commercial paper program, under which itOglethorpe may issue commercial paper
not to exceed $355$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. Oglethorpe's commercial paper is backed
100% by a committed line of credit provided by a group of banks for which Trust
Company Bank acts as agent. Historically, Oglethorpe has not relied on
commercial paper for short-term funding due to the availability of internally
generated funds and has never utilized the backup line of credit.
Oglethorpe
has also arranged one committed and two uncommitted lines of credit to provide
additional sources of short-term financing. As of December 31, 1993,
Oglethorpe's short-term credit facilities were as follows:
- --------------------------------------------------------------------------------
SHORT-TERM CREDIT FACILITIES AUTHORIZED
AMOUNT
- --------------------------------------------------------------------------------
Commercial Paper . . . . . . . . . . . . . . . . . . . . . $355,000,000
National Bank for Cooperatives (CoBank). . . . . . . . . . 70,000,000
National Rural Utilities Cooperative
Finance Corporation (CFC). . . . . . . . . . . . . . . . 50,000,000
Trust Company Bank (Committed) . . . . . . . . . . . . . . 30,000,000
- --------------------------------------------------------------------------------
The maximum amount that can be outstanding at any one time under the
commercial paper program and the lines of credit totals $425$370 million due to
certain restrictions contained in the CFCSunTrust Bank and Trust Company BankCFC line of credit
agreements. As of December 31, 1993,1995, no commercial paper was outstanding and
there was no outstanding balance on any line of credit.
As partREFINANCING 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 March$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
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 PCB refinancing transaction involving twoon 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 issued or to be issued in connection therewith.outstanding. This
minimum liquidity requirement currently equals $81 million and will decrease
proportionately as such variable rate refunding bonds are retired. The minimum liquidity must
consist of (a) any combination of (i) amounts available under committed lines
of credit and commercial paper programs to pay termination payments, if any,
due upon early termination of the forward interest rate swap transactions, (ii)
cash, (iii) United States government securities, and (iv) accounts receivable
due within 30 days, less (b) monetary 30
obligations due within 30 days. As of
December 31, 1993,1995, Oglethorpe had approximately $467$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 scheduled maturitiesBoard of
long-term debt overDirectors in December 1995 to divide Oglethorpe into three specialized
companies to respond to increasing competition in the next five
years total $425 million. Of this amount, $299 million, or seventy percent,
relateselectric 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
repaymentMembers of REAhaving the transmission business and FFB debt.
REFINANCING TRANSACTIONS
Over the past few years,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 implementedbeen
incorporated for future use as the transmission company and Georgia System
Operations Corporation (GSOC) has been incorporated as a programGeorgia 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 reduce its
interest costs by refinancing or prepaying a sizable portion of its high-
interest PCBGTC. GTC would thereafter own and FFB debt. Several transactions were completed in 1993operate the
transmission system and early
1994, covering approximately $1.3 billion in existing PCBprovide transmission services to the Members,
Oglethorpe and FFB debtthird parties. (See Note 56 of Notes to Financial Statements.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 resultbook value for the transmission assets,
plus (2) the value of certain deferred charges. If the appraised value of
the 1993 transactions wastransmission business exceeds Oglethorpe's net book value for the
transmission assets by more than 5%, GTC's Board would have to reduceapprove the
average interestpayment of any resulting purchase price. The purchase price would be paid by
GTC's assumption of a portion of
33
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 total long-term debta 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 8.18%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 December 31, 1992prices 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 7.94% at December 31, 1993.economic dispatch (pooled)
for the benefit of all pool participants. The average interestpower 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 was
further reduced to 7.13%PCBs would not be lowered as a
result of the transactions completed in early
1994.
In March 1993, Oglethorpe entered into two forward interest rate swap
agreements totaling $322 millionrestructuring and that such rating agencies would assign to refinance $364 million of existing high-
interest PCBs. Through this forward swap transaction, Oglethorpe arranged
syntheticany
comparable bonds issued by GTC the same or better credit rating as assigned
to Oglethorpe's fixed rate financing at an averagePCBs. 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 rate of 6.15% for $200
million of variable rate refunding bonds which were issued on November 30, 1993
and $122 million of variable rate refunding bonds to be issuedsooner if
specific conditions set forth in the fall of
1994. Interest savings totaling $9.1 million and an additional $4.3 million will
occur during the first full year following each respective issuance.Restructuring Agreement are met. In
February 1994, Oglethorpe refunded $205 million of PCBs through an
issuance of $195 million of fixed rate refunding bonds. With an effective
interest rate of 4.8%, this transaction will generate net interest savings of
about $10.5 million during the first full year. Oglethorpe expects to achieve
additional interest savings through a $35 million current refunding of PCBs in
the fall of 1994.
In addition to these refinancings, Oglethorpe has also recently taken
certain actions to reduce the interest expense on its FFB debt. In January 1993,
Oglethorpe prepaid six FFB advances totaling $75 million with interest rates
exceeding 10%. These advances, which had become at least 12 years old, were
prepaid with one year's interest premium. The net annual average savings in the
first full year are $6.9 million.
During 1993, Oglethorpe pursued refinancing all of its approximately $3
billion in outstanding REA and FFB debt (the REA Indebtedness) through the
issuance of bonds in the public market which would have resulted in Oglethorpe
exiting the REA program (the REA Refinancing). In January 1994, FFB advised
Oglethorpe that the Departmentlight of the Treasury would not take certain actions
requested to facilitatesignificant conditions that must be satisfied, including RUS
and other governmental and third-party approvals and assurances and receipt
of various agreements from the REA Refinancing.Members, Oglethorpe continues to believe
that an REA Refinancing is in its long-term best interest andcannot 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 to
evaluate options to exit the REA program. If the REA Refinancing were to be
consummated, it would require, among other things, a substitutionits current operations, and until
satisfaction of the REA
Mortgage with a trust indenture which would secure all of Oglethorpe's first
lien indebtedness, regulation of Oglethorpe's rates by the Federal Energy
Regulatory Commission, and certain amendmentsconditions applicable to the wholesale power contracts
between Oglethorpe and each of its Members. Oglethorpe's management is unable to
give any assurance at this time thatnew governance
structure, Oglethorpe will be able to effect the REA
Refinancing, or, if so, on what terms and conditions.
Although Oglethorpe continues to pursue the REA Refinancing, it has taken
advantage of an option currently available to reduce the interest expense oncontinue under its FFB debt. At the beginning of 1994, Oglethorpe had over $1 billion of advances
that had been outstanding for more than 12 years under notes to the FFB that
were eligible to be modified to reduce their interest rates. In two separate
transactions in early 1994, Oglethorpe modified certain FFB notes and thereby
reduced the interest rates on approximately $795 million of advances. In
connection with such note modification, a premium was paid in an amount equal to
one year's interest on the advances of approximately $64 million, which will be
expensed over the longest remaining life of the subject advances, which is 22
years. These transactions will generate net interest savings of $18.5 million in
the first full year. Oglethorpe may elect to reduce the interest rates on
approximately $250 million of additional FFB advances through this note
modification process. The timing of such election depends on the magnitude of
the interest rate savings that can be achieved.
Oglethorpe is also evaluating and may seek to reduce its interest expense
by refinancing certain of its other FFB notes upon payment of a premium as
permitted under the recently enacted Section 306C of the Rural Electrification
Act. Under 306C, an FFB borrower is able to refinance its outstanding
indebtedness at interest rates based on the then current Treasury rates upon
payment of a premium. Based on current interest rates and the premium that would
be due under Section 306C, Oglethorpe is evaluating refinancing a portion of its
FFB indebtedness and financing at least a portion of the premium. Oglethorpe's
management has not determined whether Oglethorpe will avail itself of such
refinancing option.
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.
The implementation of recently released pronouncements of the Financial
Accounting Standards Board, including Statement No. 115, "Accounting for Certain
Investments in Debt and Equity Securities" and Statement No. 112, "Employer's
Accounting for Postemployment Benefits", are not expected to have a material
effect on Oglethorpe's results of operations.
31existing governance structure.
34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
OGLETHORPE POWER CORPORATION
INDEX TO FINANCIAL STATEMENTS
Page
----
Statements of Revenues and Expenses, For the Years Ended December 31, 1993,
1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Statements of Patronage Capital, For the Years Ended December 31, 1993,
1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33
Balance Sheets, As of December 31, 1993 and 1992 . . . . . . . . . . . . . . . . 34
Statements of Capitalization, As of December 31, 1993 and 1992 . . . . . . . . . 36
Statements of Cash Flows, For the Years Ended December 31, 1993,
1992 and 1991 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37
Notes to Financial Statements. . . . . . . . . . . . . . . . . . . . . . . . . . 38
Report of Management . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48
Report of Independent Public Accountants . . . . . . . . . . . . . . . . . . . . 48
32PAGE
----
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
STATEMENTS OF REVENUES AND EXPENSES
- -------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1993, 19921995, 1994 AND 19911993
(DOLLARS IN THOUSANDS).........................................................................................................
(dollars in thousands)
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------
OPERATING REVENUES (NOTE 1):
Sales to Members . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Members..................................... $1,030,797 $ 930,875 $ 899,720
$ 816,000 $ 763,657
Sales to non-Members . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .non-Members................................. 118,764 125,207 200,940
268,763 300,293
--------- --------- ------------------- ---------- ----------
TOTAL OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .REVENUES............................... 1,149,561 1,056,082 1,100,660
1,084,763 1,063,950
--------- --------- ------------------- ---------- ----------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Fuel................................................. 219,062 203,444 176,342
167,288 165,168
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Production........................................... 133,858 132,723 129,972 115,915 130,041
Purchased power (Note 10). . . . . . . . . . . . . . . . . . . . . . . . . . . . .9)............................. 264,844 227,477 271,970
230,510 229,898
Power delivery . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .delivery....................................... 17,520 16,965 14,286 17,804 20,443
Sales, administrative and general. . . . . . . . . . . . . . . . . . . . . . . . .general.................... 39,015 32,269 30,590 32,774 28,930
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . . .amortization........................ 139,024 131,056 128,060 126,047 135,152
Taxes other than income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . .taxes........................ 27,561 24,741 23,328 15,668 22,827
Income taxes (Note 1). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3)................................ -- -- 1,820
3,966 19,595
--------- --------- ------------------- ---------- ----------
TOTAL OPERATING EXPENSES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .EXPENSES............................... 840,884 768,675 776,368
709,972 752,054
--------- --------- ------------------- ---------- ----------
OPERATING MARGIN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .MARGIN....................................... 308,677 287,407 324,292
374,791 311,896
--------- --------- ------------------- ---------- ----------
OTHER INCOME (EXPENSE):
Interest income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .income...................................... 18,031 10,518 20,316 29,218 40,814
Gain on sale of debt service reserve fund securities . . . . . . . . . . . . . . . - 3,884 32,449
Amortization of deferred gains (Notes 21 and 6) . . . . . . . . . . . . . . . . . .4)....... 2,341 9,985 12,532 12,486 12,482
Amortization of proceeds from sale of income tax
benefits (Note 6) . . . . . . . . . . . . . . . . . . . . . . . . . 8,1021).................................. 8,043 8,102 8,102
Amortization of deferred margins (Note 1) . . . . . . . . . . . . . . . . . . . ............. 15,959 18,072 4,138 35,973 31,000
Deferred margins (Note 1) . . . . . . . . . . . . . . . . . . . . . . . . . . . ............................. (14,282) (9,287) (5,083) (40,464) (11,703)
Co-owner inventory settlement (Note 7) . . . . . . . . . . . . . . . . . . . . . . - (4,827) -
Allowance for equity funds used during
construction (Note 1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . ............................... 1,715 2,907 2,278
1,377 782
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Other................................................ 1,903 498 (3,542)
179 (485)
--------- --------- ------------------- ---------- ----------
TOTAL OTHER INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .INCOME..................................... 33,710 40,795 38,741
45,928 113,441
--------- --------- ------------------- ---------- ----------
INTEREST CHARGES:
Interest on long-term debt and capital leases . . . . . . . . . . . . . . . . . .leases........ 317,968 329,738 367,439
392,454 398,999
Other interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .interest....................................... 12,979 3,856 8,539 17,049 7,357
Allowance for debt funds used during construction
(Note 1) . . . . . . . . . . . ............................................. (21,114) (36,113) (29,988) (20,255) (13,111)
Amortization of debt discount and expense . . . . . . . . . . . . . . . . . . . .expense............ 10,296 7,639 4,662
3,999 3,647
--------- --------- ------------------- ---------- ----------
NET INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .CHARGES................................... 320,129 305,120 350,652
393,247 396,892
--------- --------- ------------------- ---------- ----------
MARGIN BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE . . . . . . . . . . . . . . . . . . . . . . . .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
---------- ---------- ----------
---------- ---------- ----------
STATEMENTS OF PATRONAGE CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
(dollars in thousands)
1995 1994 1993
.........................................................................................................
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) --
--------- --------- ---------
NET MARGIN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Patronage capital and membership fees-end of year...... $ 25,721338,891 $ 27,472309,496 $ 28,445289,982
--------- --------- ---------
--------- --------- ---------
STATEMENTS OF PATRONAGE CAPITAL
- -------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991
(DOLLARS IN THOUSANDS)
1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------
PATRONAGE CAPITAL AND MEMBERSHIP FEES-BEGINNING
OF YEAR (NOTE 1) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 264,261 $ 236,789 $ 217,895
NET MARGIN . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,721 27,472 28,445
PATRONAGE CAPITAL RETIREMENTS DECLARED . . . . . . . . . . . . . . . . . . . . . . - - (9,551)
--------- --------- ---------
PATRONAGE CAPITAL AND MEMBERSHIP FEES-END OF YEAR. . . . . . . . . . . . . . . . . . $ 289,982 $ 264,261 $ 236,789
--------- --------- ---------
--------- --------- ---------
CERTAIN PRIOR YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH CURRENT YEAR
PRESENTATION.
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
3336
BALANCE SHEETS
- -------------------------------------------------------------------------------
DECEMBER 31, 19931995 AND 19921994
- ---------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)........................................................................................
(dollars in thousands)
ASSETS 1993 1992
- ---------------------------------------------------------------------------------------------------------------------1995 1994
ELECTRIC PLANT (NOTES 1, 2, 54 AND 6):
In service. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .service............................................ $ 5,047,7395,699,213 $ 4,980,2795,100,299
Less: Accumulated provision for depreciation. . . . . . . . . . . . . . . . . (1,110,296) (989,892)
------------ ------------
3,937,443 3,990,387depreciation.......... (1,362,431) (1,231,818)
----------- -----------
4,336,782 3,868,481
Nuclear fuel, at amortized cost . . . . . . . . . . . . . . . . . . . . . . . 110,177 123,627cost....................... 94,013 105,683
Plant acquisition adjustments, at amortized cost. . . . . . . . . . . . . . . 7,336 8,397cost...... 5,214 6,275
Construction work in progress . . . . . . . . . . . . . . . . . . . . . . . . 450,965 322,628
------------ ------------
4,505,921 4,445,039
------------ ------------progress......................... 35,753 538,789
----------- -----------
4,471,762 4,519,228
----------- -----------
INVESTMENTS AND FUNDS AT COST:(NOTES 1 AND 2):
Bond, reserve and construction funds, (Note 4) . . . . . . . . . . . . . . . . 110,390 163,964at market....... 56,511 64,163
Decommissioning fund, (Note 1) . . . . . . . . . . . . . . . . . . . . . . . . 56,911 47,921at market....................... 74,492 59,164
Investment in associated organizations, (Note 3) . . . . . . . . . . . . . . . 19,123 19,909
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 486 644
------------ ------------
186,910 232,438
------------ ------------at cost....... 15,853 17,371
----------- -----------
146,856 140,698
----------- -----------
CURRENT ASSETS:
Cash and temporary cash investments, at cost (Note 1). . . . . . . . . . . . 244,173 275,624201,151 190,642
Other short-term investments, at cost . . . . . . . . . . . . . . . . . . . . - 66,165
Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82,274 75,146market............... 79,165 --
Receivables........................................... 99,559 88,873
Inventories, at average cost (Note 7) . . . . . . . . . . . . . . . . . . . . 86,468 93,6401)................. 82,949 95,076
Prepayments and other current assets. . . . . . . . . . . . . . . . . . . . . 14,763 17,132
------------ ------------
427,678 527,707
------------ ------------assets.................. 14,325 14,857
----------- -----------
477,149 389,448
----------- -----------
DEFERRED CHARGES:
Premium and loss on reacquired debt, being amortized
(Note 5) . . . . . . . . 91,981 48,076............................................. 200,794 161,889
Deferred amortization of Scherer leasehold (Note 2) . . . . . . . . . . . . . 71,559 61,8804)... 87,134 80,132
Discontinued projects, being amortized (Note 1)....... 24,305 26,342
Deferred debt expense, being amortized . . . . . . . . . . . . . . . . . . . . 21,527 24,735
Discontinued project, being amortized (Note 6). . . . . . . . . . . . . . . . 18,314 19,722
------------ ------------
203,381 154,413
------------ ------------amortized................ 21,135 20,936
Other................................................. 9,361 7,657
----------- -----------
342,729 296,956
----------- -----------
$ 5,323,8905,438,496 $ 5,359,597
------------ ------------
------------ ------------
CERTAIN PRIOR YEAR AMOUNTS HAVE BEEN RECLASSIFIED TO CONFORM WITH CURRENT YEAR
PRESENTATION.5,346,330
----------- -----------
----------- -----------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE BALANCE SHEETS.
3437
- ---------------------------------------------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)........................................................................................
(dollars in thousands)
EQUITY AND LIABILITIES 1993 1992
- ---------------------------------------------------------------------------------------------------------------------1995 1994
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Patronage capital and membership fees (Note 1). . . . . . . . . . . . . . . ........ $ 289,982338,891 $ 264,261309,496
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,058,251 4,095,796debt....................................... 4,207,320 4,128,080
Obligation under capital leases (Note 2). . . . . . . . . . . . . . . . . . . 303,458 302,061
------------ ------------
4,651,691 4,662,118
------------ ------------4)............. 296,478 303,749
----------- -----------
4,842,689 4,741,325
----------- -----------
CURRENT LIABILITIES:
Long-term debt and capital leases due within one
year. . . . . . . . . . . . . . . . . . . . . . 78,644 133,136year................................................ 89,675 90,086
Deferred margins and Vogtle surcharge to be
refunded within one year (Note 1). . . . . . . . . . . . . . . . . . . . . 26,777 5,738................... 32,047 19,279
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 62,186 64,535payable..................................... 48,855 52,921
Accrued interest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 108,702 59,323interest..................................... 91,096 100,010
Accrued and withheld taxes. . . . . . . . . . . . . . . . . . . . . . . . . . 9,401 3,660
Energy cost billed in excess of actual (Note 1`). . . . . . . . . . . . . . . 11,456 29,318taxes........................... 1,785 1,566
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . 40,234 22,456
------------ ------------
337,400 318,166
------------ ------------liabilities............................ 18,007 18,177
----------- -----------
281,465 282,039
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES:
Gain on sale of plant, being amortized (Notes 2). . . . . . . . . . . . . . . 65,550 67,892
Gain on sale of Scherer common facilities, being amortized (Note 6) . . . . . 7,644 17,8354)...... 60,868 63,209
Sale of income tax benefits, being amortized
(Note 6) . . . . . . . . . . . . 66,838 74,9391)............................................ 50,194 58,236
Accumulated deferred income taxes (Note 1). . . . . . . . . . . . . . . . . .3)........... 65,510 77,22565,510
Deferred margins and Vogtle surcharge (Note 1). . . . . . . . . . . . . . . . 21,083 42,777....... -- 17,765
Decommissioning reserve (Note 1). . . . . . . . . . . . . . . . . . . . . . . 90,476 77,490
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,698 21,155
------------ ------------
334,799 379,313
------------ ------------..................... 114,049 96,291
Other................................................ 23,721 21,955
----------- -----------
314,342 322,966
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTES 2,6,94, 9 AND 10)
$ 5,323,890 $ 5,359,597
------------ ------------
------------ ------------$5,438,496 $5,346,330
----------- -----------
----------- -----------
35THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE BALANCE SHEETS.
38
STATEMENTS OF CAPITALIZATION
- -------------------------------------------------------------------------------
DECEMBER 31, 19931995 AND 19921994
........................................................................................
(dollars in thousands)
1993 1992
- ------------------------------------------------------------------------------------------------------------------------------1995 1994
LONG-TERM DEBT (NOTE 5):
Mortgage notes payable to the Federal Financing
Bank (FFB) at interest rates varying from 6.61%5.67% to
10.95%10.78% (average rate of 8.367%7.19% at December 31,
1993)1995) due in quarterly installments . . . . . . . . . . . . . .through 2023 ..... $ 3,040,7673,253,636 $ 3,111,1603,161,550
Mortgage notes payable to the Rural Electrification Administration (REA)Utilities
Service (RUS) at an interest rate of
5% due in monthly installments . . . . . . . . . . . . . . . . . . 23,927 24,365through 2021........... 22,983 23,467
Mortgage notes issued in conjunction with the sale by
public authorities of pollution control revenue bonds:
- Series 1978
Serial bonds, 6.00% to 6.40%, due serially through 1999 . . . . . . . . . . . . . . 5,440 6,180
Term bonds, 6.80%, due 2009 . . . . . . . . . . . . . . . . . . . . . . . . . . . . 16,700 16,700
- Series 1982
Serial bonds, 10.00%10.20% to 10.60%, due serially
through 1997. . . . . . . . . . . . . . 23,195 27,740
- Series 1984
Serial bonds, 9.50% to 10.50%, due serially through 2000 . . . . . . . . . . . . . . 61,800 67,790
Term bonds, 7.00% to 10.63%, due 2004 to 2014. . . . . . . . . . . . . . . . . . . . 119,135 270,965
- Series 1984B
Serial bonds, 9.75% to 10.50%, due serially through 2000 . . . . . . . . . . . . . . 11,530 25,910
Term bonds, 10.50%, due 2014 . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 69,080
- Series 1985
Serial bonds, 8.50% to 9.50%, due serially through 2001. . . . . . . . . . . . . . . 29,290 31,770
Term bonds, 7.50% to 9.88%, due 2005 to 2017 . . . . . . . . . . . . . . . . . . . . 141,890 141,890
- Series 1992A
Adjustable tender bonds, 2.10% to 2.65%, due 2025 . . . . . . . . . . . . . . . . . 216,925 216,925
Serial bonds, 3.85% to 6.80%, due serially from 1994 through 2012. . . . . . . . . . 143,710 143,7101997......................................... 6,675 16,135
- Series 1992
Term bonds, 7.50% to 8.00%, due 2003 to 2022 . . . . . . . . . . . . . . . . . . . .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, 3.10%5.15%, due 2016 . . . . . . . . . . . . . . . . . . . . . .2016.............. 199,690 199,690
- National Bank for Cooperatives (CoBank)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: $5.4$5.2 million fixed at
7.40%6.85% through April 1995,
$0.5 million fixed at 6.35%-7.35% to April 1995;July 1996, due in quarterly installments
through January 1, 2009 . . . . . . . . . . . . . . . . . . . . . . . . 5,938 6,328.............................. 5,159 5,549
- Transmission note payable: fixed at 7.40%6.85% through
April 1995;July 1996; due in bimonthly installments through
November 1, 2018 . . . . . . . . . . . . . . . 2,296 2,3102018...................................... 2,261 2,279
- Transmission note payable: fixed at 7.25%6.45% through
April 1995;November 1996; due in bimonthly installments through
September 1, 2019 . . . . . . . . . . . . . . 8,751 8,798
----------2019..................................... 8,637 8,697
----------- 4,143,114 4,263,751-----------
4,291,836 4,219,062
Less:Unamortized debt discount . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6,219) (34,819)
----------discount......................... (832) (896)
----------- -----------
Total long-term debt, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,136,895 4,228,932net.............................. 4,291,004 4,218,166
Less: AmountLong term debt due within one year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (78,644) (133,136)
----------year................ (83,684) (90,086)
----------- -----------
TOTAL LONG-TERM DEBT, EXCLUDING AMOUNT DUE WITHIN
ONE YEAR . . . . . . . . . . . . . . . . . . 4,058,251 4,095,796YEAR............................................... 4,207,320 4,128,080
OBLIGATION UNDER CAPITAL LEASES, LONG TERM (NOTE 2) . . . . . . . . . . . . . . . . . . . . . . . . . . . 303,458 302,0614)..... 296,478 303,749
PATRONAGE CAPITAL AND MEMBERSHIP FEES (NOTE 1) . . . . . . . . . . . . . . . . . . . . . . . . 289,982 264,261
----------.......... 338,891 309,496
----------- -----------
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .CAPITALIZATION.................................... $ 4,651,6914,842,689 $ 4,662,118
----------4,741,325
----------- ---------------------
----------- -----------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
3639
STATEMENTS OF CASH FLOWS
- -------------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1993, 19921995, 1994 AND 19911993
(DOLLARS IN THOUSANDS)....................................................................................................................
(dollars in thousands)
1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net margin . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .margin....................................................... $ 22,258 $ 23,082 $ 25,721
$ 27,472 $ 28,445
-------- -------- ------------------ ---------- ----------
Adjustments to reconcile net margin to net cash provided by
operating activities:
Cumulative effect of change in accounting for income taxes . . . . . . . .taxes.... -- -- (13,340) - -
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . .amortization................................. 196,920 193,351 180,221
188,285 203,770Interest on decommissioning reserve........................... 9,951 1,291 7,356
Amortization of deferred gains . . . . . . . . . . . . . . . . . . . . . ................................ (2,341) (9,985) (12,532) (12,486) (12,482)
Deferred margins and amortization of deferred margins. . . . . . . . . . .margins......... (1,677) (8,785) 945 4,491 (19,297)
Amortization of proceeds from sale of income tax benefits. . . . . . . . .benefits..... (8,043) (8,102) (8,102) (8,102)
Interest on decommissioning reserve . . . . . . . . . . . . . . . . . . . 7,356 5,443 5,850
Gain on sale of bond fund investments . . . . . . . . . . . . . . . . . . - (3,884) (32,449)
Allowance for equity funds used during construction. . . . . . . . . . . .construction........... (1,715) (2,907) (2,278) (1,377) (782)
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . .taxes......................................... -- -- 1,625
2,459 19,595
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ......................................................... (13) (3,066) 1,118(13) (13)
Change in net current assets, excluding long-term debt due within
one year and deferred margins and Vogtle surcharge to be
refunded within one year:
Receivables . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (7,128) 371 (3,956)
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Receivables................................................... (10,686) (18,055) (24,990)
Inventories................................................... 12,127 (8,608) 7,172 (1,670) (6,865)
Prepayments and other current assets . . . . . . . . . . . . . . . . .assets.......................... 532 (94) 2,369
(3,043) 109
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . .payable.............................................. (4,066) (10,569) (2,349)
1,106 19,109
Accrued interest . . . . . . . . . . . . . . . . . . . . . . . . . . .interest.............................................. (8,914) (8,692) 49,379 (1,238) (147)
Accrued and withheld taxes . . . . . . . . . . . . . . . . . . . . . .taxes.................................... 219 (7,835) 5,741 (14,505) (55)
Energy cost billed in excess of actual . . . . . . . . . . . . . . . . (17,862) 29,318 -
Other current liabilities . . . . . . . . . . . . . . . . . . . . . .liabilities..................................... (169) (24,124) 15,542
(7,532) (3,993)
-------- -------- ------------------ ---------- ----------
Total adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .adjustments................................................ 182,125 86,873 206,746
174,570 161,423
-------- -------- ------------------ ---------- ----------
NET CASH PROVIDED BY OPERATING ACTIVITIES . . . . . . . . . . . . . . . . . . .ACTIVITIES.......................... 204,383 109,955 232,467
202,042 189,868
-------- -------- ------------------ ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .additions............................................... (138,921) (206,345) (235,285)
(232,283) (225,021)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 . . . . . . . . . . . .funds........... -- -- 53,574 15,957 35,024
Decrease in investment in associated organizations . . . . . . . . . . . . . .organizations............... 1,518 1,752 786 1,213 824
Decrease (increase) in other short-term investments . . . . . . . . . . . . .investments.............. -- -- 66,165
(66,165) -
Release of safe harbor lease indemnity fund . . . . . . . . . . . . . . . . - - 120,000
Increase in decommissioning fund . . . . . . . . . . . . . . . . . . . . . . . (8,990) (6,841) (7,259)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Other............................................................ -- -- 158
(158) (486)
-------- -------- ------------------ ---------- ----------
NET CASH USED IN INVESTING ACTIVITIES . . . . . . . . . . . . . . . . . . . . .ACTIVITIES.............................. (213,299) (165,435) (123,592)
(288,277) (76,918)
-------- -------- ------------------ ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Debt proceeds, net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .net............................................... 132,874 523,518 232,675
579,938 51,157
Debt payments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .payments.................................................... (108,481) (517,530) (369,962) (554,029) (40,550)
Patronage capital retirements . . . . . . . . . . . . . . . . . . . . . . . . - (9,551) (4,877)
Return of Vogtle surcharge . . . . . . . . . . . . . . . . . . . . . . . . . .surcharge....................................... (3,320) (2,031) (1,600)
(5,085) (990)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .Other............................................................ (1,648) (2,008) (1,439)
(144) (203)
-------- -------- ------------------ ---------- ----------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES . . . . . . . . . . . . . .ACTIVITIES................ 19,425 1,949 (140,326)
11,129 4,537
-------- -------- ------------------ ---------- ----------
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS . . . . . . . . . . . . . . . . . . . . . . . .INVESTMENTS..... 10,509 (53,531) (31,451) (75,106) 117,487
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR . . . . . . . . . . . .YEAR........... 190,642 244,173 275,624
350,730 233,243
-------- -------- ------------------ ---------- ----------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR . . . . . . . . . . . . . . .YEAR................. $ 201,151 $ 190,642 $ 244,173
$ 275,624 $ 350,730
-------- -------- --------
-------- -------- ------------------ ---------- ----------
---------- ---------- ----------
CASH PAID FOR:
Interest (net of amounts capitalized) . . . . . . . . . . . . . . . . . . . ............................. $ 308,797 $ 304,882 $ 289,255
$ 388,117 $ 386,450
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .taxes..................................................... -- -- 1,658 43 -
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
3740
NOTES TO FINANCIAL STATEMENTS
- ----------------------------------------------------------------------------
FOR THE YEARS ENDED DECEMBER 31, 1995, 1994 AND 1993
1992 AND 1991..............................................................................
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 Power Corporation (Oglethorpe) follows generally accepted accounting principles and the practices
prescribed in the Uniform System of Accounts of the Federal Energy Regulatory
Commission (FERC) as modified and adopted by the Rural Utilities Service (RUS),
formerly known as the Rural Electrification Administration (REA).
B. ELECTRIC PLANT
Electric plantThe preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities as of December 31, 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 stated at original cost, whichorganized and operates as a cooperative. The Members paid a
total of $195 in membership fees. Patronage capital is the costretained net margin
of Oglethorpe. As provided in the plant when first dedicatedbylaws, any excess of revenue over
expenditures from operations is treated as advances of capital by the Members
and is allocated to public service, pluseach of them on the costbasis of any subsequent
additions. Cost includes an allowancetheir 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 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 theyears 1985 through 1995 in excess of the cost of the plantits annual
margin goals be deferred and used to Oglethorpe over the original
cost, less accumulated depreciation at the time of acquisition,mitigate rate increases associated with
Plant Vogtle and are being
amortized overRocky Mountain. In addition, during 1986 and 1987, Oglethorpe's
wholesale electric rate to its Members provided for a ten-year period.
Maintenance and repairs of property and replacements and renewals of
items determinedone mill per kilowatt-hour
charge (Vogtle Surcharge), also to be less than unitsused to mitigate the effect of property are chargedPlant
Vogtle on rates.
Pursuant to expense.
Replacementsrate actions by Oglethorpe's Board of Directors, specified
amounts of deferred margins and renewalsVogtle Surcharge were returned in 1989
through 1995 and all remaining amounts will be returned in 1996. A summary of
items considered to be unitsdeferred margins and Vogtle Surcharge as 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,December 31, 1995 and 1994 is charged to the accumulated provision for depreciation.
C.as
follows:
...................................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...................................................................................
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
--------- ---------
--------- ---------
...................................................................................
E. OPERATING REVENUES
Sales to MembersOperating revenues consist primarily of electricity sales pursuant to
long-term wholesale power contracts which Oglethorpe maintains with each of
its 39 retail electric distribution cooperatives (Members).Members. These wholesale power contracts obligate each Member to pay
Oglethorpe for capacity and energy furnished in accordance with rates
established by Oglethorpe. Energy furnished is determined based on meter
readings which are conducted at the end of each month.
For the year ended December 31, 1993, revenuesRevenues from Cobb EMC oneand 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
revenues. In 1993, Cobb EMC accounted for 10.3% of Oglethorpe's total revenues.
Prior to 1993, no individual Member accounted for 10% or more of Oglethorpe's
totaloperating
revenues.
Sales to non-Members consist primarilypartly of revenues from energy sales to non-
Member utilities other than Georgia Power Company (GPC) and partly of capacity
and energy sales to Georgia Power Company (GPC)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 purchasespurchased 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:
- ----------------------------------------------------------------------------
Fractional Part of Capacity and Energy Retained by GPC during Contract Year
Ended May 31
- ----------------------------------------------------------------------------
...................................................................................
Fractional Part of Capacity and Energy Retained
by GPC during Contract Year Ended May 31
Generating Unit 1996 1995 1994 1993
1992 1991
- ----------------------------------------------------------------------------...................................................................................
Plant Scherer,
Unit No. 12 -- -- -- 6/60
Plant Scherer,
Unit No. 2 -- 6/60 12/60 18/60
Plant Vogtle,
Unit No. 1 -- -- 4/30 8/30 11/30 14/30
Plant Vogtle,
Unit No. 2 -- 4/30 8/30 11/30
14/30 17/30
- ----------------------------------------------------------------------------...................................................................................
Pursuant to these sell-back agreements and to other contractual
arrangements with GPC, revenues from GPC accounted for approximately 15%6%, 24%8%,
and 28%15% of Oglethorpe's total operating revenues in 1995, 1994, and 1993,
1992, and 1991,
respectively.
D. DEPRECIATION
Depreciation is computed on additions when they are placed in service
using the composite straight-line method. Annual depreciation rates in effect
in 1993, 1992 and 1991 were as follows:
- ----------------------------------------------------------------------------
1993 1992 1991
- ----------------------------------------------------------------------------
Steam production 2.66% 2.66% 2.73%
Nuclear production 2.83% 2.74% 3.09%
Hydro production 2.00% 2.00% 2.00%
Other production 1.09% 1.09% 1.14%
Transmission 2.75% 2.75% 2.75%
Distribution 2.88% 2.88% 2.88%
General 2.00-17.00% 2.00-17.00% 2.00-17.00%
- ----------------------------------------------------------------------------
Oglethorpe's portion of the cost of decommissioning co-owned nuclear
facilities, based on current price levels and decommissioning promptly after
the unit is taken out of service, is estimated at approximately $71,000,000
for Hatch Unit No. 1, $93,000,000 for Hatch Unit No. 2, $79,000,000 for
Vogtle Unit No.1 and $99,000,000 for Vogtle Unit No. 2. The depreciation
rate for nuclear production includes a factor to provide for such expected
cost of decommissioning. Oglethorpe accounts for this provision for
decommissioning as depreciation expense with an offsetting credit to a
decommissioning reserve. Imputed interest calculated based on current
investment rates is applied to the decommissioning reserve balance and
charged to interest expense. The estimates for the expected cost of
decommissioning and the corresponding decommissioning factor in the
depreciation rate are adjusted periodically to reflect changing price levels
and technology.
38
In compliance with a Nuclear Regulatory Commission (NRC) regulation,
Oglethorpe maintains an external trust fund to provide for a portion of the
cost of decommissioning its nuclear facilities. The NRC regulation requires
funding levels based on average expected cost to decommission only the
radioactive portions of a typical nuclear facility. Investment earnings
generated from the external trust fund increase the decommissioning fund and
interest income.
E.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 1993, 19921995, 1994 and 19911993 amounted to $49,647,000,
$55,804,000$54,588,000, $55,229,000 and
$62,349,000,$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 recorded a remaining nuclear fuel
asset of approximately $20,000,000,$16,200,000, which is being amortized to nuclear fuel
expense over the 15-year assessment period.next 12 years. Oglethorpe has also recorded, net of
sell-back, an obligation to DOE which approximated $14,000,000$13,000,000 at December
31, 1993.
F. PATRONAGE CAPITAL1995.
G. NUCLEAR DECOMMISSIONING
Oglethorpe's portion of the costs of decommissioning
co-owned nuclear facilities is estimated as follows:
...................................................................................
(DOLLARS IN THOUSANDS) Hatch Hatch Vogtle Vogtle
Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2
...................................................................................
Year of site study 1994 1994 1994 1994
Expected start date
of decommissioning 2014 2018 2027 2029
Decommissioning cost:
Discounted $ 92,000 $109,000 $ 82,000 $106,000
Undiscounted 223,000 299,000 302,000 419,000
...................................................................................
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in regulatory requirements, changes in technology, and
changes in costs of labor, materials, and equipment.
The annual provision for decommissioning for 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
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:
...................................................................................
1995 1994 1993
...................................................................................
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%
...................................................................................
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 MEMBERSHIP FEESCONSTRUCTION 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 organizedamortizing 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 operatesfully 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 cooperative. The Members paidperiod of 15 years beginning in 1995.
43
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 $195 in membership fees. Patronage capitalapproximately $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 retained net
marginamount
over the 20-year term of Oglethorpe. As providedthe leases.
In October 1989, Oglethorpe sold to GPC a 24.45% ownership interest in the
bylaws, any excess of revenue over
expenditures from operations is treatedPlant Scherer common facilities as advances of capital byrequired under the MembersPlant Scherer Purchase
and is allocatedOwnership Agreement to each of themadjust its ownership in the Scherer units.
Oglethorpe realized a gain on the basissale of their electricity purchases
from Oglethorpe.
The margin$50,600,000. RUS and patronage capital retirements policy adopted by the
OglethorpeOglethorpe's
Board of Directors approved a plan whereby this gain was deferred and was
amortized over 60 months ending in 1992 extended from 13 yearsSeptember 1994.
P. REGULATORY ASSETS AND LIABILITIES
Oglethorpe is subject to 30 years the period that each year's net marginprovisions 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 retained by Oglethorpe. Pursuantrecovered 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:
...............................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...............................................................................
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
-------- --------
-------- --------
...............................................................................
In the event that Oglethorpe is no longer subject to the previous 13-year patronage capital retirement schedule, 1978 patronage
capital assignments were retired in 1992,provisions of
Statement No. 71, Oglethorpe would be required to write off related
regulatory assets and 1977 assignments in 1991.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:
.....................................................................................
(DOLLARS IN THOUSANDS) 1995 1994
FAIR Fair
COST VALUE Cost Value
.....................................................................................
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
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
.....................................................................................
The contractual maturities of debt securities available for sale at
December 31, 1995 and 1994, regardless of their balance sheet classification,
are as follows:
.............................................................................................
(DOLLARS IN THOUSANDS) 1995 1994
FAIR Fair
COST VALUE Cost Value
.............................................................................................
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
-------- -------- -------- --------
-------- -------- -------- --------
.............................................................................................
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 new 30-year retirement schedule, no patronage capital would be returnedinterest rate swap arrangements, Oglethorpe makes payments to
the Members until 2010,counterparty based on the notional principal at a
44
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 timeare also classified as available-for-sale, are
directly added to or deducted from the 1979 patronage capital would be
returned.
G.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:
...........................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...........................................................................
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
------- -------
------- -------
...........................................................................
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 TAX ACCOUNTINGTAXES
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.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".Taxes." In adopting SFAS No. 109, Oglethorpe recorded a $13,340,000
reduction in accumulated deferred income taxes and an increase in income from
the cumulative effect of a change in accounting principle. SFAS No. 109
requires the recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been included in the
financial statements or tax returns. Deferred tax assets and liabilities are
determined based on the differences between the financial and tax bases using
enacted tax rates in effect for the year in which the differences are
expected to reverse.
A detail of the provision for income taxes in 1993, 19921995, 1994 and 19911993 is shown
as follows:
- ---------------------------------------------------------------------------...................................................................................
(DOLLARS IN THOUSANDS) 1995 1994 1993
1992 1991
- ---------------------------------------------------------------------------...................................................................................
Current
Current
Federal $ -- $ -- $ --
State -- -- 195
1,507----- ----- -------
-- --------- -------- ---------- 195
1,507 --
--------- -------- ------------- ----- -------
Deferred
Federal -- -- 1,820
4,127 17,541
State -- -- (195)
(1,668) 2,054
--------- -------- ------------- ----- -------
-- -- 1,625
2,459 19,595
--------- -------- ------------- ----- -------
Income taxes charged
to operations $ -- $ -- $ 1,820
$ 3,966 $ 19,595
--------- -------- --------
--------- -------- --------
- -------------------------------------------------------------------------------- ----- -------
----- ----- -------
...................................................................................
3945
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:
- ------------------------------------------------------------------------------...................................................................................
1995 1994 1993
1992 1991
- ------------------------------------------------------------------------------...................................................................................
Statutory federal income tax rate 35.0% 34.0% 34.0%35.0% 35.0%
Patronage exclusion (35.6%) (35.4%) (35.1%)
(21.6%) 4.3%
Other 0.6% 0.4% 0.1% 0.7% (1.8%)
Effect of increase in statutory rate 12.8% 0.0% 0.0% ---- ---- ----12.8%
------ ------ ------
Effective income tax rate 0.0% 0.0% 12.8%
13.1% 36.5%
---- ---- ----
---- ---- ----
- ------------------------------------------------------------------------------------ ------ ------
------ ------ ------
...................................................................................
The components of the net deferred tax liabilities as of December 31,
19931995 and 1994 were as follows:
- -----------------------------------------------------------------------------...........................................................................
(DOLLARS IN THOUSANDS) 1993
- -----------------------------------------------------------------------------1995 1994
...........................................................................
Deferred tax assets:
DEFERRED TAX ASSETS
Net operating losses $ 471,069538,067 $ 451,543
Member loss carryforwards 363,140342,370 366,417
Tax credits 252,680 252,701
Accounting for safe harbor leases 102,886
Tax credits 252,70186,599 98,746
Patronage exclusions available 39,1490 80,190
Accrued nuclear decommissioning expense 45,042 38,644
Accounting for asset dispositions 38,381
Accrued nuclear decommissioning
expense 29,32433,496 34,448
Other 8,002
---------
1,304,65218,277 18,061
----------- -----------
1,316,531 1,340,750
Less: Valuation allowance (252,680) (252,701)
---------
1,051,951
---------
Deferred tax liabilities:----------- -----------
1,063,851 1,088,049
----------- -----------
DEFERRED TAX LIABILITIES
Depreciation (1,068,396)(1,034,153) (1,062,233)
Accounting for debt extinguishment (34,114)(64,006) (61,003)
Other (14,951)
---------
(1,117,461)
---------(31,202) (30,323)
----------- -----------
(1,129,361) (1,153,559)
----------- -----------
Net deferred tax liabilities $ (65,510) ---------
---------
- -----------------------------------------------------------------------------$ (65,510)
----------- -----------
----------- -----------
...........................................................................
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:
- -------------------------------------------------------------...........................................................................
(DOLLARS IN THOUSANDS)
...........................................................................
Expiration Date Tax Credits NOLs
- -------------------------------------------------------------
1997 $ 11,197 $ ---
1998 6,934 ---
1999 37,206 ---
2000 3,198 ---
2001 7,264 ---
2002 130,392 146,362130,377 146,363
2003 652 253,665
2004 55,66955,663 114,285
2005 189 213,080
2006 --- 209,009
2007 --- 86,779
2008 - 102,262
-------- ----------- 94,927
2009 -- 96,394
2010 -- 77,967
---------- ----------
$ 252,701 $1,125,442
-------- ---------
-------- ---------
- -------------------------------------------------------------252,680 $1,292,469
---------- ----------
---------- ----------
...........................................................................
Based on Oglethorpe's historical taxable transactions, and the timing of the
reversal of existing temporary differences, management believesfuture 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 thethese NOLs existing at December 31, 1993 before their
respective expiration dates. However, as reflected in the above valuation
allowance, management does not believe it is more likely than not that the tax credits will not be
utilized before expiration.
During 1992 and 1991, deferred income taxes were provided for significant
timing differences between revenues and expenses for tax and financial statement
purposes. The source and deferred tax effect of these differences are summarized
as follows:
- ----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1992 1991
- ----------------------------------------------------------------------------
Excess of tax over book depreciation $ 16,524 $ 75,042
Difference in recognition of gain/loss
on asset dispositions 6,475 6,832
Difference in accounting for safe harbor leases 6,022 5,487
Accrued nuclear decommissioning expense (558) (740)
Difference in accounting for debt extinguishment 6,956 -
Adjustments to book accrued liabilities 3,514 (425)
Difference in recognition of cost of
discontinued project (532) 8,178
Other (67) (464)
Portion of the above differences not reflected
in expense due to net operating losses (35,875) (74,315)
------- -------
$ 2,459 $ 19,595
------- -------
------- -------
- ----------------------------------------------------------------------------
H. MARGIN POLICY
Oglethorpe's margin policy is based on the provision of a Times Interest
Earned Ratio (TIER) established annually by the Oglethorpe Board of Directors.
For 1993, 1992, and 1991, the margin goal was the amount required to produce a
TIER of 1.07. Oglethorpe's Board of Directors adopted a new margin and patronage
capital retirements policy in 1992. Pursuant to the new policy, the annual net
margin goal will be the amount required to produce a TIER of 1.07 each year
through 1995, 1.08 in 1996, 1.09 in 1997 and 1.10 in 1998 and thereafter.
The Oglethorpe Board of Directors adopted resolutions annually requiring
that Oglethorpe's net margins for the years 1985 through 1993 in excess of its
annual margin goals be deferred and used to mitigate rate increases associated
with Plant Vogtle. In addition, during 1986 and 1987, Oglethorpe's wholesale
electric rate to its Members provided for a one mill per kilowatt-hour charge
(Vogtle Surcharge), also to be used to mitigate the effect of Plant Vogtle on
rates. In addition, two of Oglethorpe's Members, with the concurrence of REA,
elected to increase the level of this charge for their systems during this
period.
40
Pursuant to rate actions by Oglethorpe's Board of Directors, specified
amounts of deferred margins and Vogtle Surcharge were returned in 1989 through
1993 and will be returned in 1994. A summary of deferred margins and Vogtle
Surcharge as of December 31, 1993 and 1992 is as follows:
- ---------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993 1992
- ---------------------------------------------------------------------------
Deferred margins:
1985-90 $ 113,385 $ 113,385
1991 11,703 11,703
1992 40,464 40,464
1993 5,083 -
-------- --------
170,635 165,552
Vogtle Surcharge:
1986-87 36,613 36,613
-------- --------
Subtotal 207,248 202,165
Less: Amounts returned in:
1989-90 (80,602) (80,602)
1991 (31,990) (31,990)
1992 (41,058) (41,058)
1993 (5,738) (5,738)
1994 (26,777) -
-------- --------
Balance* $ 21,083 $ 42,777
-------- --------
-------- --------
* THE PORTION RELATING TO AMOUNTS PROVIDED VOLUNTARILY BY TWO OF OGLETHORPE'S
MEMBERS WAS APPROXIMATELY $3,320,000 OF THE BALANCE AT DECEMBER 31, 1993.
- ---------------------------------------------------------------------------
I. CASH AND TEMPORARY CASH INVESTMENTS
Oglethorpe considers all temporary cash investments purchased with a
maturity of three months or less to be cash equivalents. Temporary cash
investments with maturities of more than three months are classified as other
short-term investments.
J. ENERGY COST BILLED IN EXCESS OF ACTUAL
Oglethorpe's wholesale power rate sets forth the manner in which energy
costs are to be recovered from its Members. The rate in effect for 1993 and
1992 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 were compared, on a monthly basis, to the
billed energy costs, and an adjustment to revenues was made such that energy
revenues were equal to actual energy costs. The offset to this adjustment is a
payable to or receivable from Members for over or under-collected energy costs.
The rate further provides that any cumulative over or under-collection for the
previous six-month period be utilized to adjust projected costs for the next
six-month period. Therefore, the amounts owed to Members as of December 31,
1993 and 1992 will be and have been utilized to reduce Member billings in 1994
and 1993, respectively.
2.4. 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, 19931995 are as follows:
- -----------------------------------------------------------------------------...........................................................................
YEAR ENDING DECEMBER 31, (DOLLARS IN THOUSANDS)
- -----------------------------------------------------------------------------...........................................................................
19941996 $ 33,258
1995 36,016
1996 38,14239,293
1997 35,239
1998 37,302
1999-2021 682,454
-------1999 37,890
2000 37,755
2001-2021 606,809
---------
Total minimum lease payments 862,411794,288
Less: Amount representing interest (558,953)
-------(491,819)
---------
Present value of net minimum lease payments 302,469
Less: Current portion (5,991)
---------
Long term balance $ 303,458
-------
-------
- -----------------------------------------------------------------------------296,478
---------
---------
...........................................................................
The capital leases provide that Oglethorpe's rental payments vary to the
extent of interest rate changes associated with the debt used by the lessors
to finance their purchase of undivided ownership shares in Scherer Unit No.
2. The debt of three of the lessors is financed at fixed interest rates
averaging 9.58%9.64%. As of December 31, 1993,1995, the variable interest rates of the
debt of the remaining lessor ranged from 5.93% to 8.25%8.05% for an average rate
of 7.27%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 itits rate-making treatment. Interest
expense is applied to the obligation under the capital lease; then,
amortization of the leasehold is recognized, such that interest and
amortization equal the actual rental payment. Through 1994, the level of
actual rental payments iswas such that amortization of the Scherer Unit No. 2
leasehold calculated in this manner iswas less than zero. Thereafter, the
scheduled cash rental payments increase
46
such that positive amortization of the leasehold occurs and the entire cost of
the leased asset is recovered through the rate-making process. The difference in
the amortization recognized in this manner on the statements of revenues and
expenses and the straight-line amortization of the leasehold is reflected on
Oglethorpe's balance sheets as a deferred charge.
41
In 1991 and 1992, all four of the lessors received Notices of Proposed
Adjustments from the IRS proposing adjustments to the tax benefits claimed by
these lessors in connection with their purchase and ownership of an undivided
interest in Scherer Unit No.No 2. The proposed adjustments, if ultimately upheld,
would have the effect of reducing the lessors' tax benefits resulting from the
sale and leaseback transactions. The lessors filed responses contesting the
IRS's assertions as contained in the Notices of Proposed Adjustments.
In February 1994, the IRS issued a revised Notice of
Proposed Adjustments to one of the lessors which reduced the proposed
adjustmentsadjustments. During 1995, this lessor advised Oglethorpe that it had settled
this issue on the basis of the revised Notice of Proposed Adjustments.
Oglethorpe subsequently made a lump sum indemnity payment of $362,000 to the
lessor in order to compensate for the reduction in the lessor's tax benefits
claimed by this lessor in connection with its purchaseresulting from the sale and ownership of an
undivided interest in Scherer Unit No. 2.leaseback transaction. The IRS has indicated that
it will take consistent positions with the other three lessors. If the IRS's
current positions regarding the sale and leaseback transactions were
ultimately upheld, Oglethorpe would be required to indemnify the fourother three
lessors. Oglethorpe's potential indemnification liability in this eventto the three lessors is
estimated to be approximately $1,200,000 as of February 1994.
3. FAIR VALUE OF FINANCIAL INSTRUMENTS:
A detail of the estimated fair values of Oglethorpe's financial instruments$1,150,000 as of December 31, 1993 and 1992 is as follows:
- -----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993 1992
---------------- ----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- -----------------------------------------------------------------------------
Cash and temporary
cash investments $244,173 $244,173 $275,624 $275,624
Other short-term
investments -- -- 66,165 66,165
Bond, reserve
and construction funds 110,390 112,015 163,964 164,135
Decommissioning fund 56,911 56,686 47,921 48,508
Long-term debt 4,058,251 4,525,248 4,095,796 4,564,262
- -----------------------------------------------------------------------------
Oglethorpe uses the methods and assumptions described below to estimate the
fair value of each class of financial instruments. For cash and temporary cash
investments and other short-term investments, the carrying amount approximates
fair value because of the short-term maturity of those instruments. The fair
values of bond, reserve and construction funds and the decommissioning fund are
estimated based on quoted market prices for the investments held in the
respective funds. The fair value of Oglethorpe's long-term debt is estimated
based1995. This
liability has been reflected on the quoted market prices for the same or similar issues or on the
current rates offered to Oglethorpe for debtaccompanying balance sheet as of similar maturities.
Investment in associated organizations was as follows at December 31, 1993
and 1992:
- --------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993 1992
- --------------------------------------------------------------------------------
National Rural Utilities
Cooperative Finance Corp. $ 13,476 $ 13,476
National Bank for Cooperatives 5,546 6,362
Other 101 71
---------- ----------
Total $ 19,123 $ 19,909
---------- ----------
---------- ----------
- --------------------------------------------------------------------------------
As a member of National Rural Utilities Cooperative Finance Corporation
(CFC), Oglethorpe was obligated to purchase CFC Capital Term Certificates
annually through 1984. Such certificates begin maturing in the year 2075 and
bear interest at 5%. As a borrower from the National Bank for Cooperatives
(CoBank), Oglethorpe is obligated to purchase capital stock in that bank. Under
CoBank's capitalization plan, Oglethorpe is required to maintain an investment
in the bank equal to 7%-13% of its five-year average loan volume with the bank.
The required investment of 1993 was 11.5% of Oglethorpe's five-year average loan
volume. It is not anticipated that Oglethorpe will be required to make any
additional investments during 1994. The investments in these associated
organizations are similar to compensating bank balances in that they are
required in order to maintain current financing arrangements. Accordingly, there
is no market for these investments.
4. BOND, RESERVE AND CONSTRUCTION FUNDS:
Bond, reserve and construction funds for pollution control bonds are
maintained as required by Oglethorpe's bond agreements. Bond funds serve as
payment clearing accounts, reserve funds maintain amounts equal to the maximum
annual debt service of each bond issue and construction funds hold bond proceeds
for which construction expenditures have not yet been made. As of December 31,
1993 and 1992, substantially all of the funds were invested in U.S. Government
securities.this
date.
5. LONG-TERM DEBT:
Long termLong-term debt consists of mortgage notes payable to the UnitesUnited States of
America acting through the FFB and the REA,RUS, mortgage notes issued in
conjunction with the sale by public authorities of pollution control revenue
bonds and notes payable to CoBank. Oglethorpe's headquarters facility is
pledged as securitycollateral for the CoBank headquarters note; substantially all of
the owned tangible and certain of the intangible assets of Oglethorpe are
pledged as securitycollateral for the FFB and REARUS notes, the remaining CoBank notes
and the notes issued in conjunction with the sale of pollution control
revenue bonds. The detail of the notes is included in the statements of
capitalization.
42
Oglethorpe currently has ten REA-guaranteedRUS-guaranteed FFB notes of which
$3,040,767,000$3,253,636,000 and $3,111,160,000$3,161,550,000 were outstanding at December 31, 19931995 and
1992,1994, respectively, with rates ranging from 6.61%5.67% to 10.95%10.78%.
In March 1993,January 1995, Oglethorpe entered intoprepaid two forwardFFB advances totaling $29,940,000
of principal plus a premium equal to one year's interest rate swap
arrangements obligating Oglethorpe to sell $199,690,000 of variable rate
refunding bonds in$3,163,000. The
premium will be reported as a deferred charge on the fall of 1993 and $122,740,000 of variable rate refunding
bonds in the fall of 1994, the proceeds of which, together with certain other
funds provided or to be provided by Oglethorpe, have beenbalance sheet and will
be used in
January 1994 andamortized over 22 years, the remaining life of the prepaid advances.
In January 1995, respectively,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 refund certainthe 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 previouslywere
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, 1993,1995, Oglethorpe accounted for the pending January 1994 retirement of $233,010,000 of previously issued bonds
as an in-substance defeasance. Therefore, the cash held in debt service
reserve funds, bonds payable, and the premium and loss on reacquired debt are stated as
though the event of retiring the refunded bonds had occurred in 1993.1995.
In January 1996, Oglethorpe completed note modifications pursuant to which
it repriced $89,447,000 of FFB advances. In connection with the March 1993 swap transaction,such
modification, Oglethorpe recorded
redemption premiums which, combined with unamortized transaction costs, totaled
$38,128,000. This amount has beenpaid a premium of $9,332,000. These amounts will be
reported as a deferred chargecharges on the balance sheetssheet, and is being or will be amortized over
22 years, the longest remaining life of the related new
bonds.
Pursuant to the forward interest rate swap arrangements, Oglethorpe makes
payments to the counterparty based on the notional principal at a fixed rate and
the counterparty makes payments to Oglethorpe based on the notional principal
and on the existing variable rate of the refunding bonds. The differential to
be paid or received is accrued as interest rates change and is recognized as an
adjustment to interest expense. For the fall 1993 transaction, the notional
principal was $199,690,000 and the fixed swap rate is 5.67% (the variable rate
at December 31, 1993 was 3.10%). With respect to the fall 1994 transaction,
the notional principal will be $122,740,000 and the fixed swap rate is 6.01%.
The notional principal amount is used to measure the amount of the swap
payments and does not represent additional principal due to the counterparty.
The swap arrangements extend for the life of the refunding bonds, with
reductions in the outstanding principal amounts of the refunding bonds causing
corresponding reductions in the notional amounts of the swap payments.subject advances.
The annual interest requirement for 1994,1996, based upon all debt outstanding
at December 31, 1993,1995, will be approximately $339,000,000.$290,000,000.
Maturities for the long-term debt through 19982000 are as follows:
- --------------------------------------------------------------------------------...................................................................................
(DOLLARS IN THOUSANDS) 1994 1995 1996 1997 1998 - --------------------------------------------------------------------------------1999 2000
...................................................................................
FFB and REA $56,224 $52,095 $57,725 $63,625 $69,008RUS $ 82,026 $ 77,499 $ 82,744 $ 86,743 $ 94,897
CoBank 460 468 478 489 502 1978 Bonds 780 830 880 930 980516 532
1982 Bonds 4,985 5,485 6,050-- 6,675 -- 1984 Bonds 6,540 7,160 7,850 8,640 9,520
1984B Bonds 2,500 2,730 3,000 3,300 -- 1985 Bonds 2,685 2,915 3,170 3,445 3,760--
1992A Bonds 4,470 4,640 4,840-- 5,070 5,330 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 -- -- -- -- 2,085
1993A2,240
1994B Bonds -- -- -- -- 2,265
------- ------- ------- ------- -------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 $78,644 $76,323 $83,993 $92,174 $93,450
------- ------- ------- ------- -------
------- ------- ------- ------- -------
- -----------------------------------------------------------------------------$ 89,675 $104,878 $106,359 $113,229 $126,499
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
...................................................................................
Oglethorpe has a commercial paper program under which it may issue commercial
paper not to exceed a $355,000,000$300,000,000 balance outstanding at any time. The
commercial paper may be used as a source of short-term funds and is not
intended for any specific purpose. Oglethorpe's commercial paper is backed
100% by a committed linelines of credit provided by a group of banks for which Trust
Company Bank (Trust Company) acts as agent.banks. As of
December 31, 19931995 and 1992,1994, no commercial paper was outstanding.
Oglethorpe has arranged for uncommitted short-term lines of
47
credit with CoBank and CFC and a committed line of credit with Trust Company.SunTrust Bank,
Atlanta (SunTrust). The CoBank line amounts to $70,000,000; the CFC line
amounts to $50,000,000; and the Trust
CompanySunTrust 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 $425,000,000$370,000,000 due to certain
restrictions contained in the CFC and Trust
CompanySunTrust line of credit agreements. No
balance was outstanding on any of these three lines of credit was outstanding at either
December 31, 19931995 or 1992.
In January 1994, Oglethorpe completed a note modification pursuant to which
it repriced $590,909,000 of FFB advances. In connection with such modification,
Oglethorpe paid a premium of $50,745,000. This amount will be reported as a
deferred charge on the balance sheets and will be amortized over 22 years, the
longest remaining life of the subject advances.
43
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, 19931995 is as follows:
- -----------------------------------------------------------------------------...................................................................................
(DOLLARS IN THOUSANDS) ACCUMULATED
PLANT INVESTMENT DEPRECIATION
- -----------------------------------------------------------------------------Accumulated
Plant Investment Depreciation
...................................................................................
In-service:In-service
Owned property:
VOGTLE UNITS NO.property
Vogtle Units No. 1 & NO.No. 2
(NUCLEAR - 30% OWNERSHIP) $2,779,362 $ 2,773,510 $ 453,918
HATCH UNITS NO.594,553
Hatch Units No. 1 & NO.No. 2
(NUCLEAR - 30% OWNERSHIP) 510,670 173,992
WANSLEY UNITS NO.516,154 198,082
Wansley Units No. 1 & NO.No. 2
(FOSSIL - 30% OWNERSHIP) 165,977 78,057
SCHERER UNIT NO.171,453 82,842
Scherer Unit No. 1
(FOSSIL - 60% OWNERSHIP) 427,377 165,387
TALLASSEE (HARRISON DAM)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) 9,277 1,286
WANSLEY9,282 1,641
Wansley (COMBUSTION TURBINE-TURBINE -
30% OWNERSHIP) 3,665 955
TRANSMISSION AND
DISTRIBUTION PLANT 749,366 143,123
OTHER 108,972 27,1461,181
Transmission and distribution plant 823,087 176,553
Other 117,794 33,796
Property under capital lease:
SCHERER UNIT NO.lease
Scherer Unit No. 2
(FOSSIL - 60% LEASEHOLD) 298,925 66,432
----------- -----------299,113 83,067
---------- ----------
Total in-service $ 5,047,739 $ 1,110,296
----------- -----------
----------- -----------$5,699,213 $1,362,431
---------- ----------
---------- ----------
Construction work in progress:
ROCKY MOUNTAIN
(HYDRO - 70% OWNERSHIP*)progress
Generation improvements $ 414,187
GENERATION IMPROVEMENTS 19,067
TRANSMISSION AND
DISTRIBUTION PLANT 16,287
OTHER 1,424
-----------17,021
Transmission and distribution plant 18,258
Other 474
----------
Total construction work in progress $ 450,965
-----------
-----------
* ESTIMATED OWNERSHIP PERCENTAGE AS OF DECEMBER 31, 1993. OWNERSHIP PERCENTAGE
AT PROJECT COMPLETION IS EXPECTED TO BE APPROXIMATELY 75%.
- -----------------------------------------------------------------------------35,753
----------
----------
...................................................................................
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 construction was commenced by GPC.
Under the agreements, GPC retained its current investment in Rocky Mountain. TheMountain
with the ultimate ownership interests of Oglethorpe and GPC in the facility will be
based on the ratio of each party's direct construction costs to total project
direct construction costs with certain adjustments.
It is expected
thatOn June 1, 1995, Unit 3 and the completed Unit Common facilities were
declared to be in commercial operation by Oglethorpe. Unit 2 and Unit 1 were
declared to be in commercial operation on June 19, 1995 and July 24, 1995,
respectively. In accordance with the Rocky Mountain agreements, the final
ownership interests of Oglethorpe and GPC in Rocky Mountain atis 74.6% and
25.4%, respectively. The final ownership interests in the project
completion will be
approximately 75% and 25%, respectively. Rocky Mountain is
subjectapplied to a license issued by FERC to Oglethorpe and GPC. This license requires
that construction be completed by June 1, 1996. The current schedule anticipates
commercial operation in early 1995. Rocky Mountain was approximately 90%
complete as of December 31, 1993.
Oglethorpe is financing its share of Rocky Mountain from the proceeds of an
REA-guaranteed loan funded through the FFB. As of December 31, 1993, a total of
approximately $459,000,000 remained available to be drawn as permanent financing
for Rocky Mountain. Such amount is considered more than adequate by Oglethorpe
to complete the project. The obligation to advance funds under the FFB loan
commitment, however, is subject to certain conditions, including the requirement
that Oglethorpe maintain an annual TIER of at least 1.0 and that the REA shall
not have determined that there has occurred any material adverse change in the
assets, liabilities, operations, or financial condition of Oglethorpe or any
circumstances involving the nature or operation of the business of Oglethorpe.
In management's opinion, no such material adverse change has occurred.all future capital costs.
Oglethorpe is engaged in a continuous construction program and, as of
December 31, 1993,1995, estimates property additions (including capitalized
interest) to be approximately $284,000,000 in 1994, $204,000,000 in 1995 and $148,000,000$113,000,000 in 1996, $106,000,000 in 1997 and
$103,000,000 in 1998, primarily for construction of Rocky Mountain and replacements and additions to generation
and transmission facilities.
Primarily as a result of its ownership of a majority interest in Rocky
Mountain, Oglethorpe has determined that the Pickens County Pumped Storage
Hydroelectric Project is not needed within its present planning horizon.
Accordingly, Oglethorpe is amortizing the accumulated project costs in excess of
the value of the land purchased. The remaining unamortized project costs of
approximately $18,314,000 are reflected as deferred charges on the accompanying
balance sheets. Oglethorpe's Board of Directors has authorized that these
projects costs be amortized and fully recovered through future rates over a
period of 15 years beginning in 1992.
In April 1992, Oglethorpe sold to three purchasers certain of the income
tax benefits associated with Scherer Unit No. 1 and related common facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act of
1981. Oglethorpe received a total of approximately $110,000,000 from the safe
harbor lease transactions. Oglethorpe accounts for the proceeds as a deferred
credit, sale of income tax benefits, and is amortizing the amount over the 20-
year term of the leases.
In October 1989, Oglethorpe sold to GPC a 24.45% ownership interest in the
Plant Scherer common facilities as required under the Plant Scherer Purchase and
Ownership Agreement to adjust its ownership in the Scherer units. Oglethorpe
realized a gain on the sale of $50,600,000. The REA and Oglethorpe's Board of
Directors approved a plan whereby this gain was deferred and is being amortized
over 60 months beginning in October 1989.
44
Oglethorpe's proportionate share of direct expenses of joint operation of the
above plants is included in the corresponding operating expense captions (e.g.,
fuel, production or depreciation) on the accompanying statements of revenues and
expenses.
7. INVENTORIES:
Oglethorpe maintains inventories of fossil fuels for its generation plant
and spare parts for certain of its generation and transmission plant. These
inventories are stated at weighted average cost on the accompanying balance
sheets.
For its co-owned generating plants, Oglethorpe accounts for inventories on
the basis of information furnished by its operating agent, GPC. GPC has
historically accounted for spare parts at its generating plants on an expensed-
as-purchased basis. Prior to the commercial operation of Vogtle Unit No. 1 in
1987, GPC established a spare parts inventory for that generating facility and
used an expensed-as-consumed method of inventory accounting. Subsequently, the
spare parts inventories at Plants Hatch, Wansley and Scherer were converted to
an expensed-as-consumed method. In connection with these conversions, other
income totaling $18,877,000 was recorded by Oglethorpe in 1988 and 1989.
In 1992, GPC completed a study the objective of which was to determine the
original accounting for spare parts inventory at all of its generating plants,
including Plants Hatch, Wansley and Scherer. As a result of this study,
Oglethorpe recorded an adjustment of $4,827,000 to the original conversion which
reduced other income and plant investment.
A detail of Oglethorpe's investment in inventories at December 31, 1993 and
1992 is as follows:
- -----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS) 1993 1992
- -----------------------------------------------------------------------------
Fossil fuels:
Plant Scherer $ 13,481 $ 15,366
Plant Wansley 2,264 7,733
Plant Wansley Combustion Turbine 96 113
Other generation plant fuel oils 361 121
------- -------
Total fossil fuels 16,202 23,333
------- -------
Spare parts:
Plant Vogtle 23,173 24,892
Plant Hatch 22,947 18,125
Plant Wansley 8,415 8,070
Plant Scherer 5,947 5,513
Plant Tallassee 86 86
Transmission plant 9,672 13,606
General plant 26 15
------- -------
Total spare parts 70,266 70,307
------- -------
Total inventories $ 86,468 $ 93,640
------- -------
------- -------
- -----------------------------------------------------------------------------
8. EMPLOYEE BENEFIT PLANS:
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, $362,000 in 1992 and $1,113,000 in 1991.1993. For 1992,1995,
pension cost was reducedincreased by $539,000 by a net gain from a plan curtailment.$912,000 related to termination benefits. The
plan
curtailmenttermination benefits resulted from a workforce reductionan early retirement program undertaken in
the secondfourth quarter of 1992.1995. Plan benefits are based on years of service and
the employee's compensation during the last ten years of employment.
Oglethorpe's funding policy is to contribute annually an amount not less than
the minimum required by the Internal Revenue Code and not more than the
maximum tax deductible amount.
The plan's funded status and pension cost recognized in 1995, 1994 and 1993 is shown as
follows:
...................................................................................
(DOLLARS IN THOUSANDS) 1995 1994 1993
...................................................................................
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
------- ------- -------
------- ------- -------
...................................................................................
48
The plan's funded status in Oglethorpe's financial statements as of December 31,
19931995 and 19921994 were as follows:
- -----------------------------------------------------------------------------...........................................................................
(DOLLARS IN THOUSANDS) 1993 1992
- -----------------------------------------------------------------------------1995 1994
...........................................................................
Actuarial present value of accumulated
plan benefits:benefits
Vested $ 5,2376,868 $ 3,3855,281
Nonvested 407 344
------ ------591 380
-------- --------
$ 5,6447,459 $ 3,729
------ ------
------ ------5,661
-------- --------
-------- --------
Projected benefit obligation $(9,920) $(6,973)$(12,326) $ (9,276)
Plan assets at fair value 6,911 6,364
------ ------7,760 7,282
-------- --------
Projected benefit obligation in excess of
plan assets (3,009) (609)(4,566) (1,994)
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions 390 (1,013)223 (861)
Prior service cost not yet recognized
in net periodic pension cost 693 747548 598
Unrecognized net asset at transition date
being recognized over 19 years (145) (158)
------ ------(121) (133)
-------- --------
Pension accrual $(2,071) $(1,033)
------ ------
------ ------
Pension cost was comprised of the
following:
Service cost -- benefits earned
during the year $ 884(3,916) $ 854
Interest cost on projected benefit
obligation 617 535
Actual return on plan assets (698) (424)
Net amortization and deferral 247 (64)
Net gain from a plan curtailment (12) (539)
------ ------
Net pension cost $ 1,038 $ 362
------ ------
------ ------
- -----------------------------------------------------------------------------(2,390)
-------- --------
-------- --------
...........................................................................
The discount rate and rate of increase in future compensation levels used
in determining the actuarial present value of the projected benefit
obligations shown above were 7.5%7.25% and 5.0% in 1993,1995, and 8.5% and 5.5%5.0% in
1992,1994, respectively. The expected long-term rate of return on plan assets was
8.5% in 1995 and 8% in 19931994 and 1992,1993, and the discount rate used in
determining the pension expense was 8.5% in 19931995, 7.5% in 1994 and 1992.
45
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 10%16% of his annual compensation. Oglethorpe will match the employee's
contribution up to one-half of the first 6% of the employee's annual
compensation, as long as there is sufficient net margin to do so.
Oglethorpe's contributions to the plan were approximately $589,000 in 1995,
$565,000 in 1994 and $503,000 in 1993,
$503,000 in 1992 and $491,000 in 1991.
In December 1990, the FASB issued Statement No. 106 on postretirement
benefits other than pensions. The new statement requires the accrual of the
expected cost of such benefits during the employees' years of service.
Oglethorpe has no postretirement benefits other than pensions available to
retirees.
9.1993.
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 $8,600,000$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 with American Nuclear Insurersunder NEIL II and Mutual Atomic Energy Liability
Underwriters,NEIL III, which provide insurance to
cover decontamination, debris removal and premature decommissioning as well
as excess property damage to nuclear generating facilities of up tofor an additional
$2,250,000,000 for losses in excess of the $500,000,000 NML coverage
described above. Under the NEIL policy,policies, members are subject to retroactive
assessments in proportion to their participation if losses exceed the
accumulated funds available to the insurer under the policy. The portion of
the current maximum annual assessment for GPC that would be payable by
Oglethorpe, based on ownership share adjusted for sell-back, is limited to
approximately $8,000,000 for each nuclear incident.$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 $9,400,000,000,$8,900,000,000, which
amount is to be covered by private insurance and agreements of indemnity with
the NRC. Such private insurance (in the amount of $200,000,000 for each
plant, the maximum amount currently available) is carried by GPC for the
benefit of all the co-owners of Plants Hatch and Vogtle. Agreements of
indemnity have been entered into by and between each of the co-owners and the
NRC. In the event of a nuclear incident involving any commercial nuclear
facility in the country involving total public liability in excess of
$200,000,000, a licensee of a nuclear power plant could be assessed a
deferred premium of up to $79,275,000 per incident for each licensed reactor
operated by it, but not more than $10,000,000 per reactor per incident to be
paid in a calendar year. On the basis of its sell-back adjusted ownership
interest in four nuclear reactors, Oglethorpe could be assessed a maximum of
$89,320,000$95,130,000 per incident, but not more than $11,270,000$12,000,000 in any one year.
Oglethorpe participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, Oglethorpe could be subject to a total
maximum assessment of $3,750,000.
10.$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
August 31, 1997. Effective September 1, 1997, Oglethorpe will purchase 750 MW
of capacity through the period ending December 31, 2001,2003, 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.
The EPI
contract is subject to approval by REA.
Oglethorpe has a contract with Hartwell Energy Limited Partnership (Hartwell), a partnership 50% owned by Destec Energy, Inc. and 50% owned by
American National Power, Inc., a subsidiary of National Power, PLC, for the
purchase of approximately 300 MW of capacity from two 150 MW gas-fired turbine
generating units, now under construction, for a 25-year period commencing
no
later than Junein April 1994.
Oglethorpe has entered into a short-term seasonal power purchase agreement
with Florida Power Corporation. Under the termsagreement, Oglethorpe will purchase
50 MW of this contract, Oglethorpe does not have
responsibilitycapacity on a take-or-pay basis for constructing or financing this project.
46
the period June 1, 1997 through
September 30, 1997 and 275 MW for the period June 1, 1998 through September
30, 1998.
As of December 31, 1993,1995, 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:
- --------------------------------------------------------------------------------...........................................................................
Year Ending December 31.31, (dollars in thousands)
- --------------------------------------------------------------------------------...........................................................................
19941996 $ 140,009
1995 150,956
1996 154,976149,835
1997 159,296130,843
1998 163,311
- --------------------------------------------------------------------------------119,948
1999 118,061
2000 121,179
...........................................................................
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, $192,321,0001993.
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 1992an 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 $88,500,000related changes in 1991.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 19931995 and 19921994 is as follows:
- --------------------------------------------------------------------------------...........................................................................
First Second Third Fourth
(dollars in thousands)(DOLLARS IN THOUSANDS) Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
1993...........................................................................
1995
Operating revenues $272,143 $283,319 $284,737 $260,461$257,547 $281,228 $317,536 $293,250
Operating margin 93,807 85,945 76,515 68,02568,682 82,048 82,949 74,998
Net margin 30,090 10,020 (43) (14,346)
19928,462 20,292 10,656 (17,152)
1994
Operating revenues $260,817 $272,307 $290,845 $260,794$267,618 $263,035 $266,818 $258,611
Operating margin 97,630 91,331 93,455 92,37581,882 75,704 68,087 61,734
Net margin 21,083 15,899 20,387 (29,897)
- --------------------------------------------------------------------------------20,184 13,511 4,386 (14,999)
...........................................................................
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 marginmargins for the fourth quarter of 1993 was1995 and 1994 were
primarily attributable to the
deferral of excess margins and to the incurrence of certain non-recurring
expenses. The negative net margin for the same period of 1992 was primarily due to the deferral of excess margins. For a discussion of
the amounts of excess margins deferred, see Note 1.
4750
REPORT OF MANAGEMENT
The management of Oglethorpe Power Corporation has prepared this report
and is responsible for the financial statements and related information.
These statements were prepared in accordance with generally accepted
accounting principles appropriate in the circumstances and necessarily
include amounts that are based on best estimates and judgementsjudgments of management.
Financial information throughout this annual report is consistent with the
financial statements.
Oglethorpe maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and
records reflect only authorized transactions. Limitations exist in any system
of internal control based upon the recognition that the cost of the system
should not exceed its benefits. Oglethorpe believes that its system of
internal accounting control, together with the internal auditing function,
maintains appropriate cost/benefit relations.
Oglethorpe's system of internal controls is evaluated on an ongoing basis
by its qualified internal audit staff. The Corporation's independent public
accountants (Arthur Andersen(Coopers & Co.Lybrand L.L.P.) also consider certain elements of the
internal control system in order to determine their auditing procedures for
the purpose of expressing an opinion on the financial statements.
Arthur AndersenCoopers & Co.Lybrand L.L.P. also provides an objective assessment of how well
management meets its responsibility for fair financial reporting. Management
believes that its policies and procedures provide reasonable assurance that
Oglethorpe's operations are conducted with a high standard of business
ethics. In management's opinion, the financial statements present fairly, in
all material respects, the financial position, results of operations, and
cash flowflows of Oglethorpe Power Corporation.
/s/T.D. Kilgore
T.D.T. D. Kilgore
President and Chief Executive Officer
/s/Eugen Heckl
Eugen Heckl
Senior Vice President and
Chief Financial Officer
REPORT OF INDEPENDENT
PUBLIC ACCOUNTANTS
To the Board of Directors of Oglethorpe Power Corporation:
We have audited the accompanying balance sheetssheet and statementsstatement of
capitalization of Oglethorpe Power Corporation (a Georgia corporation) as of
December 31, 1993 and 19921995 and the related statements of revenues and expenses,
patronage capital, and cash flows for each of the three years in the period
ended December 31, 1993.year then ended. These financial
statements and the schedules referred
to below are the responsibility of Oglethorpe's management. Our
responsibility is to express an opinion on these financial statements and schedules based
on our audits.audit.
We conducted our auditsaudit in accordance with generally accepted auditing
standards. Those standardstandards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includedincludes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our 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.
51
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 (pages 33 through 47) referred to above present fairly,
in all material respects, the financial position of Oglethorpe Power
Corporation as of December 31, 1993 and 19921994 and the results of its operations and its
cash flows for each of the threetwo years in the period ended December 31, 19931994 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 Power Corporation changed
its method of accounting for income taxes.
Our audits were made for the purpose of forming an opinion on the basic
financial statements taken as a whole. The schedules listed in the index in Item
14 are presented for purposes of complying with the Securities and Exchange
Commission's rules and are not part of the basic financial statements. These
schedules have been subjected to the auditing procedures applied in the audits
of the basic financial statements and, in our opinion, fairly state in all
material respects the financial data required to be set forth therein in
relation to the basic financial statements taken as a whole.
/s/Arthur Andersen & Co.
Arthur Andersen & Co.LLP
Atlanta, Georgia,
February 11, 1994.
4824, 1995.
52
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)(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. Two of these Committees, the
External Affairs Committee and the Human Resources Management Committee, are
joint committees of Oglethorpe and Georgia Electric Membership Corporation
("GEMC"), an affiliated trade organization, and include directors of GEMC. Special committees, as
deemed necessary, are also appointed by the Chairman of the Board or the
Board of Directors. Committee recommendations and management
recommendations, subject to the approval of the Board of Directors, determine
the policies and activities of Oglethorpe.
The Directors and Alternate Directors of Oglethorpe are as follows:
ALTAMAHA EMC
Jmon Warnock--Director, age 68,70, 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 1995.1998. 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 47,49, 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 1995.1998.
Mr. Musgrove is a Director of Montgomery County Bankshares in Ailey, Georgia.
AMICALOLA EMC
Charles R. Fendley--Director, age 48,50, is a Vice-PresidentVice President of Jasper
Yarn Processing, Inc., which processes yarn. He has served on the Board of
Directors of Oglethorpe since November 1993, with his present term to expire
in March 1995.1998. 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. ForDirector, 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 descriptionmember of the
Finance Committee. Mr. Dean's
backgroundDean previously served on Oglethorpe's Operations
Review Committee and experience, see "IdentificationExecutive Committee and served as Secretary-Treasurer of
Executive OfficersOglethorpe 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 Senior
Executives" below.
49North Georgia Certified Development Corporation.
53
CANOOCHEE EMC
George C. Martin--Director, age 76,78, 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 1995.1998. From March 1978 to March 1984, he
served as Vice President of Oglethorpe.
Donald F. Kennedy--Alternate Director, age 64,66, 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 1995. He is a member of the
GEMC/Oglethorpe External Affairs Committee.1998. Mr.
Kennedy is also a Director of the Tattnall Bank in Reidsville, Georgia.
CARROLL EMC
J. G. McCalmon--Director, age 76,78, 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 1996.1999. He currently serves as Vice Chairman
of the Human Resources Management Committee. He is Chairman of the Board of
Carroll EMC. Mr. McCalmon is also a
Directorserves on the Boards of Directors of GEMC,
a Director of the Farm Bureau, a Director of Carroll County Sales Barn, and a Director of the Carroll County Chamber
of Commerce.
Gary M. Bullock--Alternate Director, age 52, is PresidentDirector. For a description of Mr.
Bullock's background and Chiefexperience, see "Identification of Executive
Officer of Carroll EMC. He has served as an Alternate Director of
Oglethorpe since June 1978,Officers and his present term will expire in March 1996. He
is a member of the Operations Committee. Mr. Bullock is also the Secretary of
Southeastern Data Cooperative, Inc., a member of the Institute of Electrical and
Electronic Engineers, a Trustee for the GEMC Workers' Compensation Fund, a
Director for the Georgia Council of Farmer Cooperatives, a Director of the
Carroll County Chamber of Commerce, and a Director of Carrollton Federal Savings
& Loan Association in Carrollton, Georgia.Senior Executives" below.
CENTRAL GEORGIA EMC
D. A. Robinson, III--Director, age 53,55, 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 1995.1998.
He is a member of the Transmission Committee. Mr. Robinson serves as
Secretary-Treasurer of Central Georgia EMC.
George L. Weaver--Alternate Director, age 46,48, 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 1995.1998. He is currently a member of the OperationsFinance Committee. He
is also a DirectorVice 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 GA,Georgia, N.A.
COASTAL EMC
James E. Estes--Director, age 58,60, has served on the Board of
Directors of Oglethorpe since March 1982, with his present term to expire in
March 1994.1997. 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. Additionally, he worksMr. Estes operates
Estes Property Management, a commercial real estate management service in
avionic maintenance for
Georgia Air National Guard,Richmond Hill, Georgia; is President of Ways Company, Inc., a real estate
development company in Richmond Hill, Georgia,Georgia; and is a proprietor of Estes Tax
Service, an income tax service in Richmond Hill, Georgia.
Wayne Collins--Alternate Director, age 43,45, 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
1994.
50
1997.
COBB EMC
Larry N. Chadwick--Director, age 53,55, 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 1995.1998.
He is currently a member of the Generation Committee. Mr. Chadwick is
Chairman of the Board of Cobb EMC.
He is Chairman of the Operations Committee.54
Dwight Brown--Alternate Director, age 48,50, 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 1995.1998. Mr. Brown currently serves on the Restructuring Advisory
Committee.
COLQUITT EMC
Simmie King--Director, age 50,52, 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 1996.1999.
R. L. Gaston--Alternate Director, age 46,48, 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 1996.
He is1999. Mr. Gaston currently a member ofserves on the Planning and ConstructionRestructuring Advisory
Committee.
COWETA-FAYETTE EMC
W. F. Farr--Director, age 81,83, is a banker. He has served on the
Board of Directors of Oglethorpe since March 1975, with his present term to
expire in March 1995.1998. He is currently a member of the Finance Committee and
previously served as Chairman of the GEMC/Oglethorpe Human Resources Management Committee.
He has been President of Coweta-Fayette EMC since 1974. He previously served
as President of the Fayette State Bank in Peachtree City, Georgia and as a
Director and Consultant for Citizens and Southern National Bank, South Metro
Board in Atlanta, Georgia. Since June 1985, heMr. Farr has been the owner and
President of Pioneer Financial Associates, Inc. in Peachtree City, Georgia.
Michael C. Whiteside--Alternate Director, age 51,53, 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 1995.
He is currently a member of Oglethorpe's Planning and Construction Committee.1998.
EXCELSIOR EMC
Vacant--Director
Gary T. Drake--Alternate Director, age 45,47, 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 1994.1997. He was
Secretary-Treasurer of Oglethorpe from March 1984 through March 1989. He is
currently a member of the OperationsGeneration Committee. Mr. Drake is also a Director
of GEMC and a Director of Pineland State Bank in Metter, Georgia.GEMC.
FLINT EMC
Jeff S. Pierce, Jr.--Director, age 62,64, has served on the Board of
Directors of Oglethorpe since June 1992, with his present term to expire in
March 1994.1997. He is a member of the Executive Committee. He has served as a
Director of Flint EMC since 1964. HeMr. 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 57,60, 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 1994.1997. He is currently a member of the Planning and Construction Committee of Oglethorpe and
51Transmission Committee.
55
Chairman of the GEMC/Oglethorpe External Affairs Committee. Mr. Smith is also
the Chairman of the Board of the Food and Energy Council.
GRADY EMC
Donald C. Cooper--Director, age 63,65, 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
1996.1999. He is currently a member of the Generation Committee.
Thomas A. Rosser--Alternate Director, age 46,48, 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 1996.
Mr. Rosser is also a Director of the Cairo Banking Company in Cairo, Georgia.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 57,59, 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 1995.1998. 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
Herbert Church--Director,Ray Meaders--Director, age 57,72, is the owner and operator of a logging contractor.farm
in Cleveland, Georgia. He has served on
the Board of Directorsas Director of Oglethorpe since August
1991,1995, with his present term to expire in March 1996.1999. He has beenis currently a
member of the Marketing Committee. Mr. Meaders is also a Director of
Habersham EMC since 1977.EMC.
William E. Canup--Alternate Director, age 58,60, 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 1996.1999.
HART EMC
Mac F. Oglesby--Director, age 61,63, 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 1994.1997. He is
currently a member of the PlanningMarketing Committee and Construction Committee of Oglethorpe. He alsothe Wholesale Power
Contract Oversight Committee. Mr. Oglesby was a U.S. Postal Service Rural
Carrier for 30 years.
Grooms Johnson--Alternate Director, age 64,66, 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 1994.1997.
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 42,44, 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 1995.1998. He is a memberChairman and past Vice Chairman of the
Finance Committee and also serves on the Restructuring Advisory Committee.
Mr. Crenshaw was Office Manager of Oglethorpe.
52Irwin EMC from 1974 to 1988.
56
JACKSON EMC
E. L. McLocklin--Director, age 81,83, 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 1996.1999. Mr. McLocklin is currently a member of the Marketing Committee.
Randall Pugh--Alternate Director, age 50,52, 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 1996.1999. He is currently the Chairmana 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 Gainesville,Jefferson, Georgia.
JEFFERSON EMC
Sam Rabun--Director, age 62,64, 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 1996.1999. He is currently a member of the Executive
Committee. Mr. Rabun is the President of Jefferson EMC.
Ralph E. Lewis--AlternateKenneth Cook--Alternate Director, age 49, has beenis the Executive Vice
President and General Manager of Jefferson EMC since 1979.EMC. He has served as an Alternatethe 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 1979,February 1996, with his present term to expire
in March 1996.1999. He is also Vice
Presidentserved on the Board of Directors of Little Ocmulgee EMC
from 1979 to 1986 and on the GEMC Workers' Compensation Fund.Board of Directors of Oglethorpe from 1982 to
1986.
LAMAR EMC
E. J. Martin, Jr.--Director, age 66,68, 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 1994.1997.
He is currently a member of the
GEMC/Oglethorpe Human Resources Management Committee. Mr.
Martin is the President of Lamar EMC and a Director of GEMC.
J. Raleigh Henry--Alternate Director, age 43,45, 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 1994.1997.
LITTLE OCMULGEE EMC
J. D. Williams--Director,Jim M. Knight--Director, age 81,60, is currently retired.owner and manager of Knight
Farms. He has served on the Board of Directors of Oglethorpe since March 1986,April
1994, with his present term to expire in March 1994. He is a member of Oglethorpe's Planning and Construction
Committee. He previously served as President, then as Vice President of Little
Ocmulgee EMC.1997. Mr. WilliamsKnight is also a
Director of Security State Bank in McRae,
Georgia, and a Director of Farmers State Bank in Dublin, Georgia.Little Ocmulgee EMC.
A. Arnold Horton--Alternate Director, age 47,49, 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 1994.1997. Mr. Horton is a member of the
Transmission Committee.
MIDDLE GEORGIA EMC
Ronnie Fleeman--Director, age 59,61, is a self-employed land and
timber developer. He has served on the Board of Directors of Oglethorpe
since 1990. His1990, with his present term as a Director willto expire in March 1995. He is a member of the
GEMC/Oglethorpe Human Resources Management Committee.1998.
Charles Hugh Richardson--Alternate Director, age 40,42, 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
53
from
September 1976 to January 1983, he was Manager of Engineering at Middle
Georgia EMC. He has served as an Alternate Director of Oglethorpe since
1983, with his present term to expire in March 1995.1998.
57
MITCHELL EMC
D. Lamar Cooper--Director, age 58,60, operates a dairy farm. He has
served on the Board of Directors of Oglethorpe since September 1974. His1974, with his
present term as a
Director willto expire in March 1996.1999. He is currently a member of the
Operations Committee
of Oglethorpe.
Gerald Freehling--AlternateGeneration Committee.
Edward A. Pritchett--Alternate Director, age 50,49, has beenserved as
General Manager of Mitchell EMC since September 1987.1995. Since that time he has
served as an
Alternate Director of Oglethorpe. HisOglethorpe, with his present term expiresto expire
in March 1996. He
previously1999. Prior to that time, Mr. Pritchett served as Assistant General
Manager, Director of Steuben Rural Electric Cooperative in
Bath, New York.Finance and Administrative Services and Supervisor of
Data Processing for Mitchell EMC.
OCMULGEE EMC
Barry H. Martin--Director, age 45,47, is a farmer. He has served on
the Board of Directors of Oglethorpe since March 1983. His1983, with his present term
as a Director
expiresto expire in March 1994.1997. Mr. Martin is the President of Ocmulgee EMC.
Dennis Grenade--Alternate Director, age 53,55, 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, andwith his present term expiresto
expire in March 1994.1997. He is a member of the FinanceTransmission Committee.
OCONEE EMC
John B. Floyd, Jr.--Director, age 51,53, has served on the Board of
Directors of Oglethorpe since March 1980, with his present term to expire in
March 1996.1999. He is currently a member of the FinanceHuman Resources Management
Committee. HeMr. Floyd is also the Vice Chairman of the Board of Oconee EMC and is a Director of CFC. Mr. Floyd also serves as First
Vice President of The Four County Bank, as Vice President of The Four County
Insurance Agency, Inc., and as President of Twiggs Gin, Inc., a home
construction company in Allentown, Georgia.EMC.
Preston L. Johnson--Alternate Director, age 59,61, 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 1996.1999. He was Secretary-Treasurer of Oglethorpe from September 1974
to March 1984.
OKEFENOKE RURAL EMC
Steve Rawl, Sr.--Director, age 47,49, 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 1994.1997. He is
alsocurrently a Directormember of GEMC.the Finance Committee.
W. Don Holland--Alternate Director, age 43,45, 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 1994.1997. He was formerly
General Manager of Little Ocmulgee EMC. He is currently Chairman of the
PlanningTransmission Committee and Constructionserves on the Restructuring Advisory Committee of Oglethorpe.and
the Wholesale Power Contract Oversight Committee.
PATAULA EMC
James Grubbs--Director, age 71,73, 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.
His1983, with his present term as a Director willto expire in March 1996. He1999. Mr. Grubbs
is a member of the Finance Committee of Oglethorpe.
54
Transmission Committee.
Gary W. Wyatt--Director,Wyatt--Alternate Director, age 41,43, 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 1996.1999. 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.
58
PLANTERS EMC
Sammy M. Jenkins--Director, age 67,69, 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 1994. He is Vice President of Planters EMC.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 58,60, 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 1994.1997.
He is currently a member of the Operations Committee of Oglethorpe.Marketing Committee.
RAYLE EMC
J. M. Sherrer--Director, age 58,60, 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
1994.1997.
Wayne Poss--Alternate Director, age 48,50, 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
toof Oglethorpe since February 1993, with his present term to expire in March
1994.1997. He is currently a member of the GEMC/Oglethorpe External AffairsGeneration Committee.
SATILLA RURAL EMC
Jack D. Vickers--Director, age 76,78, 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. His1975, with his present term willto expire in March 1994.1997.
R. Lehman Lanier--Alternate Director, age 74,76, is President and
Chief Executive Officer of Satilla Rural EMC. He has served as an Alternate
Director of Oglethorpe since September 1974, andwith his present term expiresto expire
in March 1994.1997. He is currently a member of the Operations Committee of Oglethorpe. HeGeneration Committee. Mr.
Lanier is also a Director of Southeastern Data Cooperative, Inc.
SAWNEE EMC
C. W. Cox, Jr.--Director, age 66,68, 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 1994. He1997. Mr. Cox is currently a member of the
Planning and ConstructionFinance Committee.
Michael A. Goodroe--Alternate Director, age 37,39, 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
1994.1997. He is a member of the GEMC/Oglethorpe External AffairsTransmission Committee.
SLASH PINE EMC
Johnnie Crumbley--Director, age 71,73, 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 1996.1999. He is also a Director of GEMC.
Edward Teston--Alternate Director, age 59,61, 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 1996.
55
1999.
SNAPPING SHOALS EMC
Jarnett W. Wigington--Director, age 61,63, is a self-employed
wallpapering contractor. He has served on the Board of Directors of
Oglethorpe since 1990.
His1990, with his present term expiresto expire in March 1994. He is a member of the Executive
Committee of Oglethorpe.
J. E. Robinson--Alternate1997.
59
Randall G. Meadows--Alternate Director, age 74,51, is President, CheifPresident/Chief
Executive Officer and Officer/Manager of Snapping Shoals EMC. He has been Manager ofpreviously served as
Executive Vice President/Chief Operating Officer for Snapping Shoals EMC since 1953.EMC. He
has served as an Alternate Director of Oglethorpe since September 1974,August 1995, with his
present term to expire in March 1994.1997. Mr. Robinson is also a Director ofMeadows currently serves on the
First National Bank of Newton County.Restructuring Advisory Committee.
SUMTER EMC
Bob Jernigan--Director, age 66, is a manager for Mike L. Moon Enterprises
in Columbus, Georgia, which among other things, is involved in real estate
development and wholesale and retail women's apparel. He68, has served as a Director of
Oglethorpe since March 1976, with his present term to expire in March 1996.1999.
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 ExecutiveTransmission Committee.
HeMr. Jernigan is the PresidentChairman of the Board of Sumter EMC and a Director of
GEMC.
James T. McMillan--Alternate Director, age 44, has been46, is President and
Chief Executive Officer of Sumter EMC. He was appointed General Manager of
Sumter EMC sincein 1984. The General Manager title was changed to President/CEO
in 1994. Prior to that time, he served as Manager of the Staff Services
Department of Sumter EMC, Manager of the Construction and Maintenance
Department of Sumter EMC, and Manager of the Office Services Department of
Sumter EMC. He has served as an Alternate Director of Oglethorpe since 1984,
with his present term to expire in March 1996.1999. Mr. McMillan currently serves
on the Generation Committee.
THREE NOTCH EMC
C. Willard Mims--Director, age 47,49, is a farmer. He has served on
the Board of Directors since 1991, with his present term to expire in March
1996. He is a
member of the GEMC/Oglethorpe External Affairs Committee. He1999. Mr. Mims is also a Director of GEMC.
Carlton O. Thomas--Alternate Director, age 46,48, 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 1996.1999. He
currently serves on the Transmission Committee. Mr. Thomas is also a
Director of First Federal Savings Bank of Southwest Georgia.
TRI-COUNTY EMC
James E. Dooley--Director,Thomas Noles--Director, age 67,54, is self-employed in the real estate
business.a pharmacist. He has served on
the Board of Directors of Oglethorpe since November
1986,September 1995, with his present
term to expire in March 1996. Prior to his retirement in
1982, he was employed as a Director in the U.S. Department of Agriculture.1999.
Carol Robertson--Alternate Director, age 45,47, 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 1996. She is a member of1999. Ms. Robertson
currently serves on the GEMC/Oglethorpe External AffairsRestructuring Advisory Committee.
TROUP EMC
Willis T. Woodruff--Director,Roy Tollerson, Jr.--Director, age 68,56, is a self-employed cattleman.the owner and operator of
Country Furniture. He has served on the Board of Directors of Oglethorpe
since March 1987,1995, with his present term to expire in March 1995. He1998. Mr.
Tollerson is alsocurrently a Directormember of GEMC.the Marketing Committee.
Wayne Livingston--Alternate Director, age 42,44, has been the
Executive Vice President and General Manager of Troup EMC since SeptemberAugust 1987.
Prior to that time, he was General Manager of Ocmulgee EMC. He has served
56
as
an Alternate Director of Oglethorpe since 1978, with his present term to
expire in March 1995. He is a member of1998. Mr. Livingston currently serves on the FinanceRestructuring
Advisory Committee.
60
UPSON COUNTY EMC
Hubert Hancock--Director, age 77,79, has been President of the Upson
County EMC for the past 3334 years. He has served as a Director of Oglethorpe
since September 1974, serving as Vice President from 1975 to 1978, as
President from March 1984 to July 1986, and as Chairman of the Board from
July 1986 to March 1989. His present term as Director expires in March 1995, and he1998.
Mr. Hancock currently serves on the Executive Committee of Oglethorpe.Committee. Prior to his
involvement with Oglethorpe and Upson County EMC, Mr. Hancockhe 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,
and a member of the Thomaston Upson County Industrial Authority.
Walter E. Hammond--AlternateJohn H. Brodnax--Alternate Director, age 62, is48, was appointed General
Manager of Upson County EMC in 1995. Prior to that time he served as Office
Manager of Upson County EMC. HeMr. Brodnax has served as an Alternate Director of
Oglethorpe since 1978, and1995, with his present term willto expire in March 1995.1998.
WALTON EMC
Bob J. Dickens--Director,Hendrix B. Wiley, Jr.--Director, age 67,51, is a retired dairy farmer
and is currently self-employed in 1988 from Thornton Brothers
Paper Company, Inc. in Athens, Georgia.real estate. He has served on the Board of
Directors of Oglethorpe since March 1987, andAugust 1994, with his present term expiresto expire in
March 1995.1998. He currently serves on the Generation Committee. Mr. Wiley is
also a memberdirector of Oglethorpe's Operations Committee.Walton EMC.
D. Ronnie Lee--Alternate Director, age 45,47, 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 1995.1998. Mr. Lee currently serves on
the Restructuring Advisory Committee.
WASHINGTON EMC
W. W. Archer--Director, age 62,64, 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 1995.1998. He is also a
Director of the Bank of Hancock County in Sparta, Georgia.
Robert S. Moore, Sr.--Alternate Director, age 64,66, 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
1995.1998. He is currently a member of the Planning and Construction Committee of Oglethorpe.
(b)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 52,54, 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 1995.1998. He is currently the Chairman of the
Executive Committee of
Oglethorpe and a member of the GEMC/Oglethorpe Human Resources Management Committee.
He was previously a member of the Operations Review Committee of
Oglethorpe.Committee. From 1965
through 1982, Mr. Earwood was a salesman and part owner of Builders Equipment
Company. Since January 1983, he has been the owner and President of Sunbelt
Fasteners, Inc., which sells specialty tools and fasteners to the 57
commercial
construction trade. He is also Vice Chairman of the Board of Directors of
Community Trust Bank in Hiram, Georgia and a Director of GreyStone Power
Corporation.
Benny W. Denham--ViceDenham, Vice Chairman of the Board, age 63,65, has served as
a principal executive officer of Oglethorpe since March 1993. He has served
as a
member of Oglethorpe's Executive Committee and on the Board of Directors of Oglethorpe since December 1988. His1988, with
61
his present term willto expire in March 1995.1998. He is currently the Vice-Chairman
of the Executive Committee and was previously a member of the Power Planning
and Technical Advisory Committee
of Oglethorpe. HeCommittee. Mr. Denham is also the past President of GEMC and currently serves on
GEMC's Executive Committee and is a Director of Community
National Bank in Ashland, Georgia. Mr. Denham isGeorgia and a Director of Irwin EMC.
John S. Dean, Sr.,Gary M. Bullock, Secretary-Treasurer, age 54, has served as
Secretary-Treasurer of Oglethorpe since March 1989.1995. He has served as an
Alternate Director of Oglethorpe since 1975,June 1978, with his present term to
expire in March 1995.1999. He is currently a member of the FinanceExecutive Committee
and an ex officiothe Restructuring Advisory Committee and was previously a member of the
Executive Committee. He previously served on Oglethorpe's
Operations Review Committee. Mr. Dean has been General Manager/Bullock is President and Chief Executive Officer
of Amicalola EMC since 1974. Prior to his employment with Amicalola EMC,
he was Controller of Pickens General Hospital. Currently, heCarroll EMC. Mr. Bullock is onalso the Board of
DirectorsSecretary of Southeastern Data
Cooperative, Inc., Crescent and serves on the Boards of Directors of the Georgia
Cooperative Council, the Federated Rural Electric Insurance Corporation, and
the Carrollton Federal Bank, & Trust Company,
CoBank, and GEMC Workers' Compensation Fund. Mr. Dean has a Bachelor of Arts
degreeF.S.B. in Accounting from the University ofCarrollton, Georgia.
T. D. Kilgore, President and Chief Executive Officer, age 46,48, 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 the present.October 1995. Mr. Kilgore has
over 20 years of utility experience, including five years in senior management
positions with Arkansas Power & Light Co. and seven years as a civilian
employee with the Department of the Army in positions ranging from
reliability engineering to construction management. Mr. Kilgore has served
on various industry committees including Electric Power Research Institute's
Board of Directors and its Advanced Power Systems Division and Coal System
Division Advisory Committees. He has also served on the Boards of Directors
of the U.S. Committee for Energy Awareness, the Advanced Reactor Corporation,
on the Edison Electric Institute's Power Plant Availability Improvement Task
Force and the Nuclear Power Oversight Committee,
an organization of industry executives which considers policy issues for the
nation's nuclear power industry.Committee. Mr. Kilgore currently
serves on the Board of Directors of the Georgia Chamber of Commerce and on
the National Rural Electric Cooperative Association's Power and Generation
Committee. Mr. Kilgore has a BS degree in mechanical engineering from the
University of Alabama, where he has been recognized as a Distinguished
Engineering Fellow, and aan 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:
Charles T. Autry, SeniorClarence Mitchell, Vice President and General Counsel,Group Executive, Generation,
age 45,42, has served as an executive of Oglethorpe since February 1986 (from February 1986 to
July 1986, as Corporate Counsel; from July 1986 to December 1989, as General
Counsel; from December 1989 to November 1991, as Senior Vice President,
Governmental Affairs and General Counsel; from November 1991 to February 1994,
as Senior Vice President, Corporate Services and General Counsel; and since
February 1994, as Senior Vice President and General Counsel).January 1995. Prior
to that time, Mr. AutryMitchell served as Staff AttorneyAssistant to the Senior Vice President
for Generation from August 1979February 1994 to December 1994; Manager of Corporate
Planning from September 1992 to January 1985 and as
Corporate Attorney1994; Manager of Construction from
January 19851992 to February 1986.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. Autry joined
Oglethorpe in August 1979 after fiveMitchell spent four
years of militaryas a field engineer with General Electric Company and private practice
experience. Heworked various
installation and maintenance projects related to coal, nuclear, gas and
oil-fired generation. Mr. Mitchell has been admitted to practice before all State Courts in Georgia
as well as the Federal District Court for the Northern District of Georgia, and
the Fifth and Eleventh Circuit Courts of Appeal and the U. S. Tax Court. He has
a BA degree from the University of Georgia, a JD degree from the University of
Alabama School of Law, a LLMan MS degree in Taxation from Emory University School of
Law, and an MBA degreeManagement from
Georgia State University.
58
Eugen Heckl, Senior Vice President and Chief Financial Officer, age 59, has
served as an executive of Oglethorpe since March 1975 (from March 1975 to July
1986, as senior finance and accounting executive; from July 1986 to February
1994 as Senior Vice President, Finance; and since February 1994, as Senior Vice
President and Chief Financial Officer). Mr. Heckl has approximately 30 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
hasUniversity, a BS degree in accountingMechanical Engineering from Samford UniversityGeorgia
Institute of Technology and an MBA degree from
Emory University. Mr. Heckl has served as a Director of the GEMC Federal Credit
Union since 1983, and as its Chief Financial Officer since 1984.
G. Stanley Hill, Senior Vice President, External Affairs, age 58, has
served as an executive of Oglethorpe since October 1975 (from October 1975 to
November 1988, as Director of Planning, Director of Power 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, External Affairs). Mr. Hill has
approximately 36 years experience with electric utilities, including four years
in the Engineering Department of the South Carolina Public Service Authority and
11 years as engineer and senior engineer with Southern Engineering Company of
Georgia, a consulting engineering firm. Mr. Hill is a registered Professional
Engineer and a certified Cogeneration Professional in Georgia and has a BS degree in electrical engineeringInterdisciplinary Science from
Clemson UniversityMorehouse College. Mr. Mitchell is presently the Oglethorpe representative on
both the Nuclear Managing Board and an MBAthe 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 State University.Institute of
Technology and has participated in Harvard University's postgraduate Program
for Management Development. Mr. HillSanders 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
62
TRANSMISSION AGREEMENTS-TheAGREEMENTS--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 47,49, 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.
David L. Self,Eugen Heckl, Senior Vice President and Group Executive, Generation,Chief Financial Officer, age
65,61, has served as an executive of Oglethorpe since August 1991March 1975 (from August 1991March
1975 to November 1991,July 1986, as senior finance and accounting executive; from July 1986
to February 1994 as Senior Vice President, Power Supply; from November 1991 to
February 1994, Senior Vice President, Operations;Finance; and since February 1994,
as Senior Vice President and Group Executive, Generation)Chief Financial Officer). Mr. Self joined
Oglethorpe in February 1988 as the corporation's on-site representative at Plant
Hatch afterHeckl has over 30
years in the United States Navyof experience, including ten years as a consultant and fiveauditor to
electric utilities with Arthur Andersen & Co. and two years with Illinois
Power Company. Heas
Secretary-Treasurer of Davis Brothers, Inc. Mr. Heckl is a member of the Board of Trustees of Southern Tech
Foundation, Inc. HeCertified Public
Accountant in Georgia and has a BS degree in accounting from Saint Mary's CollegeSamford
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 California.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. SelfHill 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 the Oglethorpe representative on both the Nuclear Managing
Board and the Plant Scherer Managing Board, and is an Oglethorpe representative on the
Joint Committee. For information about the Managing Boards and the Joint Committee, see "CO-OWNERS
OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS-The Plant Agreements" and "-TheAGREEMENTS--The Joint Committee
Agreement" in Item 1. Nelson G. Hawk, ViceMr. Hill has elected to retire from
63
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 GroupChief Executive Marketing, age 44,
joined Oglethorpe in February 1994 after almost 24 years of electric utility
experience. Prior to coming to Oglethorpe, he held various management positions
with Florida Power & Light Company and related subsidiaries, including as
Director of Regulatory Affairs at Florida Power & Light from October 1993 to
January 1994; as Director of Market Planning from July 1991 to September 1993;
and as Director of Strategic Business and President of FPL Enersys Services,
Inc. (a utility subsidiary providing energy services to commercial/industrial
customers) from April 1989 to June 1991. Mr. Hawk has a BS degree in Electrical
Engineering from Georgia Institute of Technology and an MBA degree from Florida
International University.
59
Wylie H. Sanders, Vice President and Group Executive, Transmission, age 57,
joined Oglethorpe in January 1994 after 35 years of utility experience,
including 20 years in management positions with Florida Power & Light Company.
Prior to coming to Oglethorpe, he served as Division Commercial Manager from
April 1973 to August 1983; as District General Manager from August 1983 to July
1991; and as Director of Transmission from July 1991 to September 1993 with
Florida Power & Light. Mr. Sanders has a Bachelor's degree in Industrial
Engineering from Georgia Institute of Technology and has participated in Harvard
University's postgraduate Program for Management Development.
60Officer.
64
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth, for Oglethorpe's President and
Chief Executive Officer and the fourfive most highly compensated senior
executives, all compensation paid or accrued for services rendered in all
capacities during the years ended December 31, 1993, 19921995, 1994 and 1991.1993. 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 remain
fairly stable and are targeted below the market valuations for
similar positions.positions and remain fairly stable unless the job content changes.
ANNUAL
COMPENSATION
NAME AND ------------------------------- ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS(3)BONUS(2) COMPENSATION
- ------------------ ---- -------- -------- --------------------- -------------
T. D. Kilgore 1993 $211,250 $ 0 $6,256(1)1995 $235,000 $10,000 $6,012(1)
President and Chief Executive Officer 1992 195,0001994 224,997 0 5,891
1991 181,1476,758
1993 211,250 0 (2)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 19931995 142,114 12,228 5,103(1)13,174 7,651(1)
Sr. Vice President and Chief 19921994 142,114 19,135 4,07913,919 7,600
Financial Officer 19911993 142,114 0 (2)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 4,905(1)
Sr. Vice President, 1992 140,000 18,195 4,391
External Affairs 1991 134,872 0 (2)
Charles T. Autry 1993 139,750 10,991 4,326(1)7,001
W. Clayton Robbins 1995 142,310 10,631 4,716(1)
Sr. Vice President and 1992 139,750 16,950 4,232
General Counsel 1991 139,750 0 (2)
David L. Self1994 140,366 11,946 4,986
Group Executive, Support Services 1993 135,000 12,143 5,077(1)
Sr.128,000 12,461 4,582
Nelson G. Hawk (4) 1995 140,000 10,899 4,589(1)
Vice President and 1992 131,800 18,286 4,168
Group 1994 116,005 9,620 36,972(4)
Executive, Generation 1991 110,067 0 (2)
- -------------------------
(1) Includes contributions made inMarketing 1993 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. Kilgore, Heckl, Hill, Autry and
Self in the amounts of $4,497, $4,497, $4,200, $4,193 and $4,050, respectively,
and above market amounts of interest earned by Messrs. Kilgore, Heckl, Hill,
Autry and Self on deferred compensation amounts paid by Oglethorpe in the
amounts of $1,759, $606, $705, $133, and $1,027,N/A N/A N/A
______________________
(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) In accordance with the transition provision applicable to the Commission's
new rules regarding executive compensation disclosure, Oglethorpe is not
required to provide any information for fiscal year 1991.
(3) Mr. Kilgore is not a participant in the incentive compensation program.
His compensation is governed solely by the Board of Directors.
61(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.
65
PENSION PLAN TABLE
YEARS OF CREDITED SERVICE
-----------------------------------------------------------
AVERAGE COMPENSATION 15 20 25
OR MORE
- -------------------- ------ ------ ----------------- ------- -------
$125,000 . . . . . . . . . . . . . . $35,592 $47,456 $ 59,320
150,000 . . . . . . . . . . . . . . 43,092 57,456 71,820
175,000 . . . . . . . . . . . . . . 50,592 67,456 84,320
200,000 . . . . . . . . . . . . . . 58,092 77,456 96,820
225,000 . . . . . . . . . . . . . . 65,592 87,456 109,320
250,000 . . . . . . . . . . . . . . 68,844 91,792 114,74050,000...................................... $12,823 $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
The preceding table shows estimated annual straight life annuity
benefits payable upon retirement to persons in specified compensation and
years-of-service classifications assuming such persons had attained age 65
and retired during 1993.1995. 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, 1993,1995, the years of credited service under the
Pension Plan for the individuals listed in the Summary Compensation Table are
as follows:
YEARS OF
NAME CREDITED SERVICE
---- ----------------
Mr. Kilgore. . . . . . . . . . . . . . . . . . . . . . . . . . 8Kilgore.......................................... 10
Mr. Heckl. . . . . . . . . . . . . . . . . . . . . . . . . . . 17Self............................................. 7
Mr. Autry. . . . . . . . . . . . . . . . . . . . . . . . . . . 14Heckl............................................ 19
Mr. Hill . . . . . . . . . . . . . . . . . . . . . . . . . . . 17Hill............................................. 19
Mr. Self . . . . . . . . . . . . . . . . . . . . . . . . . . . 5Robbins.......................................... 9
Mr. Hawk............................................. 0.8
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
66
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
W. F. Farr,E. J. Martin, Jr., J. Calvin Earwood, Ronnie Fleeman, E.John B. Floyd, Jr., and J. Martin, Jr. and
Robert A. ReevesG.
McCalmon serve as members of the GEMC/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.
62
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
6367
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
PAGE
----
(a)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, 1993, 19921995, 1994 and 1991. . . . . . . . . . 331993........................ 36
Statements of Patronage Capital, For the Years Ended
December 31, 1993, 19921995, 1994 and 1991. . . . . . . . . . . . . 331993.............................. 36
Balance Sheets, As of December 31, 19931995 and 1992 . . . . . 341994............... 37
Statements of Capitalization, As of December 31, 19931995
and 1992. . . . . . . . . . . . . . . . . . . . . . . . . 361994...................................................... 39
Statements of Cash Flows, For the Years Ended December 31,
1993, 19921995, 1994 and 1991 . . . . . . . . . . . . . . . . . 371993........................................... 40
Notes to Financial Statements. . . . . . . . . . . . . . . 38Statements.................................. 41
Report of Management . . . . . . . . . . . . . . . . . . . 48
ReportManagement........................................... 51
Reports of Independent Public Accountants . . . . . . . . . 48Accountants...................... 51
(2) FINANCIAL STATEMENT SCHEDULES
Schedule I -- Marketable Securities--Other Security
Investments, AsNone 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 December 31, 1993 78
Schedule V -- Utility Plant, Including Intangibles, For the Years Ended December 31, 1993, 1992 and 1991 79
Schedule VI -- Accumulated Provision for Depreciation
of Utility Plant, For the Years Ended
December 31, 1993, 1992 and 1991 82
Schedule X -- Supplementary Income Statement
Information, For the Years Ended
December 31, 1993, 1992 and 1991 85
(3) EXHIBITSexhibit.
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- 7591.33-7591.)
*4.1 -- Serial Facility Bond (included in Collateral Trust Indenture
listed as Exhibit 4.2).
68
*4.2 -- Collateral Trust Indenture, dated as of October 15, 1986,
between OPC Scherer Funding Corporation, Oglethorpe and Trust
Company Bank, a banking corporation, as Trustee. (Filed 64
NUMBER DESCRIPTION
- ------ -----------
as
Exhibit 4.2 to the Registrant's Form S-1 Registration Statement,
File No. 33- 7591,33-7591, filed on October 9, 1986.)
*4.3 -- Refunding Lessor Notes. (Filed as Exhibit 4.3.1 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*4.4(a) -- Nonrecourse Promissory Secured Note, due June 30, 2011, from
Wilmington Trust Company and William J. Wade, as Owner Trustees,
to Columbia Bank for Cooperatives. (Filed as Exhibit 4.3.4 to the
Registrant's Form S-1 Registration Statement, File No. 33- 7591,33-7591,
filed on October 9, 1986.)
*4.4(b) -- First Amendment to Nonrecourse Promissory Secured Note, dated as
of June 30, 1987, by Wilmington Trust Company and The Citizens and
Southern National Bank, as Owner Trustee under Trust Agreement No.
1 with IBM Credit Financing Corporation, to Columbia Bank for
Cooperatives. (Filed as Exhibit 4.3.4(a) to the Registrant's Form
10-K for the fiscal year ended December 31, 1987, File No.
33-7591.)
*4.5(a) -- Indenture of Trust, Deed to Secure Debt and Security Agreement
No. 2, dated December 30, 1985, between Wilmington Trust Company
and William J. Wade, as Owner Trustees under Trust Agreement No.
2 dated December 30, 1985, with Ford Motor Credit Company and The
First National Bank of Atlanta, as Indenture Trustee, together
with a Schedule identifying three other substantially identical
Indentures of Trust, Deeds to Secure Debt and Security
Agreements. (Filed as Exhibit 4.4(b) to the Registrant's Form
S-1 Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.5(b) -- First Supplemental Indenture of Trust, Deed to Secure Debt and
Security Agreement No. 2 (included as Exhibit A to the
Supplemental Participation Agreement No. 2 listed as 10.1.1(b)).
*4.5(c) -- First Supplemental Indenture of Trust, Deed to Secure Debt and
Security Agreement No. 1, dated as of June 30, 1987, between
Wilmington Trust Company and The Citizens and Southern National
Bank, collectively as Owner Trustee under Trust Agreement No. 1
with IBM Credit Financing Corporation, and The First National
Bank of Atlanta, as Indenture Trustee. (Filed as Exhibit 4.4(c)
to the Registrant's Form 10-K for the fiscal year ended December
31, 1987, File No. 33-7591.)
*4.6(a) -- Lease Agreement No. 2 dated December 30, 1985, between Wilmington
Trust Company and William J. Wade, as Owner Trustees under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, Lessor, and Oglethorpe, Lessee, with a Schedule
identifying three other substantially identical Lease Agreements.
(Filed as Exhibit 4.5(b) to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*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.)
6569
NUMBER DESCRIPTION
- ------ -----------
*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)*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. 66(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.)
70
NUMBER DESCRIPTION
- ------ -----------
*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- 7591,33-7591, 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 67
NUMBER DESCRIPTION
- ------ -----------
Cooperatives, and
Trust Company Bank, as trustee under certain indentures
identified therein, Mortgagees, dated as of November 1, 1988.
(Filed as Exhibit 4.7(a) to the Registrant's Form 10-K for the
fiscal year ended December 31, 1988, File No. 33- 7591.33-7591.)
71
*4.8.7(a) -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, and Trust Company Bank, as trustee under
certain indentures identified therein, Mortgagees, dated as of
December 1, 1989. (Filed as Exhibit 4.19 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1989, File No.
33-7591.)
*4.8.7(b) -- Supplement to Consolidated Mortgage and Security Agreement made
by and among Oglethorpe, Mortgagor, and United States of
America, National Bank for Cooperatives, and Trust Company Bank,
as trustee under certain indentures identified therein,
Mortgagees, dated as of November 20,21, 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*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.
68
NUMBER DESCRIPTION
- ------ -----------
++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
72
County Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Scherer Project), Series 1992A.
+4.10.14.10.1 (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.
+4.10.24.10.2 (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.
+4.10.34.10.3 (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.
+4.10.44.10.4(a) -- First Amended and Restated Letter of Credit Reimbursement
(2) Agreement, dated as of June 1, 1992, as amended by First
Amendment to First Amended and Restated Letter of Credit
Reimbursement Agreement, dated as of September 15, 1993, between Credit Suisse and
Oglethorpe relating to an Irrevocable Letter of Credit issued in
connection with the Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe
Power Corporation Vogtle Project), Series 1992A.
+++4.10.4(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.
6973
NUMBER DESCRIPTION
- ------ -----------
+4.11.64.11.6 (2) -- Standby Bond Purchase Agreement, dated as of November 30,
1993,December 14, 1995,
between Oglethorpe and The IndustrialCanadian Imperial Bank of Japan,
LimitedCommerce, New
York Agency, relating to Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe
Power Corporation Vogtle Project), Series 1993A.
*4.12.14.11.7 (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.)
*4.12.2*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.)
*4.13.1*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.)
*4.13.2*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.)
*4.14.1*4.15.1 -- Loan Agreement, Loan No. T-830404, between Oglethorpe and
Columbia Bank for Cooperatives, dated as of April 29, 1983.
(Filed as Exhibit 4.18.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.14.2*4.15.2 -- Promissory Note, Loan No. T-830404-1, in the original principal
amount of $9,935,000, from Oglethorpe to Columbia Bank for
Cooperatives, dated as of April 29, 1983. (Filed as Exhibit
4.18.2 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*4.14.3*4.15.3 -- Security Deed and Security Agreement, dated April 29, 1983,
between Oglethorpe and Columbia Bank for Cooperatives. (Filed as
Exhibit 4.18.3 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.1.1(a) -- Participation Agreement No. 2 among Oglethorpe as Lessee,
Wilmington Trust Company as Owner Trustee, The First National
Bank of Atlanta as Indenture Trustee, Columbia Bank for
Cooperatives as Loan Participant and Ford Motor Credit Company as
Owner Participant,
74
dated December 30, 1985, together with a Schedule identifying
three other substantially identical Participation Agreements.
(Filed as Exhibit 10.1.1(b) to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*10.1.1(b)-- Supplemental Participation Agreement No. 2. (Filed as Exhibit
10.1.1(a) to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)
*10.1.1(c)-- Supplemental Participation Agreement No. 1, dated as of June 30,
1987, among Oglethorpe as Lessee, IBM Credit Financing
Corporation as Owner Participant, Wilmington Trust Company and
The Citizens and Southern National Bank as Owner Trustee, The
First National Bank of Atlanta, as Indenture Trustee, and
Columbia Bank for Cooperatives, as
70
NUMBER DESCRIPTION
- ------ ----------- Loan Participant. (Filed as
Exhibit 10.1.1(c) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1987, File No. 33-7591.)
*10.1.2 -- General Warranty Deed and Bill of Sale No. 2 between Oglethorpe,
Grantor, and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Grantee, together with a
Schedule identifying three substantially identical General
Warranty Deeds and Bills of Sale. (Filed as Exhibit 10.1.2 to
the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.1.3(a)-- Supporting Assets Lease No. 2, dated December 30, 1985, between
Oglethorpe, Lessor, and Wilmington Trust Company and William J.
Wade, as Owner Trustees, under Trust Agreement No. 2, dated
December 30, 1985, with Ford Motor Credit Company, Lessee,
together with a Schedule identifying three substantially
identical Supporting Assets Leases. (Filed as Exhibit 10.1.3 to
the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.1.3(b)-- First Amendment to Supporting Assets Lease No. 2, dated as of
November 19, 1987, together with a Schedule identifying three
substantially identical First Amendments to Supporting Assets
Leases. (Filed as Exhibit 10.1.3(a) to the Registrant's Form
10-K for the fiscal year ended December 31, 1987, File No.
33-7591.)
*10.1.4(a)-- Supporting Assets Sublease No. 2, dated December 30, 1985,
between Wilmington Trust Company and William J. Wade, as Owner
Trustees under Trust Agreement No. 2 dated December 30, 1985,
with Ford Motor Credit Company, Sublessor, and Oglethorpe,
Sublessee, together with a Schedule identifying three
substantially identical Supporting Assets Subleases. (Filed as
Exhibit 10.1.4 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.1.4(b)-- First Amendment to Supporting Assets Sublease No. 2, dated as of
November 19, 1987, together with a Schedule identifying three
substantially identical First Amendments to Supporting Assets
Subleases. (Filed as Exhibit 10.1.4(a) to the Registrant's Form
10-K for the fiscal year ended December 31, 1987, File No.
33-7591.)
*10.1.5 -- Tax Indemnification Agreement No. 2, dated December 30, 1985,
between Ford Motor Credit Company, Owner Participant, and
Oglethorpe, Lessee, together with a Schedule identifying three
substantially identical Tax Indemnification Agreements. (Filed
as Exhibit 10.1.5 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.1.6 -- Assignment of Interest in Ownership Agreement and Operating
Agreement No. 2, dated December 30, 1985, between Oglethorpe,
Assignor, and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
75
1985, with Ford Motor Credit Company, Assignee, together with
Schedule identifying three substantially identical Assignments of
Interest in Ownership Agreement and Operating Agreement. (Filed
as Exhibit 10.1.6 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.1.7 -- Consent, Amendment and Assumption No. 2 dated December 30, 1985,
among Georgia Power Company and Oglethorpe and Municipal Electric
Authority of Georgia and City of Dalton, Georgia and Gulf Power
Company and Wilmington Trust Company and William 71
NUMBER DESCRIPTION
- ------ -----------
J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, together with a Schedule
identifying three substantially identical Consents, Amendments
and Assumptions. (Filed as Exhibit 10.1.9 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.1.7(a)-- Amendment to Consent, Amendment and Assumption No. 2, dated as of
August 16, 1993, among Oglethorpe, Georgia Power Company,
Municipal Electric Authority of Georgia, City of Dalton, Georgia,
Gulf Power Company, Jacksonville Electric Authority, Florida
Power & Light Company and Wilmington Trust Company and
NationsBank of Georgia, N.A., as Owner Trustees under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, together with a Schedule identifying three substantially
identical Amendments to Consents, Amendments and Assumptions.
(Filed as Exhibit 10.1.9(a) to the Registrant's Form 10-Q for the
quarterly period ended September 30, 1993, File No. 33-7591.)
*10.2.1 -- Section 168 Agreement and Election dated as of April 7, 1982,
between Continental Telephone Corporation and Oglethorpe. (Filed
as Exhibit 10.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.2.2 -- Section 168 Agreement and Election dated as of April 9, 1982,
between National Service Industries, Inc. and Oglethorpe. (Filed
as Exhibit 10.3 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.2.3 -- Section 168 Agreement and Election dated as of April 9, 1982,
between Rollins, Inc. and Oglethorpe. (Filed as Exhibit 10.4 to
the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.2.4 -- Section 168 Agreement and Election dated as of December 13, 1982,
between Selig Enterprises, Inc. and Oglethorpe. (Filed as
Exhibit 10.5 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)
*10.3.1(a)-- Plant Robert W. Scherer Units Numbers One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit
10.6.1 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*10.3.1(b)-- Amendment to Plant Robert W. Scherer Units Numbers One and Two
Purchase and Ownership Participation Agreement among Georgia
Power Company, Oglethorpe, Municipal Electric Authority of
Georgia and City of Dalton, Georgia, dated as of December 30,
1985. (Filed as Exhibit 10.1.8 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*10.3.1(c)-- Amendment Number Two to the Plant Robert W. Scherer Units Numbers
One and Two Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia, dated as of
76
July 1, 1986. (Filed as Exhibit 10.6.1(a) to the Registrant's
Form 10-K for the fiscal year ended December 31, 1987, File
No. 33-7591.)
*10.3.1(d)-- Amendment Number Three to the Plant Robert W. Scherer Units
Numbers One and Two Purchase and Ownership Participation
Agreement among Georgia Power Company,
72
NUMBER DESCRIPTION
- ------ ----------- Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 1, 1988. (Filed as Exhibit 10.6.1(b) to the
Registrant's Form 10-Q for the quarterly period ended September
30, 1993, File No. 33-7591.)
*10.3.1(e)-- Amendment Number Four to the Plant Robert W. Scherer Units Number
One and Two Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia, dated as of December 31,
1990. (Filed as Exhibit 10.6.1(c) to the Registrant's Form 10-Q
for the quarterly period ended September 30, 1993, File No.
33-7591.)
*10.3.2(a)-- Plant Robert W. Scherer Units Numbers One and Two Operating
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of May 15, 1980. (Filed as Exhibit 10.6.2 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.3.2(b)-- Amendment to Plant Robert W. Scherer Units Numbers One and Two
Operating Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.7
to the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.3.2(c)-- Amendment Number Two to the Plant Robert W. Scherer Units Numbers
One and Two Operating Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of December 31, 1990. (Filed as
Exhibit 10.6.2(a) to the Registrant's Form 10-Q for the quarterly
period ended September 30, 1993, File No. 33-7591.)
*10.3.3 -- Plant Scherer Managing Board Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia,
City of Dalton, Georgia, Gulf Power Company, Florida Power &
Light Company and Jacksonville Electric Authority, dated as of
December 31, 1990. (Filed as Exhibit 10.6.3 to the Registrant's
Form 10-Q for the quarterly period ended September 30, 1993, File
No. 33-7591.)
*10.4.1(a)-- Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit
10.7.1 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*10.4.1(b)-- Amendment Number One, dated January 18, 1977, to the Alvin W.
Vogtle Nuclear Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia. (Filed as Exhibit 10.7.3 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.1(c)-- Amendment Number Two, dated February 24, 1977, to the Alvin W.
Vogtle Nuclear Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia. (Filed as Exhibit 10.7.4 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1986, File No. 33-7591.)
7377
NUMBER DESCRIPTION
- ------ -----------
*10.4.2 -- Alvin W. Vogtle Nuclear Units Numbers One and Two Operating
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 27, 1976. (Filed as Exhibit 10.7.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*10.5.1 -- Plant Hal Wansley Purchase and Ownership Participation Agreement
between Georgia Power Company and Oglethorpe, dated as of March
26, 1976. (Filed as Exhibit 10.8.1 to 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, 74
NUMBER DESCRIPTION
- ------ -----------
between Oglethorpe and Planters Electric
Membership Corporation, together with a Schedule identifying 37
other substantially identical Wholesale Power Contracts, and an
additional
78
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- K10-K for the fiscal
year ended December 31, 1990, File No. 33-7591.)
*10.11(a) -- Amendment No. 1 to Interconnection Agreement between Alabama
Electric Cooperative, Inc. and Oglethorpe, dated as of April 22,
1994. (Filed as Exhibit 10.11(a) to the Registrant's Form 10-Q
for the quarter ended June 30, 1994, File No. 33-7591.)
*10.11(b) -- Letter of Commitment (Firm Power Sale) Under Service Schedule J -
Negotiated Interchange Service between Alabama Electric
Cooperative, Inc. and Oglethorpe, dated March 31, 1994. (Filed
as Exhibit 10.11(b) to the Registrant's Form 10-Q for the quarter
ended June 30, 1994, File No. 33-7591.)
*10.12 -- Oglethorpe Deferred Compensation Plan for Key Employees, as
Amended and Restated January, 1987. (Filed as Exhibit 10.19 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1986, File No. 33-7591.)
*10.13.1 -- Assignment of Power System Agreement and Settlement Agreement,
dated January 8, 1975, by Georgia Electric Membership Corporation
to Oglethorpe. (Filed as Exhibit 10.20.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.13.2 -- Power System Agreement, dated April 24, 1974, by and between
Georgia Electric Membership Corporation and Georgia Power
Company. (Filed as Exhibit 10.20.2 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*10.13.3 -- Settlement Agreement, dated April 24, 1974, by and between
Georgia Power Company, Georgia Municipal Association, Inc., City
of Dalton, Georgia Electric Membership Corporation and Crisp
County Power Commission. (Filed as Exhibit 10.20.3 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*10.14 -- Distribution Facilities Joint Use Agreement between Oglethorpe
and Georgia Power Company, dated as of May 12, 1986. (Filed as
Exhibit 10.21 to the Registrant's Form 0-K10-K for the fiscal year
ended December 31, 1986, File No. 33-7591.)
*10.15.1 -- Long Term Firm Power Purchase Agreement, dated as of July 19,
1989, by and between Oglethorpe and Big Rivers Electric
Corporation. (Filed as Exhibit 10.24.1 to the Registrant's Form
10-K for the fiscal year ended December 31, 1989, File No.
33-7591.)
79
*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.)
75
NUMBER DESCRIPTION
- ------ -----------
*10.15.3 -- Long Term Firm Power Purchase Agreement between Big Rivers
Electric Corporation and Oglethorpe, dated as of December 17,
1990. (Filed as Exhibit 10.24.3 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1990, File No. 33-7591.)
*10.15.4 -- Interchange Agreement between Oglethorpe and Big Rivers Electric
Corporation, dated as of November 12, 1990. (Filed as Exhibit
10.24.4 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*10.16 -- Block Power Sale Agreement between Georgia Power Company and
Oglethorpe, dated as of November 12, 1990. (Filed as Exhibit
10.25 to the Registrant's Form 8-K, filed January 4, 1991, File
No. 33-7591.)
*10.17 -- Coordination Services Agreement between Georgia Power Company and
Oglethorpe, dated as of November 12, 1990. (Filed as Exhibit
10.26 to the Registrant's Form 8-K, filed January 4, 1991, File
No. 33-7591.)
*10.18 -- Revised and Restated Integrated Transmission System Agreement
between Oglethorpe and Georgia Power Company, dated as of
November 12, 1990. (Filed as Exhibit 10.27 to the Registrant's
Form 8-K, filed January 4, 1991, File No. 33-7591.)
*10.19 -- ITSA, Power Sale and Coordination Umbrella Agreement between
Oglethorpe and Georgia Power Company, dated as of November 12,
1990. (Filed as Exhibit 10.28 to the Registrant's Form 8-K,
filed January 4, 1991, File No. 33-7591.)
*10.20 -- Amended and Restated Nuclear Managing Board Agreement among
Georgia Power Company, Oglethorpe Power Corporation, Municipal
Electric Authority of Georgia and City of Dalton, Georgia dated
as of July 1, 1993. (Filed as Exhibit 10.36 to the Registrant's
10-Q for the quarterly period ended September 30, 1993, File No.
33-7591.)
*10.21 -- Supplemental Agreement by and among Oglethorpe, Tri-County
Electric Membership Cooperation and Georgia Power Company, dated
as of November 12, 1990, together with 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.)
7680
NUMBER DESCRIPTION
- ------ -----------
*10.25.1 -- Excess Energy and Short-term Power Agreement between Oglethorpe
and Tennessee Valley Authority, effective as of January 23, 1991.
(Filed as Exhibit 10.34.1 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1990, File No. 33-7591.)
*10.25.2 -- Transmission Service Agreement between Oglethorpe and Tennessee
Valley Authority, effective as of January 23, 1991. (Filed as
Exhibit 10.34.2 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1990, File No. 33-7591.)
*10.26 -- Power Purchase Agreement between Oglethorpe and Hartwell Energy
Limited Partnership, dated as of June 12, 1992. (Filed as
Exhibit 10.35 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1992, File No. 33-7591).
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).
- -------------------------
* Incorporated herein by reference.
+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,herewith; however the registrant hereby agrees that such documentsdocument will be
provided to the Commission upon request.
++(3) For the reason stated in footnote (+)(2), this document and eight other
substantially identical documents are not filed as exhibits to this
Registration Statement.
+++(4) For the reason stated in the footnote (+)(2), this document and another
substantially identical document are not filed as exhibits to this
Registration Statement.
(5) Certain portions of this document have been omitted as confidential and
filed separately with the Commission.
(6) Indicates a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this form pursuant to Item 14(c)
of this report.
All other schedules and exhibits are omitted because of the absence of
the conditions under which they are required or because the required
information is included in the financial statements and related notes to
financial statements.
(b)(B) REPORTS ON FORM 8-K.
No reports on Form 8-K were filed by Oglethorpe for the quarter ended
December 31, 1993.
77
SCHEDULE I
OGLETHORPE POWER CORPORATION
MARKETABLE SECURITIES--OTHER SECURITY INVESTMENTS
AS OF DECEMBER 31, 1993
(DOLLARS IN THOUSANDS)
NAME OF ISSUER AND PRINCIPAL MARKET CARRYING
TITLE OF EACH ISSUE AMOUNT COST VALUE AMOUNT
------------------- --------- ---- ------ --------
BOND, RESERVE AND CONSTRUCTION FUNDS:
United States Government
securities . . . . . . . . . . . . . $ 58,416 $ 57,622 $ 59,247 $ 57,622
Repurchase agreements. . . . . . . . . 52,768 52,768 52,768 52,768
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . $111,184 $110,390 $112,015 $110,390
-------- -------- -------- --------
-------- -------- -------- --------
DECOMMISSIONING FUND:
United States Government
securities . . . . . . . . . . . . . $ 37,112 $ 40,182 $ 39,694 $ 40,182
Corporate bonds. . . . . . . . . . . . 8,305 8,669 8,932 8,669
Cash and money market securities . . . 8,060 8,060 8,060 8,060
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . $ 53,477 $ 56,911 $ 56,686 $ 56,911
-------- -------- -------- --------
-------- -------- -------- --------
CASH AND TEMPORARY CASH INVESTMENTS:
Financial institution commercial
paper. . . . . . . . . . . . . . . . $ 55,700 $ 55,593 $ 55,593 $ 55,593
Other corporate commercial paper . . . 160,920 152,793 152,793 152,793
CFC commercial paper . . . . . . . . . 9,935 9,935 9,935 9,935
Repurchase agreements. . . . . . . . . 25,549 25,549 25,549 25,549
Cash and money market securities . . . 303 303 303 303
-------- -------- -------- --------
Total. . . . . . . . . . . . . . . $252,407 $244,173 $244,173 $244,173
-------- -------- -------- --------
-------- -------- -------- --------
78
SCHEDULE V
OGLETHORPE POWER CORPORATION
UTILITY PLANT, INCLUDING INTANGIBLES
FOR THE YEAR ENDED DECEMBER 31, 1993
(DOLLARS IN THOUSANDS)
BALANCE AT OTHER BALANCE
BEGINNING ADDITIONS CHANGES AT END
CLASSIFICATION OF PERIOD AT COST RETIREMENTS(1) DEBIT/(CREDIT) OF PERIOD
- -------------- ---------- --------- -------------- -------------- ---------
Plant in service:
Intangible . . . . . . . . .$ 8,002 $ 1,214 $ - $ - $ 9,216
Production plant
Steam. . . . . . . . . . . 889,989 2,818 (354) (174)(4) 892,279
Nuclear. . . . . . . . . . 3,271,428 19,566 (2,553) (4,261)(4) 3,284,180
Hydro. . . . . . . . . . . 10,344 5 (8) - 10,341
Other. . . . . . . . . . . 3,665 - - - 3,665
Transmission plant . . . . . 469,275 7,455 (2,407) - 474,323
Distribution plant . . . . . 243,233 37,537 (5,727) - 275,043
General plant. . . . . . . . 72,624 13,971 (2,996) - 83,599
Construction work in
progress . . . . . . . . . . 322,628 128,337(2) - - 450,965
Plant held for future use. . . 11,720 3,375(3) - - 15,095
Plant acquisition
adjustments. . . . . . . . . 34,832 - - - 34,832
Nuclear fuel . . . . . . . . . 269,476 35,547 (73,773) - 231,250
---------- -------- -------- ------- ----------
Total Utility Plant. . . . .$5,607,216 $249,825 $(87,818) $(4,435) $5,764,788
---------- -------- -------- ------- ----------
---------- -------- -------- ------- ----------
- -----------------
Notes:
(1) Retirements have been charged to accumulated provision for depreciation
(Schedule VI).
(2) CWIP additions represent transfers to plant in service of $(72,512) and
additions and other miscellaneous transfers of $200,849.
(3) Plant held for future use additions represent transfers to plant in service
of $(66) and additions and other miscellaneous transfers of $3,441.
(4) Amounts represents an adjustment related to a change in inventory methods
at jointly owned generating plants. Certain items of spare parts inventory
were originally charged to plant investment.
79
SCHEDULE V
OGLETHORPE POWER CORPORATION
UTILITY PLANT, INCLUDING INTANGIBLES
FOR THE YEAR ENDED DECEMBER 31, 1992
(DOLLARS IN THOUSANDS)
BALANCE AT OTHER BALANCE
BEGINNING ADDITIONS CHANGES AT END
CLASSIFICATION OF PERIOD AT COST RETIREMENTS(1) DEBIT/(CREDIT) OF PERIOD
- -------------- ---------- --------- -------------- -------------- ---------
Plant in service:
Intangibles. . . . . . . . .$ 7,925 $ 77 $ - $ - $ 8,002
Production plant
Steam. . . . . . . . . . . 894,904 1,465 (2,017) (4,363)(4) 889,989
Nuclear. . . . . . . . . . 3,270,823 13,016 (3,348) (9,063)(4) 3,271,428
Hydro. . . . . . . . . . . 10,327 17 - - 10,344
Other. . . . . . . . . . . 3,867 (202) - - 3,665
Transmission plant . . . . . 444,678 28,342 (3,745) - 469,275
Distribution plant . . . . . 216,326 28,927 (2,020) - 243,233
General plant. . . . . . . . 69,328 3,764 (468) - 72,624
Construction work in
progress . . . . . . . . . . 178,980 143,648 (2) - - 322,628
Plant held for future use. . . 11,803 (83)(3) - - 11,720
Plant acquisition
adjustments. . . . . . . . . 34,796 36 - - 34,832
Nuclear fuel . . . . . . . . . 309,102 51,992 (91,618) - 269,476
---------- -------- --------- -------- ----------
Total Utility Plant. . . . .$5,452,859 $270,999 $(103,216) $(13,426) $5,607,216
---------- -------- --------- -------- ----------
---------- -------- --------- -------- ----------
- ------------------
Notes:
(1) Retirements have been charged to accumulated provision for depreciation
(Schedule VI).
(2) CWIP additions represent transfers to plant in service of $(62,280) and
additions and other miscellaneous transfers of $205,928.
(3) Plant held for future use additions represent transfers to plant in service
of $(165) and additions and other miscellaneous transfers of $82.
(4) Amount represents an adjustment related to a change of inventory accounting
methods at jointly owned generating plants. Certain items of spare parts
inventory were originally charged to plant investment.
80
SCHEDULE V
OGLETHORPE POWER CORPORATION
UTILITY PLANT, INCLUDING INTANGIBLES
FOR THE YEAR ENDED DECEMBER 31, 1991
(DOLLARS IN THOUSANDS)
BALANCE AT OTHER BALANCE
BEGINNING ADDITIONS CHANGES AT END
CLASSIFICATION OF PERIOD AT COST RETIREMENTS(1) DEBIT/(CREDIT) OF PERIOD
- -------------- ---------- --------- -------------- -------------- ---------
Plant in service:
Intangibles. . . . . . . . .$ 7,642 $ 283 $ - $ - $ 7,925
Production plant
Steam. . . . . . . . . . . 894,045 872 (13) - 894,904
Nuclear. . . . . . . . . . 3,254,930 21,298 (5,405) - 3,270,823
Hydro. . . . . . . . . . . 9,482 845 - - 10,327
Other. . . . . . . . . . . 3,867 - - - 3,867
Transmission plant . . . . . 422,946 22,838 (1,106) - 444,678
Distribution plant . . . . . 175,012 46,030 (4,716) - 216,326
General plant. . . . . . . . 67,311 2,152 (135) - 69,328
Construction work in
progress . . . . . . . . . . 102,045 76,935 (2) - - 178,980
Plant held for future use. . . 22,325 (10,522)(3) - - 11,803
Plant acquisition
adjustments. . . . . . . . . 34,588 208 - - 34,796
Nuclear fuel . . . . . . . . . 309,643 41,229 (41,770) - 309,102
---------- -------- -------- ---- ----------
Total Utility Plant. . . . .$5,303,836 $202,168 $(53,145) $ - $5,452,859
---------- -------- -------- ---- ----------
---------- -------- -------- ---- ----------
- ----------------
Notes:
(1) Retirements have been charged to accumulated provision for depreciation
(Schedule VI).
(2) CWIP additions represent transfers to plant in service of $(93,151) and
additions and other miscellaneous transfers of $170,086.
(3) Plant held for future use additions represent transfers to deferred debits
of $(21,131) and additions and other miscellaneous transfers of $10,609.
1995.
81
SCHEDULE VI
OGLETHORPE POWER CORPORATION
ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1993
(DOLLARS IN THOUSANDS)
BALANCE RETIREMENTS ADJUSTMENTS BALANCE
BEGINNING ANNUAL LESS NET AND AT END
DESCRIPTION OF PERIOD ACCRUALS(1) SALVAGE(2) TRANSFERS OF PERIOD
- ----------- ---------- ----------- ----------- ----------- ---------
Production plant:
Steam. . . . . . . . . . . $ (285,448) $ (24,830) $ 402 $ - (309,876)
Nuclear. . . . . . . . . . (546,748) (85,612) 4,450 - (627,910)
Hydro. . . . . . . . . . . (1,261) (252) 8 - (1,505)
Other. . . . . . . . . . . (915) (40) - - (955)
Transmission plant . . . . . (103,602) (11,057) 2,027 - (112,632)
Distribution plant . . . . . (27,105) (6,681) 3,295 - (30,491)
General plant. . . . . . . . (18,887) (4,240) 2,931 - (20,196)
Nuclear fuel . . . . . . . . (145,850) (48,996) 73,773 - (121,073)
Plant acquisition
adjustments. . . . . . . . (26,435) (1,061) - - (27,496)
Other miscellaneous. . . . . (5,926) (805) - - (6,731)
----------- --------- ------- ---- -----------
Total Accumulated
Provision For
Depreciation . . . . . . $(1,162,177) $(183,574) $86,886 $ - $(1,258,865)
----------- --------- ------- ---- -----------
----------- --------- ------- ---- -----------
- ----------------
Notes:
(1) Amount of annual accrual charged to:
Expense $(171,431)
Other accounts (12,143)
---------
$(183,574)
---------
---------
(2) Property Retirements:
Book cost $ 87,581
Removal cost 2,617
Salvage materials (3,312)
---------
$ 86,886
---------
---------
82
SCHEDULE VI
OGLETHORPE POWER CORPORATION
ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1992
(DOLLARS IN THOUSANDS)
BALANCE RETIREMENTS ADJUSTMENTS BALANCE
BEGINNING ANNUAL LESS NET AND AT END
DESCRIPTION OF PERIOD ACCRUALS(1) SALVAGE(2) TRANSFERS OF PERIOD
- ----------- ---------- ----------- ----------- ----------- ---------
Production plant:
Steam. . . . . . . . . . . $ (262,639) $ (24,924) $ 2,115 $ - $ (285,448)
Nuclear. . . . . . . . . . (466,631) (84,093) 3,976 - (546,748)
Hydro. . . . . . . . . . . (1,010) (251) - - (1,261)
Other. . . . . . . . . . . (873) (42) - - (915)
Transmission plant . . . . . (96,070) (10,795) 3,263 - (103,602)
Distribution plant . . . . . (22,134) (6,165) 1,194 - (27,105)
General plant. . . . . . . . (15,469) (3,921) 503 - (18,887)
Nuclear fuel . . . . . . . . (181,833) (55,635) 91,618 - (145,850)
Plant acquisition
adjustments. . . . . . . . (25,229) (1,206) - - (26,435)
Other miscellaneous. . . . . (5,025) (901) - - (5,926)
----------- --------- -------- ---- -----------
Total Accumulated
Provision For
Depreciation . . . . . . . $(1,076,913) $(187,933) $102,669 $ - $(1,162,177)
----------- --------- -------- ---- -----------
----------- --------- -------- ---- -----------
- ----------------
Notes:
(1) Amount of annual accrual charged to:
Expense $(170,916)
Other accounts (17,017)
---------
$(187,933)
---------
---------
(2) Property Retirements:
Book cost $103,215
Removal cost 1,538
Salvage materials (2,084)
---------
$102,669
---------
---------
83
SCHEDULE VI
OGLETHORPE POWER CORPORATION
ACCUMULATED PROVISION FOR DEPRECIATION OF UTILITY PLANT
FOR THE YEAR ENDED DECEMBER 31, 1991
(DOLLARS IN THOUSANDS)
BALANCE RETIREMENTS ADJUSTMENTS BALANCE
BEGINNING ANNUAL LESS NET AND AT END
DESCRIPTION OF PERIOD ACCRUALS(1) SALVAGE(2) TRANSFERS OF PERIOD
- ----------- ---------- ----------- ----------- ----------- ---------
Production plant:
Steam. . . . . . . . . . . $(237,102) $ (25,603) $ 66 $ - $ (262,639)
Nuclear. . . . . . . . . . (379,311) (93,931) 6,611 - (466,631)
Hydro. . . . . . . . . . . (756) (254) - - (1,010)
Other. . . . . . . . . . . (829) (44) - - (873)
Transmission plant . . . . . (86,901) (10,301) 1,132 - (96,070)
Distribution plant . . . . . (19,493) (5,229) 2,588 - (22,134)
General plant. . . . . . . . (11,731) (3,856) 118 - (15,469)
Nuclear fuel . . . . . . . . (169,122) (54,481) 41,770 - (181,833)
Plant acquisition
adjustments. . . . . . . . (23,970) (1,259) - - (25,229)
Other miscellaneous. . . . . (4,137) (888) - - (5,025)
--------- --------- ------- ---- -----------
Total Accumulated
Provision For
Depreciation . . . . . . $(933,352) $(195,846) $52,285 $ - $(1,076,913)
--------- --------- ------- ---- -----------
--------- --------- ------- ---- -----------
- ----------------
Notes:
(1) Amount of annual accrual charged to:
Expense $(184,094)
Other accounts (11,752)
---------
$(195,846)
---------
(2) Property Retirements:
Book cost $ 53,047
Removal cost 1,631
Salvage materials (2,393)
---------
$ 52,285
---------
---------
84
SCHEDULE X
OGLETHORPE POWER CORPORATION
SUPPLEMENTARY INCOME STATEMENT INFORMATION
DECEMBER 31, 1993, 1992 AND 1991
(DOLLARS IN THOUSANDS)
COLUMN A COLUMN B
- -------- -----------------------
CHARGED TO COSTS AND EXPENSES
-----------------------------
ITEM 1993 1992 1991
---- ---- ---- ----
Maintenance & repairs. . . . . . . . . . . . . . $67,572 $57,890 $74,050
Taxes other than payroll and income taxes:
Real & personal property taxes . . . . . . . . 21,992 14,640 22,431
J
- -
85
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 31st1st day
of March, 1994.April 1996.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION &
TRANSMISSION CORPORATION)
By: /s/ J. CALVIN EARWOOD
---------------------------------------------------------------------------------
J. CALVINCalvin EARWOOD, CHAIRMAN OF THE BOARD
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ J. CALVIN EARWOOD Chairman of the Board, March 31, 1994
- --------------------------- Director (Principal Executive
J. CALVIN EARWOOD Officer)
/s/ T. D. KILGORE President and Chief Executive March 31, 1994
- --------------------------- Officer (Principal Executive
T. D. KILGORE Officer)
/s/ JOHN S. DEAN, SR. Secretary-Treasurer (Principal March 31, 1994
- --------------------------- Financial Officer)
JOHN S. DEAN, SR.
/s/ EUGEN HECKL Senior Vice President and Chief March 31, 1994
- --------------------------- Financial Officer (Principal
EUGEN HECKL Financial Officer)
/s/ LARRY N. BROWNLEE Controller March 31, 1994
- --------------------------- (Principal Accounting Officer)
LARRY N. BROWNLEE
/s/ JMON WARNOCK Director March 31, 1994
- ---------------------------
JMON WARNOCK
/s/ CHARLES R. FENDLEY Director March 31, 1994
- ---------------------------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 March 31, 1994
- --------------------------- GEORGE C. MARTIN
86Director April 1, 1996
- --------------------------
GEORGE C. MARTIN
/s/ J. G. MCCALMON Director April 1, 1996
- --------------------------
J. G. MCCALMON
82
SIGNATURE TITLE DATE
--------- ----- ----
/s/ J. G. MCCALMON Director March 31, 1994
- ---------------------------
J. G. MCCALMON
/s/ D. A. ROBINSON, III Director March 31, 1994
- ---------------------------
D. A. ROBINSON, III
/s/ JAMES E. ESTES Director March 31, 1994
- ---------------------------
JAMES E. ESTES
/s/ LARRY N. CHADWICK Director March 31, 1994
- ---------------------------
LARRY N. CHADWICK
/s/ SIMMIE KING Director March 31, 1994
- ---------------------------
SIMMIE KING
/s/ W. F. FARR Director March 31, 1994
- ---------------------------
W. F. FARR
/s/ GARY T. DRAKE Alternate Director March 31, 1994
- ---------------------------
GARY T. DRAKE
/s/ JEFF S. PIERCE, JR. Director March 31, 1994
- ---------------------------
JEFF S. PIERCE, JR.
/s/ DONALD C. COOPER Director March 31, 1994
- ---------------------------
DONALD C. COOPER
/s/ HERBERT CHURCH Director March 31, 1994
- ---------------------------
HERBERT CHURCH
/s/ MAC F. OGLESBY Director March 31, 1994
- ---------------------------
MAC F. OGLESBY
/s/ BENNY W. DENHAM Director March 31, 1994
- ---------------------------
BENNY W. DENHAM
/s/ E. L. MCLOCKLIN Director March 31, 1994
- ---------------------------
E. L. MCLOCKLIN
/s/ SAM RABUN Director March 31, 1994
- ---------------------------/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 March 31, 1994
- --------------------------- E. J. MARTIN, JR.
87Director 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
SIGNATURE TITLE DATE
--------- ----- ----
/s/ J. D. WILLIAMS Director March 31, 1994
- ---------------------------
J. D. WILLIAMS
/s/ RONNIE FLEEMAN Director March 31, 1994
- ---------------------------
RONNIE FLEEMAN
/s/ D. LAMAR COOPER Director March 31, 1994
- ---------------------------
D. LAMAR COOPER
/s/ BARRY H. MARTIN Director March 31, 1994
- ---------------------------/s/ BARRY H. MARTIN Director April 1, 1996
- --------------------------
BARRY H. MARTIN
/s/ JOHN B. FLOYD, JR. Director March 31, 1994
- --------------------------- 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/ STEVE RAWL, SR. Director March 31, 1994
- ---------------------------
STEVE RAWL, SR.
/s/ JAMES GRUBBS Director March 31, 1994
- ---------------------------
JAMES GRUBBS
/s/ SAMMY M. JENKINS Director March 31, 1994
- ---------------------------
SAMMY M. JENKINS
/s/ J. M. SHERRER Director March 31, 1994
- ---------------------------
J. M. SHERRER
/s/ JACK D. VICKERS Director March 31, 1994
- ---------------------------
JACK D. VICKERS
/s/ C. W. COX, JR. Director March 31, 1994
- ---------------------------
C. W. COX, JR.
/s/ JOHNNIE CRUMBLEY Director March 31, 1994
- ---------------------------
JOHNNIE CRUMBLEY
/s/ JARNETT W. WIGINGTON Director March 31, 1994
- ---------------------------
JARNETT W. WIGINGTON
/s/ BOB JERNIGAN Director March 31, 1994
- ---------------------------
BOB JERNIGAN
/s/ C. WILLARD MIMS Director March 31, 1994
- ---------------------------
C. WILLARD MIMS
/s/ JAMES E. DOOLEY Director March 31, 1994
- ---------------------------
JAMES E. DOOLEY
/s/ WILLIS T. WOODRUFF Director March 31, 1994
- ---------------------------
WILLIS T. WOODRUFF
88
SIGNATURE TITLE DATE
--------- ----- ----
/s/ HUBERT HANCOCK Director March 31, 1994
- ---------------------------
HUBERT HANCOCK
/s/ BOB J. DICKENS Director March 31, 1994
- ---------------------------
BOB J. DICKENS
/s/ W. W. ARCHER Director March 31, 1994
- --------------------------- W. W. ARCHER
89Director April 1, 1996
- --------------------------
W. W. ARCHER
84
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.
9085