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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.D. C. 20549
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FORM 10-K
(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 19951997
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ______ TO ______
COMMISSION FILE NO. 33-7591
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OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION)
(Exact name of registrant as specified in its charter)
GEORGIA 58-1211925
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
POST OFFICE BOX 1349 30085-1349
2100 EAST EXCHANGE PLACE (Zip Code)
TUCKER, GEORGIA
(Address of principal executive
offices)
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 to such
filing requirements for the past 90 days. Yes _X_ No ____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 stockand non-voting common equity
held by nonaffiliatesnon-affiliates of the registrant. NONE
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. THE REGISTRANT IS A
MEMBERSHIP CORPORATION AND HAS NO AUTHORIZED OR OUTSTANDING EQUITY SECURITIES.
Documents Incorporated by Reference: NONE
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OGLETHORPE POWER CORPORATION
19951997 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
ITEM PAGE
---- ----- ----------- -----
PART I
1 Business ...............................................................Business........................................................................................... 1
Oglethorpe Power Corporation .........................................Corporation..................................................................... 1
The Members of Oglethorpe ............................................ 8
TheMembers...................................................................................... 9
Member Requirements and Power Supply System .............................................. 11Resources................................................... 13
Certain Factors Affecting the Electric Utility Industry.......................................... 18
Other Information................................................................................ 21
2 Properties......................................................................................... 22
Generating Facilities............................................................................ 22
Co-Owners of the Plants and the Plant and Transmission Agreements .... 21
2 Properties .............................................................Agreements................................................. 25
3 Legal Proceedings ...................................................... 25Proceedings.................................................................................. 28
4 Submission of Matters to a Vote of Security Holders .................... 25Holders................................................ 28
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters .. 26Matters.............................. 29
6 Selected Financial Data ................................................ 26Data............................................................................ 29
7 Management's Discussion and Analysis of Financial Condition and Results of Operations ............................................. 27Operations.............. 30
7A Quantitative and Qualitative Disclosures About Market Risk......................................... 41
8 Financial Statements and Supplementary Data ............................ 35Data........................................................ 41
9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure .............................................. 53Disclosure............... 61
PART III
10 Directors and Executive Officers of the Registrant ..................... 53Registrant................................................. 61
11 Executive Compensation .................................................Compensation............................................................................. 65
12 Security Ownership of Certain Beneficial Owners and Management .........Management..................................... 67
13 Certain Relationships and Related Transactions .........................Transactions..................................................... 67
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K .......8-K................................... 68
i
SELECTED DEFINITIONS
When used herein the following terms will have the meanings indicated below:
TERM MEANING
---- -------- ------------- ---------------------------------------------------------------------------------------------------
ADSCR Annual Debt Service Coverage Ratio
AFUDC Allowance for Debt and EquityFor 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 AgencyEMC Electric Membership Corporation
EPI Entergy Power, Inc.
EPMI Enron Power Marketing, Inc.
FERC Federal Energy Regulatory Commission
FFB Federal Financing Bank
G&T Generation and Transmission Cooperative
GEMC Georgia Electric Membership Corporation
GPC Georgia Power Company
GPSC Georgia Public Service Commission
GSOC Georgia System Operations Corporation
GTC Georgia Transmission Corporation (An Electric Membership 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 OglethorpeLEM LG&E Energy Marketing Inc.
MEAG Municipal Electric Authority of Georgia
MFI Margins for Interest
MW Megawatts
MWh Megawatt-hours
NRC Nuclear Regulatory Commission
Oglethorpe Oglethorpe Power CorporationPCBs Pollution Control Revenue Bonds
PCR Percentage Capacity Responsibility
PPA Prior Period Adjustment
PURPA Public Utility Regulatory Policies Act
RUS Rural Utilities Service formerly known as the Rural Electrification
Administration
SEPA Southeastern Power Administration
SONOPCO Southern Nuclear Operating Company
TIER Times Interest Earned Ratio
TVA Tennessee Valley Authority
ii
PART I
ITEM 1. BUSINESS
OGLETHORPE POWER CORPORATION
GENERAL
Oglethorpe Power Corporation (An Electric Membership Generation &
Transmission Corporation)
("Oglethorpe") is ana Georgia electric generation and
transmission cooperative ("G&T")membership corporation incorporated in 1974
in the State of
Georgia. It isand headquartered in metropolitan Atlanta. Oglethorpe is entirely owned by its 39 retail
electric distribution cooperative members (the "Members"), who, in turn, are
entirely owned by their retail consumers. Oglethorpe is the largest G&Telectric cooperative
in the United States in terms of operating revenues, assets, kilowatt-hour ("kWh")kWh sales and,
through the Members, consumers served. It is one of the ten largest electric utilities in the
United States in terms of land area served. Oglethorpe hasand its subsidiary,
EnerVision, Inc., Tailored Energy Solutions ("EnerVision"), have approximately
427
full-time and 39 part-time170 employees.
As with cooperatives generally, Oglethorpe operates on a not-for-profit
basis. Oglethorpe's principal business is providing wholesale electric servicepower to
the Members. (See "Power Supply Business" herein.) The Members are local
consumer-owned distribution cooperatives providing retail electric service on a
not-for-profit basis. In general, the membershipcustomer base of the distribution cooperative Members consists of
residential, commercial and industrial consumers within specific geographic
areas. The Members serve approximately 1.11.2 million electric consumers (meters)
representing a total population of approximately 2.62.8 million people. MEMBER CONTRACTS
Each Member currently purchases capacityFor information on the Members,
see "THE MEMBERS."
Oglethorpe's mailing address is 2100 East Exchange Place, Post Office Box
1349, Tucker, Georgia 30085-1349, and energyits telephone number is (770) 270-7600.
COOPERATIVE PRINCIPLES
Cooperatives like Oglethorpe are business organizations owned by their
members, which are also either their wholesale or retail customers. As
not-for-profit organizations, cooperatives are intended to provide services to
their members at the lowest possible cost, in part by eliminating the need to
produce profits or a return on equity. Cooperatives may make sales to
non-members, the effect of which is generally to reduce costs to members. Today,
cooperatives operate throughout the United States in such diverse areas as
utilities, agriculture, irrigation, insurance and credit.
All cooperatives are based on similar business principles and legal
foundations. Generally, an electric cooperative designs its rates to recover its
cost-of-service and plans to collect a reasonable amount of revenues in excess
of expenses (i.e., margins) to increase its patronage capital, which is the
equity component of its capitalization. Any such margins, which are considered
capital contributions (i.e., equity) from Oglethorpe
pursuantthe members, are held for the accounts
of the members and returned to a long-term, "all-requirements" wholesale power contract between
Oglethorpethem when the board of directors of the
cooperative deems it prudent to do so. The timing and amount of any actual
return of capital to the members depends on the financial goals of the
cooperative and the Member (each a "Wholesale Power Contract"cooperative's loan and collectively
the "Wholesale Power Contracts"). The existing Wholesale Power Contracts
have a term ending December 31, 2025 and continue thereafter until terminated
by three years' written notice by Oglethorpe or the respective Member. Each
Wholesale Power Contract provides that, except for power purchased from the
Southeastern Power Administration ("SEPA"), Oglethorpe shall sell and deliver
to the Member, and the Member shall purchase and receive from Oglethorpe, all
electric capacity and energy that the Member requires for the operation of
its system to the extent that Oglethorpe has capacity and energy and
facilities available. Oglethorpe supplies the capacity and energy
requirements of the Members from a combination of owned and leased generating
plants and from power purchased under long-term contracts with other power
suppliers, principally Georgia Power Company ("GPC"), a wholly owned
subsidiary of The Southern Company. In 1995, the aggregate SEPA allocation
to the Members was 542 megawatts ("MW") plus associated energy, representing
approximately 11% of total Member peak demand and approximately 5% of total
Member energy requirements. The amount of capacity and energy available from
SEPA is not expected to increase in an amount sufficient to serve a material
portion of the projected growth in the Members' requirements. (See "Member
Demand and Energy Requirements" herein and "THE MEMBERS OF OGLETHORPE--Contracts
with SEPA".)
PROPOSEDsecurity agreements.
CORPORATE RESTRUCTURING
For some time,
Oglethorpe and the Members have been discussing various
options to provide the Members greater flexibility for meeting their power
supply needscompleted a corporate restructuring (the
"Corporate Restructuring") on March 11, 1997, in an increasingly competitive utility environment. These
discussions led to a restructuring plan approved by Oglethorpe's Board of
Directors in December 1995 to dividewhich Oglethorpe was divided
into three specialized operating companies to respond to increasing competition
and regulatory changes 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 andindustry. Oglethorpe's retention of the generation business.
Oglethorpe's Board believes there are significant potential benefits to
the Members of having the transmission
business was sold to and the system operations
businessis now owned and 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,by Georgia Transmission
Corporation (An Electric Membership Corporation) ("GTC") has
been incorporated, a Georgia electric
membership corporation formed for future use as the transmission companythat purpose. Oglethorpe's system operations
business was sold to and is now owned and operated by Georgia System Operations
Corporation ("GSOC") has been incorporated as, a Georgia non-profitnonprofit corporation formed for future use asthat purpose.
1
Oglethorpe and the system operations company. On
March 29, 1996,39 Members are the Boardsowners and members of GTC. Oglethorpe, the
39 Members and GTC are the owners and members of GSOC.
GTC purchased the transmission business for an appraised fair market value
purchase price of approximately $709 million. The purchase price was paid
primarily by GTC's assumption of a portion (approximately 16.86%) of
Oglethorpe's long-term secured debt in an amount equal to approximately $686
million. Approximately $541 million of this debt (payable to the Rural Utilities
Service ("RUS"), the Federal Financing Bank ("FFB") and CoBank, ACB ("CoBank"))
became the sole obligation of GTC, and GSOC approved an agreement
(the "Restructuring Agreement"Oglethorpe was released from all
liability with regard to this debt. The remaining $145 million of debt assumed
by GTC relates to Oglethorpe's pollution control revenue bonds ("PCBs"). While
GTC assumed and agreed to pay this $145 million of debt, Oglethorpe was not
legally released from its obligation to repay this debt. For financial reporting
purposes, this debt is not shown on Oglethorpe's balance sheet and is shown on
Oglethorpe's capitalization table as being assumed by GTC. (See "SELECTED
FINANCIAL DATA" in Item 6 and "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA" in
Item 8). The remainder of the purchase price was paid by GTC from cash obtained
through a loan from National Rural Utilities Cooperative Finance Corporation
("CFC") and the assumption of approximately $2 million of other Oglethorpe
liabilities. Oglethorpe also made a special patronage capital distribution of
approximately $49 million to the Members which sets forthwas used by the termsMembers to
establish equity in 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 provide initial working capital to GTC. GTC would thereafter own and operate
the transmission system and providenow
provides transmission services to the Members, Oglethorpe and third parties. (See Note 6 of NotesGTC
succeeded to Financial Statements
in Item 8 for a summaryall of Oglethorpe's investments in electric plant,
including transmissionrights and distribution plant.obligations with respect to the
Integrated Transmission System ("ITS"). (See "Relationship with GTC" herein for
further discussion of the ITS.)
The system operations business and assets sold to GSOC consist of the system
control center and related energy control and revenue metering systems
equipment. The purchase price fortotaled approximately $9.4 million and was paid by
(i) GSOC's assumption of Oglethorpe's obligations under an existing note held by
the transmission business would be equalRUS, (ii) delivery of a purchase money note payable to Oglethorpe, and (iii)
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 valueassumption of certain deferred charges. Ifother liabilities of Oglethorpe. GSOC now operates 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 operationscontrol center and related computer and dispatch equipment, to GSOC.
GSOC would thereafter own and operate theprovides system operations center and provide system
operation services to the Members,
Oglethorpe GTC and third parties.GTC.
Oglethorpe also planscontinues to operate its power supply business and administer its
power purchase contracts. Oglethorpe retained all of its owned and leased
generation assets and, as of December 31, 1997, had total assets of
approximately $4.5 billion and total long-term debt of approximately $3.6
billion. (See "Power Supply Business" herein and "MEMBER REQUIREMENTS AND POWER
SUPPLY RESOURCES.")
Effective with the Corporate Restructuring, the Members amended Oglethorpe's
Bylaws 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 awith an 11-member board of
directors consisting of six directors elected from the Members, four independent
outside directors and Oglethorpe's President and Chief Executive Officer, rather thanOfficer. This
smaller board replaced Oglethorpe's currentformer 39-member board which is comprised of
directors nominated from and 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(See "DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT" in accordanceItem 10 for further information.)
Contemporaneously with the numberCorporate Restructuring, Oglethorpe replaced its
prior Consolidated Mortgage and Security Agreement, dated as of retail customers servedSeptember 1,
1994, by such Member and then
elected byamong Oglethorpe and the United States of America, acting through
the Administrator of the RUS, and certain other mortgagees (the "RUS Mortgage"),
with an Indenture, dated as of March 1, 1997, from Oglethorpe to SunTrust Bank,
Atlanta ("SunTrust"), as trustee (as supplemented, the "Mortgage Indenture"). As
did the RUS Mortgage, the Mortgage Indenture constitutes a votelien on substantially
all of the owned tangible and certain intangible property of Oglethorpe. (See
"Electric Rates" herein and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--General--RATES AND FINANCIAL COVERAGE
REQUIREMENTS" in Item 7 for further discussion of the revenue requirements of
the Mortgage Indenture.)
2
Immediately after the Corporate Restructuring, Oglethorpe's corporate name
was changed from "Oglethorpe Power Corporation (An Electric Membership
Generation & Transmission Corporation)" to "Oglethorpe Power Corporation (An
Electric Membership Corporation)" to reflect that it no longer provides
transmission services.
In connection with the Corporate Restructuring, Oglethorpe undertook to
remove the costs of its marketing services business from its general rates and
recover these costs on a fee-for-services basis beginning in 1998. To do so,
Oglethorpe created a subsidiary, EnerVision, to which it has transferred its
marketing services business, which includes 30 full-time and 13 part-time
employees. Further, all or part of this subsidiary may be sold to third parties.
Oglethorpe does not expect any of these potential actions to have a material
effect on its financial condition or results of operations.
POWER SUPPLY BUSINESS
Oglethorpe provides wholesale electric service to the 39 Members pursuant to
long-term, take-or-pay Wholesale Power Contracts described herein that obligate
the Members on a one-member, one-vote basis.
In adoptingjoint and several basis to pay rates sufficient to pay all the
Restructuring Agreement,costs of owning and operating Oglethorpe's Board recommendedpower supply business. (See
"Wholesale Power Contracts" herein.) Oglethorpe supplies capacity and energy to
the Members that they become membersfrom a combination of owned and leased generating plants and power
purchased under long-term contracts with other power suppliers and power
marketers. GTC provides transmission services to the Members for delivery of the
Members' power purchases.
Oglethorpe owns or leases undivided interests in thirteen generating units.
These units provide Oglethorpe with a total of 3,335 megawatts ("MW") of
nameplate capacity, consisting of 1,500.6 MW of coal-fired capacity, 1,185 MW of
nuclear-fueled capacity, 632.5 MW of pumped storage hydroelectric capacity, 14.8
MW of oil-fired combustion turbine capacity and GSOC2.1 MW of conventional
hydroelectric capacity. Oglethorpe's generating units consist of 30% undivided
interests in the Edwin I. Hatch Plant ("Plant Hatch"), the Hal B. Wansley Plant
("Plant Wansley") and that they jointhe Alvin W. Vogtle Plant ("Plant Vogtle"), a 60%
undivided interest in the Robert W. Scherer Unit No. 1 ("Scherer Unit No. 1"), a
60% undivided interest in the Robert W. Scherer Unit No. 2 ("Scherer Unit No.
2"), a 100% interest in the Tallassee Project at the Walter W. Harrison Dam
("Tallassee") and a 74.61% undivided interest in the Rocky Mountain Pumped
Storage Hydroelectric Facility ("Rocky Mountain"). Plant Hatch consists of two
nuclear-fueled units, with nameplate ratings of 810 MW and 820 MW, respectively.
Plant Wansley consists of two coal-fired units, each with a nameplate rating of
865 MW. Plant Wansley also includes a 49.2 MW oil-fired combustion turbine.
Plant Vogtle consists of two nuclear-fueled units, each with a nameplate rating
of 1,160 MW. Plant Scherer consists of four coal-fired units, each with a
nameplate rating of 818 MW, with Oglethorpe GTChaving an interest only in Scherer
Unit No. 1 and GSOCScherer Unit No. 2. Tallassee is a conventional hydroelectric
facility with a nameplate rating of 2.1 MW. Rocky Mountain is a 3 unit pumped
storage hydroelectric facility with a nameplate rating of 847.8 MW. (See "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES--General" and "GENERATING
FACILITIES--General" in executing an agreement (the "Member Agreement"Item 2.")
Participants in Plants Hatch, Wansley and Vogtle and Scherer Units No. 1 and
No. 2 also include the Municipal Electric Authority of Georgia ("MEAG"), the
City of Dalton ("Dalton") and Georgia Power Company ("GPC"). GPC serves as
operating agent for these units. GPC is also a participant in Rocky Mountain
which is operated by Oglethorpe.
Oglethorpe utilizes long-term power marketer arrangements to those matters contemplated inreduce the Restructuring Agreement that directly
involvecost
of power to the Members. Oglethorpe has entered into power marketer agreements
with LG&E Energy Marketing Inc. ("LEM") effective January 1, 1997, for
approximately 50% of the load requirements of the Members in their capacities as separate corporations. The Member
Agreement will specifyand with Morgan
Stanley Capital Group Inc. ("Morgan Stanley") effective May 1, 1997, with
respect to 50% of the formforecasted load requirements of transmission contracts and system
operation contracts to be signed by the Members. The Member Agreement will
also provide, subject to the approval of the Rural Utilities Service ("RUS"),
formerly known as the Rural Electrification Administration, that Oglethorpe
and each Member executing the Member Agreement would execute a new wholesale
power contract to govern the purchase and sale of power between Oglethorpe
and each such Member. Each Member signing the new wholesale power contract
would have a choice as to whether or not to participate in future power supply
projects sponsored by Oglethorpe. Such Members would be free to own
generation directly and to engage in purchases and sales with other power
suppliers. To the extent such Members
2
choose to satisfy their projected load growth from sources other than
Oglethorpe, the growth in Oglethorpe's revenues from the sale of power would
decrease but the growth in related expenses also would decrease.
Members agreeing to the new wholesale power contracts would have the
option to have energy and reserves priced on a pooled basis or to schedule
their capacity and associated energy separately at pricesLEM
agreements are based on the costactual requirements of production. GSOC would administer the newMembers during the
contract term, whereas the Morgan Stanley agreement represents
3
a fixed supply obligation. Under these power pool contemplatedmarketer agreements, Oglethorpe
purchases energy at fixed prices covering a portion of the costs of energy to
its Members. LEM and Morgan Stanley, in turn, have certain rights to market
excess energy from the Oglethorpe system. All of Oglethorpe's existing
generating facilities and power purchase arrangements are available for use by
the
new wholesale power contractsLEM 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)Morgan Stanley for the benefitterm of the respective agreements. Oglethorpe
continues to be responsible for all pool participants. Thethe costs of its system resources but
receives revenue from LEM and Morgan Stanley for the use of the resources. (See
"MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--General" and "--Power Marketer
Arrangements.")
Oglethorpe purchases a total of approximately 1,250 MW of power pool arrangementpursuant to
power purchase agreements with GPC, Big Rivers Electric Corporation ("Big
Rivers"), Entergy Power, Inc. ("EPI"), and Hartwell Energy Limited Partnership
("Hartwell"). Oglethorpe has also would
allowcontracted to purchase 275 MW of peaking
capacity from Florida Power Corporation during the participants to pool resource reserves.summer of 1998. (See "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES--Power Purchase and Sale Arrangements.")
WHOLESALE POWER CONTRACTS
In connection with the restructuring,Corporate Restructuring, Oglethorpe plansand each of the
Members entered into substantially similar Amended and Restated Wholesale Power
Contracts, dated August 1, 1996 (the "Wholesale Power Contracts"), each of which
extends through December 31, 2025. Each Wholesale Power Contract permits a
Member to adopt specific
implementation procedurestake future incremental power requirements either from Oglethorpe or
other sources. Under its Wholesale Power Contract, a Member is unconditionally
obligated on an express "take-or-pay" basis for a fixed allocation of
Oglethorpe's costs for its existing generation and purchased power resources, as
well as the costs with respect to any future resources in which such Member
elects to participate. Each Wholesale Power Contract specifically provides that
the Member must make payments whether or not power is delivered and whether or
not a plant has been sold or is otherwise unavailable. Oglethorpe is obligated
to use its reasonable best efforts to operate, maintain and manage its resources
in accordance with prudent utility practices. The Wholesale Power Contracts
provide that Oglethorpe will be responsible for power supply planning, resource
procurement and sales of capacity and energy for Members unless a Member
notifies Oglethorpe that it does not want Oglethorpe to provide those services
to it.
Each Member's cost responsibility under its Wholesale Power Contract is
based on agreed-upon fixed percentage capacity responsibilities ("PCRs"). PCRs
have been assigned for all of Oglethorpe's existing generation and purchased
power resources. PCRs for any future resource will be assigned only to Members
choosing to participate in that resource. The Wholesale Power Contracts provide
that each Member will be jointly and severally responsible for all costs and
expenses of all existing generation and purchased power resources, as well as
for any future resources (whether or not such Member has elected to participate
in such future resource) that are approved by 75% of Oglethorpe's Board of
Directors and 75% of the Members. For resources so approved in which less than
all Members participate, costs are shared first among the participating Members,
and if all participating Members default, each non-participating Member is
expressly obligated to pay a proportionate share of such default.
The Wholesale Power Contracts contain covenants by each Member (i) to
establish, maintain and collect rates and charges for the existing bylaw provision that grantsservice of its
electric system, and (ii) to conduct its business in a manner which will produce
revenues and receipts at least sufficient to enable the Member to pay to
Oglethorpe, when due, all amounts payable by 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 contractWholesale
Power Contract and to pay any and all other amounts payable from, or which might
constitute a charge or a lien upon, the revenues and receipts derived from its
electric system, including all operation and maintenance expenses and the
principal of, premium, if any, and interest on all indebtedness related to assign its rights and obligations under such wholesale
power contract to another party withthe
Member's electric system.
See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES" for 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) executiondescription of
the Member Agreement by the Members, execution of new wholesale power
contracts by Oglethorpe and the Members, and execution of the transmission
contracts and system operation contracts specified in the Member Agreement,
(3) RUS approval of new wholesale power contracts and the restructuring,
(4) governmental, lender and other third party consents, authorizations,
waivers, orders and approvals, (5) receipt by GTC and GSOC of certain capital
contributions by the Members and (6) assurances from rating agencies that the
ratings on Oglethorpe's outstanding fixed rate PCBs would not be lowered as a
result of the restructuring and that such rating agencies would assign to any
comparable bonds issued by GTC the same or better credit rating as assigned
to Oglethorpe's fixed rate PCBs. Most of these conditions may be waived by
Oglethorpe's Board, subject to RUS approval in certain instances.
The restructuring is expected to take the remainder of 1996 to complete,
although limited aspects of the restructuring may become effective sooner if
specific conditions set forth in the Restructuring Agreement are met. In
light of the significant conditions that must be satisfied, including RUS and
other governmental and third-party approvals and assurances and receipt of
various agreements from the Members, Oglethorpe cannot predict the actual timing
of or the ultimate likelihood of full implementation of the restructuring or
governance changes. Until implementation of the restructuring, Oglethorpe
will continue its current operations, and until satisfaction of the conditions
applicable to the new governance structure, Oglethorpe will continue under
its existing governance structure.
MEMBER DEMAND AND ENERGY REQUIREMENTS
The following table shows the aggregate peakMembers' demand and energy requirements ofand the Members for the years 1993 through 1995 andrelated power supply
resources. See also
shows
the amounts of such requirements supplied by Oglethorpe and SEPA. For the
years 1993 through 1995, demand and energy requirements increased at an
average annual compound growth rate of 6.4% and 5.9%, respectively.
34
DEMAND (MW) ENERGY REQUIREMENTS (MWH)
--------------------------------------- -----------------------------------------
TOTAL TOTAL
REQUIRE- SUPPLIED BY SUPPLIED BY REQUIRE- SUPPLIED BY SUPPLIED BY
MENTS(1) OGLETHORPE(2) SEPA(3) MENTS OGLETHORPE(2) SEPA(3)
--------- ------------- ----------- ---------- ------------- -----------
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"MEMBER REQUIREMENTS AND POWER SUPPLY SYSTEM--Power SalesRESOURCES--Power Marketing
Arrangements--RELATED AGREEMENTS" regarding supplemental agreements to and Purchases from GPC--POWER PURCHASE ARRANGEMENTS" and "--Otherthe
Wholesale Power Purchases".)
(3) Supplied by SEPA through existing contracts withContracts relating to the Members. (See "THE
MEMBERS OF OGLETHORPE--Contracts with SEPA".)
In 1995, Cobb EMC and Jackson EMC accounted for approximately 11.3% and
10.4% of Oglethorpe's total revenues, respectively.
SEASONAL VARIATIONS
The demand for energy by the Members is influenced by seasonal weather
conditions. Historically, Oglethorpe's peak demand occurs during the months
of June through September. (See "Electric Rates" herein.) Energy revenues
track energy costs as they are incurred and also fluctuate month to month.
Capacity revenues reflect the recovery of Oglethorpe's fixed costs which do
not vary significantly from month to month; therefore, the capacity revenues
are billed and recognized in equal monthly amounts.
DEMAND MANAGEMENT
Oglethorpe and the Members have implemented various demand management
programs. The program goal, developed in conjunction with Oglethorpe's
integrated resource planning process, is to modify demand patterns so that
current resources are used efficiently and the need for additional generating
resources is delayed. The programs that have been implemented include an
energy efficient home program (the "Good Cents Home" program),
remote-controlled switching of air conditioners, water heaters and irrigation
pumps, residential energy audits and public appeals to encourage consumers to
use less energy during periods of peak demand. The demand management programs
have reduced, and are expected to continue to reduce, the growth of peak
demand and have also resulted in an increase in off-peak sales. (See "THE
POWER SUPPLY SYSTEM--Future Power Resources".)power marketer agreements.
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,together with its revenues from all other sources, will be sufficient,
but only sufficient to pay all costs of its system, including 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, andall costs associated with decommissioning or
otherwise retiring any generating facility, to provide for the establishment and
maintenance of reasonable reserves. Rates are also required to be established so asreserves, and to enable Oglethorpe to comply with all
financial requirements (including coverage ratios) under the Consolidated Mortgage and Security Agreement, dated as of September 1,
1994 (the "RUS Mortgage"), among Oglethorpe, as mortgagor, and the United
States of America acting through the Administrator of RUS, CoBank, ACB,
formerly known as the National Bank for Cooperatives ("CoBank"), Credit
Suisse, acting by and through its New York Branch ("Credit Suisse"), and
SunTrust Bank, Atlanta, formerly known as Trust Company Bank ("SunTrust"), as
4
trustee under certain pollution control bond indentures identified in the RUS
Mortgage.Indenture. (See "General--RATES"MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--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 reflectUnder the amortization of the deferred margins accumulated
from 1985 through 1995, which amounts will be fully amortized by the end of
1996. (See Note 1 of Notes to Financial Statements in Item 8.) Oglethorpe's
rate policy provides for a number of separate rates for certain qualified
consumer loads, which are designed to have a favorable impact on the Members'
competitiveness for certain new commercial and industrial loads. (See "THE
MEMBERS OF OGLETHORPE--Service Area and Competition".)
Oglethorpe's rates, as established by its Board of Directors, are
subject to review and approval by RUS.Mortgage Indenture, Oglethorpe is required, subject to any
necessary regulatory approval, to establish and collect rates which are
reasonably expected, together with other revenues of Oglethorpe, to yield an MFI
Ratio described herein for each fiscal year equal to at least 1.10. Margins for
Interest ("MFI") is defined in the Mortgage Indenture to be the sum of net
margins of Oglethorpe (which includes revenues of Oglethorpe subject to refund
at a later date but excludes provisions for (i) non-recurring charges to income,
including the non-recoverability of assets or expenses, except to the extent
Oglethorpe determines to recover such charges in rates, and (ii) refunds of
revenues collected or accrued subject to refund) plus interest charges, whether
capitalized or expensed, on all indebtedness secured under the RUS
Mortgage
Indenture or by a lien equal or prior to implement rates designed to maintain a Times the lien of the Mortgage Indenture,
including amortization of debt discount and expense or premium but excluding
interest charges on indebtedness assumed by GTC ("Interest Earned
Ratio ("TIER"Charges"), plus any
amount included in net margins for accruals for federal or state income taxes
imposed on income after deduction of not less than 1.05, a Debt Service Coverage Ratio ("DSC")interest expense. MFI takes into account
any item of not less than 1.0 and an Annual Debt Service Coverage Ratio ("ADSCR")net margin, loss, gain or expenditure of not less than 1.25.any affiliate or subsidiary
of Oglethorpe only if Oglethorpe has always metreceived such net margins or exceededgains as a
dividend or other distribution from such affiliate or subsidiary or if
Oglethorpe has made a payment with respect to such losses or expenditures. "MFI
Ratio" is the TIER, DSC and
ADSCR requirementsratio of the RUS Mortgage. Oglethorpe's current policy isMFI to set rates to meettotal Interest Charges for a TIER of 1.07 in 1996.given period. (See
"General-RATES"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--General--RATES AND FINANCIAL COVERAGE REQUIREMENTS" in Item 7.)
The formulary rate established by Oglethorpe in the rate schedule to the
Wholesale Power Contracts employs a rate methodology under which all categories
of costs are specifically separated as components of the formula to determine
Oglethorpe's revenue requirements. The rate schedule also implements the
responsibility for fixed costs assigned to each Member (i.e., the PCR). The
monthly charges for capacity and other non-energy charges are based on
Oglethorpe's annual budget. Such capacity and other non-energy charges may be
adjusted by the Board of Directors, if necessary, during the year through an
adjustment to the annual budget. Energy charges reflect the pass-through of
actual energy costs whether incurred from generation or purchased power
resources or under the power marketing arrangements.
The rate schedule formula also includes a prior period adjustment ("PPA")
mechanism designed to ensure that Oglethorpe achieves the minimum 1.10 MFI
Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum 1.10 MFI
Ratio would be accrued as of December 31 of the applicable year and collected
from the Members during the period April through December of the following year.
Amounts within a range from a 1.10 MFI Ratio to a 1.20 MFI Ratio are retained as
margins. Amounts, if any, by which Oglethorpe exceeds the maximum 1.20 MFI Ratio
would be charged against revenues as of
5
December 31 of the applicable year and refunded to the Members during the period
April through December of the following year. The rate schedule formula is
intended to provide that no rate revision shall be
effective unless approvedfor the collection of revenues which, together with revenues
from all other sources, are equal to all costs and expenses recorded by
Oglethorpe, plus amounts necessary to achieve at least the minimum 1.10 MFI
Ratio.
Under the terms of Oglethorpe's prior RUS but suchMortgage, all rate revisions by
Oglethorpe were subject to the approval of RUS. Under the Mortgage Indenture and
related loan contract with RUS, however, adjustments to Oglethorpe's rates to
reflect changes in Oglethorpe's budgets are not subject to RUS approval, except
for any reduction in rates in a fiscal year following a fiscal year in which
Oglethorpe has failed to meet the minimum 1.10 MFI Ratio set forth in the
Mortgage Indenture. Changes to the rate schedule under the Wholesale Power
Contracts are subject to RUS approval. Oglethorpe's rates are not subject to the
approval of any other Federalfederal or state agency or authority, including the
Georgia Public Service Commission (the "GPSC").
To date, RUS has not reduced
or delayed the effectiveness of any rate increase proposed by Oglethorpe.
For information regarding future rates, see "General--RATES"MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--General--RATES AND
FINANCIAL COVERAGE REQUIREMENTS", "Results of Operations--FACTORS AFFECTING FUTURE
FINANCIAL PERFORMANCE" and "Proposed Restructuring" in Item 7.
CERTAIN FACTORS AFFECTING THE UTILITY INDUSTRY IN GENERAL
The electric utility industry is becoming increasingly competitive as a
result of deregulation, competing energy suppliers, technologies, and other
factors. The Energy Policy Act of 1992 (the "Energy Policy Act") amended the
Federal Power ActRELATIONSHIP WITH GTC
Oglethorpe and the Public Utility Holding Company Act39 Members are members of GTC. GTC provides transmission
services to the Members for delivery of the Members' power purchases from
Oglethorpe, Southeastern Power Administration ("SEPA") and any other power
suppliers. GTC also provides transmission services to Oglethorpe and third
parties. Oglethorpe has entered into a transmission agreement with GTC to
provide transmission services for third party transactions and for service to
Oglethorpe's headquarters and the administration building at Rocky Mountain.
GTC and the Members have entered into Member Transmission Service Agreements
(the "Member Transmission Agreements") under which GTC provides transmission
service to the Members pursuant to a transmission tariff. The Member
Transmission Agreements have a minimum term for network service for current load
until December 31, 2025. After an initial ten-year term, load growth above 1995
requirements may, with notice to GTC, be served by others. The Member
Transmission Agreements provide that if a Member elects to purchase a part of
its network service elsewhere, it must pay appropriate stranded costs to protect
the other Members from any rate increase that could otherwise occur. Under the
Member Transmission Agreements, Members have the right to design, construct and
own new distribution substations.
The Member Transmission Agreements provide that the Members are responsible,
on a joint and several basis, for all of GTC's costs relating to its
transmission business. The Member Transmission Agreements contain express
covenants of the Members to set and collect retail rates sufficient to allow the
Members to meet their respective obligations under the Member Transmission
Agreements. The rate formula set forth in the transmission tariff is intended to
recover all costs and expenses paid or incurred by GTC. The rate expressly
includes in the description of costs to be recovered all principal and interest
on indebtedness of GTC (including any indebtedness of Oglethorpe assumed by
GTC). The rate further expressly provides for increased competition among wholesale electric suppliers and increased accessGTC to transmission services by such suppliers. Theearn sufficient margins to
satisfy the requirements of its new competitive environment
is subject to rapidly evolving regulatory policy at both the federal and
state levels,mortgage indenture, which is based on a shiftsubstantially
similar to a market-driven environment from a
regulated one. Significant legislative developmentsOglethorpe's Mortgage Indenture.
The GTC transmission tariff and regulatory
developments atassociated Member Transmission Agreements
were developed to be consistent with federal transmission policy as expressed in
Order No. 888 of the Federal Energy Regulatory Commission ("FERC"). FERC's Order
No. 888 mandates open access to essentially all transmission systems in order to
promote competition in the bulk power markets and provides that non-regulated
utilities (such as Oglethorpe and GTC) must provide access to their transmission
systems on reciprocal terms and conditions in state commissionsorder to obtain transmission from
FERC-regulated utilities. The transmission tariff and Member Transmission
Agreements have been designed to facilitate the operation of GTC in the new
6
regulatory environment and, accordingly, provide for GTC to serve on a
nondiscriminatory basis both member and non-member customers on terms intended
to meet FERC's reciprocity requirement. For information regarding a FERC filing
relating to GTC and Oglethorpe, see "LEGAL PROCEEDINGS" in Item 3.
GTC owns approximately 2,400 miles of transmission line and approximately
460 substations of various voltages. In connection with the Corporate
Restructuring, GTC succeeded to Oglethorpe's rights in the ITS, which consists
of transmission facilities owned by GTC, GPC, MEAG and Dalton. Through
agreements, common access to the combined facilities that compose the ITS
enables the owners to use their combined resources to make deliveries to or for
their respective consumers, to provide transmission service to third parties and
to make off-system purchases and sales.
GTC's rights and obligations with respect to the ITS are expectedgoverned by the
Revised and Restated Integrated Transmission System Agreement with GPC (the
"ITSA"), which was assigned to continue to clarifyGTC in connection with the policy and
regulatory framework for increased competition. (See "THE MEMBERS OF
OGLETHORPE--Service Area and Competition".)
A number of other significant factors have affected the operations of
electric utilities. They include the cost of fuelCorporate
Restructuring. The ITSA provides for the generationtransmission and distribution of
electric energy recoveryin the State of Georgia, other than in certain counties, and for
bulk power transactions, through use of the ITS. The ITS was established in
order to obtain the benefits of a coordinated development of the parties'
transmission facilities and to make it unnecessary for any party to construct
duplicative facilities. The ITS consists of all transmission facilities,
including land, owned by the parties on the date the ITSA became effective and
those thereafter acquired, which are located in the State of Georgia (other than
in the excluded counties) and which are used or usable to transmit power of a
certain minimum voltage and to transform power of a certain minimum voltage and
a certain minimum capacity (the "Transmission Facilities"). GPC has entered into
agreements with 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 committee (the "Joint Committee") composed of
two representatives from each of GTC, GPC, MEAG and Dalton. 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. Each ITS participant is generally required to
maintain an original cost investment in the Transmission Facilities in
proportion to their respective Peak Loads (as defined in the ITSA).
GTC and GPC are parties to a Transmission Facilities Operation and
Maintenance Contract (the "Transmission Operation Contract"), under which GPC
provides System Operator Services (as defined in the Transmission Operation
Contract) for GTC. In addition, GPC is required to provide such supervision,
operation and maintenance supplies, spare parts, equipment and labor for the
operation, maintenance and construction of Transmission Facilities as may be
specified by GTC. GPC is also required to perform certain emergency work under
the Transmission Operation Contract. GTC is permitted, upon notice to GPC, to
perform, or contract with others for the performance of, certain services
performed by GPC. Absent termination or amendment of the Transmission Operation
Contract, however, GPC will continue to perform System Operator Services for
GTC. The term of the Transmission Operation Contract will continue from year to
year unless terminated by either party upon four years' notice. GTC is required
to pay its proportionate share of the cost for the services provided by GPC.
RELATIONSHIP WITH GSOC
Oglethorpe, the 39 Members and GTC are members of existing facilities, fluctuating
rates of load growth,GSOC. GSOC now owns and
operates the effects of conservationsystem control center and energyprovides system operations services to
the Members, Oglethorpe and GTC. GTC has contracted with GSOC to provide certain
transmission system operation services including reliability monitoring,
switching operations, and the real-time management on
the use of electric energy and compliance with environmental and other
governmental regulations.
All of the factors mentioned above present an increasing challenge to
companies in the electric utility industry, including Oglethorpe and the
Members, to reduce costs, improve the management of resources and respond to
the changing environment. (See "Proposed Restructuring" herein and "THE
POWER SUPPLY SYSTEM--General", "--Future Power Resources" and
"--Environmental and Other Regulations".)
5transmission system.
7
RELATIONSHIP WITH GPC
Oglethorpe's relationship with GPC is a significant factor in several
aspects of Oglethorpe's business. GPC is one of Oglethorpe's principal suppliersuppliers
of purchased power, and Oglethorpe is one of GPC's largest customers. In 1995,
Oglethorpe derived 6% of its total revenues from sales to GPC, making GPC oneAll of
Oglethorpe's largest customers. Substantially all of Oglethorpe'sco-owned generating facilities, were purchased at various stages of construction from
GPC and most were constructed andexcept Rocky Mountain, are now operated
by GPC. Oglethorpe
completed the constructionGPC on behalf of itself as a co-owner and is now the primary owner and operatingas agent for the Rocky Mountain Project, a pumped storage hydroelectric facility
("Rocky Mountain"), in which it acquired an interest from GPC. Oglethorpe
purchases coordination services fromother co-owners.
GPC to schedule its power resources and
its off-system purchases and sales. Oglethorpe, through the Members, is one
of GPC's principalare competitors in the State of Georgia
for electric service to new customers that have a choice of supplier under the
Georgia Territorial Electric Service Act, which was enacted in 1973 (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--ServiceMEMBERS--Service Area and Competition", "THECompetition," "MEMBER
REQUIREMENTS AND POWER SUPPLY SYSTEM--General", "--FuelRESOURCES--Power Purchase and Sale
Arrangements--POWER PURCHASES FROM GPC," "--Power Purchase and Sale
Arrangements--OTHER POWER PURCHASES," "GENERATING FACILITIES-- Fuel Supply", "--Power Sales to and Purchases from GPC",
"--Transmission and Other Power System Arrangements", in
Item 2, "CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--Co-Owners of the
Plants--Georgia Power Company",Plants--GEORGIA POWER COMPANY" and "--The Plant Agreements", "--Agreements
Relating to the Integrated Transmission System", and "--The Joint Committee
Agreement". in Item 2.
RELATIONSHIP WITH RUS
FederalHistorically, federal loan programs administered by RUS have provided the
principal source of financing for electric cooperatives. Direct loans from RUS have
been a major source of funding for the Members, while loansLoans guaranteed by RUS
and made by the Federal Financing Bank ("FFB")FFB have been a major source of funding for Oglethorpe. Through provisions of the RUS Mortgage, RUS exercises
substantial control and supervision over OglethorpeHowever, in such areas as
accounting, the issuance of secured indebtedness, rates and charges for the
sale of power, construction and acquisition of facilities, and the purchase
and sale of power.
In
recent years, there have been legislative, administrative and budgetary
initiatives intended to reduce or, in some cases, eliminate federal funding for
electric cooperatives. In any event, Oglethorpe's management does not anticipate
the need for loans guaranteed by RUS well into the future. (See "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES-- Power Marketer Arrangements" for a
discussion of the long-term power marketer arrangements.)
In connection with the Corporate Restructuring, Oglethorpe replaced its RUS
Mortgage with the Mortgage Indenture, which, like the RUS Mortgage, constitutes
a lien on substantially all of the owned tangible and certain intangible
property of Oglethorpe. Oglethorpe also entered into a new loan contract with
RUS in connection with the Mortgage Indenture. Under the new loan contract, RUS
has retained approval rights over certain significant actions and arrangements,
including, without limitation, (i) significant additions to or dispositions of
system assets, (ii) significant power purchase and sale contracts, (iii) changes
to the Wholesale Power Contracts, including the rate schedule contained therein,
(iv) changes to plant ownership and operating agreements and (v) in limited
circumstances, issuance of additional secured debt. The extent of RUS's approval
rights under the new loan contract with Oglethorpe is substantially less than
the supervision and control RUS has traditionally exercised over borrowers under
its standard loan and security documentation. In addition, the RUS loan and guarantee
programs have been characterized byMortgage
Indenture improves Oglethorpe's ability to borrow funds in the imposition of increasingly
problematic terms and conditions and extended delays in access to necessary
funding.
For fiscal year 1996, the Congress set the level of funding for the 100%
guarantee program at $300 million, which if sustained at that level in future
years would not likely provide adequate funding for the transmission and
power supply needs of RUS borrowers. For fiscal year 1997, the
Administration's budget proposal to Congress calls for a level of $400
million for the guarantee program. Congress historically has increased
Administration-proposed lending levels to those necessary to meet borrower
demand. Notwithstanding historical practices, the future cost, availability
and magnitude of RUS-guaranteed loans cannot be predicted. Seepublic capital
markets. (See "THE MEMBERS
OF OGLETHORPE--Members'MEMBERS--Members' Relationship with RUS" for a discussion of
the impact of changes in the budget proposalRUS lending program on the direct loan program.
For a number of years, RUS has been re-evaluating its regulatoryMembers.)
RELATIONSHIP WITH INTELLISOURCE
In conjunction with the Corporate Restructuring and
lending relationship with its borrowers through what it has described as a comprehensive rule-making project. RUS has saidpart of its
continuing efforts to reduce costs, effective February 1, 1997, Oglethorpe
implemented a business alliance with Intellisource, Inc., a national provider of
outsourcing services. Pursuant to an agreement with Intellisource, approximately
150 support services division employees of Oglethorpe in the purposeareas of
accounting, auditing, communications, human resources, facility management,
purchasing, telecommunications and information technology became employees of
Intellisource. Oglethorpe, GTC and GSOC are key customers of Intellisource and
are being served on-site by the project
is to improve the credit-worthinessmanagers and employees of loans made or guaranteed by RUS. In
addition to adopting new rules regulating policies and procedures for insured
and guaranteed loans and lien accommodations, RUS has published a proposed
rule describing a new form of wholesale power contract and a new standard
form of loan contract for distribution borrowers. RUS has not, however,
pursued finalization of the new form of wholesale power contract earlier
proposed. RUS has adopted a new standard form of mortgage for distribution
borrowers.
6
In advance notices of proposed rule-makings, RUS also has requested
suggestions for revisions to its standard form of mortgage for power supply
borrowers and comments on proposals for creditOglethorpe's former
support for loans to power
supply borrowers. While no formal notice has been issued by RUS, RUS has
advised borrowers informally that it will for the present use a case-by-case
approach to power supply borrower mortgage reform and member credit support.
These rule-makings continue to take many months or years to complete and the
outcome of these various rule-making initiatives, whether others may be
forthcoming, whether any of such rule-making initiatives may achieve the
objectives stated by RUS, or the extent to which such initiatives may affect
Oglethorpe or the Members cannot be predicted.
7services division.
8
THE MEMBERS OF OGLETHORPE
SERVICE AREA AND COMPETITION
The Members are identified in Item 10(a) of this Reportlisted below and include 39 of the 42 electric distribution
cooperatives in the State of Georgia.
Altamaha EMC Habersham EMC Planters EMC
Amicalola EMC Hart EMC Rayle EMC
Canoochee EMC Irwin EMC Satilla Rural EMC
Carroll EMC Jackson EMC Sawnee EMC
Central Georgia EMC Jefferson EMC Slash Pine EMC
Coastal EMC Lamar EMC Snapping Shoals EMC
Cobb EMC Little Ocmulgee EMC Sumter EMC
Colquitt EMC Middle Georgia EMC Three Notch EMC
Coweta-Fayette EMC Mitchell EMC Tri-County EMC
Excelsior EMC Ocmulgee EMC Troup EMC
Flint EMC Oconee EMC Upson County EMC
Grady EMC Okefenoke Rural EMC Walton EMC
GreyStone Power Pataula EMC Washington EMC
Corporation, an EMC
The Members serve approximately 1.11.2 million electric consumers (meters)
representing a total population of approximately 2.62.8 million people. The Members serve a region
covering approximately 40,000 square miles, which is approximately 70% of the
land area in the State of Georgia, served by the owners of the
ITS, encompassing 150 of the State's 159 counties.
Sales by the Members in 19951997 amounted to approximately 18.220 million megawatt-hours
("MWh"), with approximately 72% to residential consumers, 26% to commercial and
industrial consumers and 2% to other consumers. No single consumer of any Member constituted more than
1% of the Members' aggregate sales in 1995. The Members are the principal
suppliers for the power needs of rural Georgia. While the Members do not serve
any major cities, portions of their service territories are in close proximity
to urban areas and are experiencing substantial growth due to the expansion of
urban areas, including metropolitan Atlanta, into suburban areas and the growth
of suburban areas into neighboring rural areas. The Members have experienced
average annual compound growth rates from 19931995 through 19951997 of 4.0%6% in number of
consumers 5.9%and 5% in MWh sales and 6.3% in electric
revenues.sales.
The Territorial Act regulates the service rights of all retail electric
suppliers in the State of Georgia. Pursuant to the Territorial Act, the GPSC
assigned substantially all areas in the State to specified retail suppliers;
however, the Territorial Act permits competition among electric suppliers for
new retail loads of 900 kilowatts or more outside existing municipal limits.
Except for these 900-kilowatt loads,suppliers.
With limited exceptions, the Members have the exclusive right to provide retail
electric service in their respective assigned territories, which are predominately
outside of the municipal limits.limits existing at the time the Territorial Act was
enacted in 1973. The chief exception to this rule of exclusivity is that
electric suppliers may compete for most new retail loads of 900 kilowatts or
greater. The GPSC may not
reassign territory or transfer service except in limited circumstances
provided byonly if it determines that an electric
supplier has breached the Territorial Act.tenets of public convenience and necessity. The GPSC
may transfer service for specific premises only:only if: (i) upon a determination by the GPSC determines,
after joint application of electric suppliers and proper notice and hearing,
that the public convenience and necessity require a transfer of service from one
electric supplier to another; or (ii) upon a finding bythe GPSC finds, after proper notice and
hearing, that an electric supplier's service to a premise is not adequate or
dependable or that its rates, charges, service rules and regulations
unreasonably discriminate in favor of or against the consumer utilizing such
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 assigneeSince 1973, unlike in the electric supplier has breached the tenets
of public convenience and necessity.
As referenced above,utility industry in general, the
Territorial Act allowshas allowed limited competition among electric utilities in
Georgia by allowing 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
9
actively engaged in competition with other retail electric suppliers for these
new industrialcommercial and commercialindustrial loads. The number of commercial and industrial
loads served by the Members continues to increase annually. While the
competition for 900-kilowatt900 kilowatt loads represents only limited competition in
Georgia, retail competition in the electric
utility industry is currently rare and this competition has given Oglethorpe and the Members the opportunity
to develop resources and strategies to operate in an increasingly competitive
market.
The electric utility industry in the United States is undergoing fundamental
change and is becoming increasingly competitive. (See "CERTAIN FACTORS AFFECTING
THE ELECTRIC UTILITY INDUSTRY--General" and "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Competition" in Item
7.)
From time to time, utilities are approached by other parties interested in
purchasing their systems. Some of the Members have been approached in the past
by third parties indicating an interest in purchasing their systems. The
Wholesale Power Contract between Oglethorpe and each Member providesContracts provide that noa Member may reorganize,not dissolve, liquidate or
otherwise wind up its affairs without Oglethorpe's approval. A Member may not
consolidate or merge with any person or reorganize or change the form of its
business organization from an electric membership corporation or sell, transfer,
lease or transferotherwise dispose of all or a substantial portionsubstantially all of its assets (or maketo any
agreement therefor), so
long as Oglethorpe has notes outstanding to RUS andperson, whether in a single transaction or series of transactions, unless
either: (i) the FFB, without first
paying such portion of any such outstanding notes as may be determinedtransaction is approved by Oglethorpe withor (ii) other specified
conditions are satisfied including, but not limited to, an assumption agreement
by the prior written consent of RUS and otherwise complying with
such reasonable terms and conditions astransferee, satisfactory to Oglethorpe, and RUS may require. The
enforceabilitycontaining an assumption by the
transferee of the RUS formperformance and observance 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 partiesevery covenant and that it will expect cooperative distribution
utilities to retire a proportionate sharecondition of
the 8
associated G&T indebtednessMember under the Wholesale Power Contract, and certifications of accountants
as to pay other appropriate costs and expensescertain specified financial requirements of the G&T as a condition of a buyout.transferee (taking into
account the transfer).
COOPERATIVE STRUCTURE
The Members are cooperatives that operate their systems on a not-for-profit
basis. Accumulated margins derived after payment of operating expenses and
provision for depreciation constitute patronage capital of the consumers of the
Members. Refunds of accumulated patronage capital to the individual consumers
may be made from time to time subject to limitations contained in mortgages
between the Members and RUS or loan documents with other lenders. The RUS
mortgages generally prohibit such distributions unless, after any such
distribution, the Member's total equity will equal at least 40% (30% in the case
of Members, if any, that have the new form of RUS loan documents, discussed
below) 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,year (provided that equity is at least 20% in the case of Members, if any, that
borrow fromhave the new form of RUS distribute accumulated patronage capital
from time to time subject to their respective financial policies and in
conformity with their respective RUS mortgages.loan documents). (See "Members' Relationship Withwith 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".CORPORATION-- Wholesale Power Contracts.") The revenues of the Members are not
pledged as security to Oglethorpe but are the source from which moneys are
derived by the Members to pay for power supplied by Oglethorpe under the
Wholesale Power Contracts. Revenues of the Members that borrow from RUS are, however, pledged under
thetheir respective RUS mortgages of the Members.or loan documents with other lenders.
RATE REGULATION OF MEMBERS
Through provisions in the loan documents securing loans to the Members, RUS
exercises control and supervision over the rates for the sale of power of the
Members that borrow from it 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.it. The individual RUS mortgages of thesuch Members require them to
design rates with a view to maintaining an average TIERTimes Interest
10
Earned Ratio ("TIER") of not less than 1.50 and an average DSCDebt Service Coverage
Ratio ("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
ofby any Federalfederal or state agency or authority other than RUS, the Territorial Act
prohibits the Members from unreasonable discrimination in the setting of rates,
charges, service rules or regulations and requires the Members to obtain GPSC
approval of long-term borrowings.
CONTRACTS WITH SEPA
In additionSnapping Shoals EMC, Mitchell EMC, Troup EMC, Walton EMC and Cobb EMC have
prepaid their RUS indebtedness and are no longer RUS borrowers. Each of these
Members now has a rate covenant with its current lender. Other Members may also
pursue this option. To the extent that a Member who is not an RUS borrower
engages in wholesale sales or transmission in interstate commerce, it would be
subject to energy received from Oglethorperegulation by FERC under the WholesaleFederal Power Contracts, the Members purchase hydroelectric power under contracts with
SEPA. In 1995, the aggregate SEPA allocation to the Members was 542 MW plus
associated energy, representing approximately 11% of total Member peak demand
and
9
approximately 5% of total Member energy requirements. (See "OGLETHORPE POWER
CORPORATION--Member Contracts" and "--Member Demand and Energy Requirements"
and the table thereunder.)
On December 8, 1994, SEPA issued its final Power Marketing Policy for the
Georgia - Alabama - South Carolina System of Projects. This policy will
govern the renewal of SEPA's contracts with the Members. There were no
significant changes in this final marketing policy and the Members'
allocation of capacity and energy remained unchanged.
SEPA has contracted with The Southern Company for scheduling and
dispatching services for SEPA's generating projects in Georgia and Alabama
and for transmission services to certain preference customers. During 1994,
SEPA began negotiating revised arrangements for these services. Originally
scheduled for renewal on May 31, 1994, SEPA extended the term of the Members'
contracts until January 31, 1995, with a provision automatically to extend
one month at a time thereafter until negotiations with The Southern Company
are completed. An order was sought from FERC requiring the provision of
these services at just and reasonable rates; however, SEPA and The Southern
Company have continued negotiations in an effort to reach agreement.
During 1995, legislative proposals were made that would have resulted in
the privatization of several of the federal power marketing administrations,
in particular SEPA. Ultimately, no proposal for the privatization of the
power marketing administrations was included in the final budget proposal.
The President's Budget for fiscal year 1997 does not include any proposals to
privatize the federal power marketing administrations. The ultimate outcome
of this issue in Congress cannot be predicted with certainty.Act.
MEMBERS' RELATIONSHIP WITH RUS
FederalThrough provisions in the loan documents securing loans to the Members, RUS
also exercises control and supervision over the Members that borrow from it in
such areas as accounting, borrowings, construction and acquisition of
facilities, and the purchase and sale of power.
Historically, federal loan programs providing direct loans from RUS to
electric cooperatives have been a major source of funding for the Members.
However, in recent years, there have been legislative, administrative and
budgetary initiatives intended to reduce or, in some cases, eliminate federal
funding for electric cooperatives. In addition, the RUS loan and guarantee
programs have been characterized by the imposition of increasingly problematic
terms and conditions and extended delays in access to necessary funding. RUS has
adopted new standard forms of mortgages and loan contracts for distribution
borrowers the stated purpose of which is to update and modernize the loan and
security documentation employed by RUS. Distribution borrowers are required to
adopt these new forms as a condition to receiving new loans from RUS.
Recent changes and proposals for further changes have made the direct loan
program administered by RUS more costly. Uncertainties continue about the level of
funding available under the RUS loan program. The Rural Electrification Loan
Restructuring Act of 1993 eliminated the long-standing 2%5% loan program and
substituted a new program, the interest rates for which are based on rates being
paid on municipal bonds with comparable maturities. Certain borrowers with
either low consumer density or higher-than-average rates and lower-than-average
consumer income are still eligible for special loans at 5%. The President's
budget proposal for fiscal year 1999 includes a 5%reduction under these loan
programs, and replacement with a new program with interest rates based on
Treasury rates. However, no legislation has yet been introduced to implement
this proposed program. The future cost, availability and amount of RUS direct
and guaranteed loans which may be available to the Members cannot be predicted.
A number of Members have recently prepaid their RUS indebtednessMEMBERS' RELATIONSHIP WITH GTC AND GSOC
For information about the Members' relationship with GTC and are
no longer RUS borrowers. Other Members may also pursue this option. (See
"Rate Regulation of Members" herein.) For further information regarding the
RUS program,GSOC, see
"OGLETHORPE POWER CORPORATION--Relationship with RUS".
10GTC" and "--Relationship with
GSOC."
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 1997, the aggregate SEPA allocation to the Members was 523 MW plus associated
energy, representing approximately 10% of total Member peak demand and
approximately 5% of total Member energy requirements. New 20-year contracts
between each of the Members and SEPA have been executed, effective as of October
1, 1996. The provisions of the new contracts are essentially the same as the
existing contracts with a few exceptions. Each Member must schedule its energy
allocation, and each Member has designated Oglethorpe to perform this function.
11
THEPursuant to a separate agreement, Oglethorpe will schedule, through GSOC, the
Members' SEPA power deliveries. Further, each Member may be required, if certain
conditions are met, to contribute funds for capital improvements for Corps of
Engineers projects from which its allocation is derived in order to retain the
allocation. GTC delivers the Members' SEPA purchases under its network tariff
and contract with each Member. The new contracts are subject to RUS approval.
The amount of capacity and energy available from SEPA is not expected to
increase in an amount sufficient to serve a material portion of the projected
growth in the Members' requirements. (See "OGLETHORPE POWER
CORPORATION--Wholesale Power Contracts" and "MEMBER REQUIREMENTS AND POWER
SUPPLY SYSTEMRESOURCES--Member Demand and Energy Requirements" and the table
thereunder.)
During 1996, 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 passed by Congress. The President's Budget for
fiscal year 1999 does not include any proposals to privatize the federal power
marketing administrations. The ultimate outcome of this issue in Congress cannot
be predicted with certainty.
12
MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES
GENERAL
Oglethorpe supplies the current capacity and energy requirements ofto the Members from a combination of
owned and leased generating plants and from power purchased under long-term
contracts with other power suppliers. These
resources are scheduledsuppliers and dispatched so as to minimize the operating cost
of Oglethorpe's system. In addition, Oglethorpe purchases and sells capacity
and energy in the bulk power market to make the best use of its resources and
thus minimize the cost of capacity and energy delivered to the Members.
The following table sets forth certain information with respect to the
generating facilities in which Oglethorpe currently has ownership or
leasehold interests, all of which are in commercial operation. The Edwin I.
Hatch Plant ("Plant Hatch"), the Hal B. Wansley Plant ("Plant Wansley"), the
Alvin W. Vogtle Plant ("Plant Vogtle") and the Robert W. Scherer Units No. 1
and No. 2 ("Scherer Units No. 1 and No. 2") are co-owned by Oglethorpe, GPC,
the Municipal Electric Authority of Georgia ("MEAG") and the City of Dalton
("Dalton"). GPC is the operating agent for each of these plants, except
Rocky Mountain. Rocky Mountain is co-owned by Oglethorpe and GPC, and
Oglethorpe is the operating agent. Oglethorpe is the sole owner of the
Tallassee Project at the Walter W. Harrison Dam ("Tallassee"). (See
"CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--The Plant
Agreements".)
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(2)
Unit No. 2 Coal 30 259.5 1978 N/A(2)
Combustion Turbine Oil 30 14.8 1980 N/A(2)
Plant Scherer (near Forsyth)
Unit No. 1 Coal 60 490.8 1982 N/A(2)
Unit No. 2 Coal 60 490.8 1984 N/A(2)
Tallassee (near Athens) Hydro 100 2.1 1986 2023
Rocky Mountain Pumped Storage
(near Rome) Hydro 74.61 632.5 1995 2027
-------
Total Ownership 3,335.0
-------
-------
______________________
(1) Oglethorpe has an ownership interest in all of the facilities except
Scherer Unit No. 2. The 60% interest in Scherer Unit No. 2 is leased
under leases that expire in 2013, subject to options to renew for a
total of 8.5 years.
(2) Coal-fired units and combustion turbines do not operate under operating
licenses similar to those granted to nuclear units by the Nuclear
Regulatory Commission and to hydroelectric plants by the Federal Energy
Regulatory Commission.marketers. Oglethorpe owns or
leases 3,335 MW of nameplate capacity, consisting of 1,500.6 MW of coal-fired
capacity, 1,185 MW of nuclear-fueled capacity, 632.5 MW of pumped storage
hydroelectric capacity, 14.8 MW of oil-fired combustion turbine capacity and 2.1
MW of conventional hydroelectric capacity. (See "GENERATING FACILITIES--General"
and "--Plant Performance" in Item 2 for a description of Oglethorpe's generating
facilities.) These resources are generally scheduled and dispatched so as to
minimize the operating cost of Oglethorpe's system. However, Oglethorpe has
entered into long-term arrangements with power marketers to better utilize its
resources to reduce the cost of capacity and the other co-owners of the above plants also own
transmission facilities which together form the ITS. Through agreements,
common accessenergy delivered to the combined facilities that composeMembers, in
part by giving certain dispatch rights to 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.power marketers. (See "Transmission and Other Power System"Power
Marketer Arrangements" herein and "CO-OWNERS OF THE PLANTSherein.)
MEMBER DEMAND AND THE PLANT AND
TRANSMISSION AGREEMENTS--Agreements Relating to Integrated Transmission
System".)
PLANT PERFORMANCEENERGY REQUIREMENTS
The following table sets forth certain operating performance information
of eachshows the aggregate peak demand and energy requirements
of the major generating facilities in whichMembers for the years 1995 through 1997, and also shows the amounts of
such requirements supplied by Oglethorpe currently has
ownership or leasehold interests:and SEPA. From 1995 through 1997,
demand and energy requirements increased at an average annual compound growth
rate of 4.1% and 5.6%, respectively.
EQUIVALENT AVAILABILITY(1) CAPACITY FACTOR(2)
-------------------------- ------------------
Unit 1995 1994 1993 1995 1994 1993
- ---- ---- ---- ---- ---- ---- ----DEMAND (MW) ENERGY REQUIREMENTS (MWH)
--------------------------------------------------- -----------------------------------------
TOTAL SUPPLIED BY SUPPLIED BY TOTAL SUPPLIED BY SUPPLIED BY
REQUIREMENTS(1) OGLETHORPE(2) SEPA(3) REQUIREMENTS OGLETHORPE(2) SEPA(3)
----------------- --------------- --------------- ------------- ------------- -----------
Plant Hatch
Unit No. 1 .......... 98% 84% 76% 100% 85% 77%
Unit No. 2 .......... 75 78 75 75 79 75
Plant Vogtle
Unit No. 1 .......... 98 86 85 98 86 86
Unit No. 2 .......... 89 91 87 90 91 87
Plant Wansley
Unit No. 1 .......... 90 92 88 56 62 71
Unit No. 2 .......... 89 88 90 56 58 73
Plant Scherer(3)
Unit No. 1 .......... 95 97 88 73 64 36
Unit No. 2 .......... 97 85 95 85 60 37
Rocky Mountain(4)
Unit No. 1 .......... 83 N/A N/A 16 N/A N/A
Unit No. 2 .......... 92 N/A N/A 15 N/A N/A
Unit No. 3 .......... 92 N/A N/A 16 N/A N/A1995.............................. 4,850 4,308 542 19,403,703 18,442,153 961,550
1996.............................. 5,045 4,503 542 20,793,864 19,807,101 986,763
1997.............................. 5,252 4,729 523 21,648,366 20,664,786 983,580
______________________- ------------------------
(1) Equivalent Availability is a measureSystem peak demand of the percentageMembers measured at the Members' delivery points
(net of time that a unit
was available to generate if called upon, adjustedsystem losses).
(2) Includes purchased power. (See "Power Marketer Arrangements," "Power
Purchase and Sale Arrangements--POWER PURCHASES FROM GPC" and "Power
Purchase and Sale Arrangements--OTHER POWER PURCHASES" herein.)
(3) Supplied by SEPA through contracts with the Members. (See "THE
MEMBERS--Contracts with SEPA.") Under the new SEPA contracts effective
October 1, 1996, the SEPA capacity allocation has been reduced by
approximately 3.7% for periods when the
unit is partially derated from the "maximum dependable capacity" rating.
(2) Capacity Factor is a measurelosses.
In 1997, Cobb EMC and Jackson EMC accounted for approximately 12.9% and
11.8% of Oglethorpe's total revenues, respectively. None of the output of a unitother Members
accounted for 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.
12
FUEL SUPPLY
Coal for Plant Wansley is purchased under a long-term contract, which is
estimated to be sufficient to provide the majority of the coal requirements
of Plant Wansley through 1997, with the remainder being provided through spot
market transactions. As of February 29, 1996, there was a 33-day coal supply
at Plant Wansley based on nameplate rating.
Low-sulfur "compliance" coal for Scherer Units No. 1 and No. 2 is
purchased under long-term contracts and spot market transactions. As of
February 29, 1996, the coal stockpile at Plant Scherer contained a 21-day
supply based on nameplate rating. During 1994, Plant Scherer was converted
to burn both sub-bituminous and bituminous coals, and a separate stockpile of
sub-bituminous coal was built in addition to the stockpile of bituminous coal.
The Scherer ownership and operating agreements were amended in 1993 to
allow each co-owner (i) to dispatch separately its respective ownership
interest in conjunction with contracting separately for long-term coal
purchases procured by GPC and (ii) to procure separately long-term coal
purchases. Pursuant to the amendments, Oglethorpe implemented separate
dispatch in 1994. Oglethorpe intends to continue to use GPCmuch as its agent for
fuel procurement. The co-owners have negotiated similar amendments to the
Plant Wansley Operating Agreement. Upon approval by RUS, Oglethorpe expects
to implement separate dispatch at Plant Wansley as well.
To take advantage of these changes at Plants Scherer and Wansley,
Oglethorpe formed a wholly owned subsidiary to acquire rail cars designed for
hauling coal from the western coal mining regions. The subsidiary, Black
Diamond Energy, Inc., has acquired 231 cars. Oglethorpe has entered into an
initial 15-year lease with the subsidiary which obligates Oglethorpe to pay
all of the ownership and operating expenses of the subsidiary relating to the
leased rail cars during the lease term.
For information relating to the impact that the Clean Air Act will have
on Oglethorpe, see "Environmental and Other Regulations" herein.
GPC, as operating agent, has the responsibility to procure nuclear fuel
for Plants Hatch and Vogtle. GPC has contracted with Southern Nuclear
Operating Company ("SONOPCO") to provide nuclear services, including nuclear
fuel procurement. SONOPCO employs both spot purchases and long-term
contracts to satisfy nuclear fuel requirements. The nuclear fuel supply and
related services are expected to be adequate to satisfy current and future
nuclear generation requirements.
Plants Hatch and Vogtle currently have on-site spent fuel storage
capacity. Based on normal operations and retention of all spent fuel in the
reactor, it is anticipated that existing on-site pool capacity would not be
sufficient in 2003 and 2009, respectively, to accept the number of spent fuel
assemblies that would normally be removed from the reactor during a
refueling. Contracts with the Department of Energy ("DOE") have been executed
to provide for the permanent disposal of spent nuclear fuel produced at
Plants Hatch and Vogtle. The services to be provided by DOE are scheduled to
begin in 1998; however, the DOE has stated that permanent nuclear waste
storage facilities will not be available by that date, and it is uncertain
when they will be available. If DOE does not begin receiving the spent fuel
from Plant Hatch in 2003 or from Plant Vogtle in 2009, alternative methods of
spent fuel storage will be needed. One option available is expansion of
spent fuel storage at the plant sites. (See "Environmental and Other
Regulations" herein for a discussion of the Nuclear Waste Policy Act and Note
1 of Notes to Financial Statements in Item 8 regarding nuclear fuel cost.)
PROPOSED CHANGES TO NUCLEAR PLANT OPERATING ARRANGEMENTS
In September 1992, GPC filed applications with the Nuclear Regulatory
Commission (the "NRC") to add SONOPCO to the operating license of each unit
of Plants Hatch and Vogtle and designate SONOPCO as the operator. The
application is currently pending before the Atomic Safety and Licensing
Board. SONOPCO, a
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
--------------------------
1995 1994
---------- ----------
SOURCES OF ENERGY:
Owned or Leased Generation ....... 18,402,839 16,924,038
Purchased -- GPC ............... 2,711,203 2,632,039
-- Others ............ 3,027,431 1,749,048
---------- ----------
Total Sources .............. 24,141,473 21,305,125
---------- ----------
DISTRIBUTION OF ENERGY:
Members .......................... 18,442,153 16,285,127
Non-Members -- GPC ............. 2,195,012 2,140,526
-- Others .......... 2,520,462 2,067,443
Transmission Losses .............. 983,846 812,029
---------- ----------
Total Distribution ......... 24,141,473 21,305,125
---------- ----------
The sales to GPC were made under the GPC Sell-back (as herein defined)
and the Coordination Services Agreement (the "CSA"). The purchases from GPC
were made under the Block Power Sale Agreement (the "BPSA") and the CSA.
GPC SELL-BACK
Pursuant to the contractual arrangements with GPC, Oglethorpe had an
obligation to sell to GPC, and GPC had an obligation to buy from Oglethorpe,
commencing with the commercial operation of each co-owned unit (other than
Rocky Mountain) and extending for various periods, a declining percentage of
Oglethorpe's entitlement to the capacity and energy of such unit (the "GPC
Sell-back"). As of May 31, 1995, the GPC Sell-back expired in accordance
with its terms for all units. For 1995, energy sales from the GPC Sell-back
represented less than 1% of total sales by Oglethorpe. Capacity and energy
revenues from the GPC Sell-back represented 1%10% of Oglethorpe's total revenues in 1995.
As GPC's entitlement1997. Due to
capacitygreater than average growth rates, certain of Oglethorpe's customers, including
its larger customers such as Cobb EMC and energyJackson EMC, have historically
accounted for an increasing percentage of Oglethorpe's total revenues. However,
under the GPC Sell-back
decreased,new Wholesale Power Contracts described above, a Member may choose to
supply all or a portion of its increased requirements with purchases from other
suppliers. Although the Members have contracted for significant portions of
their anticipated future needs by participating in Oglethorpe's increased entitlementpower marketer
agreements, certain of the Members' future needs during the terms of the power
marketer agreements could still be purchased from other suppliers. (See "Power
Marketer Arrangements" herein.)
SEASONAL VARIATIONS
The demand for energy by the Members is influenced by seasonal weather
conditions. Historically, Oglethorpe's peak demand has occurred during the
months of June through August. (See "OGLETHORPE POWER CORPORATION--Electric
Rates.") Energy revenues track energy costs as they are incurred and also
fluctuate month to month. Capacity revenues reflect the recovery of Oglethorpe's
fixed
13
costs, which do not vary significantly from month to month; therefore, capacity
charges are billed and capacity revenues are recognized in equal monthly
amounts.
POWER MARKETER ARRANGEMENTS
In 1996, Oglethorpe began utilizing power marketer arrangements to reduce
the cost of power to the Members. During 1997, Oglethorpe entered into long-term
power marketer agreements with LEM for approximately 50% of the load
requirements of the Members and with Morgan Stanley with respect to 50% of the
Members' then forecasted load requirements. The LEM agreements are based on the
actual requirements of the Members during the contract term, whereas the Morgan
Stanley agreement represents a fixed supply obligation. Generally, these
arrangements reduce the cost of supplying power to the Members by limiting the
risk of unit availability, by providing a guaranteed benefit for the use of
excess resources and by providing future power needs at a fixed price. All of
Oglethorpe's existing generating facilities and power purchase arrangements are
available for use by LEM and Morgan Stanley for the term of the respective
agreements. Oglethorpe continues to be responsible for all of the costs of its
system resources but receives revenue, as described below, from LEM and Morgan
Stanley for the use of the resources.
LEM AGREEMENTS
Effective January 1, 1997, Oglethorpe entered into power marketer agreements
with LEM for 50% of the load requirements of the Members. Under the agreements,
LEM is obligated to deliver, and Oglethorpe is obligated to take, approximately
50% of the load requirements of the participating Members less the load
requirements for certain customers who have the right to choose electric
suppliers, plus 50% of the delivery obligations under Oglethorpe's existing firm
power off-system sale contracts. For certain smaller customer choice loads, LEM
is obligated to deliver, if Oglethorpe requests, 50% of the associated load
requirements. Oglethorpe has the option of purchasing the energy requirements
for any customer choice load from another supplier. Oglethorpe is obligated to
sell and LEM is obligated to buy 50% of the output of each participating
Member's PCR share of the "must run" units (primarily nuclear units). Oglethorpe
is also obligated to make available the same share of all other resources, which
LEM may schedule. LEM does not have the right to the output of each unit was
usedupgrades to serve its own requirements. The increased costs thereof are
recovered through Member rates and through off-system sales transactions.
The historical ability ofthese
resources. LEM pays Oglethorpe to sell power from new units to GPC
under the GPC Sell-back while at the same time purchasing power from GPC
under lower-cost arrangements enabled Oglethorpe to moderate the effects of
the higher costs associated with new generatingthe energy taken,
subject to certain adjustments. Oglethorpe must pay LEM a contractually
specified price for each MWh purchased.
The LEM agreement relating to 37 of the 39 Members has a term extending
through 2011. With one year's notice, Oglethorpe has the right to terminate the
LEM agreement beginning in 2002. With 18 months' notice, LEM has the right to
terminate the LEM agreement beginning in 2005. The LEM agreement relating to the
other two Members has a term extending through 1999.
LEM is a subsidiary of LG&E Energy Corp., a Kentucky corporation, which is a
diversified energy services holding company. LG&E Energy Corp. is subject to the
informational requirements of the Securities Exchange Act of 1934, as amended,
and, in accordance therewith, files reports and other information with the
Commission.
MORGAN STANLEY AGREEMENT
Effective May 1, 1997, Oglethorpe entered into a power marketer agreement
with Morgan Stanley with respect to 50% of the Members' then forecasted load
requirements. The agreement obligates Oglethorpe to purchase fixed quantities of
energy at fixed prices. Each Member selected a term for its obligation, as well
as the portion of its then forecasted requirements to be purchased as a fixed
quantity. Oglethorpe is obligated to sell and Morgan Stanley is obligated to buy
50% of the output, in contractually fixed amounts, of each Member's PCR share
(for the term and portion selected) of the "must run" units on Oglethorpe's costs(primarily nuclear
units). Oglethorpe is also obligated to make available the same share of service, and therefore on the rates charged the Members. (See "CO-OWNERS
OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--The Plant
Agreements--HATCH,all
other
14
WANSLEY, VOGTLE AND SCHERER"resources, in contractually fixed amounts, which Morgan Stanley may schedule for
each 24-hour day. This schedule is set the day prior based on availability
limitations in the contract. Morgan Stanley pays a contractually fixed amount
each month and an amount for the scheduled energy based on contractually fixed
prices. The agreement has a term extending to March 31, 2005, but the purchases
for certain Members decline to zero prior to that date. Oglethorpe plans to
manage the portion of the system resources covered by the Morgan Stanley
agreement through scheduling and dispatching such resources. Oglethorpe will
also make purchases and sales to balance the fixed purchase obligation against
the actual requirements and to optimize the use of the resources after receiving
the daily schedule from Morgan Stanley.
Morgan Stanley is a subsidiary of Morgan Stanley, Dean Witter, Discover &
Co., "General--HISTORICAL FACTORS AFFECTING
FINANCIAL PERFORMANCE"a diversified investment banking and financial services company. Morgan
Stanley, Dean Witter, Discover & Co. is subject to the informational
requirements of the Securities Exchange Act of 1934, as amended, and, in
Item 7accordance therewith, files reports and Note 1other information with the Commission.
RELATED AGREEMENTS
Oglethorpe has contracted with GTC to provide available transmission
services to deliver to the border of Notesthe ITS any energy sold to Financial Statements
in Item 8.LEM or Morgan
Stanley, as well as any other wholesale power purchase. Each Member will use its
Member Transmission Agreement for delivery of energy purchased by Oglethorpe
from LEM, Morgan Stanley and others.
In connection with the LEM and Morgan Stanley arrangements, each Member has
entered into supplemental agreements to its Wholesale Power Contract. The
supplemental agreements are the vehicle through which Oglethorpe and the Members
assure that the Members receive the benefits of and support the obligations for
the power marketer arrangements under the Wholesale Power Contracts.
Each Member has approved the agreements with LEM and Morgan Stanley as
"future resources" under the Wholesale Power Contracts. Accordingly, each Member
has a PCR for each of the LEM and Morgan Stanley agreements and all costs
incurred by Oglethorpe under such agreements are recovered from the Members
under the Wholesale Power Contracts on a joint and several basis. To this
extent, the Members have elected, under the Wholesale Power Contracts, to
purchase a substantial portion of their future requirements from Oglethorpe.
(See "--Future Power Resources" herein and "OGLETHORPE POWER
CORPORATION--Wholesale Power Contracts.")
POWER PURCHASE AND SALE ARRANGEMENTS
POWER PURCHASES FROM GPC
Oglethorpe currently purchases 1,250750 MW of capacity and associated energy from GPC on a
take-or-pay basis under the BPSA,Block Power Sale Agreement ("BPSA"), which extends
through December 31, 2003. The BPSA, along with the Revised and Restated Integrated
Transmission System Agreement (the "ITSA") and the CSA, became effective in
1991. Together these agreements enabled Oglethorpe to restructure the way it
plans for and meets the Members' power requirements. These agreements have
improved Oglethorpe's ability to buy and sell power and transmission services
in the bulk power markets. The capacity purchases under the BPSA are from sixfour
Component Blocks (as defined in the BPSA), composed of fourtwo Component Blocks of
250 MW each (coal-fired units) and two Component Blocks of 125 MW each
(combustion turbine units). The capacity in one or more Component Blocks may,
however, be less than the MW stated above, as the result of scheduled retirement
of units or retirements due to force majeure events. Although Oglethorpe may not
increase its capacity purchases under the BPSA, it may reduce or extend its
purchases of one or more Component Blocks upon proper notice to GPC. Oglethorpe
has given notice of its intent to reduce its purchases by two 250 MW Component
Blocks (coal-fired units) effective September 1, 19961998 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,1999.
Also, pursuant to its long-term power marketer agreements with LEM, Oglethorpe
has committed to continue reducing its purchases from GPC as the result of
scheduled retirement of units or retirements due to force majeure events.
All units in the combustion turbine Component Blocks are scheduled to be
retired by 2003.
Under the CSA, GPC provides various control-area services to Oglethorpe.
Oglethorpe schedules and directs GPC to dispatch and coordinate power from
all of Oglethorpe's generation and purchased power resources through December
31, 1999. The CSA requires Oglethorpe to give GPC one hour's notice in order
to schedule any off-system transactions, which could limit Oglethorpe's
ability to compete with GPC for short-term energy transactions requiring less
than one hour's notice. Oglethorpe may elect to establish its own control
area and terminate regulation servicespermitted under the
CSA upon one year's notice
to GPC. Upon such termination,BPSA and thus will no longer purchase any energy under the parties will, if necessary, negotiate new
service schedules and applicable rates. In order to optimize its use of
coordination services, Oglethorpe is currently installing the equipment that
would provide Oglethorpe with the capability to operate its own control area.
ForBPSA effective
September 1, 2001. (See "Power Marketer Arrangements--LEM AGREEMENTS" herein 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".LEM agreement.)
15
OTHER POWER PURCHASES
Oglethorpe has entered into power purchase contracts with Entergy Power,
Inc. ("EPI")purchases 100 MW of capacity from each of EPI and Big Rivers,
Electric Corporation ("Big Rivers"), each for the
purchase of 100 MW,under agreements extending through June and July 2002, respectively. The
availability of capacity under the EPI contract is dependent on the availability
of two specific generating units available to EPI. The Tennessee Valley
Authority ("TVA") provides the transmission service to deliver the power from
the Big Rivers electric system to the ITS. TVA and Southern Company Services, as
agent for Alabama Power Company and Mississippi Power Company, provide the
transmission service necessary to deliver the power from EPI to the ITS. (See
"Transmission and Other Power System
Arrangements" herein and Note 9 of Notes to Financial Statements in Item 8.)
Oglethorpe also has a contract through 2019 to purchase approximately 300 MW
of capacity withfrom Hartwell, Energy Limited Partnership ("Hartwell"), a partnership owned 50% by Destec Energy, Inc.NGC Corporation and 50% by
American National Power, Inc., a subsidiary of National Power, PLC, through April 2019.PLC. This
capacity is provided by 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. 15
Prior to the merger of Destec
Energy, Inc. and NGC Corporation, Oglethorpe notified Hartwell that Oglethorpe's
rights under the power purchase agreement to consent to the merger or to
exercise its rights of first refusal to purchase equity interests in the
partnership would be triggered by the merger. Hartwell, however, refused to
recognize Oglethorpe's rights and the parties are seeking a court order to
clarify Oglethorpe's contractual rights with respect to the merger.
In addition to the purchases from GPC, Big Rivers, EPI and EPI,Hartwell,
Oglethorpe also purchases small amounts of capacity and energy from "qualifying
facilities" under the Public Utility Regulatory Policies Act of 1978 ("PURPA").
Under a waiver order from FERC, Oglethorpe will makehistorically made all purchases the
Members would have otherwise been required to make under PURPA and Oglethorpe
was relieved of its obligation to sell certain services to "qualifying
facilities" so long as the Members make those sales. Oglethorpe provideshistorically
provided the Members with the necessary services to fulfill these sale
obligations. Purchases by Oglethorpe from such qualifying facilities provided
0.3%0.2% of Oglethorpe's energy requirements for the Members in 1995.
EPMI POWER PURCHASE AND SALE1997. As a meansresult of
reducing the cost of power provided toCorporate Restructuring, 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 tomay make such agreement, EPMI must provide allpurchases in 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 responsibilityfuture
instead of operating the power supply
system and continues to dispatch the generating resources to ensure system
reliability.
FUTURE POWER RESOURCES
Oglethorpe uses an integrated resource planning process to study
regularly the need for and feasibility of adding additional generation
facilities. This planning process also considers demand-side management
options that could be implemented by the Members as well as off-system sales
of capacity and energy to optimize the use of Oglethorpe's resources.
In its current integrated resource plan,Oglethorpe.
Finally, Oglethorpe has identified a
potential need for additional peaking capacity in the late 1990s. Oglethorpe
has agreed to purchase fromcontracted with Florida Power Corporation 50 MW of peaking
capacity during the Summer of 1997 andto
purchase 275 MW of peaking capacity during the Summersummer of 1998. In 1993, Oglethorpe issued a request for proposals for the
purchase of up to 600 MW of long-term peaking capacity to be available by
June 1, 1999. While Oglethorpe is still considering some of these proposals,
it continues to pursue other options to keep the Members power cost as low as
possible.
On February 7, 1996, Oglethorpe issued another request for proposals.
This RFP did not seek a specific amount of power; instead, it requested
proposals for meeting the combined power needs of the Members with term
options ranging from two to 15 years. Action is anticipated by Oglethorpe's
Board of Directors during April, with implementation of a new arrangement as
soon thereafter as possible.
FUTURE
LONG-TERM POWER SALES
Oglethorpe has an agreement to sell 100 MW of base capacity to Alabama
Electric Cooperative beginning June 1, 1998, and extending through December 31,
2005. Oglethorpe has also submitted bids to various formalDuring the term of the power marketer agreements, LEM and informal
solicitations for capacity sales. Whether any such bidMorgan Stanley
will be successful is
uncertain.
TRANSMISSION ANDresponsible for supplying Oglethorpe with sufficient power to fulfill
these power sales.
OTHER POWER SYSTEM ARRANGEMENTS
Oglethorpe owns approximately 2,267 miles of transmission line and 426
substations of various voltages. Oglethorpe provides power and energy to the
Members through the ITS consisting of transmission system facilities owned by
Oglethorpe, GPC, MEAG and Dalton. As a result of its participation in the
ITS, Oglethorpe is entitled to use any of the transmission facilities
included in the system, regardless of ownership. Oglethorpe's rights and
obligations with respect to the system are governed by the ITSA. (See "Power
Sales to and Purchases from
16
GPC--POWER PURCHASE ARRANGEMENTS" herein and "CO-OWNERS OF THE PLANTS AND THE
PLANT AND TRANSMISSION AGREEMENTS--Agreements Relating to Integrated
Transmission System".)
In addition to the interconnections available to Oglethorpe through the
ITS, Oglethorpe has interconnection, interchange, transmission and/or short-term capacity and
energy purchase or sale agreements with over 2060 utilities, power marketers and
other power suppliers. The agreements provide variously for the purchase and/or
sale of capacity and energy and/or for the purchase of transmission service.
Implementation of such contracts and other off-system transactions are
accomplished by the CSA. (See "Power Sales to and Purchases from GPC--POWER
PURCHASE ARRANGEMENTS" herein.) Oglethorpe has purchased from GPC sufficient
entitlement to the interface between the ITS and TVA to implement the
purchases from Big Rivers and EPI. Oglethorpe regularly buys and sells power
in the short-term bulk power market. The
development of and access to a
statewide transmission networkthe ITS and the interconnections with other
utilities are key elements in Oglethorpe's ability to make off-system sales and
purchases to providethrough its transmission service to third partiescontract with GTC and to compete in an
increasingly competitive market.
FUTURE POWER RESOURCES
Under the Wholesale Power Contracts, Oglethorpe provides joint planning
services for all participating Members. A Member may elect not to have
Oglethorpe provide joint planning, procurement or bulk power marketing services.
Although the existing long-term power marketer arrangements with LEM and
16
Morgan Stanley were designed to provide substantially all of the Members'
requirements during their contract terms, Oglethorpe will continue to offer
these planning services for requirements beyond the contract terms as well as
for evaluation of contract options and balancing of actual requirements against
fixed purchase obligations. Consequently, Oglethorpe has forecasted that peak
requirements for the Members will exceed contracted purchases over the next
several years and has issued a request for proposals for an aggregate of 100 MW
to 1,100 MW to supply these additional requirements. Oglethorpe has signed
contracts for an aggregate of 160 MW for delivery during the summer months of
1998, and may sign additional contracts up to 350 MW in the aggregate for supply
during that period. Oglethorpe is continuing to analyze proposals for deliveries
after 1998. All Members currently participate in joint planning.
17
CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY
GENERAL
The electric utility industry has been and in the future will continue to be
affected by a number of factors which could have an impact on the financial
condition of an electric utility such as Oglethorpe. These factors likely would
affect individual utilities in different ways. Such factors include, among
others: (i) the transition to increasing competition in the generation of
electricity and the corresponding increase in competition from other suppliers
of electricity, (ii) fluctuations in the market price for electricity, (iii)
effects of compliance with changing environmental, licensing and regulatory
requirements, (iv) regulatory and other changes in national and state energy
policy, including open access transmission, (v) uncertain access to low cost
capital for replacement of aging fixed assets, (vi) increases in operating
costs, including the cost of fuel for the generation of electric energy, (vii)
uncertain recovery of the cost of existing facilities, (viii) fluctuations in
demand, including rates of load growth and changes in competitive market share,
(ix) unbundling of services and corresponding corporate and functional
restructurings by electric utility companies, and (x) the effects of
conservation and energy management on the use of electric energy. These factors
present an increasing challenge to companies in the electric utility industry,
including Oglethorpe and the Members, to reduce costs, improve the management of
resources and respond to the changing environment. (See "Environmental and Other
Regulation" herein, "OGLETHORPE POWER CORPORATION--Corporate Restructuring,"
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Competition" in Item 7, "MEMBER REQUIREMENTS AND POWER SUPPLY
RESOURCES--General" and "--Power Purchase and Sale Arrangements--OTHER POWER
PURCHASES.")
COMPETITION
The electric utility industry in the United States is undergoing fundamental
change and is becoming increasingly competitive. (See "MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Competition" in
Item 7.)
ENVIRONMENTAL AND OTHER REGULATIONSREGULATION
GENERAL
As is typical in the utility industry,for electric utilities, Oglethorpe is subject to Federal,
Statevarious
federal, state and local air and water quality requirements which, among other
things, regulate emissions of pollutants, such as particulate matter, sulfur
oxides and nitrogen oxides ("NO(x)") into the air and discharges of other pollutants,
including heat, into waters of the United States. Oglethorpe is also subject to
Federal, Statefederal, state and local waste disposal requirements whichthat regulate the manner of
transportation, storage and disposal of solid and othervarious types of waste.
In general, environmental requirements are becoming increasingly stringent, and
further or newstringent.
New requirements may substantially increase the cost of electric service, by
requiring changes in the design or operation of existing facilities as well asor changes
or delays in the location, design, construction or operation of new facilities.
Failure to comply with these requirements could result in the imposition of
civil and criminal penalties as well as the complete shutdown of individual
generating units not in compliance. There is no assurance that theOglethorpe's
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 expenditures and operating costs. Based on the current
status of regulatory requirements, Oglethorpe does not anticipate that any
capital expenditures or operating expenses associated with its compliance with
current laws and regulations will have a material effect on its results of
operations or its financial
18
condition. Oglethorpe's direct capital costs to achieve compliance with current
environmental requirements are expected to be approximately $1.0 million in 1996, $3.6 million in 1997minimal for 1998, 1999 and $1.4 million in 1998.2000.
As further discussed below, however, capital costs to achieve compliance with
potential future environmental requirements could be significant.
CLEAN AIR ACT
TheEnvironmental concerns of the public, the scientific community and Congress
have resulted in the enactment of legislation that has had and will continue to
have a significant impact on the electric utility industry. In particular, on
November 15, 1990, legislation was enacted (the "1990 Amendments") that
substantially revised the Clean Air Act ("Act") seeksAct. One of the principal purposes of the
1990 Amendments is to improve air quality throughoutby reducing the United
States. The acid rain provisions of the Act require the reductionemissions of sulfur
dioxide and NO(x) emissionsnitrogen oxides from affected utility units, includingwhich include the
coal-fired units that generate electric power facilities. Theat Plants Wansley and Scherer.
These sulfur dioxide reductions required by the Act will be
achieved in two phases. Phase I addresses specific generating units named in
the Act. Both units of Plant Wansley are "affected units" under Phase I.
Scherer Units No. 1 and No. 2 are not "affected units" under Phase I but are
"affected units" under Phase II. Beginning in 1995, Phase I affected units
became subject to thebeing imposed through a 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 emission allowance, which gives the
holder the authority to emit one ton of sulfur dioxide during a calendar year,
is transferable and can be bought, sold or banked for use in the years following
its issuance. Oglethorpe expectsAllowances are issued by the U.S. Environmental Protection Agency
("EPA") to comply withimpose limited reductions on certain affected units in 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(1995-1999) and may resultmore stringent reductions on all affected units in unused allowances
that can be banked for future use.
17
For Phase II
which begins in(after the year 2000, when total U.S.1999). After 1999, aggregate emissions of sulfur dioxide from
all units subject to this program will be capped at 8.9 million tons per year.
Oglethorpe is now complying with this program by using lower-sulfur fuel at
Plant Wansley. After 1999, Oglethorpe could use a variety of options for
sulfur dioxide compliance at Plants Wansley and Scherer, including the use of emission
allowances (allocated,(issued, banked or purchased, if needed), fuel-switching or
installation of flue gas desulfurization equipment.
Achieving compliance
with Phase II has already resultedA number of recently finalized regulations, proposed regulations, petitions
and on-going studies could result in some equipment upgrades at Scherer
Units No. 1 and No. 2.
Although some NO(x) regulations implementingmore stringent controls on all emissions,
including utility emissions. The most significant of these appear to be the
requirements of the Act
have been finalized, there remains the possibility that other regulations
couldfollowing. First, because nitrogen oxides are considered to 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, compliancea precursor to
ozone, coupled with the Act will continue to require expenditures
for monitoring and permitting, and in some instances may involve increased
operating or maintenance expenses. Capital expenditures of Oglethorpe through
1995 for pollution control equipment needed to comply with the Act at Plant
Wansley have been approximately $7,200,000 and at Scherer Units No. 1 and No. 2
have been approximately $720,000. The estimated cost of any additional
improvements at Plant Wansley and Scherer Units No. 1 and No. 2 remains
dependent upon the chosen compliance plan and may be affected by future plan
amendments and/or future regulations. In addition, the final capital cost of
improvements and any effect on operating costs will be determined by the
compliance plan as finally implemented and any applicable regulatory changes.
Metropolitanfact that metropolitan Atlanta is classified as a
"serious nonattainment area" with
regard tounder the one hour ozone ambient air quality standards. The Act, under which these
standards are promulgated, requiresNational Ambient Air
Quality Standards ("NAAQS"), EPA and the State of Georgia may impose further
limits on emissions of nitrogen oxides at Plants Wansley and/or Scherer. Second,
EPA has tightened the NAAQS for both ozone and particulate matter, an action
that could affect any source that emits nitrogen oxides and sulfur dioxide,
including utility units. Court challenges to conduct specific
studies and establish new rules regulating sources of NO(x) and volatile organic
compounds, to achieve attainment of theboth standards by 1999 and to maintain
compliance thereafter. As a required first step, Georgiaare now being made.
Third, EPA has issued rulesa proposed regulation for the applicationregional control of reasonably available control technology for NO(x) emissions.
Those regulations, however, did notozone
which, if implemented as proposed, could require substantial reductions in
nitrogen oxides emissions from Plants Wansley and Scherer. Fourth, EPA has
proposed a new regional haze program, an action that could affect Plant Wansleyany source
that emits nitrogen oxides or Scherer Units No. 1sulfur dioxide and No. 2, whichthat may contribute to the
degradation of visibility in mandatory federal Class I areas, including utility
units. Fifth, various Northeastern states have filed petitions under the Clean
Air Act asking EPA to set more stringent nitrogen oxides limits on sources that
are not in the Atlantasignificantly contributing to ozone nonattainment area.in their own states.
Georgia was named in only one of these petitions. Sixth, although EPA has
decided not to impose a new NAAQS for sulfur dioxide, that decision has been
remanded (after appeal) to EPA for further rulemaking, so it is still performing photochemical grid modeling, however, and aspossible
that a result may yet
promulgate new rulesshort-term standard for power plants insulfur dioxide could be established. Finally,
the State. Plant Wansley is near the
nonattainment area while Plant Scherer is located further away. The results of
these studies and new rules could require NO(x) controls more stringent than
those now required under the acid rain provisions of the Act for compliance.
Portions of Subchapter I of the Act1990 Amendments require that several studies be conducted regarding the
health effects offrom power plant emissions of certain hazardous air pollutants.
TheThese studies, willwhich have now been completed, indicate that further research is
needed before decisions can be used in making decisionsmade on whether additional controls of theseutility
emissions of such pollutants are necessary.
Depending on the final outcome of these developments, and the implementation
approach selected by EPA and the State of Georgia, significant capital
expenditures and increased operation expenses could be incurred by Oglethorpe
for the continued operation of Plants Wansley and/or Scherer. The power marketer
arrangements generally do not provide for the recovery from the power marketers
of increased environmental costs. (See "MEMBER REQUIREMENTS AND POWER SUPPLY
RESOURCES--
19
Power Marketer Arrangements.") Because of the uncertainty associated with these
various developments, Oglethorpe cannot now predict the effect ofthat any of these
potential regulatory changes underrequirements may have on the Act, including new rules underoperations of Plants Wansley and/or
Scherer.
Compliance with the amended provisions, cannot now be predicted.
The Act also requires EPA to review all National Ambient Air Quality
Standards ("NAAQS") periodically, revising such standards as necessary. EPA
continues to evaluate the need for a new short-term standard for sulfur oxides
(measured as sulfur dioxide). If a new short-term NAAQS for sulfur dioxide were
imposed, it might require numerous power plants to install emission controls,
perhaps in addition to any required under the acid rain provisionsrequirements of the Act.
These controls could result in substantial costs to Oglethorpe. Although EPA
has evaluated the need and decided for now not to revise the NAAQS for nitrogen
dioxides, there is no certainty that that standard will not be revised in the
future. In addition, EPA has finalized a criteria document and is updating a
staff paper for ozone, which could lead to a change in the NAAQS for ozone.
EPA is also updating a criteria document and staff paper for particulate matter,
which could lead to a revision of the NAAQS for particulate matter. The impact
of any change in the ozone, sulfur dioxide, nitrogen dioxides or particulate
matter NAAQS cannot now be determined because the effect of any change would
depend in part on the final ambient standards developed.
Although Oglethorpe's management is currently unable to determine the
overall effect that compliance with requirements under the Act will have on
its operations, it does not believe that any required increases in capital or
operating expenses would have a material effect on its results of operations
or financial condition. Compliance with requirements under theClean 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"MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--Power
Purchase and Purchases from GPC--POWER PURCHASE ARRANGEMENTS" herein.Sale Arrangements--POWER PURCHASES FROM GPC.")
CLEAN WATER ACT
Congress is considering reauthorization of the Clean Water Act. If that
occurs, Oglethorpe's operations could be affected. However, the full impact
of any reauthorization cannot now be determined and will depend on the
specific changes to the statute, as well as to any implementing state or
federal regulations that might be promulgated.
NUCLEAR REGULATION
Oglethorpe is subject to the provisions of the Atomic Energy Act of 1954, as
amended (the "Atomic Energy Act"), which vests jurisdiction in the NRCNuclear
Regulatory Commission ("NRC") over the construction and operation of nuclear
reactors, particularly with regard to certain public health, safety and
antitrust matters. The National Environmental Policy Act has been construed to
expand the jurisdiction of the NRC to consider the environmental impact of a
facility licensed under the Atomic Energy Act. Plants Hatch and Vogtle are being
operated under licenses issued by the NRC. All aspects of the operation and
maintenance of nuclear power plants are regulated by the NRC. From time to time,
new NRC regulations require changes in the design, operation and maintenance of
existing nuclear reactors. Operating licenses issued by the NRC are subject to
revocation, suspension or modification, and the operation of a nuclear unit may
be suspended if the NRC determines that the public interest, health or safety so
requires. (See "Proposed Changes to Nuclear Plant Operating
Arrangements" herein.)The operating licenses issued for each unit of Plants Hatch and Vogtle
expire in 2014 and 2018 and 2027 and 2029, respectively.
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 DOEthe Department of Energy ("DOE") for such material.
These contracts require each such owner to pay a fee, which is currently one
dollar per MWh for the net electricity generated and sold by each of its
reactors. Oglethorpe is a party to agreements with DOE regarding Plants Hatch
and Vogtle. 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 be
sufficient until 2003 and 2008, respectively, to accept the number of spent fuel
assemblies that would normally be removed from the reactor during a refueling.
Contracts with the DOE have been executed to provide for the permanent disposal
of spent nuclear fuel produced at Plants Hatch and Vogtle. The services to be
provided by DOE were scheduled to begin in 1998; however, the DOE has stated
that permanent nuclear waste storage facilities are not available, and it is
uncertain when they will be available. If DOE does not begin receiving the spent
fuel from Plant Hatch in 2003 or from Plant Vogtle in 2008, alternative methods
of spent fuel storage will be needed. Activities for adding dry cask storage
capacity at Plant Hatch by 2000 are in progress. (See "Fuel
Supply" herein.Note 1 of Notes to
Financial Statements regarding nuclear fuel cost in Item 8.)
For information concerning nuclear insurance, see Note 8 of Notes to
Financial Statements in Item 8. For information regarding NRC's regulation
relating to decommissioning of nuclear facilities and regarding DOE's
assessments pursuant to the Energy Policy Act for decontamination and
decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to
Financial Statements in Item 8.
OTHER ENVIRONMENTAL REGULATION
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.I.E., not mixed with other wastes. Pursuant to court order, EPA
has until 1998the Spring of 1999 to classify co-managed utility wastes as either
20
hazardous or non-hazardous. If the wastes are classified as hazardous,
substantial additional costs for the management of such wastes might be required
of Oglethorpe, 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 Clean Water Act, the Georgia Water Quality Control Act, the
Georgia Hazardous Site Response Act, the Toxic Substances Control Act, the
Resource Conservation & Recovery Act, ("RCRA"), the Endangered Species Act, ("ESA"), the
Comprehensive Environmental Response, Compensation and Liability Act, ("CERCLA"), the
Emergency Planning and Community Right to Know Act, the Georgia Hazardous
Site Response Act, and to the regulations
implementing these statutes. Oglethorpe does not believe that compliance with
these statutes and regulations will have a material impact on its financial
condition or results of operations. Changes to any of these laws, however,some of which
are being reviewed by Congress, could affect many areas of Oglethorpe's
operations.
Congress is considering amending the ESA and reauthorizing CERCLA and perhaps
RCRA. Although compliance with new environmental legislation could have a
significant impact on Oglethorpe,
19
those impacts cannot be fully determined at
this time and would depend in part on the final legislation and the development
of implementing regulations.
The scientific community, regulatory agencies and the electric utility
industry are continuing to examine the issues of global warming and the possible
health effects of electromagnetic fields. While no definitive scientific
conclusions have been reached, regarding these issues, it is possible that new laws or regulations
pertaining to these matters could increase the capital and operating costs of
electric utilities, including Oglethorpe or entities from which Oglethorpe
purchases power. In addition, the potential for liability exists from lawsuits
that might be brought alleging damages from electromagnetic fields.
ENERGY POLICY ACTOTHER INFORMATION
Information with respect to fuel supply for Oglethorpe's plants is set forth
under the caption "GENERATING FACILITIES--Fuel Supply" included in Item 2 and is
incorporated herein by reference.
21
ITEM 2. PROPERTIES
GENERATING FACILITIES
GENERAL
The Energy Policy Act allows for increased competition among wholesale
electric suppliers and increased accessfollowing table sets forth certain information with respect to transmission services by such
suppliers. It creates a new classthe
generating facilities in which Oglethorpe currently has ownership or leasehold
interests, all of utilities called Exempt Wholesale
Generators ("EWGs"), which are exempt from certain restrictions otherwise
imposedin commercial operation. Plant Hatch, Plant Wansley,
Plant Vogtle and Scherer Unit No. 1 and Scherer Unit No. 2 are co-owned by
Oglethorpe, GPC, MEAG and Dalton. GPC is the operating agent for each of these
co-owned plants. Rocky Mountain is co-owned by Oglethorpe and GPC, and
Oglethorpe is the operating agent. Oglethorpe is the sole owner of Tallassee.
(See "CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--The Plant Agreements.")
OGLETHORPE'S
SHARE OF
NAMEPLATE COMMERCIAL LICENSE
TYPE OF PERCENTAGE CAPACITY OPERATION EXPIRATION
FACILITIES FUEL INTEREST(1) (MW) DATE DATE
- -------------------------------------------------- --------- ----------- ------------ ------------- -----------
Plant Hatch (near Baxley, Ga.)
Unit No. 1...................................... Nuclear 30 243.0 1975 2014
Unit No. 2...................................... Nuclear 30 246.0 1979 2018
Plant Vogtle (near Waynesboro, Ga.)
Unit No. 1...................................... Nuclear 30 348.0 1987 2027
Unit No. 2...................................... Nuclear 30 348.0 1989 2029
Plant Wansley (near Carrollton, Ga.)
Unit No. 1...................................... Coal 30 259.5 1976 N/A(2)
Unit No. 2...................................... Coal 30 259.5 1978 N/A(2)
Combustion Turbine.............................. Oil 30 14.8 1980 N/A(2)
Plant Scherer (near Forsyth, Ga.)
Unit No. 1...................................... Coal 60 490.8 1982 N/A(2)
Unit No. 2...................................... Coal 60 490.8 1984 N/A(2)
Tallassee (near Athens, Ga.)...................... Hydro 100 2.1 1986 2023
Rocky Mountain (near Rome, Ga.)................... Pumped
Storage
Hydro 74.61 632.5 1995 2027
------------
Total Ownership............................. 3,335.0
------------
------------
- ------------------------------
(1) 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. The 74.61%
interest in Rocky Mountain is leased under leases that expire in 2016.
Oglethorpe has an ownership interest in all of the other facilities. (See
"CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--The Plant
Agreements--ROCKY MOUNTAIN.")
(2) Coal-fired units and combustion turbines do not operate under operating
licenses similar to those granted to nuclear units by the Public Utility Holding Company Act.Nuclear Regulatory
Commission and to hydroelectric plants by FERC.
22
PLANT PERFORMANCE
The effectfollowing table sets forth certain operating performance information of
this
exemptioneach of the major generating facilities in which Oglethorpe currently has
ownership or leasehold interests:
EQUIVALENT AVAILABILITY(1) CAPACITY
FACTOR(2)
------------------------------------- -----------
UNIT 1997 1996 1995 1997
- --------------------------------------------------------------------- ----- ----- ----- -----
Plant Hatch
Unit No. 1......................................................... 86% 83% 98% 86%
Unit No. 2......................................................... 85 97 75 84
Plant Vogtle
Unit No. 1......................................................... 81 80 98 81
Unit No. 2......................................................... 100 88 89 101
Plant Wansley
Unit No. 1......................................................... 91 88 90 62
Unit No. 2......................................................... 92 91 89 59
Plant Scherer
Unit No. 1......................................................... 76 92 95 57
Unit No. 2......................................................... 99 84 97 84
Rocky Mountain(3)
Unit No. 1......................................................... 96 94 83 20
Unit No. 2......................................................... 96 95 92 13
Unit No. 3......................................................... 97 95 92 19
UNIT 1996 1995
- --------------------------------------------------------------------- ----- -----
Plant Hatch
Unit No. 1......................................................... 83% 100%
Unit No. 2......................................................... 99 75
Plant Vogtle
Unit No. 1......................................................... 80 98
Unit No. 2......................................................... 89 90
Plant Wansley
Unit No. 1......................................................... 58 56
Unit No. 2......................................................... 62 56
Plant Scherer
Unit No. 1......................................................... 74 73
Unit No. 2......................................................... 72 85
Rocky Mountain(3)
Unit No. 1......................................................... 15 16
Unit No. 2......................................................... 13 15
Unit No. 3......................................................... 10 16
- ------------------------------
(1) Equivalent Availability is to facilitatea measure of the developmentpercentage of independent third-party
generators potentiallytime that a unit
was available to satisfy utilities' needsgenerate if called upon, adjusted for increased
power supplies. Unlike purchasesperiods when the unit
is partially derated 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"maximum dependable capacity" rating.
(2) Capacity Factor is a utility to transmit power to or on behalf of other participants in the
electric utility industry, including EWGs and qualifying facilities, but FERC
is precluded from requiring a utility to transmit power from another entity
directly to a retail customer. In March 1995, FERC issued a proposed rule
implementing the open access provisionsmeasure of the Energy Policy Act. The Chairoutput of FERC has publicly predicted a final rule before mid-1996. Although
RUS-financed cooperatives will not be subject to all provisionsunit as a percentage of the
FERC
rule, they will be subjectmaximum output, based on the "maximum dependable capacity" rating, over the
period of measure.
(3) Rocky Mountain Commercial Operation Dates: Unit 1--July 24, 1995; Unit
2--June 19, 1995; Unit 3--June 1, 1995. This information was calculated
beginning from the commercial operation date for each unit. As a pumped
storage plant, Rocky Mountain primarily operates in peaking service.
The nuclear refueling cycle for Plants Hatch and Vogtle exceeds twelve
months. Therefore, in some calendar years the units at these plants are not
taken out of service for refueling, resulting in higher levels of equivalent
availability and capacity factor.
FUEL SUPPLY
COAL. Coal for Plant Wansley is currently purchased under long-term
contracts and in spot market transactions. As of February 28, 1998, there was a
33-day coal supply at Plant Wansley based on nameplate rating.
Low-sulfur "compliance" coal for Scherer Units No. 1 and No. 2 is purchased
under long-term contracts and in spot market transactions. As of February 28,
1998, the coal stockpile at Plant Scherer contained a 33-day supply based on
nameplate rating. During 1994, Plant Scherer was converted to FERC ordersburn both
sub-bituminous and bituminous coals, and a separate stockpile of sub-bituminous
coal was built in addition to provide transmission on justthe stockpile of bituminous coal.
The Plant Scherer and reasonable termsWansley ownership and conditions.
A significant outgrowthoperating agreements were
amended in 1993 and 1996, respectively, to allow each co-owner (i) to dispatch
separately its respective ownership interest in conjunction with contracting
separately for long-term coal purchases procured by GPC and (ii) to procure
separately long-term coal purchases. Pursuant to the amendments, Oglethorpe
implemented separate
23
dispatch of Plant Scherer in 1994 and at Plant Wansley in May 1997. Oglethorpe
continues to use GPC as its agent for fuel procurement.
To take advantage of these changes at Plants Scherer and Wansley, Oglethorpe
formed a wholly owned subsidiary, Black Diamond Energy, Inc., to acquire rail
cars. This subsidiary has purchased or leased approximately 300 rail cars.
Oglethorpe entered into an initial 15-year lease with this subsidiary which
obligates Oglethorpe to pay all of the Energy Policyownership and operating expenses of the
subsidiary relating to the rail cars during the lease term.
For information relating to the impact that the Clean Air Act iswill have on
Oglethorpe, see "CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY
INDUSTRY--Environmental and Other Regulations--CLEAN AIR ACT" in Item 1.
NUCLEAR FUEL. GPC, as operating agent, has the rapid increaseresponsibility to procure
nuclear fuel for Plants Hatch and Vogtle. GPC has contracted with Southern
Nuclear Operating Company ("SONOPCO"), a subsidiary of power marketers. Power marketersThe Southern Company
specializing in nuclear services, to operate these plants, including nuclear
fuel procurement. (See "CO-OWNERS OF THE PLANTS AND PLANT AGREEMENTS--The Plant
Agreements.") SONOPCO employs both spot purchases and long-term contracts to
satisfy nuclear fuel requirements. The nuclear fuel supply and related services
are FERC-regulated public utilities that
sell under "market-based" rates. Power marketers rely heavily on
transmission accessexpected to buybe adequate to satisfy current and sell power across several systems. (See "EPMI
Power Purchase and Sale" and "Future Power Resources" herein.)
20future nuclear generation
requirements.
24
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). Oglethorpe is the operating agent for
Rocky Mountain. 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.other plants. (See
"The Plant Agreements" herein.)
Nuclear Coal-Fire Pumped Storage
-------------------------- ---------------------------- --------------
Plant Plant Plant Scherer Units Rocky
Hatch Vogtle Wansley No.NUCLEAR COAL-FIRED
-------------------- --------------------------------------------
PLANT PLANT PLANT SCHERER UNITS
HATCH VOGTLE WANSLEY NO. 1 & No.NO. 2
Mountain Total
------------ ------------ ------------ --------------- -------------- ------------------------- -------------------- -------------------- --------------------
% MW(1) % MW(1) % MW(1) % MW(1)
% MW(1) MW(1)
----- ----- ----- ----- ----- ----- -------- ----- ------ ----- ------------- -------- -------- -------- -------- -------- --------
Oglethorpe ..Oglethorpe..... 30.0 489 30.0 696 30.0 519 60.0(2) 982
74.61 633 3,319
GPC .........GPC............ 50.1 817 45.7 1,060 53.5 926 8.4 137
25.39 215 3,155
MEAG ........MEAG........... 17.7 288 22.7 527 15.1 261 30.2 494
-- -- 1,570
Dalton ......Dalton......... 2.2 36 1.6 37 1.4 24 1.4 23
-- -- 120
----- ----- ----- ----- ----- ----- -------- ----- ------ ----- -----
Total........-------- -------- -------- -------- -------- -------- --------
Total.......... 100.0 1,630 100.0 2,320 100.0 1,730 100.0 1,636
-------- -------- -------- -------- -------- -------- -------- --------
-------- -------- -------- -------- -------- -------- -------- --------
PUMPED
STORAGE
------------------------
ROCKY
MOUNTAIN
------------------------ TOTAL
% MW(1) MW(1)
---------- ---------- --------
Oglethorpe..... 74.61 (2) 633 3,319
GPC............ 25.39 215 3,155
MEAG........... -- -- 1,570
Dalton......... -- -- 120
---------- ----- --------
Total.......... 100.00 848 8,164
----- ----- ----- ----- --------------- ----- --------
---------- ----- ------ ----- -----
----- ----- ----- ----- ----- ----- -------- ----- ------ ----- -----
______________________- ------------------------------
(1) Based on nameplate ratings.
(2) Oglethorpe leases its interest in Scherer Unit No. 2 and Rocky Mountain
pursuant to long-term net leases.
GEORGIA POWER COMPANY
GPC is a wholly owned subsidiary of The Southern Company, a registered
holding company under the Public Utility Holding Company Act, and is engaged
primarily in the generation and purchase of electric energy and the
transmission, distribution and sale of such energy within the State of Georgia
at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus,
Macon, Rome and Valdosta), as well as in rural areas, and at wholesale to
Oglethorpe, MEAG and three municipalities. GPC is the largest supplier of
electric energy in the State of Georgia. (See "OGLETHORPE POWER CORPORATION--RelationshipCORPORATION--
Relationship with GPC". in Item 1.) GPC is subject to the informational
requirements of the Securities Exchange Act of 1934, as amended, and, in
accordance therewith, files reports and other information with the Securities and Exchange Commission (the
"Commission"). 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.Commission.
MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA
MEAG, an instrumentality of the State of Georgia, was created for the
purpose of providing electric capacity and energy to those political
subdivisions of the State of Georgia that owned and operated electric
distribution systems at that time. MEAG, also known as MEAG Power, has entered
into power sales contracts with each of 48 cities and one county in the State of
Georgia. Such political subdivisions, located in 39 of the State's 159 counties,
collectively serve approximately 270,000 electric customers.
21
CITY OF DALTON, GEORGIA
The City of Dalton, located in northwest Georgia, supplies electric capacity
and energy to consumers in Dalton, and presently serves more than 10,000
residential, commercial and industrial customers.
25
THE PLANT AGREEMENTS
HATCH, WANSLEY, VOGTLE AND SCHERER
Oglethorpe's rights and obligations with respect to Plants Hatch, Wansley,
Vogtle and Scherer are contained in a number of contracts between Oglethorpe and
GPC and, in some instances, MEAG and Dalton. Oglethorpe is a party to four
Purchase and Ownership Participation Agreements ("Ownership Agreements") under
which it acquired from GPC a 30% undivided interest in each of Plants Hatch,
Wansley and Vogtle, a 60% undivided interest in Scherer Units No. 1 and No. 2
and a 30% undivided interest in those facilities at Plant Scherer intended to be
used in common by Scherer Units No. 1, No. 2, No. 3 and No. 4 (the "Scherer
Common Facilities"). Oglethorpe has also entered into four Operating Agreements
("Operating Agreements") relating to the operation and maintenance of Plants
Hatch, Wansley, Vogtle and Scherer, respectively. The OperatingOwnership Agreements and
OwnershipOperating Agreements relating to Plants Hatch and Wansley are two-party
agreements between Oglethorpe and GPC. The otherOwnership Agreements and Operating
Agreements relating to Plants Vogtle and Ownership AgreementsScherer 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.
SALE AND LEASEBACK TRANSACTIONS. In 1985, in four separate transactions, Oglethorpe
sold its entire 60% undivided ownership interest in Scherer Unit No. 2 to four
separate owner trusts (the "Lessors") established by four different
institutional investors.investors (the "Sale and Leaseback Transaction"). (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. The Operating Agreements gives GPC, as agent, sole authority and
responsibility for the management, control, maintenance and operation of the
plant to which it relates and provides for the use of power and energy from such
plant and the sharing of the costs thereof by the parties thereto in accordance
with their respective interests therein. In performing its responsibilities
under the Ownership and Operating Agreements, GPC is required to comply with
prudent utility practices. GPC's liabilities with respect to its duties under
the Ownership and Operating Agreements are limited by the terms thereof.
Under the Ownership Agreements, Oglethorpe is obligated to pay a percentage
of capital costs of the respective plants, as incurred, equal to the percentage
interest which it owns or leases at each plant. GPC has responsibility for
budgeting capital expenditures subject to, in the case of Scherer Units No. 1
and No. 2, certain limited rights of the Participants to disapprove capital
budgets proposed by GPC and to substitute alternative capital budgets and, in
the case of Plants Hatch and Vogtle, the right of any co-owner to disapprove
large discretionary capital improvements.
Each Operating Agreement gives GPC, as agent, sole authority and
responsibility for the management, control, maintenance, operation,
scheduling and dispatching of the plant to which it relates. However, as
provided in the recent amendments to the Plant Scherer Ownership and
Operating Agreements, Oglethorpe is separately dispatching its ownership
share of Scherer Units No. 1 and No. 2. Similar amendments to the Plant
Wansley Operating Agreement have been negotiated and, upon approval of RUS,
Oglethorpe expects to dispatch separately its ownership share in Plant
Wansley. (See "THE POWER SUPPLY SYSTEM--Fuel Supply".) In 1990, the co-owners of Plants Hatch and Vogtle entered into the NMBANuclear
Managing Board Agreement which amended the Plant Hatch and Plant Vogtle
Ownership and Operating agreements,Agreements, primarily with respect to GPC's reporting
requirements, but did not alter GPC's role as agent with respect to the nuclear
plants. In 1993, the co-owners entered into the Amended and Restated NMBANuclear
Managing Board Agreement (the "Amended and Restated NMBA") which provides for a
managing board (the "Nuclear Managing Board") to coordinate the implementation
and administration of the Plant Hatch and Plant Vogtle Ownership and Operating
Agreements, and
provides for increased rights for the co-owners regarding certain
decisions and allowedallows GPC to contract with a third party for the operation of the
nuclear units. Upon approval in March 1997 by the NRC of GPC's application to
add SONOPCO to the operating
26
license of each unit of Plants Hatch and Vogtle and designate SONOPCO as the
operator, the Nuclear Operating Agreement between GPC and SONOPCO, which the
co-owners had previously approved, became effective. 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.
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 tounit. GPC, as
described below.agent, schedules and dispatches Plants Hatch and Vogtle. Pursuant to amendments
to the plant agreements, Oglethorpe began separately dispatching its ownership
share of Scherer Units No. 1 and No. 2 in 1993 and of Plant Wansley in 1997.
(See "GENERATING FACILITIES--Fuel Supply.") Except as otherwise provided, each
party is responsible for a percentage of Operating Costs (as defined in the
Operating Agreements) and fuel costs of each plant or unit equal to the
percentage of its undivided interest which is owned or leased in such plant or
unit. For Scherer Units No. 1 and No. 2 and for Plant Wansley, once the proposed amendments to the
Plant Wansley Operating Agreement are effective, each party will
be responsible for its fuel costs and for variable Operating Costs in proportion
to the net energy output for its ownership interest, while responsibility for
fixed Operating Costs will continue to be equal to the percentage undivided
ownership interest which is owned or leased in such unit. GPC is required to
furnish budgets for Operating Costs, fuel plans and scheduled maintenance plans
subject to, in the case of Scherer Units No. 1 and No. 2, certain limited rights
of the Participants to disapprove such budgets proposed by GPC and to substitute
alternative budgets. The Ownership Agreements and Operating Agreements provide
that, should a Participant fail to make any payment when due, among other
things, such nonpaying Participant's rights to output of capacity and energy
would be suspended.
(See "THE POWER Supply SYSTEM--Proposed Changes to Nuclear Plant
Operating Arrangements".)
TERMS. The Operating Agreement for Plant Hatch will remain in effect with respect
to Hatch Units No. 1 and No. 2 until 2009 and 2012, respectively. The Operating
Agreement for Plant Vogtle will remain in effect with respect to each unit at
Plant Vogtle until 2018. The Operating Agreement for Plant Wansley will remain
in effect with respect to Wansley Units No. 1 and No. 2 until 2016 and 2018,
respectively. The Operating Agreement for Scherer Units No. 1 and No. 2 will
remain in effect with respect to Scherer Units No. 1 and No. 2 until 2022 and
2024, respectively. Upon termination of each Operating Agreement, following any
extension agreed to by the parties, GPC will retain such powers as are necessary
in connection with the disposition of the property of the applicable plant, and
the rights and obligations of the parties shall continue with respect to actions
and expenses taken or incurred in connection with such disposition.
ROCKY MOUNTAIN
Oglethorpe's rights and obligations with respect to Rocky Mountain are
contained in several contracts between Oglethorpe and GPC, the co-owners of
Rocky Mountain.Mountain (the "Co-Owners"). Pursuant to Rocky Mountain Pumped Storage
Hydroelectric Ownership Participation Agreement, by and between Oglethorpe and
GPC (the "Ownership Participation"Rocky Mountain Ownership Agreement"), Oglethorpe initially acquired a
3% undivided interest in Rocky Mountain which interest increased as Oglethorpe
expended funds to complete construction of Rocky Mountain. The final ownership
percentages for Rocky Mountain are Oglethorpe 74.61% and GPC 25.39%. In
connection with this acquisition, Oglethorpe and GPC also entered into the Rocky
Mountain Pumped Storage Hydroelectric Project Operating Agreement (the "Rocky
Mountain Operating Agreement").
The Rocky Mountain Ownership Participation Agreement appoints Oglethorpe as agent with
sole authority and responsibility for, among other things, the planning,
licensing, design, construction, operation, maintenance and disposal of Rocky
Mountain. The Rocky Mountain Operating Agreement gives Oglethorpe, as
27
agent, sole authority and responsibility for the management, control,
maintenance and operation of Rocky Mountain.
In general, each co-ownerCo-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'sCo-Owner's share of net
available capacity and net energy is the same as its respective ownership
interest under the Rocky Mountain Ownership
Participation Agreement. Oglethorpe and GPC have
each elected to schedule separately their respective ownership interests. The
Rocky Mountain Operating Agreement will terminate in 2035. 23
AGREEMENTS RELATING TO THE INTEGRATED TRANSMISSION SYSTEMThe Rocky Mountain
Ownership and Operating Agreements provide that, should a Co-Owner fail to make
any payment when due, among other things, such non-paying Co-Owner's rights to
output of capacity and energy or to exercise any other right of a Co-Owner would
be suspended until all amounts due, together with interests, had been paid. The
capacity and energy of a non-paying Co-Owner may be purchased by a paying
Co-Owner or sold to a third party.
In late 1996 and early 1997, Oglethorpe completed lease transactions for its
74.61% undivided ownership interest in Rocky Mountain. Under the terms of these
transactions, Oglethorpe leased the facility to three institutional investors
for the useful life of the facility, who in turn leased it back to Oglethorpe
for a term of 30 years. Oglethorpe will continue to control and GPC have entered intooperate Rocky
Mountain during the ITSAleaseback term, and it will exercise its fixed price
purchase option at the end of the leaseback period so as to retain all other
rights of ownership with respect to the plant if it is advantageous for
Oglethorpe to exercise such option.
ITEM 3. LEGAL PROCEEDINGS
On June 17, 1997, PECO Energy Company--Power Team ("PECO") filed an
application with FERC pursuant to Section 211 of the Federal Power Act
requesting FERC to compel Oglethorpe and/or GTC to provide PECO with 250 MW of
firm point-to-point transmission service from the TVA-ITS interface to the
Florida-ITS interface for an initial three-year period, with an automatic
roll-over provision. PECO also seeks $10,000 per day in penalties from
Oglethorpe and/or GTC, alleging bad faith and delays in negotiations. In their
response to FERC, GTC and Oglethorpe contend that they negotiated with PECO in
good faith, and thus there is no reasonable basis for imposing the transmissionpenalties
sought by PECO. GTC also responded that it does not have firm "available
transfer capability" at the TVA-ITS interface to fulfill PECO's request, after
taking into account the need to protect system reliability, existing firm
commitments, 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, togetherTVA-ITS interface to serve "native load," in
accordance with North American Electric Reliability Council guidelines. In the
event GTC is ordered by FERC to provide the requested service, PECO would be
required to compensate GTC at rates set by FERC in the order. As a consequence
of any such order, power purchased by Oglethorpe for delivery through the
TVA-ITS interface would probably be curtailed (based on past operational
experience at that interface), and could result in higher purchased power cost
than would otherwise be the case. Although FERC transmission pricing policy is
designed to ensure that a transmission provider is fully compensated for the
cost of providing transmission service, potentially including opportunity cost,
there can be no assurance that rates ordered by FERC for service to PECO would
fully compensate GTC, Oglethorpe and the Members for the use of the 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 partiesresulting effect on the date the
ITSA became effective and those thereafter acquired, which are locatedreliability or increase in the Statecost of
Georgia other than in the excluded counties and which are used or
usable to transmit power of a certain minimum voltage and to transform power
of a certain minimum voltage and a certain minimum capacity (the
"Transmission Facilities"). GPC has entered into agreements with MEAG and
Dalton that are substantially similar to the ITSA, and GPC may enter into
such agreements with other entities. The ITSA will remain in effect through
December 31, 2012 and, if not then terminated by five years' prior written
notice by either party, will continue until so terminated.
The ITSA is administered by a Joint Committee established by a Joint
Committee Agreement, summarized below. Each year, the Joint Committee
determines a four-year plan of additions to the Transmission Facilities that
will reflect the current and anticipated future transmission requirements of
the parties. Oglethorpe and GPC are each required to maintain an original
cost investment in the Transmission Facilities in proportion to their
respective Peak Loads (as defined in the ITSA).
Oglethorpe and GPC are parties to a Transmission Facilities Operation and
Maintenance Contract (the "Transmission Operation Contract"), under which GPC
provides System Operator Services (as defined in the Transmission Operation
Contract) for Oglethorpe. In addition, GPC is required to provide such
supervision, operation and maintenance supplies, spare parts, equipment and
labor for the operation, maintenance and construction as may be specified by
Oglethorpe. GPC is also required to perform certain emergency work under the
Transmission Operation Contract. Oglethorpe is permitted, upon notice to
GPC, to perform, or contract with others for the performance of, certain
services performed by GPC. Absent termination or amendment of the
Transmission Operation Contract, however, GPC will continue to perform System
Operator Services for Oglethorpe. The term of the Transmission Operation
Contract will continue from year to year unless terminated by either party
upon four years' notice. Oglethorpe is required to pay its proportionate
share of the cost for the services provided by GPC.
THE JOINT COMMITTEE AGREEMENT
Oglethorpe, GPC, MEAG and Dalton are parties to a Joint Committee
Agreement. In the past, the Joint Committee coordinated the implementation
and administration of the various Ownership Agreements and Operating
Agreements, the various integrated transmission system agreements, and the
various integrated transmission system operation and maintenance agreements
among the parties. However, the Nuclear Managing Board has assumed such
responsibilities for Plants Hatch and Vogtle, the Plant Scherer Managing
Board has assumed such responsibilities for Plant Scherer and an operating
committee will assume such responsibilities for Plant Wansley once the
proposed amendments to the Plant Wansley Operating Agreement are effective.
(See "The Plant Agreements--HATCH, WANSLEY, VOGTLE AND SCHERER" herein.) The
Joint Committee Agreement also makes allowance for the joint planning of
future transmission and generation facilities.
24
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 PROCEEDINGSpower.
Oglethorpe is a party to various other 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.
2528
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Not applicable.NOT APPLICABLE.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected historical financial data of
Oglethorpe. The financial data presented as of the end of and for each year in
the five-year period ended December 31, 1997, have been derived from the audited
financial statements of Oglethorpe. Due to the Corporate Restructuring, the
results of operations and financial condition reflect operations as a combined
power supply, transmission and system operations company through March 31, 1997,
and operations solely as a power supply company thereafter. These data should be
read in conjunction with the financial statements of Oglethorpe and the notes
thereto included in Item 8, "OGLETHORPE POWER CORPORATION-Corporate
Restructuring" in Item 1 and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS" in Item 7.
...............................................................................................................
(dollars in thousands)(DOLLARS IN
THOUSANDS)
1997 1996 1995 1994 1993
1992 1991------------ ------------ -------------------- ------------ ------------
OPERATING REVENUES:
Sales to Members ................Members............ $ 1,000,319 $ 1,023,094 $ 1,030,797 $ 930,875 $ 899,720
$ 816,000 $ 763,657
Sales to non-Members.............non-Members........ 47,533 78,343 118,764 125,207 200,940
268,763 300,293------------ ------------ ----------- ----------- ----------- ----------- -----------
Total operating revenues ........------------ ------------
TOTAL OPERATING REVENUES...... 1,047,852 1,101,437 1,149,561 1,056,082 1,100,660
1,084,763 1,063,950------------ ------------ ----------- ----------- ----------- ----------- ----------------------- ------------
OPERATING EXPENSES:
Fuel.............................Fuel........................ 206,315 206,524 219,062 203,444 176,342
167,288 165,168
Production....................... 133,858 132,723 129,972 115,915 130,041Production.................. 157,932 150,787 155,549 153,174 150,027
Purchased power..................power............. 266,875 229,089 264,844 227,477 271,970
230,510 229,898
Depreciation and
amortization....amortization.............. 126,730 163,130 139,024 131,056 128,060
126,047 135,152
Taxes............................Taxes....................... 26,293 30,262 27,561 24,741 25,148
19,634 42,422
Other operating expenses......... 56,535 49,234 44,876 50,578 49,373expenses.... 4,032 38,896 34,844 28,783 24,821
------------ ------------ ----------- ----------- ----------- ----------- -----------
Total operating expenses.........------------ ------------
TOTAL OPERATING EXPENSES...... 788,177 818,688 840,884 768,675 776,368
709,972 752,054------------ ------------ ----------- ----------- ----------- ----------- ----------------------- ------------
OPERATING MARGIN...................MARGIN.............. 259,675 282,749 308,677 287,407 324,292
374,791 311,896
OTHER INCOME, NET..................NET............. 46,646 65,334 33,710 40,795 38,741
45,928 113,441
NET INTEREST CHARGES...............CHARGES.......... (283,916) (326,331) (320,129) (305,120) (350,652)
(393,247) (396,892)------------ ------------ ----------- ----------- ----------- ----------- ----------------------- ------------
MARGIN BEFORE CUMULATIVE
EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE...PRINCIPLE........ 22,405 21,752 22,258 23,082 12,381 27,472 28,445
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING FOR INCOME
TAXES......TAXES..................... -- -- -- -- 13,340
-- -------------- ------------ ----------- ----------- ----------- ----------- ----------------------- ------------
NET MARGIN.........................MARGIN.................... $ 22,405 $ 21,752 $ 22,258 $ 23,082 $ 25,721
$ 27,472 $ 28,445------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- ----------------------- ------------
ELECTRIC PLANT, NET:
In service.......................service.................. $ 3,588,204 $ 4,345,200 $ 4,436,009 $ 3,980,439 $ 4,054,956
$ 4,122,411 $ 4,196,966
Construction work in
progress....progress.................. 13,578 31,181 35,753 538,789 450,965
322,628 178,980------------ ------------ ----------- ----------- ----------- ----------- ----------------------- ------------
$ 3,601,782 $ 4,376,381 $ 4,471,762 $ 4,519,228 $ 4,505,921
------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ------------ ------------
TOTAL ASSETS.................. $ 4,445,0394,509,857 $ 4,375,946
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
TOTAL ASSETS.......................5,362,175 $ 5,438,5365,438,496 $ 5,346,330 $ 5,323,890
$ 5,359,597 $ 5,246,435------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- ----------------------- ------------
CAPITALIZATION:
Long-term debt...................debt.............. $ 3,258,046 $ 4,052,470 $ 4,207,320 $ 4,128,080 $ 4,058,251
$ 4,095,796 $ 4,093,218
Obligation under capital
leases..leases.................... 288,638 293,682 296,478 303,749 303,458
302,061 300,833Other obligations........... 52,176 41,685 -- -- --
Patronage capital and
membership fees............................fees............. 330,509 356,229 338,891 309,496 289,982
264,261 236,789------------ ------------ ----------- ----------- ----------- ----------- ----------------------- ------------
$ 3,929,369 $ 4,744,066 $ 4,842,689 $ 4,741,325 $ 4,651,691
------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ------------ ------------
PROPERTY ADDITIONS............ $ 4,662,11863,527 $ 4,630,840
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
PROPERTY ADDITIONS.................93,704 $ 138,921 $ 206,345 $ 235,285
$ 232,283 $ 225,021------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- ----------------------- ------------
ENERGY SUPPLY (MEGAWATT-HOURS)(MEGAWATT-
HOURS):
Generated........................Generated................... 17,722,059 17,866,143 18,402,839 16,924,038 14,575,920
13,805,683 12,686,323
Purchased........................Purchased................... 6,377,643 6,606,931 5,738,634 4,381,087 7,620,815
6,233,262 6,915,758------------ ------------ ----------- ----------- ----------- ----------- ----------------------- ------------
Available for sale...............sale.......... 24,099,702 24,473,074 24,141,473 21,305,125 22,196,735
20,038,945 19,602,081------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- ----------------------- ------------
MEMBER REVENUE PER KWH SOLD........ 5.53CENTS 5.65CENTS 5.47CENTS 5.55CENTS 5.36CENTSSOLD... 4.83 cents 5.11 cents 5.53 cents 5.65 cents 5.47 cents
------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- ----------------------- ------------
2629
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
CORPORATE RESTRUCTURING
Oglethorpe and the Members completed a corporate restructuring (the
"Corporate Restructuring") on March 11, 1997, in which Oglethorpe was divided
into three specialized operating companies to respond to increasing competition
and regulatory changes in the electric industry. As part of the Corporate
Restructuring, Oglethorpe's transmission business was sold to, and is now owned
and operated by, Georgia Transmission Corporation ("GTC"). Oglethorpe's system
operations business was sold to, and is now owned and operated by, Georgia
System Operations Corporation ("GSOC"). (See Note 11 of Notes to Financial
Statements.) Oglethorpe continues to own and operate its power supply business.
Oglethorpe retained all of its owned and leased generation assets. Oglethorpe
also continues to administer its power purchase contracts and, through a wholly
owned subsidiary, EnerVision, Inc., Tailored Energy Solutions ("EnerVision"),
provide marketing support functions to the Members.
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 as net margin in Oglethorpe's statements of revenues and expenses
and patronage capital as net margin.capital. Retained net margins are designated on Oglethorpe's
balance sheets as patronage capital, which is allocated to each of the Members
on the basis of its electricity purchases from Oglethorpe. Since its formation
in 1974, Oglethorpe has generated a positive net margin in each yearyear.
Oglethorpe's equity ratio (patronage capital and as ofmembership fees divided by
total capitalization) increased from 7.5% at December 31, 1995, had1996 to 8.4% at
December 31, 1997.
In connection with the Corporate Restructuring, Oglethorpe made a balance
of $339$49
million special patronage capital distribution to the Members which was used
by the Members to establish equity in and to provide initial working capital
to GTC. This distribution was offset primarily by current year margins and
resulted in a net decrease in patronage capital.capital from $356 million at
December 31, 1996, to $331 million at December 31, 1997.
Patronage capital constitutes the principal equity of Oglethorpe. Under
Oglethorpe's patronage capital retirement policy, margins are returned to the
Members 30 years after the year in which the margins are earned. Pursuant to
such policy, no patronage capital would be retired until 2010, at which time
the 1979 patronage capital would be returned. (See "Proposed Restructuring"
below regarding a special patronage capital distribution contemplated in
connection with the proposed restructuring.) Any
distributions of patronage capital are subject to the discretion of the Board
of Directors, andsubject to Indenture rerquirements. Under the approval byIndenture, dated
as of March 1, 1997, from Oglethorpe to SunTrust Bank, Atlanta, as trustee
("Mortgage Indenture"), Oglethorpe is prohibited from making any distribution
of patronage capital to the Rural Utilities Service (RUS), formerly known asMembers if, at the Rural
Electrification Administration (REA).time thereof or after giving
effect thereto, (i) an event of default exists under the Mortgage Indenture,
(ii) Oglethorpe's equity ratio (patronage capital and membership fees divided
byas of the end of the immediately preceding fiscal
quarter is less than 20% of Oglethorpe's total capitalization) increased from 6.5% at December 31, 1994capitalization, or (iii) the
aggregate amount expended for distributions on or after the date on which
Oglethorpe's equity first reaches 20% of Oglethorpe's total capitalization
exceeds 35% of Oglethorpe's aggregate net margins earned after such date.
This last restriction, however, will not apply if, after giving effect to
7.0% at
December 31, 1995.such distribution, Oglethorpe's equity as of the end of the immediately
preceding fiscal quarter is not less than 30% of Oglethorpe's total
capitalization.
RATES AND FINANCIAL COVERAGE REQUIREMENTSREGULATION
Pursuant to the Amended and Restated Wholesale Power Contracts between
Oglethorpe has entered into an "all-requirements" wholesale power
contract withand each of its Members. Pursuant to such contracts,the Members dated as of August 1, 1996 ("Wholesale
Power Contracts"), Oglethorpe is required to design capacity and energy rates
that generate sufficient revenues to recover all costs as described in such
contracts, and to establish and maintain reasonable margins.margins and to meet its
financial coverage requirements. Oglethorpe reviews its capacity rates at
least annually to ensure that its fixed costs are being adequately recovered
and, if necessary, adjusts its rates to meet its net margin goals.
Oglethorpe's energy rate is set annually and adjusted at mid-yearestablished 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 additionalnew 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 year1995 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 new1995 rates
options produced $2.5 million of revenues in excess
30
of budgeted amounts. Such excess amounts will bewere returned to the Members in 1996.
Under an interima capacity rate mechanism effective from January 1, 1996 to April
30,throughout 1996, each Member haswas
responsible for an assigned share of responsibility for fixed costs based on an agreed-upon
allocation. Under this approach, capacity costs will
bewere 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 theThis interim rate mechanism was extended 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 thatMarch 31, 1997 until a
new rate schedule would bebecame effective forunder the Wholesale Power Contracts on April
1, 1997, which would implementin connection with the Corporate Restructuring. This new rate schedule
implements on a long-term basis the assignment of responsibility for fixed
costscosts. The monthly charges for capacity and other non-energy charges are based
on historical
demand factors. In 1996, management expects a rate formula using the Oglethorpe budget. The Board of Directors may adjust
such capacity and other non-energy charges during the year through an adjustment
to the annual budget. Energy charges are based on actual energy costs, whether
incurred from generation or purchased power resources or under the power
marketing arrangements.
Under the Mortgage Indenture, Oglethorpe is required, subject to any
necessary regulatory approval, to establish and collect rates that are
reasonably expected, together with other revenues of Oglethorpe, to yield a
Margins for Interest ("MFI") Ratio for each fiscal year equal to at least
1.10. The MFI Ratio is determined by dividing the sum of (i) Oglethorpe's net
increasemargins (after certain defined adjustments), (ii) Interest Charges and (iii)
any amount included in fixed costs
duenet margins for accruals for federal or state income
taxes by Interest Charges. The definition of MFI takes into account any item
of net margin, loss, gain or expenditure of any affiliate or subsidiary of
Oglethorpe only if Oglethorpe has received such net margins or gains as a
dividend or other distribution from such affiliate or subsidiary or if
Oglethorpe has made a payment with respect to absorbingsuch losses or expenditures.
The rate schedule also includes a full year's costsPrior Period Adjustment ("PPA") mechanism
designed to ensure that Oglethorpe achieves the minimum 1.10 MFI Ratio. Amounts,
if any, by which Oglethorpe fails to achieve a minimum 1.10 MFI Ratio would be
accrued as of December 31 of the Rocky Mountain pumped storage
hydroelectric facility (Rocky Mountain); however, becauseapplicable year and collected from the Members
during the period April through December of anticipated
increasesthe following year. Amounts within a
range from a 1.10 MFI Ratio to a 1.20 MFI Ratio are retained as patronage
capital. Amounts, if any, by which Oglethorpe exceeds the maximum 1.20 MFI Ratio
would be charged against revenues as of December 31 of the applicable year and
refunded to the Members during the period April through December of the
following year. The rate schedule formula is intended to provide for the
collection of revenues which, together with revenues from all other sources, are
equal to all costs and expenses recorded by Oglethorpe, plus amounts necessary
to achieve at least the minimum 1.10 MFI Ratio.
For 1997, Oglethorpe achieved an MFI Ratio of 1.10. For comparative purposes
only, the pro forma MFI Ratio for 1996 would have been 1.09.
Under the terms of Oglethorpe's prior mortgage, all rate revisions by
Oglethorpe were subject to the approval of the Rural Utilities Service ("RUS").
Under the Mortgage Indenture and related loan contract with RUS, adjustments to
Oglethorpe's rates to reflect changes in energy sales and decreasesOglethorpe's budgets are not subject to
RUS approval, except for any reduction in energy costs, average Member
revenues (measuredrates in cents per kilowatt-hour (kWh)) should remain ata fiscal year following a
fiscal year in which Oglethorpe has failed to meet the minimum 1.10 MFI Ratio
set forth in the Mortgage Indenture. Changes to the rate schedule under the
Wholesale Power Contracts are subject to RUS approval. Oglethorpe's rates are
not subject to the approval of any other federal or nearstate agency or authority,
including the 1995 level.Georgia Public Service Commission.
Prior to 1997, Oglethorpe utilizesutilized a Times Interest Earned Ratio (TIER)("TIER") as
the basis for establishing its annual net margin goal. TIER is determined by dividing the
sum ofUnder Oglethorpe's net margin plus interest on long-term debt (including
interest charged to construction) by Oglethorpe's interest on long-term debt
(including interest charged to construction). The RUS Mortgage requiresprior
mortgage, Oglethorpe was required to implement rates that arewere 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 for1995 and 1996, is also a 1.07 TIER.and such TIER was achieved in each year. In addition to
the TIER requirement under the RUS Mortgage,prior mortgage, Oglethorpe iswas also required
under the RUS Mortgageprior mortgage to implement rates designed to maintain a Debt Service
Coverage Ratio (DSC)("DSC") of not less than 1.0 and an Annual Debt Service Coverage
Ratio (ADSCR)("ADSCR") of not less than 1.25. By paying in fullOglethorpe always met or defeasing certain outstanding pollution control revenue bonds (PCBs),
Oglethorpe could reduceexceeded the
TIER, DSC and ADSCR requirementrequirements of the prior mortgage.
TIER is determined by dividing the sum of Oglethorpe's net margin plus
interest on long-term debt (including interest charged to 1.15.construction) by
Oglethorpe's interest on long-term debt (including interest charged to
construction). 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
31
amortization (excluding amortization of nuclear fuel and debt discount and
expense) by Oglethorpe's interest and principal payable on long-term debt
secured under the RUS Mortgageprior mortgage (excluding interest charged to construction).
RESULTS OF OPERATIONS
HISTORICAL FACTORS AFFECTING FINANCIAL PERFORMANCE
Oglethorpe has always met orutilized both long-term contractual arrangements with
Georgia Power Company ("GPC") and a rate mechanism utilizing deferred margins
to allow for a gradual absorption of costs of generating plants into rates
over several years. As of May 31, 1995, Oglethorpe's Members have fully
absorbed into rates responsibility for the cost of its ownership interests in
Plant Vogtle Units No. 1 and No. 2, and as of December 31, 1996, Oglethorpe's
Members have fully absorbed into rates the costs of Rocky Mountain, the last
of Oglethorpe's generating plants to be placed into service.
Contractual arrangements with GPC provided that Oglethorpe sell to GPC 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 (the "GPC Sell-back"). As of May 31, 1995, the GPC
Sell-back expired for all units.
Prior to the completion of the first unit of Plant Vogtle in 1987,
Oglethorpe's Board of Directors implemented policies that resulted in the
gradual absorption of the costs of Plant Vogtle by the Members. In each of the
years 1985 through 1995, Oglethorpe exceeded its net margin goal. The Board
adopted resolutions in each of these years requiring that these excess margins
be retained and used to mitigate rate increases associated with Plant Vogtle
and, subsequently, with Rocky Mountain. In each year beginning with 1989, a
portion of these margins was returned to the TIER, DSCMembers through billing credits.
(See Note 1 of Notes to Financial Statements.) As of December 31, 1996, all
amounts previously retained have been returned to the Members and ADSCRthis rate
mechanism ended.
POWER MARKETER ARRANGEMENTS
Oglethorpe is utilizing long-term power marketer arrangements to reduce the
cost of power to the Members. Oglethorpe has entered into power marketer
agreements with LG&E Energy Marketing Inc. ("LEM") effective January 1, 1997,
for approximately 50% of the load requirements of the RUS Mortgage. TIER, DSCMembers and ADSCRwith Morgan
Stanley Capital Group Inc. ("Morgan Stanley"), effective May 1, 1997, with
respect to 50% of the Members' then forecasted load requirements. The LEM
agreements are based on the actual requirements of the Members during the
contract term, whereas the Morgan Stanley agreement represents a fixed supply
obligation. Under these power marketer agreements, Oglethorpe purchases energy
at fixed prices covering a portion of the costs of energy to its Members. LEM
and Morgan Stanley, in turn, have certain rights to market excess energy from
the Oglethorpe system. All of Oglethorpe's existing generating facilities and
power purchase arrangements are available for use by LEM and Morgan Stanley for
the years 1993term of the respective agreements. Oglethorpe continues to be responsible
for all of the costs of its system resources but receives revenue from LEM and
Morgan Stanley for the use of the resources.
Oglethorpe utilized short-term power marketer arrangements during 1996. The
initial agreement was with Enron Power Marketing, Inc. ("EPMI") and was in place
January through August. From September through December 1996, another power
marketer arrangement was utilized with Duke/Louis Dreyfus L.L.C. ("DLD"). Under
each of the agreements, the power marketer was required to provide to Oglethorpe
at a favorable fixed rate all the energy needed to meet the Members'
requirements and Oglethorpe was required to provide to the power marketer at
cost, subject to certain limitations, upon request, all energy available from
Oglethorpe's total power resources. Under both agreements, Oglethorpe continued
to operate the power supply system and continued to dispatch the generating
resources to ensure system reliability.
CORPORATE RESTRUCTURING
As a result of the Corporate Restructuring, the Statements of Revenues
and Expenses for 1997 reflect operations as a combined power supply,
transmission and system operations company through March 31, 1997, and
operations solely as a power supply company thereafter. (See Note 11 of Notes
to Financial Statements for a pro forma Statement of Revenues and Expenses
for the year ended December 31, 1997). Although the Corporate Restructuring
was completed on March 11, 1997, pursuant to the restructuring agreement
among Oglethorpe, GTC and GSOC, all transmission-related and systems
operations-related revenues were assigned to Oglethorpe, and all
transmission-related and systems operations-related costs were paid or
reimbursed by Oglethorpe during the period March 11, 1997 through March 31,
1997.
Decreases in operating revenues, power delivery expenses, depreciation and
amortization, taxes other than income taxes, operating margin and net interest
charges from 1996 to 1997 are primarily attributable to the Corporate
Restructuring.
32
OPERATING REVENUES
SALES TO 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. Revenues from sales to
Members decreased by 2.2% for 1997 compared to 1996 and decreased by 0.7% in
1996 compared to 1995. For 1997 compared to 1996, four factors primarily
contributed to the change in revenues. Two factors were the result of the
Corporate Restructuring and affected comparability, as follows: (1) Member
capacity revenues declined by approximately $75 million due to the transfer
of the transmission and system operations businesses to GTC and GSOC in
connection with the Corporate Restructuring; and (2) as discussed under
"OTHER INCOME (EXPENSE)" herein, Member revenues for 1997 of approximately
$19.5 million related to EnerVision were reflected in "Other Income" since
these marketing support activities are no longer part of operations of the
power supply business. In addition, revenues were significantly affected by
two operational factors: (1) Member energy revenues increased by $80 million
primarily because the short-term power marketer arrangements with DLD and
EPMI allowed Oglethorpe to pass through significant savings during 1996 (see
the discussion of purchased power under "OPERATING EXPENSES" herein); and (2)
in August 1997, capacity revenues were reduced by a $4 million refund to the
Members as a result of an interim budget adjustment to reflect higher than
anticipated investment income.
Revenues from Members for 1996 decreased compared to 1995 due to the
pass-through of savings in energy costs, which more than offset higher
capacity revenue requirements and the effect of increased amounts of energy
sold (see the discussion of savings in purchased power costs under "OPERATING
EXPENSES" herein). Member capacity revenues in 1996 and 1995 were as follows:also
affected by additional fixed costs related to the commercial operation of
Rocky Mountain beginning in June 1995.
The energy portion of Member revenues per kilowatt-hour ("kWh") increased
24.4% in 1997 compared to 1996 and declined 13.2% in 1996 compared to 1995.
Actual energy costs are passed through to the Members such that energy
revenues equal energy costs. The increase in 1997 resulted from the $80
million increase in net energy costs discussed above. The decrease in 1996
resulted from savings of approximately $32 million in energy costs (compared
to budget) achieved under the power marketer arrangements in effect during
1996.
The following table summarizes the amounts of kWh sold to Members and
revenues per kWh during each of the past three years:
KILOWATT-HOURS CENTS PER
(IN THOUSANDS) KILOWATT-HOUR
------------------- -------------------
1997..... 20,664,786 4.83(1)
1996..... 19,807,101 5.11
1995..... 18,442,153 5.53
- ------------------------
(1) Excludes revenues related to the transmission business effective
April 1, 1997.
In spite of mild weather in 1997, kWh sales to Members increased by 4.3%
compared to 1996 due to continued growth in the Member systems' service
territories. Member sales increased 7.4% in 1996 also due to Member growth,
despite a summer in which temperatures were lower than the prolonged hot
weather in 1995.
SALES TO NON-MEMBERS. Sales of electric services to non-Members were
primarily from energy sales to other utilities and power marketers, and
pursuant to contractual arrangements with GPC. The following table summarizes
the amounts of non-Member revenues from these sources for the past three
years:
1997 1996 1995
1994 1993
---- ---- ------------- --------- ----------
TIER 1.07 1.07 1.07
DSC 1.21 1.19 1.23
ADSCR 1.27 1.25 1.26(DOLLARS IN THOUSANDS)
Sales to other utilities.......................... $ 17,533 $ 38,956 $ 52,828
Sales to power marketers.......................... 14,623 15,895 --
GPC power supply arrangements..................... 13,169 13,703 43,226
ITS transmission agreements....................... 2,208 9,789 12,614
GPC plant operating agreements.................... -- -- 10,096
--------- --------- ----------
Total............................................. $ 47,533 $ 78,343 $ 118,764
--------- --------- ----------
--------- --------- ----------
Historically,Revenues from sales to non-Members declined in 1997 compared to 1996 and
in 1996 compared to 1995. Sales to other utilities in 1997 represent sales
made directly by setting ratesOglethorpe. Oglethorpe sells for its own account any energy
available from the portion of its resources dedicated to meetMorgan Stanley that
is not scheduled by Morgan Stanley pursuant to its power marketer
arrangements. EPMI and DLD initiated sales to other utilities in 1996. In
1996, where the TIER goals establishedpower marketer did not have a contractual relationship with
the purchaser and Oglethorpe did, Oglethorpe recorded the sale and credited
the revenues to the power marketer in its monthly billing. In 1995,
Oglethorpe made these sales directly to other utilities.
Under the LEM and Morgan Stanley power marketer arrangements, and
previously, under the EPMI and DLD power marketer arrangements, sales to the
power marketers represented the net energy trans-
33
mitted on behalf of LEM, Morgan Stanley, EPMI and DLD off-system on a daily
basis from Oglethorpe's total resources. Such energy was sold to LEM, EPMI
and DLD at Oglethorpe's cost, subject to certain limitations, and to Morgan
Stanley at a contractually fixed price. The volume of sales to power
marketers depends primarily on the power marketers' decisions for servicing
their load requirements.
The third source of non-Member revenues was power supply arrangements
with GPC. These revenues were derived, for the most part, from energy sales
arising from dispatch situations whereby GPC caused co-owned coal-fired
generating resources to be operated when Oglethorpe's system did not require
all of its contractual entitlement to the generation. These revenues
compensated Oglethorpe for its costs because, under the operating agreements
(before the agreements were recently amended as discussed below), Oglethorpe
was responsible for its share of fuel costs any time a unit operated.
Revenues from sales of this type to GPC varied slightly in 1997 compared to
1996 and were lower in 1996 compared to 1995. In 1996, the power marketers
elected to retain more of the output from Plant Wansley than in 1995.
Pursuant to the amendments to the Plant Wansley ownership and operating
agreements, Oglethorpe elected to separately dispatch its ownership interest
in Plant Wansley beginning May 1, 1997. Thereafter, Plant Wansley ceased to
be a source of this type of sales transaction; therefore, this type of sale
to GPC has ended.
The fourth source of non-Member revenues was primarily payments from GPC
for use of the Integrated Transmission System ("ITS") and related
transmission interfaces. GPC compensated Oglethorpe to the extent that
Oglethorpe's percentage of investment in the ITS exceeded its percentage use
of the system. In such case, Oglethorpe was entitled to compensation for the
use of its investment by the other ITS participants. As a result of the
Corporate Restructuring, all of the revenues in this category have accrued to
GTC since April 1, 1997. The change in revenues for 1996 compared to 1995
resulted from normal variations of Oglethorpe's investment percentages and
its use of the system.
The fifth source of non-Member revenue was plant operating agreements
with GPC. The elimination of the revenues from the plant operating agreements
was due to the scheduled conclusion, effective June 1, 1995, of the GPC
Sell-back with respect to Plant Vogtle.
OPERATING EXPENSES
Oglethorpe's operating expenses decreased 3.7% in 1997 compared to 1996
and decreased 2.6% in 1996 compared to 1995. The overall decrease in
operating expenses for 1997 compared to 1996 was primarily attributable to
the expenses relating to the transmission business assumed by GTC in
connection with the Corporate Restructuring. The decrease in operating
expenses in 1996 compared to 1995 was primarily attributable to energy cost
savings achieved under the short-term power marketer arrangements offset
somewhat by an increase in depreciation and amortization.
The increase in 1997 production operations and maintenance costs was
partly attributable to a maintenance outage at Scherer Unit No. 1. In
addition, effective January 1, 1996, the costs of nuclear refueling outages
are deferred and amortized over the 18-month period following the outage.
Such change in accounting resulted in a $12.4 million deferral of maintenance
costs in 1996.
The decrease in total fuel costs in 1996 as compared to 1995 resulted
partly from unplanned outages at Plant Scherer and Plant Wansley Unit No. 1
and partly from the power marketer electing to dispatch the fossil units
less. These factors resulted in 3.1% lower fossil generation in 1996 compared
to 1995.
Purchased power cost increased 16.5% in 1997 compared to 1996, despite
the fact that effective September 1, 1997 another 250 megawatt ("MW")
component block (coal-fired units) of the Block Power Sale Agreement (the
"BPSA") between Oglethorpe and GPC was eliminated. Although 3.5% fewer
megawatt-hours ("MWhs") were purchased in 1997 compared to 1996, average
purchased power cost increased by 20.7%. As noted below, significant energy
cost savings were realized in 1996 from the EPMI and DLD power marketer
arrangements. Purchased power cost decreased by 14% in 1996 compared to 1995.
Lower purchased power costs were achieved in 1996 despite a 15% increase in
energy purchases in 1996 from 1995 levels. The 1996 cost reduction was due to
(1) energy cost savings of $32 million realized from the short-term power
marketer arrangements and (2) reductions in purchased power capacity costs
due to (a) proceeds of $10.8 million from the settlement of a lawsuit with
GPC and (b) savings resulting from the elimination effective September 1,
1996, of a 250 MW component block (coal-fired units) of the BPSA between
Oglethorpe and GPC.
Purchased power expenses for the years 1995 through 1997 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 require-
34
ments. For 1995 through 1997, Oglethorpe utilized its energy from these
purchase power agreements in excess of the take-or-pay requirements.
Oglethorpe's power purchases from these agreements amounted to approximately
$176 million in 1997, $191 million in 1996 and $207 million in 1995. (For a
discussion of the power purchase agreements, see Note 9 of Notes to Financial
Statements.)
The increase in depreciation and amortization in 1996 was partly due to a
full year of depreciation on Rocky Mountain which began commercial operation
in June 1995 and to $14 million of Board-approved accelerated amortization of
deferred charges of the discontinued Pickens County pumped storage
hydroelectric project. All remaining unamortized charges related to this
project were expensed in 1996.
Other operating expenses for 1996 and 1995 represent marketing services
expenses. As discussed under "Other Income (Expense)" herein, such expenses
for 1997 of approximately $18.3 million related to EnerVision were shown in
"OTHER INCOME (EXPENSE)" since these marketing support activities are no
longer part of operations of the power supply business.
OTHER INCOME (EXPENSE)
Interest income increased for 1997 compared to 1996 and 1996 compared to
1995. Interest income was higher in 1997 as a result of higher earnings from
the decommissioning fund and partly due to income from the deposits from the
Rocky Mountain transactions. The deposits were made in December 1996 and
January 1997. In 1996, interest income was higher due to higher average
investment balances.
In contemplation of separating its marketing support services from the
power supply business, in 1997 Oglethorpe began accounting for the revenues
and expenses relating to EnerVision as a non-operating "Other income
(expense)" item. Such activities produced a margin of approximately $1.2
million and are reflected in the "Other" caption of "Other income (expense)"
on the Statement of Revenues and Expenses.
In 1996, Oglethorpe utilized all remaining amounts available ($32
million) under its deferred margin rate mechanism, and, as scheduled, this
mechanism ended. Likewise, deferred margins of $16 million were amortized as
credits against Member revenue requirements in 1995 to mitigate the rate
impact of increased capacity costs related to Plant Vogtle and Rocky
Mountain. Also, in 1995, Oglethorpe's Board of Directors authorized the
DSC and ADSCR requirementsretention of approximately $14 million in excess of the 1.07 TIER margin
requirement as deferred margins under the mechanism. (See Note 1 of Notes to
Financial Statements for a discussion of deferred margins and amortization of
deferred margins.)
INTEREST CHARGES
Net interest charges for 1997 decreased compared to 1996 primarily due to
the debt assumed by GTC in connection with the Corporate Restructuring. Net
interest charges increased in 1996 compared to 1995 due to the decrease in
allowance for debt funds used during construction ("AFUDC") as a result of
the three units of Rocky Mountain becoming commercially operable in June and
July 1995. The decrease in gross interest on long-term debt and capital
leases in 1996 compared to 1995 was due to the refinancing efforts discussed
under "Financial Condition--Refinancing Transactions" below.
FINANCIAL CONDITION
GENERAL
The principal changes in Oglethorpe's financial condition in 1997 were
due to property additions, reductions in the cost of capital and a special
patronage capital distribution. Property additions totaled $64 million and
were funded entirely with funds from operations.
A decrease in the cost of capital was achieved through the refinancing of
$237 million of long-term debt and the prepayment of an additional $116
million of long-term debt. The average interest rate on long-term debt
decreased from 6.56% at December 31, 1996 to 6.46% at December 31, 1997. (For
a further discussion of the refinancing transactions, see "REFINANCING
TRANSACTIONS" and "ROCKY MOUNTAIN LEASE TRANSACTIONS" herein.)
Finally, Oglethorpe's equity was reduced by $49 million due to a special
patronage capital distribution made to the Members in conjunction with the
Corporate Restructuring.
CAPITAL REQUIREMENTS
As part of its ongoing capital planning, Oglethorpe forecasts
expenditures required for generation facilities and other capital projects.
The table below details these expenditure forecasts for 1998 through 2000.
Actual capital expenditures may vary from the
35
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, cost
of capital, equipment, material and labor, and decisions to construct, rather
than purchase, additional capacity.
CAPITAL EXPENDITURES
(DOLLARS IN THOUSANDS)
------------------------------------------------------------
GENERATING NUCLEAR GENERAL
YEAR PLANT(1) FUEL PLANT AFUDC(2) TOTAL
- -------------------------- ----------- ---------- ----------- ----------- ----------
1998...................... $ 15,303 $ 35,337 $ 1,940 $ 1,290 $ 53,870
1999...................... 13,147 33,301 1,875 1,800 50,123
2000...................... 10,916 39,780 1,931 1,800 54,427
--------- ---------- --------- --------- ----------
Total..................... $ 39,366 $ 108,418 $ 5,746 $ 4,890 $ 158,420
--------- ---------- --------- --------- ----------
--------- ---------- --------- --------- ----------
- ------------------------
(1) Consists of capital expenditures required for replacements and additions
to facilities in service and compliance with environmental regulations.
Oglethorpe currently does not have any new generation facilities under
construction.
(2) Allowance for funds used during construction of generation and general
plant facilities.
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $3.6 billion as of December 31, 1997. The reduction in net
plant compared to December 31, 1996 was primarily due to the transfer of
assets to GTC and GSOC in connection with the Corporate Restructuring.
Expenditures for property additions during 1997 amounted to $64 million and
were funded entirely from operations. These expenditures were primarily for
additions and replacements to generation facilities, and prior to the
Corporate Restructuring, also for transmission facilities.
In addition to the funds needed for capital expenditures, approximately
$268 million will be required over the next three years (1998-2000) for
current sinking fund requirements and maturities of long-term debt. Of this
amount, $201 million, or 75%, relates to the repayment of RUS Mortgageand Federal
Financing Bank ("FFB") debt. Excluded from these amounts is the amount of
debt assumed by GTC and GSOC as part of the Corporate Restructuring.
LIQUIDITY AND SOURCES OF CAPITAL
In the past, Oglethorpe has obtained the majority of its long-term
financing from RUS-guaranteed loans funded by FFB. Oglethorpe has also
obtained a substantial portion of its long-term financing requirements from
tax-exempt pollution control revenue bonds ("PCBs").
In addition, Oglethorpe's operations have alwaysconsistently provided a sizable
contribution to its funding of capital requirements, such that internally
generated funds have provided interim funding or long-term capital for
nuclear fuel reloads, 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 2000 primarily with funds generated from
operations and, if necessary, with short-term borrowings.
To meet short term cash needs and liquidity requirements, Oglethorpe had,
as of December 31, 1997, (i) approximately $63 million in cash and temporary
cash investments, (ii) $97 million in other short term investments and (iii)
up to $330 million total available under the following credit facilities ($92
million of which was in use):
SHORT-TERM CREDIT FACILITIES AMOUNT
- ---------------------------------------------------------- --------------
Commercial Paper.......................................... $ 280,000,000
Committed lines of credit: SunTrust Bank.................. 30,000,000
Uncommitted lines of credit: CFC.......................... 50,000,000
Under its commercial paper program, Oglethorpe may issue commercial paper
not to exceed $280 million outstanding at any one time. The commercial paper
is backed 100% by committed lines of credit provided by a group of banks for
which SunTrust Bank acts as agent. The maximum amount that can be outstanding
at any one time under the commercial paper program and the other lines of
credit totals $330 million due to certain restrictions contained in the
SunTrust Bank committed line of credit agreement. As of December 31, 1997,
$92 million of commercial paper was outstanding which was issued to fund the
defeasance of certain PCBs in conjunction with the Corporate Restructuring.
(See "REFINANCING TRANSACTIONS" below for a further discussion of this
defeasance.)
REFINANCING TRANSACTIONS
Over the past few years, Oglethorpe has implemented a program to reduce
its interest costs by refinancing a sizable portion of its high-interest rate
debt. Since the first transaction was completed in June 1992, Oglethorpe has
refinanced $1.2 billion in FFB debt, $1.1 billion in PCB debt and $225
million in serial facility bond debt. Refinancings completed in 1997 include
the $225 million of serial facility bonds and the refinancing of $14.6
million of maturing PCB principal.
36
Oglethorpe has also prepaid $222 million of FFB debt, including 1997
prepayments of $92 million of FFB debt in connection with the Rocky Mountain
transactions described herein and a prepayment of $25 million of FFB debt in
connection with the Corporate Restructuring. (See Note 5 of Notes to
Financial Statements.)
The net result of these transactions has been met or exceeded. Basedto reduce the average
interest rate on Oglethorpe's current financial
projections, however, TIER levelstotal long-term debt from 8.83% at December 31,
1991 to 6.46% at December 31, 1997.
Oglethorpe has implemented a program under which it is refinancing, on a
continued tax-exempt basis, the current Board policy may not
produce rates sufficientannual principal maturities of certain
tax-exempt serial bonds and tax-exempt term bonds under their mandatory
sinking fund schedules. The refinancing of these principal maturities allows
Oglethorpe to meetpreserve a low-cost source of financing while conserving cash.
To date, Oglethorpe has refinanced approximately $53 million under this
program, including $14.6 million in 1997, and has a plan in place to
refinance principal maturities relating to certain PCB issues through the
current ADSCR requirementyear 2002.
In connection with the Corporate Restructuring, Oglethorpe defeased
approximately $92 million in principal amount of Series 1992 PCBs. Initially
these bonds have been defeased with proceeds from the issuance of
approximately $92 million in commercial paper. Oglethorpe has a plan in place
to refinance the commercial paper issuance with a medium-term loan in 1998
and ultimately expects to refinance the loan with an issuance of PCBs at some
point in the near
future.
InAlso, in connection with the Corporate Restructuring, Oglethorpe
refinanced approximately $217 million in principal amount of Series 1992A
PCBs through the issuance of PCBs maturing on December 1, 1997 (the "Series
1997A Bonds"), which were in turn refinanced through the issuance of PCBs
maturing on May 28, 1998 (the "Series 1997B Bonds"). Oglethorpe has a plan in
place and is in the final stages of a debt offering to refund the Series
1997B Bonds in March 1998 through the issuance of the Series 1998A and Series
1998B PCBs (the "Series 1998 Bonds"), having a January 1, 2019 maturity. The
Series 1998 Bonds will be issued as variable rate bonds and will be supported
by both a municipal bond insurance policy and bank liquidity agreements.
INTEREST RATE SWAP TRANSACTIONS
To refinance high-interest rate PCBs, Oglethorpe entered into two
interest rate swap transactions with a swap counterparty, AIG Financial
Products Corp. ("AIG-FP"), which were designed to create a contractual fixed
rate of interest on $322 million of variable rate PCBs. These transactions
were entered into in early 1993 on a forward basis, pursuant to which
approximately $200 million of variable rate PCBs were issued on November 30,
1993 and approximately $122 million of variable rate PCBs were issued on
December 1, 1994. Oglethorpe is obligated to pay the variable interest rate
that event,accrues on these PCBs; however, the swap arrangements provide a
mechanism for Oglethorpe to achieve a contractual fixed rate which is lower
than Oglethorpe would have obtained had it issued fixed rate bonds.
Oglethorpe's use of financial derivatives is for the purpose of mitigating
business risks and is not for speculative purposes. Oglethorpe's use of
derivatives is currently limited to set ratesthese two swap transactions.
In connection with GTC's assumption of liability on a portion of the PCBs
pursuant to meet the current ADSCR requirementCorporate Restructuring, commencing April 1, 1997, GTC
assumed and agreed to pay 16.86% of any amounts due from Oglethorpe under
these swap arrangements, including the net swap payments and termination
payments described below. Should GTC fail to make such payments under the
assumption, Oglethorpe remains obligated for the full amount of such payments.
Under the swap arrangements, Oglethorpe is obligated to make periodic
payments to AIG-FP based on a notional principal amount equal to the
aggregate principal amount of the bonds outstanding during the period and a
contractual fixed rate ("Fixed Rate"), and AIG-FP is obligated to make
periodic payments to Oglethorpe based on a notional principal amount equal to
the aggregate principal amount of the bonds outstanding during the period and
a variable rate equal to the variable rate of interest accruing on the bonds
during the period ("Variable Rate"). These payment obligations are netted,
such that if the Variable Rate is less than the Fixed Rate, Oglethorpe makes
a net payment to AIG-FP. Likewise, if the Variable Rate is higher than the
Fixed Rate, Oglethorpe receives a net payment from AIG-FP. Thus, although
changes in the Variable Rate affect whether Oglethorpe is obligated to make
payments to AIG-FP or take actionis 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, 1995, 1996 and 1997, Oglethorpe has made in connection
with both interest rate swap arrangements combined net swap payments to
AIG-FP of $6.4 million, $8.2 million and $6.4 million, respectively.
37
The swap arrangements extend for the life of these pcbs. If the swap
arrangements were to be terminated while the PCBs are still outstanding,
Oglethorpe or AIG-FP may owe the other party a termination payment depending
on a number of factors, including whether the fixed rate then being offered
under comparable swap arrangements is higher or lower than the ADSCR requirement by
prepayingFixed 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 defeasing certaina reduction in ratings on Oglethorpe's PCBs, as described above.
MISCELLANEOUS
As with utilities generally, inflation has the effectwithout credit enhancement,
to a level that is below investment grade. Oglethorpe estimates that its
maximum aggregate liability (net of increasing the
cost of Oglethorpe's operations and construction program. Operating and
construction costsGTC's assumed percentage) for termination
payments under both swap arrangements had such payments been due on December
31, 1997 would have been less affected by inflation overapproximately $38 million.
In connection with these interest rate swap arrangements, Oglethorpe (but
not GTC) is obligated to maintain minimum liquidity in an amount equal to 25%
of the last few
years because ratesprincipal amount of inflation have been relatively low.
Currently,the variable rate PCBs outstanding. As of December
31, 1997, the minimum liquidity requirement equaled $81 million and will
decrease proportionately as such bonds are retired as a result of scheduled
sinking fund payments.
ROCKY MOUNTAIN LEASE TRANSACTIONS
Oglethorpe completed, in two separate closings on December 31, 1996 and
January 3, 1997, lease transactions for its 74.61% undivided ownership
interest in Rocky Mountain. Under the terms of these transactions, Oglethorpe
leased the facility to three institutional investors for the useful life of
the facility, who in turn leased it back to Oglethorpe for a term of 30
years. Rocky Mountain is subject to the provisionslien of the Mortgage Indenture. The
leasehold interest transferred is subject and subordinate to such lien.
Oglethorpe will continue to control and operate the plant during the
leaseback term, and will exercise its fixed price purchase option at the end
of the leaseback period so as to retain all other rights of ownership with
respect to the plant if it is advantageous for Oglethorpe to exercise such
option. As a result of these transactions, Oglethorpe received net present
value cash benefits of approximately $96 million that is being recorded as a
deferred credit and will be recognized in income over the term of the
leaseback. Approximately $92 million was used for the early retirement of FFB
debt and approximately $4 million was used to pay alternative minimum taxes
on the transactions. The combination of the debt prepayment and the amortized
gain will result in an estimated $11 million in annual savings through 2001,
and additional savings in declining amounts for the remaining 25 years of the
lease. In connection with these transactions, Oglethorpe is obligated to
maintain minimum liquidity of $50 million.
SCHERER UNIT NO. 1 LEASE TRANSACTION
Oglethorpe is considering a lease transaction for its 60% interest in
Scherer Unit No. 1. Should Oglethorpe decide to proceed with this
transaction, it could close in mid-to-late 1998. This transaction, if
completed, would provide a substantial up-front cash payment to Oglethorpe
which would be amortized over the term of the lease to reduce revenue
requirements from the Members. Oglethorpe expects that substantially all of
any such net cash benefit would be used to prepay a portion of FFB debt.
COMPETITION
The electric utility industry in the United States is undergoing
fundamental change and is becoming increasingly competitive. This change is
promoted by the Energy Policy Act of 1992, recently adopted and proposed
policies from the Federal Energy Regulatory Commission ("FERC") regarding
transmission access and pricing, state deregulation initiatives, increased
consolidation and mergers of electric utilities, the proliferation of power
marketers and independent power producers, surplus generation in certain
regional markets and other factors.
Several states are in the process of implementing varying forms of
"retail wheeling" (the transmission of power for a third party directly to a
retail customer) and most others are in the various stages of considering
retail competition. Proposed federal legislation could mandate retail
wheeling in every state. No legislation related to retail wheeling has yet
been enacted in Georgia, and, currently, no bill is pending in the Georgia
legislature which would amend the Georgia Territorial Electric Service Act
(the "Territorial Act") or otherwise affect the exclusive right of the
Members to supply power to their current service territories. In 1997, the
staff of the GPSC conducted a series of workshops to solicit views from the
various parties impacted by electric industry restructuring and to discuss
potential resolutions of these issues. The GPSC has issued a report
identifying electric industry restructuring issues, potential resolutions and
the views of the parties who participated in the workshops. The GPSC does not
have the authority under Georgia law to order retail wheeling or amend the
Territorial Act. Oglethorpe and the Members participated in the GPSC staff
workshops and are actively monitoring and studying legislative initiatives in
Congress and in other states to take advantage of the experiences of
cooperatives and other utilities in other states to protect their interests
in future legislative activities in Georgia.
Under current Georgia law, the Members general-
38
ly have the exclusive right to provide retail electric service in their
respective territories. Since 1973, however, Georgia has permitted limited
competition among electric utilities located in Georgia for sales of
electricity to certain large commercial or industrial customers. Pursuant to
the Territorial Act, the owner of any new facility may receive electric
service from the power supplier of its choice if the facility is located
outside of municipal limits and has a connected demand upon initial full
operation of 900 kilowatts or more. The Members, with Oglethorpe's support,
are actively engaged in competition with other retail electric suppliers for
these new commercial and industrial loads. While the competition for 900
kilowatt loads represents only limited competition in Georgia, this
competition has given Oglethorpe and the Members the opportunity to develop
resources and strategies to operate in an increasingly competitive market.
Over the past years, Oglethorpe has taken several steps to prepare for
and adapt to the fundamental changes that have occurred or are likely to
occur in the electric utility industry and to reduce the possibility of
incurring stranded costs. Most importantly, Oglethorpe completed the
Corporate Restructuring and divided itself into generation, transmission and
system operations companies in order to better serve its Members in a
deregulated and competitive environment. (See "General"Corporate
Restructuring" herein.) Since 1992, Oglethorpe also has pursued an interest
cost reduction program. As a result of this program, Oglethorpe has prepaid
$222 million of FFB debt and refinanced $1.2 billion of FFB debt, $1.1
billion of PCB debt and $225 million of serial facility bond debt. These
steps have reduced Oglethorpe's interest costs significantly. (See "Financial
Condition"Refinancing Transactions" herein.)
Oglethorpe and the Members also amended the Wholesale Power Contracts in
connection with the Corporate Restructuring. The Wholesale Power Contracts
provide that the Members are jointly and severally responsible for all costs
and expenses of all existing generation and purchased power resources of
Oglethorpe, as well as certain future power resources. Each Wholesale Power
Contract specifically provides that the Member must make payments whether or
not power has been delivered and whether or not a plant has been sold or is
otherwise unavailable. The formulary rate established by Oglethorpe in the
rate schedule to the Wholesale Power Contracts employs a rate methodology
under which all categories of costs are specifically separated as components
of a formula to determine Oglethorpe's revenue requirements. The rate
schedule also allocates to the Members the responsibility for all of
Oglethorpe's fixed costs. The Board of Directors may adjust Oglethorpe's
charges under the Wholesale Power Contracts. With respect to Oglethorpe, the
RUS has retained certain approval rights over the changes to the Wholesale
Power Contracts, including the rate schedule. (See "General-RATES AND
FINANCIAL COVERAGE REQUIREMENTS" herein.) As a result of these contractual
agreements, the Members ultimately are liable for the existing power
resources of Oglethorpe.
Oglethorpe has also entered into arrangements with power marketers to
obtain the value that can be brought by power marketers and to provide for
future load requirements without taking all the risk associated with
traditional suppliers. (See "Results of Operations-POWER MARKETER
ARRANGEMENTS" herein.)
Oglethorpe and the Members continue to consider and evaluate a wide array
of other potential actions to reduce costs and to maintain their
competitiveness in anticipation of future competition. These activities on
the part of Oglethorpe and the Members are in various stages of study or
preliminary consideration. Many Members are now providing or considering
proposals to provide non-traditional products and services such as
telecommunications and other services. Depending on the nature of future
competition in Georgia, there could be reasons for the Members to separate
their physical distribution business from their energy business, or otherwise
restructure their current businesses to operate effectively under retail
competition. Oglethorpe continues to seek to identify and evaluate
opportunities to reduce the cost of wholesale power to the Members.
Oglethorpe currently defers certain costs of providing services to the
Members pursuant to Statement of Financial Accounting Standards ("SFAS") No.
71, "Accounting for the Effects of Certain Types of Regulation". Oglethorpe has recordedRegulation." Note 1 of
Notes to Financial Statements sets forth the regulatory assets and
liabilities relatedreflected on Oglethorpe's balance sheet as of December 31, 1997.
Regulatory assets represent probable future revenues to its generation and transmission operations.Oglethorpe associated
with certain costs that will be recovered from Members through the ratemaking
process. Regulatory liabilities represent probable future reduction in
revenues associated with amounts that are to be credited to Members through
the ratemaking process. (See "General-RATES AND FINANCIAL COVERAGE
REQUIREMENTS" herein.) In the event that Oglethorpe is no longer subject to
the provisions of StatementSFAS No. 71, Oglethorpe would be required to write off related
regulatory assets and liabilities. In addition, Oglethorpe would be required
to determine any
39
impairment ofto other assets, including utility plant, and write down the plant
assets, if
impaired, to their fair value.
See Note 1At this time, Oglethorpe cannot predict the outcome of Notesthe various
developments that may lead to Financial Statements for
additional information.increased competition in the electric utility
industry or the effect of such developments on Oglethorpe or the Members.
MISCELLANEOUS
DECOMMISSIONING COSTS
The staff of the Securities and Exchange Commission (the "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
regulatoryan offsetting asset for differences in the timing of
recognition of the costs of decommissioning for financial reporting and
rate-makingratemaking 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
Plant 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
Overresources due to available amounts
that have been placed in reserves for this purpose.
INFLATION
As with utilities generally, inflation has the past three years, Oglethorpe's Members have absorbed into rates
additional responsibility foreffect of increasing the
cost of its ownership interests in Plant
Scherer Unit No. 2Oglethorpe's operations and Plant Vogtle Units No. 1construction program. Operating and
No. 2. These generating
units were placed in commercial operation in 1984, 1987, and 1989,
respectively.construction costs have been less affected by inflation over the last few
years because rates of inflation have been relatively low.
YEAR 2000 ISSUE
Many information systems have been designed to function based on years
that begin with "19". Oglethorpe has utilized both long-term contractual
arrangements with Georgia Power Company (GPC) and margin and rates mechanisms
to allow for a gradual absorption of costs over several years. In addition,
Oglethorpe is utilizing margin and rates mechanisms to mitigate the impact of
absorbing the costs of Rocky Mountain which was placed in service during June
and July 1995.
Contractual arrangements with GPC providedexpects that Oglethorpe sell to GPC
and GPC purchase from Oglethorpe a declining percentage of Oglethorpe's
entitlement to the capacity and energy of certain co-owned generating plants
during the initial seven to ten years of operation of such units (GPC
Sell-back). As of May 31, 1995, the GPC Sell-back has expired for all units.
(See Note 1 of Notes to Financial Statements.) The historical ability of
Oglethorpe to sell power from new units to GPC under the GPC Sell-back
enabled Oglethorpe to moderate the effects of the higher costs associated
with new generating units on Oglethorpe's cost of service and, therefore, on
the rates charged to Members. Furthermore, the GPC Sell-back enabled
Oglethorpe to obtain the generating capacity needed to serve anticipated
increases in Member loads while minimizing the risks and costs of excess
generating capacity.
Prior to the completion of the first unit of Plant Vogtle in 1987,
Oglethorpe's Board of Directors implemented policies that have resulted in
the gradual absorption of the costs of Plant Vogtle by the Members. In each
of the years 1985 through 1995, Oglethorpe exceededyear 2000 it will have
adapted its net margin goal. The
Board adopted resolutions in each of these years requiring that these excess
margins be retained and used to mitigate rate increases associated with Plant
Vogtle and, subsequently, with Rocky Mountain. In each year beginning with
1989, a portion of these margins has been returned to the Members through
billing credits. (See Note 1 of Notes to Financial Statements.) As of
December 31, 1995, Oglethorpe held a balance of approximately $32 million
from deferred margins which will be utilized in 1996 for rate mitigation as
the annual costs of Rocky Mountain are absorbed.
28
OPERATING REVENUES
Oglethorpe's operating revenues are derived from sales of electric
services to the Members and non-Members. Revenues from Members are collected
pursuant to the wholesale power contracts and are a function of the demand
for power by the Members' consumers and Oglethorpe's cost of service.
Historically, most of Oglethorpe's non-Member revenues have resulted from
various plant operating agreements with GPC as discussed below.
For the period 1993 through 1995, although total revenues have varied
slightly, the scheduled reduction of the GPC Sell-back has resulted in the
planned decrease of non-Member revenues from GPC of about $96 million. As
expected, the capacity and energy no longer being sold to GPC have been used
by Oglethorpe to meet increased Member requirements. In addition to
increasing sales to Members, Oglethorpe has increased revenues from energy
sales to other utilities and achieved reductions in fixed and operating costs
in order to mitigate the need to recover from the Members costs which were
previously recovered through sales to GPC. The refinancing transactions
discussed under "Financial Condition--REFINANCING TRANSACTIONS" below have
resulted in a reduction in gross interest charges from $367 million in 1993
to $318 million in 1995, or a 13% decrease in that fixed cost component of
the capacity rates.
SALES TO MEMBERS. Revenues from sales to Members increased 10.7% in 1995
compared to 1994 and increased 3.5% in 1994 compared to 1993. These increases
reflect two factors: (1) higher capacity revenues, offset by the pass-through
of savings in energy costs (see discussion of savings in fuel costs under
"OPERATING EXPENSES" herein), and (2) increased amounts of energy sold.
As non-Member revenues from GPC have declined, Oglethorpe's Member
capacity revenues are higher reflecting the recovery of the fixed costs which
had previously been recovered from GPC through the GPC Sell-back. Member
capacity revenues in 1995 were also affected by additional fixed costs
related to the commercial operation of Rocky Mountain in June 1995.
Member energy revenues per kWh declined 7.6% in 1995 compared to 1994 and
6.9% in 1994 compared to 1993, reflecting savings in fuel and production
costs. The 1995 decline in revenues per kWh also reflects lower average
purchased power costs. Actual energy costs are passed through to the Members
such that energy revenues equal energy costs.
The following table summarizes the amounts of kWh sold to Members during
each of the past three years:
(IN THOUSANDS) KILOWATT-HOURS
-------------------------------
1995 18,442,153
1994 16,285,127
1993 16,253,283
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 PER KILOWATT-HOUR
-----------------------
1995 5.53 CENTS
1994 5.65
1993 5.47
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:
(DOLLARS IN THOUSANDS) 1995 1994 1993
- -------------------------------------------------------------
Plant operating agreements $ 10,096 $ 45,392 $106,146
Power supply arrangements 43,226 26,280 44,904
Transmission agreements 12,614 10,974 15,763
Other utilities 52,828 42,561 34,127
-------- -------- --------
Total $118,764 $125,207 $200,940
Revenues from sales to non-Members declined in 1995 compared to 1994 and
in 1994 compared to 1993. These decreases were primarily attributable to
scheduled reductions in plant operating agreement revenues attributable to
the GPC Sell-back with respect to Plants Vogtle and Scherer.
The second source of non-Member revenues is power supply arrangements
with GPC. These revenues are derived, for the most part, from energy sales
arising from dispatch situations whereby GPC causes co-owned coal-fired
generating resources to be operated when Oglethorpe's system does not require
all of its contractual entitlement to the generation. These revenues
essentially represent reimbursement of costs to Oglethorpe because, under the
operating agreements, Oglethorpe is responsible for its share of fuel costs
any time a unit operates. Revenues from sales of this type to GPC were
higher in 1995 compared to 1994 and lower in 1994 compared to 1993. In 1995,
Oglethorpe retained less of its share of the output from Plant Wansley units
because the added cost associated with emission allowances made those units
less attractive than certain purchased resources. The lower 1994 revenues
were due to the fact that Oglethorpe retained much of its share of the output
from the Plant Scherer and Wansley units because the lower average fuel costs
made those units more attractive than certain purchased resources. Emission
allowances for Plant Wansley were not required in 1994. See the discussion
under "OPERATING EXPENSES" herein of the lower average fuel costs of the
coal-fired generating units in 1995 and 1994. Pursuant to the amendments to
the Plant Scherer ownership and operating agreements, Oglethorpe elected to
separately dispatch its ownership interest in Plant Scherer beginning May 1,
1994. Thereafter, Plant Scherer ceased to be a source of the above
"automatic" type of sales transaction; however, Oglethorpe did continue to
make other sales to GPC from Plant Scherer in this
29
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 Oglethorpesystems, to the extent it considers necessary, to process years
that begin with "20", and does not expect that the year 2000 issue will have
a material adverse effect on its financial condition or results of operations.
FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS
This Annual Report on Form 10-K contains forward-looking statements,
including statements regarding, among other items, (i) anticipated trends in
Oglethorpe's percentage of investment in the ITS exceeds its percentage use of the system.
In such case, Oglethorpe is entitled to income as compensation for the use
of its investment by the other ITS participants. The change in revenues for
1995 through 1993 resulted from normal variations ofbusiness and (ii) Oglethorpe's investment
percentages and its use of the system.
Revenues from other non-Member utilities increased substantially due to a
22% increase in kWh sales in 1995 as compared to 1994 and a 28% increase in kWh
sales in 1994 as compared to 1993. Oglethorpe is continuing to aggressively
seek additional off-system sales opportunities as a means of reducing amounts
that must be recovered from Members. See "FACTORS AFFECTING FUTURE FINANCIAL
PERFORMANCE" herein regarding Oglethorpe's 1996 short-term power swap
arrangement which committed Oglethorpe's total power resources under a single
contractual arrangement, and regarding Oglethorpe's consideration of a similar
power supply swap arrangement for a longer term basis.
OPERATING EXPENSES
Oglethorpe's operating expenses increased 9.4% in 1995 compared to 1994
and decreased 1.0% in 1994 compared to 1993. The increase in operating
expenses in 1995 compared to 1994 was primarily attributable to a 13.0%
increase in kWh sold to Members and non-Members. In addition, depreciation
and amortization, sales, and administrative and general expenses were also
higher. The slight decrease in operating expenses in 1994 compared to 1993
was largely due to the decline in purchased power expenses offset somewhat by
the increase in fuel expenses. The total kWh of energy supplied through
generation and purchased power in 1994 was 4% less than 1993.
Generally, over the years 1993 through 1995, the Members have received
the benefit of declining per unit fuel costs of Oglethorpe's generating
resources through the pass-through of lower energy costs. The per unit fuel
costs of Oglethorpe's nuclear and fossil generating resources for the last
three years are as follows:
CENTS PER KILOWATT-HOUR
-------------------------
NUCLEAR FOSSIL
---------- ----------
1995 0.59 CENTS 1.74 CENTS
1994 0.64 1.78
1993 0.61 1.96
Oglethorpe began receiving shipments at Plant Scherer of lower-priced
coal from the mining regions of the western United States in the last quarter
of 1993. The use of lower-priced western coal combined with a greater
reliance on a favorable spot market for coal resulted in a per unit fuel cost
decrease for Plant Scherer of 13% in 1995 from 1993 levels. Because of the
decline in fuel cost per kWh at Plant Scherer, the usage of the units
increased significantly. Output from Plant Scherer was 23% higher in 1995
compared to 1994 and 75% higher in 1994 compared to 1993. Oglethorpe
retained significantly less of its output from Plant Wansley in 1995 compared
to 1994 primarily as a result of higher costs associated with the emission
allowances requirement. In 1994 compared to 1993, the per unit fuel cost at
Plant Wansley decreased by almost 10% and thus, Oglethorpe retained more of
its output. The decrease in per unit fuel costs resulted from a greater
reliance on a favorable spot market for coals.
Purchased power cost increased by 16% in 1995 compared to 1994 and
decreased 16% in 1994 compared to 1993. In 1995, the 13% higher kWh sales,
including the increased Member sales and sales to GPC pursuant to power
supply arrangement (see discussion under "OPERATING REVENUES" herein)
resulted in higher utilization of purchased power resources. Energy
purchases increased 31% in 1995 compared to 1994.
The significant increase in 1994 in coal-fired generation (prompted by
declining average fuel costs) as well as declining sales from these
coal-fired resources to GPC pursuant to power supply arrangement resulted in
substantially lower utilization of purchased power resources. Energy
purchases decreased by approximately 43% from 1993 levels.
Purchased power expense for 1993 through 1995 reflect the cost of
capacity and energy purchases under various long-term power purchase
agreements. These long-term agreements have, in some cases, take-or-pay
minimum energy requirements. For 1993 through 1995, Oglethorpe utilized its
energy from these purchase power agreements in excess of the take-or-pay
requirements. Oglethorpe's power purchases from these agreements amounted to
approximately $207 million in 1995, $182 million in 1994 and $192 million in
1993. For a discussion of the power purchase agreements, see Note 9 of Notes
to Financial Statements.
The increase in depreciation and amortization in 1995 is due to the
commercial operation of Rocky Mountain in June.
Sales, administrative and general expenses increased in 1995 primarily as
a result of increased marketing efforts in support of Oglethorpe's Members.
OTHER INCOME
Interest income increased in 1995 compared to 1994 due to higher earnings
from the decommissioning trust fund. In 1994, interest income decreased
compared to 1993 as a result of lower average investment balances.
In 1995, 1994 and 1993, Oglethorpe's Board of Directors authorized the
retention of approximately $14 million, $9 million and $5 million,
respectively, in excess of the 1.07 TIER margin requirement as deferred
margins. The remaining amount at December 31, 1995 of $32 million will be
available in 1996 to mitigate rate increases. Amortization of deferred
margins for 1995 was $16 million, slightly less than the amount utilized in
1994 but significantly more than the amount utilized in 1993. (See Note 1 of
Notes to Financial Statements for a discussion of deferred margins and
amortization of deferred margins.) The decrease in
30
amortization of deferred gains resulted from the completion of amortization in
September 1994 of a gain on the sale of Plant Scherer common facilities. (Also
see Note 1 of Notes of Financial Statements for a discussion of the sale.)
INTEREST CHARGES
Net interest charges increased in 1995 compared to 1994 and decreased
significantly in 1994 compared to 1993. The continued decrease in gross
interest on long-term debtfuture liquidity requirements and
capital leases in 1995 and 1994 was due to the
refinancing efforts discussed under "Financial Condition--REFINANCING
TRANSACTIONS" below. Allowance for debt and equity funds used during
construction (AFUDC) decreased in 1995 compared to 1994 as a result of the
three units of Rocky Mountain becoming commercially operable in June and July
1995. The change in other interest expense in 1995 was due to gains received
on the sale of securities contained in the decommissioning trust fund,
whereas, the decrease in 1994 was primarily due to losses incurred on the
sale of securities contained in the decommissioning trust fund. (See Note 1
of Notes to Financial Statements for explanation of Oglethorpe's accounting
for decommissioning gains and losses.)
FACTORS AFFECTING FUTURE FINANCIAL PERFORMANCE
Future Member rates will be affected by such factors as the annualized
fixed costs relating to Rocky Mountain and related transmission facilities,
the cost of adding to Oglethorpe's existing transmission system, changes in
fuel costs, fluctuating rates of load growth, environmental and other
governmental regulations applicable to Oglethorpe and its suppliers and the
completion in 1996 of the amortization of deferred margins. Oglethorpe's
future rates will also be affected by its ability to forecast accurately its
future power resource needs and by its ability to obtain and manage its power
resources, including its purchases and construction of generating capacity
and its procurement of coal. Also, see "Proposed Restructuring" below for a
discussion of Oglethorpe's proposed restructuring.
The electric utility industry is also becoming increasingly competitive
as a result of deregulation, competing energy suppliers, technologies and
other factors. The Energy Policy Act of 1992 allows for increased
competition among wholesale electric suppliers and increased access to
transmission services by such suppliers. The new competitive environment is
subject to rapidly evolving regulatory policy at both the federal and state
levels which isresources. These forward-looking statements are based on a shift to a market-driven environment from a
regulated one. Significant legislative developments and regulatory
developments at the Federal Energy Regulatory Commission (FERC) and in state
commissions are expected to continue to clarify policy and the regulatory
framework for increased competition. All of these factors present an
increasing challenge to Oglethorpe and the Members to reduce costs, improve
the management of resources and respond to the changing environment.
As a means of reducing the cost of power provided to the Members, on
January 3, 1996, Oglethorpe entered into a power supply swap agreement with
Enron Power Marketing, Inc. (EPMI). The agreement, effective January 4, 1996
through April 30, 1996, requires EPMI to sell to Oglethorpe at a favorable
fixed cost all the energy needed to serve the Members (approximately 5.2
million MWh). Pursuant to the agreement, Oglethorpe is required to sell to
EPMI at cost, subject to certain limitations, all available energy from
Oglethorpe's total power resources. EPMI has the option to market any excess
energy that remains from Oglethorpe's total power resources.
On February 7, 1996, Oglethorpe issued a Request for Proposals (RFP) to
selected bidders for a long-term power supply arrangement. This RFP did not
seek a specific amount of power; instead, it requested proposals for meeting
the combined power needs of the Members with term options ranging from two to
15 years. Action is anticipated by Oglethorpe's Board of Directors during
April, with implementation of a new arrangement as soon thereafter as possible.
FINANCIAL CONDITION
GENERAL
The principal changes in Oglethorpe's financial condition in 1995 were
additions of $599 million to gross utility plant and a decrease in the cost
of capital achieved through the refinancing or prepayment of $336 million of
long-term debt during 1995 and an additional $89 million in January 1996.
The average interest rate on long-term debt decreased from 7.07% at December
31, 1994 to 6.60% at January 31, 1996.
CAPITAL REQUIREMENTS
As part of its ongoing capital planning, Oglethorpe forecasts
expenditures required for generation and transmission facilities and related
capital projects. Actual construction costs may vary from the estimates
listed below because of factors such as changes in business conditions,
fluctuating rates of load growth, environmental requirements, design changes
and rework required by regulatory bodies, delays in obtaining necessary
Federal and other regulatory approvals, construction delays, and cost of
capital, equipment, material and labor. The table below indicates
Oglethorpe's estimated capital expenditures through 1998:
CAPITAL EXPENDITURES
(DOLLARS IN THOUSANDS)
GENERAL
YEAR GENERATION(1) TRANSMISSION(2) PLANT AFUDC(3) TOTAL
- -----------------------------------------------------------------------
1996 $60,640 $ 44,795 $ 4,499 $3,466 $113,400
1997 60,682 39,004 4,000 2,428 106,114
1998 56,703 40,564 4.000 2,086 103,353
-------- -------- ------- ------ --------
Total $178,025 $124,363 $12,499 $7,980 $322,867
-------- -------- ------- ------ --------
-------- -------- ------- ------ --------
(1) Consists of capital expenditures required for (i) replacements and
additions to facilities in service, (ii) compliance with environmental
regulations, and (iii) nuclear fuel reloads.
(2) If the transmission assets are transferred to a new transmission
corporation, the new transmission corporation, and not Oglethorpe, would be
responsible for the transmission capital expenditures and related AFUDC. (See
"Proposed Restructuring" below)
(3) Allowance for funds used during construction of generation, transmission
and general plant facilities.
31
In 1988, Oglethorpe acquired from GPC an undivided ownership interest in
Rocky Mountain and assumed responsibility for its construction and operation.
By July 1995, all three units of Rocky Mountain were in-service and
Oglethorpe's investment in the project at December 31, 1995 was $565 million,
including related transmission facilities. Construction of Rocky Mountain's
recreational facilities is still in progress and should be completed in the
summer of 1996. Oglethorpe expects the final project cost to be
approximately $570 million, or more than $130 million under budget.
Oglethorpe financed its share of Rocky Mountain from the proceeds of an
RUS-guaranteed loan funded by the FFB. As of December 31, 1995, $555 million
had been advanced under this loan. Oglethorpe expects to draw the additional
$15 million to close out the project in 1996.
Currently, Oglethorpe does not have any new generation facilities under
construction, and management does not anticipate the need for construction of
any new capacity well into the future. The System peaking capacity needs
through the early 2000 time frame are expected to be met through purchased
power alternatives. (See discussion of the Member's future power supply
options under "Proposed Restructuring" and Oglethorpe's current request for
proposals under "Results of Operations--FACTORS AFFECTING FUTURE FINANCIAL
PERFORMANCE".)
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $4.5 billion as of December 31, 1995. Expenditures for
property additions during 1995 amounted to $139 million, of which $6 million
was provided from operations. These expenditures were primarily for the
construction of Rocky Mountain and replacements and additions to generation
and transmission facilities.
In addition to the funds needed for capital expenditures, approximately
$541 million will be required over the next five years for sinking fund
requirements and maturities of long-term debt. Of this amount, $424 million,
or 78%, relates to the repayment of RUS and FFB debt.
LIQUIDITY AND SOURCES OF CAPITAL
In the past, Oglethorpe, like most other G&Ts, has obtained the majority
of its long-term financing from RUS-guaranteed loans funded by the FFB.
Oglethorpe has also obtained a substantial portion of its long-term financing
requirements from tax-exempt PCBs.
In addition, Oglethorpe's operations have consistently provided a sizable
contribution to the funding of capital requirements, such that internally
generated funds have provided interim funding or long-term capital for
nuclear fuel reloads, new generation, transmission and general plant
facilities, replacements and additions to existing facilities, and retirement
of long-term debt. Oglethorpe anticipates that it will meet its future
capital requirements through 1998 primarily with funds generated from
operations and, if necessary, with short-term borrowings.
To meet short term cash needs and contingencies, Oglethorpe had
approximately $201 million in cash and temporary cash investments plus $79
million in other short term investments available at the beginning of 1996.
The Corporation also has available credit facilities as follows:
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, Oglethorpe may issue commercial paper
not to exceed $300 million outstanding at any one time. The commercial
paper, which is backed 100% by committed lines of credit provided by a group
of banks, may be used as a source of short-term funds and is not designated
for any specific purpose. Historically, Oglethorpe has not relied on
commercial paper for short-term funding due to the availability of internally
generated funds and has never utilized the backup line of credit.
The maximum amount that can be outstanding at any one time under the
commercial paper program and the lines of credit totals $370 million due to
certain restrictions contained in the SunTrust Bank and CFC line of credit
agreements. As of December 31, 1995, no commercial paper was outstanding and
there was no outstanding balance on any line of credit.
REFINANCING TRANSACTIONS
Over the past few years, Oglethorpe has implemented a program to reduce its
interest costs by refinancing or prepaying a sizable portion of its
high-interest rate PCB and FFB debt. Since the first transaction was completed
in June 1992, Oglethorpe has refinanced $1.1 billion in PCB debt and $1.2
billion in FFB debt and has prepaid another $105 million in FFB debt. Included
in these amounts are a January 1995 refinancing of $285 million of FFB debt and
prepayment of an additional $30 million of FFB debt, and a December 1995
refinancing of $22 million of PCB debt. (See Note 5 of Notes to Financial
Statements.) The net result of the 1995 transactions was to reduce the average
interest rate on total long-term debt from 7.07% at December 31, 1994 to 6.76%
at December 31, 1995. The average interest rate was further reduced to 6.60%
as of January 31, 1996 as a result of a $89 million FFB debt refinancing. The
refinancings completed since the program began will result in total estimated
savings of $90 million in gross interest expense and $80 million in net
interest expense (net of transaction costs) in 1996.
Oglethorpe's use of financial derivatives are for the purpose of
mitigating business risks and are not used for speculative purposes.
Derivatives have been used on a very limited basis, as discussed below, and
at December 31, 1995, the credit risk for derivatives outstanding was not
material.
To refinance high-interest rate PCBs, Oglethorpe entered into two
interest rate swap transactions with a swap counterparty, AIG
32
Financial Products Corp. (AIG-FP), which were designed to create a
contractual fixed rate of interest on $322 million of variable rate PCBs.
These transactions were entered into in early 1993 on a forward basis,
pursuant to which $200 million of variable rate PCBs were issued on November
30, 1993 and $122 million of variable rate PCBs were issued on December 1,
1994. Oglethorpe is obligated to pay the variable interest rate that accrues
on these PCBs; however, the swap agreements provide a mechanism for
Oglethorpe to achieve a contractual fixed rate which is lower than Oglethorpe
would have obtained had it issued fixed rate bonds.
Under the swap agreements, Oglethorpe is obligated to make periodic
payments to AIG-FP based on a notional principal amount equal to the
aggregate principal amount of the bonds outstanding during the period and a
contractual fixed rate (Fixed Rate), and AIG-FP is obligated to make periodic
payments to Oglethorpe on a notional principal amount equal to the aggregate
principal amount of the bonds outstanding during the period and a variable
rate equal to the variable rate of interest accruing on the bonds during the
period (Variable Rate). These payment obligations are netted, such that if
the Variable Rate is less than the Fixed Rate, Oglethorpe makes a net payment
to AIG-FP. Likewise, if the Variable Rate is higher than the Fixed Rate,
Oglethorpe receives a net payment from AIG-FP. Thus, although changes in the
Variable Rate affects whether Oglethorpe is obligated to make payments to
AIG-FP or is entitled to receive payments from AIG-FP, the effective interest
rate Oglethorpe pays with respect to the PCBs is not affected by changes in
interest rates. The Fixed Rate for the $200 million of variable rate bonds
issued in 1993 is 5.67% and the Fixed Rate for the $122 million of variable
rate bonds issued in 1994 is 6.01%. For the three years ended December 31,
1993, 1994 and 1995, Oglethorpe has made in connection with both interest
rate swap arrangements combined net swap payments to AIG-FP of $0.6 million,
$6.0 million, and $6.4 million, respectively, totaling $13.0 million for such
three-year period.
The swap arrangements extend for the life of these PCBs. If the swap
arrangements were terminated while the PCBs were still outstanding,
Oglethorpe or AIG-FP may owe the other party a termination payment depending
on a number of factors, including whether the fixed rate then being offered
under comparable swap arrangements is higher or lower than the Fixed Rate.
Under the terms of the swap agreements, AIG-FP has limited rights to
terminate the swaps only upon the occurrence of specified events of default
or a reduction in ratingslargely on
Oglethorpe's PCBs without credit enhancement
below investment grade. Oglethorpe estimates that its maximum aggregate
liability for termination payments under both swap arrangements had such
payments been due on December 31, 1995 would have been approximately $52
million. (For additional information about the swap arrangements, see Note 2
of Notes to Financial Statements.)
In connection with these interest rate swap agreements, Oglethorpe is
obligated to maintain minimum liquidity in an amount equal to 25% of the
principal amount of the variable rate refunding bonds outstanding. This
minimum liquidity requirement currently equals $81 millionexpectations and will decrease
proportionately as such bonds are retired. The minimum liquidity must
consist of (a) any combination of (i) amounts available under committed lines
of credit and commercial paper programs to pay termination payments, if any,
due upon early termination of the interest rate swap transactions, (ii)
cash, (iii) United States government securities, and (iv) accounts receivable
due within 30 days, less (b) monetary obligations due within 30 days. As of
December 31, 1995, Oglethorpe had approximately $518 million of such
liquidity available to meet this requirement.
PROPOSED RESTRUCTURING
For some time, Oglethorpe and the Members have been discussing various
options to provide the Members greater flexibility for meeting their power
supply needs in an increasingly competitive utility environment. These
discussions led to a restructuring plan approved by Oglethorpe's Board of
Directors in December 1995 to divide Oglethorpe into three specialized
companies to respond to increasing competition in the electric industry
and to settle certain issues confronting Oglethorpe and the Members,
including several Members' previously stated intention to withdraw from
membership in Oglethorpe in order to gain more flexibility. The December
plan proposed the creation of a new transmission company and a new system
operations company and Oglethorpe's retention of the generation business.
Oglethorpe's Board believes there are significant potential benefits to the
Members of having the transmission business and the system operations
business operated in separate companies. Among the principal benefits is that
the Members' freedom to choose among power suppliers, including Oglethorpe,
for their future growth would be enhanced.
The current target date for full implementation of the
restructuring is January 1, 1997. As a preliminary step, Georgia
Transmission Corporation (An Electric Membership Corporation) (GTC) has been
incorporated for future use as the transmission company and Georgia System
Operations Corporation (GSOC) has been incorporated as a Georgia non-profit
corporation for future use as the system operations company. On March 29,
1996, the Boards of Oglethorpe, GTC and GSOC approved an agreement (the
Restructuring Agreement) which sets forth the terms and conditions on which the
restructuring and related changes would occur. The Restructuring Agreement
contemplates that Oglethorpe would operate primarily as a power supply
company, but initially would retain economic development, marketing and
service functions.
Oglethorpe would transfer its transmission business, including its existing
transmission assets, to GTC. GTC would thereafter own and operate the
transmission system and provide transmission services to the Members,
Oglethorpe and third parties. (See Note 6 of Notes to Financial Statements
for a summary of Oglethorpe's investments in electric plant, including
transmission and distribution plant.) The purchase price for the
transmission business would be equal to the sum of (1) the higher of: (a) the
appraised fair market value of such business as determined by an independent
appraiser, or (b) Oglethorpe's net book value for the transmission assets,
plus (2) the value of certain deferred charges. If the appraised value of
the transmission business exceeds Oglethorpe's net book value for the
transmission assets by more than 5%, GTC's Board would have to approve the
payment of any resulting purchase price. The purchase price would be paid by
GTC's assumption of a portion of
33
Oglethorpe's long-term secured debt and by cash obtained through third party
borrowing. Oglethorpe also would make a special patronage capital
distribution to the Members which could be used by the Members to
establish equity in and to provide initial working capital to GTC.
Oglethorpe would transfer its system operations business, consisting of
its operations center and related computer and dispatch equipment, to GSOC.
GSOC would thereafter own and operate the operations center and provide system
operation services to the Members, Oglethorpe, GTC and third parties.
Oglethorpe also plans to implement a new governance structure when: (a)
it receives a favorable ruling from the Internal Revenue Service that such
structure would not affect Oglethorpe's status for federal income tax purposes
as a corporation operating on a cooperative basis, and (b) a new rate
schedule which allocates to each Member responsibility for a specified
percentage of all costs of Oglethorpe's existing resources becomes legally
binding and effective. It is contemplated that the new governance structure
would become effective at the same time as the restructuring, although it is
possible that it could become effective independent of the restructuring.
The new governance structure provides for a board of directors consisting of
six directors elected from the Members, four independent outside directors and
Oglethorpe's President and Chief Executive Officer, rather than Oglethorpe's
current 39-member board which is comprised of directors nominated by each
Member. To be elected, the new directors must be nominated by a committee
composed of a representative from each Member whose vote would be weighted in
accordance with the number of retail customers served by such Member and then
elected by a vote of the Members on a one-member, one-vote basis.
In adopting the Restructuring Agreement, Oglethorpe's Board recommended to
the Members that they become members of GTC and GSOC and that they join with
Oglethorpe, GTC and GSOC in executing an agreement (the Member Agreement) as to
those matters contemplated in the Restructuring Agreement that directly involve
the Members in their capacities as separate corporations. The Member Agreement
will specify the form of transmission contracts and system operation contracts
to be signed by the Members. The Member Agreement will also provide, subject to
the approval of RUS, that Oglethorpe and each Member executing the Member
Agreement would execute a new wholesale power contract to govern the purchase
and sale of power between Oglethorpe and each such Member. Each Member signing
the new wholesale power contract would have a choice as to whether or not to
participate in future power supply projects sponsored by Oglethorpe. Such
Members would be free to own generation directly and to engage in purchases and
sales with other power suppliers. To the extent such Members choose to satisfy
their projected load growth from sources other than Oglethorpe, the growth in
Oglethorpe's revenues from the sale of power would decrease but the growth in
related expenses also would decrease.
Members agreeing to the new wholesale power contracts would have the
option to have energy and reserves priced on a pooled basis or to schedule
their capacity and associated energy separately at prices based on the cost
of production. GSOC would administer the new power pool contemplated by the
new wholesale power contracts and would implement the separate schedules for
Members electing that option. Under the power pool, Oglethorpe resources and
any Member-procured resources would be committed to economic dispatch (pooled)
for the benefit of all pool participants. The power pool arrangement also
would allow the participants to pool resource reserves.
In connection with the restructuring, Oglethorpe plans to adopt specific
implementation procedures for the existing bylaw provision that grants a
Member the right to withdraw from membership in Oglethorpe upon satisfying
certain conditions. These conditions generally would require the withdrawing
Member either to affirm its obligations under its then-existing wholesale
power contract or to assign its rights and obligations under such wholesale
power contract to another party with a credit rating meeting certain
specified requirements. Withdrawal by a Member would continue to be
conditioned upon approval by RUS.
The restructuring is subject to a number of conditions, including (1)
implementationrisks and
uncertainties, certain of which are beyond Oglethorpe's new governance structure, (2) execution of the
Member Agreementcontrol. For factors
that could cause actual results to differ materially from those anticipated
by the Members, execution of new wholesale power contracts
by Oglethorpethese forward-looking statements, see "Competition" herein and the Members, and execution of the transmission contracts
and system operation contracts specified"CERTAIN
FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY" in the Member Agreement, (3) RUS
approval of new wholesale power contracts and the restructuring, (4)
governmental, lender and other third party consents, authorizations, waivers,
orders and approvals, (5) receipt by GTC and GSOC of certain capital
contributions by the Members and (6) assurances from rating agencies that the
ratings on Oglethorpe's outstanding fixed rate PCBs would not be lowered as a
result of the restructuring and that such rating agencies would assign to any
comparable bonds issued by GTC the same or better credit rating as assigned
to Oglethorpe's fixed rate PCBs. Most of these conditions may be waived by
Oglethorpe's Board, subject to RUS approval in certain instances.
The restructuring is expected to take the remainder of 1996 to complete,
although limited aspects of the restructuring may become effective sooner if
specific conditions set forth in the Restructuring Agreement are met.Item 1. In light of these
risks and uncertainties, there can be no assurance that events anticipated by
the significant conditions that must be satisfied, including RUS
and other governmental and third-party approvals and assurances and receipt
of various agreements from the Members, Oglethorpe cannot predict the actual
timing of or the ultimate likelihood of full implementation of the
restructuring or governance changes. Until implementation of the
restructuring, Oglethorpeforward-looking statements contained in this Annual Report will continue its current operations, and until
satisfaction of the conditions applicable to the new governance
structure, Oglethorpe will continue under its existing governance structure.
34in fact
transpire.
40
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not Applicable.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Statements of Revenues and Expenses, For the Years Ended
December 31, 1995, 1994 and 1993................................. 36
Statements of Patronage Capital, For the Years Ended
December 31, 1995, 1994 and 1993................................. 36
Balance Sheets, As of December 31, 1995 and 1994................... 37
Statements of Capitalization, As of December 31, 1995 and 1994..... 39
Statements of Cash Flows, For the Years Ended December 31, 1995,
1994 and 1993.................................................... 40
Notes to Financial Statements......................................
PAGE
-----
Statements of Revenues and Expenses,
For the Years Ended December 31, 1997, 1996 and 1995..................................................... 42
Statements of Patronage Capital,
For the Years Ended December 31, 1997, 1996 and 1995..................................................... 42
Balance Sheets, As of December 31, 1997 and 1996........................................................... 43
Statements of Capitalization, As of December 31, 1997 and 1996............................................. 45
Statements of Cash Flows, For the Years Ended
December 31, 1997, 1996 and 1995......................................................................... 46
Notes to Financial Statements.............................................................................. 47
Report of Management....................................................................................... 60
Report of Independent Public Accountants................................................................... 60
41
Report of Management............................................... 51
Reports of Independent Public Accountants.......................... 51
35
STATEMENTS OF REVENUESREVENUE AND EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1995, 19941997, 1996 AND 19931995
.........................................................................................................
(dollars in thousands)
1997 1996 1995
1994 1993------------ ------------ ------------
OPERATING REVENUES (NOTE 1):
Sales to Members..................................... $1,030,797Members.......................................... $ 930,8751,000,319 $ 899,7201,023,094 $ 1,030,797
Sales to non-Members.................................non-Members...................................... 47,533 78,343 118,764
125,207 200,940
---------- ---------- ---------------------- ------------ ------------
TOTAL OPERATING REVENUES...............................REVENUES.................................... 1,047,852 1,101,437 1,149,561
1,056,082 1,100,660
---------- ---------- ---------------------- ------------ ------------
OPERATING EXPENSES:
Fuel.................................................Fuel...................................................... 206,315 206,524 219,062
203,444 176,342
Production........................................... 133,858 132,723 129,972Production................................................ 157,932 150,787 155,549
Purchased power (Note 9)............................................................... 266,875 229,089 264,844
227,477 271,970
Power delivery.......................................delivery............................................ 4,032 18,216 17,520 16,965 14,286
Sales, administrative and general.................... 39,015 32,269 30,590
Depreciation and amortization........................amortization............................. 126,730 163,130 139,024 131,056 128,060
Taxes other than income taxes........................taxes............................. 26,293 30,262 27,561 24,741 23,328
Income taxes (Note 3)..................................................................... -- -- 1,820
---------- ---------- ------------
Other operating expenses.................................. -- 20,680 17,324
------------ ------------ ------------
TOTAL OPERATING EXPENSES...............................EXPENSES.................................... 788,177 818,688 840,884
768,675 776,368
---------- ---------- ---------------------- ------------ ------------
OPERATING MARGIN.......................................MARGIN............................................ 259,675 282,749 308,677
287,407 324,292
---------- ---------- ---------------------- ------------ ------------
OTHER INCOME (EXPENSE):
Interest income......................................income........................................... 29,303 23,485 18,031 10,518 20,316
Amortization of deferred gains (Notes 1 and 4)................... 2,441 2,341 9,985 12,5322,341
Amortization of proceeds fromnet benefit of sale of income tax benefits
(Note 1).................................................................................. 11,195 8,054 8,043 8,102 8,102
Amortization of deferred margins (Note 1)............................. -- 32,047 15,959 18,072 4,138
Deferred margins (Note 1)............................................................. -- -- (14,282) (9,287) (5,083)
Allowance for equity funds used during construction
(Note 1).............................................................................. 157 238 1,715
2,907 2,278
Other................................................Other..................................................... 3,550 (831) 1,903
498 (3,542)
---------- ---------- ---------------------- ------------ ------------
TOTAL OTHER INCOME.....................................INCOME.......................................... 46,646 65,334 33,710
40,795 38,741
---------- ---------- ---------------------- ------------ ------------
INTEREST CHARGES:
Interest on long-term debt and capital leases........leases............. 261,290 308,013 317,968
329,738 367,439
Other interest.......................................interest............................................ 13,845 10,006 12,979 3,856 8,539
Allowance for debt funds used during construction
(Note 1)............................................................................................ (1,674) (2,576) (21,114) (36,113) (29,988)
Amortization of debt discount and expense............expense................. 10,455 10,888 10,296
7,639 4,662
---------- ---------- ---------------------- ------------ ------------
NET INTEREST CHARGES...................................CHARGES........................................ 283,916 326,331 320,129
305,120 350,652
---------- ---------- ----------
MARGIN BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE.................................. 22,258 23,082 12,381
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR
INCOME TAXES ......................................... -- -- 13,340
---------- ---------- ---------------------- ------------ ------------
NET MARGIN ............................................MARGIN.................................................. $ 22,405 $ 21,752 $ 22,258
$ 23,082 $ 25,721
---------- ---------- ----------
---------- ---------- ---------------------- ------------ ------------
------------ ------------ ------------
STATEMENTS OF PATRONAGE CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 1995, 19941997, 1996 AND 19931995
(dollars in thousands)
1997 1996 1995
1994 1993
.........................................................................................................---------- ---------- ----------
Patronage capital and membership fees - beginningfees--beginning of year (Note 1)................................................. $ 356,229 $ 338,891 $ 309,496
$ 289,982 $ 264,261
Net margin.............................................margin................................................................... 22,405 21,752 22,258
23,082 25,721Special patronage capital distribution (Note 11)............................. (48,863) -- -00
Change in unrealized gain (loss) on available-for-sale securities, net of
income taxes (Note 2)................................................................... 738 (4,414) 7,137
(3,568) --
--------- --------- ------------------- ---------- ----------
Patronage capital and membership fees-end of year......year............................ $ 330,509 $ 356,229 $ 338,891
$ 309,496 $ 289,982
--------- --------- ---------
--------- --------- ------------------- ---------- ----------
---------- ---------- ----------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
36The accompanying notes are an integral part of these financial statements.
42
BALANCE SHEETS
DECEMBER 31, 19951997 AND 19941996
........................................................................................
(dollars in thousands)
ASSETS 1995 19941997 1996
------------ ------------
ELECTRIC PLANT (NOTES 1, 4 AND 6):
In service............................................service............................................................ $ 5,699,2134,910,067 $ 5,100,2995,742,597
Less: Accumulated provision for depreciation.......... (1,362,431) (1,231,818)
----------- -----------
4,336,782 3,868,481depreciation.......................... (1,412,287) (1,488,272)
------------ ------------
3,497,780 4,254,325
Nuclear fuel, at amortized cost....................... 94,013 105,683cost....................................... 90,424 86,722
Plant acquisition adjustments, at amortized cost...... 5,214 6,275cost...................... -- 4,153
Construction work in progress......................... 35,753 538,789
----------- -----------
4,471,762 4,519,228
----------- -----------progress......................................... 13,578 31,181
------------ ------------
3,601,782 4,376,381
------------ ------------
INVESTMENTS AND FUNDS (NOTES 1 AND 2):
Decommissioning fund, at market....................................... 105,817 86,269
Deposit on Rocky Mountain transactions, at cost....................... 52,176 41,685
Bond, reserve and construction funds, at market....... 56,511 64,163
Decommissioning fund, at market....................... 74,492 59,16433,161 53,955
Investment in associated organizations, at cost....... 15,853 17,371
----------- -----------
146,856 140,698
----------- -----------cost....................... 15,940 15,379
Other, at cost........................................................ 4,640 --
------------ ------------
211,734 197,288
------------ ------------
CURRENT ASSETS:
Cash and temporary cash investments, at cost (Note 1). 201,151 190,642................. 63,215 132,783
Other short-term investments, at market............... 79,165 --
Receivables........................................... 99,559 88,873market............................... 97,021 91,499
Receivables........................................................... 105,993 113,289
Inventories, at average cost (Note 1)................. 82,949 95,076................................. 65,528 89,825
Prepayments and other current assets.................. 14,325 14,857
----------- -----------
477,149 389,448
----------- -----------assets.................................. 12,530 14,625
------------ ------------
344,287 442,021
------------ ------------
DEFERRED CHARGES:
Premium and loss on reacquired debt, being amortized (Note 5)............................................. 200,794 161,889......... 196,583 201,007
Deferred amortization of Scherer leasehold (Note 4)... 87,134 80,132
Discontinued projects, being amortized (Note 1)....... 24,305 26,342................... 96,303 90,717
Deferred debt expense, being amortized................ 21,135 20,936
Other................................................. 9,361 7,657
----------- -----------
342,729 296,956
----------- -----------amortized................................ 15,345 21,703
Other (Note 1)........................................................ 43,823 33,058
------------ ------------
352,054 346,485
------------ ------------
$ 5,438,4964,509,857 $ 5,346,330
----------- -----------
----------- -----------5,362,175
------------ ------------
------------ ------------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE BALANCE SHEETS.
37The accompanying notes are an integral part of these financial statements.
43
........................................................................................
(dollars in thousands)
EQUITY AND LIABILITIES 1995 19941997 1996
------------ ------------
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Patronage capital and membership fees (Note 1)............................................. $ 338,891330,509 $ 309,496356,229
Long-term debt....................................... 4,207,320 4,128,080debt...................................................................... 3,258,046 4,052,470
Obligation under capital leases (Note 4)............. 296,478 303,749
----------- -----------
4,842,689 4,741,325
----------- -----------............................................ 288,638 293,682
Obligation under Rocky Mountain transactions (Note 1)............................... 52,176 41,685
------------ ------------
3,929,369 4,744,066
------------ ------------
CURRENT LIABILITIES:
Long-term debt and capital leases due within one year................................................ 89,675 90,086
Deferred margins and Vogtle surcharge to be
refunded within one year (Note 1)................... 32,047 19,279year............................... 89,556 159,622
Accounts payable..................................... 48,855 52,921payable.................................................................... 51,103 42,891
Accrued interest..................................... 91,096 100,010interest.................................................................... 12,961 15,931
Accrued and withheld taxes........................... 1,785 1,566taxes.......................................................... 517 4,940
Other current liabilities............................ 18,007 18,177
----------- -----------
281,465 282,039
----------- -----------liabilities........................................................... 8,428 14,022
------------ ------------
162,565 237,406
------------ ------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Gain on sale of plant, being amortized (Note 4)...... 60,868 63,209
Sale..................................... 60,756 58,527
Net benefit of sale of income tax benefits, being amortized (Note 1)............................................ 50,194 58,236................ 34,039 42,049
Net benefit of Rocky Mountain transactions, being amortized (Note 1)................ 92,375 70,701
Accumulated deferred income taxes (Note 3)........... 65,510 65,510
Deferred margins and Vogtle surcharge (Note 1)....... -- 17,765.......................................... 63,117 61,985
Decommissioning reserve (Note 1)..................... 114,049 96,291
Other................................................ 23,721 21,955
----------- -----------
314,342 322,966
----------- -----------.................................................... 142,354 124,468
Other............................................................................... 25,282 22,973
------------ ------------
417,923 380,703
------------ ------------
COMMITMENTS AND CONTINGENCIES (NOTES 4 9 AND 10)
$5,438,496 $5,346,330
----------- -----------
----------- -----------9)
$ 4,509,857 $ 5,362,175
------------ ------------
------------ ------------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE BALANCE SHEETS.
3844
STATEMENTS OF CAPITALIZATION
DECEMBER 31, 19951997 AND 19941996
........................................................................................
(dollars in
thousands)
1995 1994
1997 1996
--------- ---------
LONG-TERM DEBT (NOTE 5):
Mortgage notes payable to the Federal Financing Bank (FFB) at
interest rates varying from 5.67%5.27% to 10.78%8.43% (average rate of 7.19%6.89%
at December 31, 1995)1997) due in quarterly installments through
2023 ..... $ 3,253,636 $ 3,161,5502023............................................................. $2,456,300 $3,172,851
Mortgage notes payable to the Rural Utilities Service (RUS) at an
interest rate of 5% due in monthly installments through 2021........... 22,983 23,4672021..... 14,499 22,475
Mortgage notes issued in conjunction with the sale by public
authorities of pollution control revenue bonds (PCBs):
- Series 1982
Serial bonds, 10.60%, due serially through 1997................ -- 6,675
- Series 1992
Term bonds, 7.50% to 8.00%, due 2003 to 2022................... -- 92,130
-Series 1992A
Adjustable tender bonds, 3.40% to 3.70%, due 2025.............. -- 216,925
Serial bonds, 5.35% to 6.80%, due serially from 1998 through
2012......................................................... 124,690* 124,690
- Series 1993
Serial bonds, 3.75% to 5.25%, due serially from 1998 through
2013......................................................... 36,380* 37,255
- Series 1993A
Adjustable tender bonds, 3.65%, due 2016....................... 199,690* 199,690
- Series 1993B
Serial bonds, 3.75% to 5.05%, due serially from 1998 through
2008......................................................... 126,935* 126,935
- Series 1994
Serial bonds, 5.45% to 7.125%, due serially from 1998 through
2015......................................................... 10,035* 10,365
Term bonds, 7.15% due 2016 to 2021............................. 11,550* 11,550
- Series 1994A
Adjustable tender bonds, 3.65%, due 2000 to 2019............... 122,740* 122,740
- Series 1994B
Serial bonds, 5.45% to 6.45%, due serially from 1998 through
2005......................................................... 11,140* 11,140
- Series 1997A
Adjustable rate bonds, 3.90% to May 1998, due 2018............. 5,330* --
- Series 1997B
Term bonds, 3.80% due May 1998................................. 216,925* --
- Series 1997C
Adjustable rate bonds, 3.90% to May 1998, due 2018............. 9,305* --
Unsecured notes issued in conjunction with the sale by public
authorities of pollution control revenue bonds:
- Series 1982
Serial bonds, 10.20% to 10.60%, due serially
through 1997......................................... 6,675 16,135
- Series 1992
Term bonds, 7.50% to 8.00%, due 2003 to 2022.......... 92,130 92,130
-Series 1992A
Adjustable tender bonds, 3.25% to 3.95%, due 2025..... 216,925 216,925
Serial bonds, 5.10% to 6.80%, due serially from 1997
through 2012......................................... 129,760 139,240
- Series 1993
Serial bonds, 3.30% to 5.25%, due serially from 1996
through 2013......................................... 38,110 39,090
- Series 1993A
Adjustable tender bonds, 5.15%, due 2016.............. 199,690 199,690
- Series 1993B
Serial bonds, 3.55% to 5.05%, due serially from 1997
through 2008......................................... 136,745 155,610
- Series 1994
Serial bonds, 4.90% to 7.125%, due serially from 1996
through 2015......................................... 10,690 10,690
Term bonds, 7.15% due 2021............................ 11,550 11,550
- Series 1994A
Adjustable tender bonds, 5.05%, due 2019.............. 122,740 122,740
- Series 1994B
Serial bonds, 5.20% to 6.45%, due serially from 1997
through 2005......................................... 12,475 13,720
- Series 1995
Adjustable rate bonds, 3.70%3.90% to June 1996,May 1998, due in 2015................................................. 21,670 --2017.......... 37,885 37,885
CoBank, ACB notes payable:
- Headquarters note payable: $5.2 million fixed at 6.85%6.46% through July 1996,August 1998,
due in quarterly installments through January 1, 2009 .............................. 5,159 5,5492009.......... 4,380 4,672
- Transmission note payable: fixed at 6.85%6.78% through July 1996;February
1998; due in bimonthly installments through November 1, 2018...................................... 2,261 2,2792018... 1,844 2,237
- Transmission note payable: fixed at 6.45%6.61% through November 1996;February
1998; due in bimonthly installments through September 1,
2019..................................... 8,637 8,697
----------- -----------
4,291,836 4,219,0622019........................................................... 7,060 8,556
Commercial Paper, 5.84% to 6.15%, due at various maturities through
February 1998.................................................... 91,992 --
--------- ---------
3,488,680 4,208,771
*Less: Portion (16.86%) of PCBs assumed by Georgia Transmission
Corporation...................................................... (147,513) --
--------- ---------
3,341,167 4,208,771
--------- ---------
Less:Unamortized debt discount......................... (832) (896)
----------- -----------discount.................................... -- (766)
--------- ---------
Total long-term debt, net.............................. 4,291,004 4,218,166net.......................................... 3,341,167 4,208,005
Less:Long termLong-term debt due within one year................ (83,684) (90,086)
----------- -----------year............................ (83,121) (155,535)
--------- ---------
TOTAL LONG-TERM DEBT, EXCLUDING AMOUNT DUE WITHIN ONE YEAR............................................... 4,207,320 4,128,080YEAR........... 3,258,046 4,052,470
OBLIGATION UNDER CAPITAL LEASES, LONG TERMLONG-TERM (NOTE 4).................. 288,638 293,682
OBLIGATION UNDER ROCKY MOUNTAIN TRANSACTIONS, LONG-TERM (NOTE 1)..... 296,478 303,74952,176 41,685
PATRONAGE CAPITAL AND MEMBERSHIP FEES (NOTE 1).......... 338,891 309,496
----------- -----------....................... 330,509 356,229
--------- ---------
TOTAL CAPITALIZATION.................................... $ 4,842,689 $ 4,741,325
----------- -----------
----------- -----------CAPITALIZATION................................................. $3,929,369 $4,744,066
--------- ---------
--------- ---------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
39The accompanying notes are an integral part of these financial statements.
45
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1995, 19941997, 1996 AND 19931995
....................................................................................................................
(dollars in thousands)(DOLLARS IN THOUSANDS)
1997 1996 1995
1994 1993--------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net margin.......................................................margin........................................................................ $ 22,405 $ 21,752 $ 22,258
$ 23,082 $ 25,721
---------- ---------- ------------------- --------- ---------
Adjustments to reconcile net margin to net cash provided by operating activities:
Cumulative effect of change in accounting for income taxes.... -- -- (13,340)
Depreciation and amortization.................................amortization................................................. 171,573 196,593 196,920
193,351 180,221Net benefit of Rocky Mountain transactions.................................... 21,673 70,701 --
Interest on decommissioning reserve...........................reserve........................................... 12,113 7,167 9,951 1,291 7,356
Amortization of deferred gains ...............................gains................................................ (2,441) (2,341) (9,985) (12,532)(2,341)
Deferred margins and amortization of deferred margins.........margins......................... -- (32,047) (1,677) (8,785) 945
Amortization of proceeds fromnet benefit of sale of income tax benefits.....benefits.................... (11,195) (8,145) (8,043) (8,102) (8,102)
Allowance for equity funds used during construction...........construction........................... (157) (238) (1,715) (2,907) (2,278)
Deferred income taxes.........................................taxes......................................................... 1,132 (3,525) --
Option payment on power swap agreement........................................ (2,042) (3,750) --
1,625
Other ........................................................ (13)Other......................................................................... (3) (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...................................................Receivables................................................................... 7,297 (13,731) (10,686)
(18,055) (24,990)
Inventories...................................................Inventories................................................................... 15,316 (6,875) 12,127 (8,608) 7,172
Prepayments and other current assets..........................assets.......................................... 2,025 (299) 532
(94) 2,369
Accounts payable..............................................payable.............................................................. 8,797 (5,964) (4,066)
(10,569) (2,349)
Accrued interest..............................................interest.............................................................. (2,850) (75,165) (8,914) (8,692) 49,379
Accrued and withheld taxes....................................taxes.................................................... (4,423) 3,155 219 (7,835) 5,741
Other current liabilities.....................................liabilities..................................................... 2,903 (3,985) (169)
(24,124) 15,542
---------- ---------- ------------------- --------- ---------
Total adjustments................................................adjustments................................................................. 219,718 121,538 182,125
86,873 206,746
---------- ---------- ------------------- --------- ---------
NET CASH PROVIDED BY OPERATING ACTIVITIES..........................ACTIVITIES........................................... 242,123 143,290 204,383
109,955 232,467
---------- ---------- ------------------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions...............................................additions.............................................................. (63,527) (93,704) (138,921) (206,345) (235,285)
Activity in decommissioning fund - Purchases.....................fund--Purchases..................................... (435,799) (327,233) (410,597)
(297,492) --
- Proceeds......................--Proceeds...................................... 419,930 316,542 399,077 293,990 --
Activity in bond, reserve and construction funds - Purchases.....funds--Purchases..................... (35,646) (107,890) (27,762)
(498,052) --
- Proceeds......--Proceeds...................... 57,035 109,230 39,566 540,712 --
Activity in other short-term investments - Purchases.............investments--Purchases............................. (5,380) (15,532) (76,180)
-- --
Increase in decommissioning fund................................. -- -- (8,990)
Net proceeds from bond, reserve and construction funds........... -- -- 53,574
Decrease(decrease) in investment in associated organizations...............organizations................... (561) 474 1,518
1,752 786
Decrease (increase)Net cash received in other short-term investments..............Corporate Restructuring (Note 11).......................... 24,540 -- --
66,165
Other............................................................ -- -- 158
---------- ---------- ------------------- --------- ---------
NET CASH USED IN INVESTING ACTIVITIES..............................ACTIVITIES............................................... (39,408) (118,113) (213,299)
(165,435) (123,592)
---------- ---------- ------------------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Debt proceeds, net...............................................net.............................................................. 5,671 2,243 132,874
523,518 232,675
Debt payments....................................................payments................................................................... (229,242) (95,367) (108,481) (517,530) (369,962)
Return of Vogtle surcharge.......................................surcharge...................................................... -- -- (3,320)
(2,031) (1,600)
Other............................................................Special patronage capital distribution.......................................... (48,863) -- --
Other......................................................................... 151 (421) (1,648)
(2,008) (1,439)
---------- ---------- ------------------- --------- ---------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES................ACTIVITIES................................. (272,283) (93,545) 19,425
1,949 (140,326)
---------- ---------- ------------------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS.....INVESTMENTS...................... (69,568) (68,368) 10,509 (53,531) (31,451)
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR...........YEAR............................ 132,783 201,151 190,642
244,173 275,624
---------- ---------- ------------------- --------- ---------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR.................YEAR.................................. $ 63,215 $ 132,783 $ 201,151
$ 190,642 $ 244,173
---------- ---------- ----------
---------- ---------- ------------------- --------- ---------
--------- --------- ---------
CASH PAID FOR:
Interest (net of amounts capitalized)....................................................................... $ 277,294 $ 383,440 $ 308,797
$ 304,882 $ 289,255
Income taxes..................................................... --taxes.................................................................... 830 -- 1,658--
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
40The accompanying notes are an integral part of these financial statements.
46
NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1995, 19941997, 1996 AND 1993
..............................................................................1995
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. BUSINESS DESCRIPTION
Oglethorpe Power Corporation (Oglethorpe) is an electric generation and
transmission (G&T) cooperativemembership
corporation incorporated in 1974 and headquartered in suburban Atlanta.
Oglethorpe provides wholesale electric service, on a not-for-
profitnot-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 2.6approximately 2.8 million people across two-thirds of the State. Oglethorpe
is the nation's largest G&Telectric cooperative in terms of operating revenues,
assets, kilowatt-hour sales and, through its Members, consumers served.
Oglethorpe supplies energy to the Members fromowns or leases undivided interests in thirteen generating units
totaling 3,335 megawatts (MW) of owned
or leased generating capacity and purchases the remainder from other power
suppliers.capacity. Oglethorpe also purchases a total of
1,250 MW of power pursuant to power purchase agreements. In addition Oglethorpe
has accesscontracted to over 16,000 milespurchase 435 MW of transmission line
through its ownershippeaking capacity during the summer of 1998.
Oglethorpe and the Members completed on March 11, 1997, a corporate
restructuring (the Corporate Restructuring) in which Oglethorpe, effective April
1, 1997, was divided into three specialized operating companies to respond to
increasing competition and regulatory changes in the statewide Integratedelectric industry.
Oglethorpe's transmission business was sold to, and is now owned and operated by
Georgia Transmission System.Corporation (GTC), a Georgia electric membership
corporation formed for that purpose. Oglethorpe's system operations business was
sold to and is now owned and operated by, Georgia System Operations Corporation
(GSOC), a Georgia nonprofit corporation formed for that purpose. Oglethorpe
continues to own and operate its power supply business. For more information
regarding the Corporate Restructuring, see Note 11.
B. BASIS OF ACCOUNTING
Oglethorpe follows generally accepted accounting principles and the
practices prescribed in the Uniform System of Accounts of the Federal Energy
Regulatory Commission (FERC) as modified and adopted by the Rural Utilities
Service (RUS),
formerly known as the Rural Electrification Administration (REA).
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities as of December 31, 19951997 and 19941996
and the reported amounts of revenues and expenses for each of the three years
ending December 31, 1995.1997. Actual results could differ from those estimates.
C. PATRONAGE CAPITAL AND MEMBERSHIP FEES
Oglethorpe is organized and operates as a cooperative. The Members paid a
total of $195 in membership fees. Patronage capital is the retained net margin
of Oglethorpe. As provided in the bylaws, any excess of revenue over
expenditures from operations is treated as advances of capital by the Members
and is allocated to each of them on the basis of their electricity purchases
from Oglethorpe.
The margin andAny distributions of patronage capital retirements policy adopted byare subject to the Oglethorpediscretion of
the Board of Directors, in 1992 extended from 13 yearssubject 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.Indenture requirements. Under the new 30-year retirement schedule, noMortgage
Indenture, Oglethorpe is prohibited from making any distribution of patronage
capital would be returned to the Members until 2010,if, at the time thereof or giving effect thereto, (i)
an event of default exists under the Mortgage Indenture, (ii) Oglethorpe's
equity as of the end of the immediately preceding fiscal quarter is less than
20% of Oglethorpe's total capitalization, or (iii) the aggregate amount
expended for distributions on or after the date on which timeOglethorpe's equity
first reaches 20% of Oglethorpe's total capitalization exceeds 35% of
Oglethorpe's aggregate net margins earned after such date. This last
restriction, however will not apply if, after giving effect to such
distribution, Oglethorpe's equity as of the 1979 patronage capital would be returned.end of the immediately preceding
fiscal quarter is not less than 30% of Oglethorpe's total capitalization.
D. MARGIN POLICY
Under Oglethorpe's prior RUS mortgage, Oglethorpe's margin policy iswas 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, 19941996 and 19931995 was the amount required to produce a TIER of 1.07.
The RUS Mortgage was replaced with the Mortgage Indenture in connection with
Oglethorpe's corporate restructuring. For 1997 under the Mortgage Indenture,
Oglethorpe is required to produce a Margins for Interest (MFI) Ratio of at least
1.10.
The Oglethorpe Board of Directors adopted resolutions annually requiring
that Oglethorpe's net margins for the years 1985 through 1995 in excess of its
47
annual margin goals be deferred and used to mitigate rate increases associated
with Plant Vogtle and Rocky Mountain. In addition, during 1986 and 1987,
Oglethorpe's wholesale electric rate to its Members provided for a one mill per
kilowatt-hour charge (Vogtle Surcharge), also to be used to mitigate the effect
of Plant Vogtle on rates.
Pursuant to rate actions by Oglethorpe's Board of Directors, specified
amounts of deferred margins and Vogtle Surcharge were returned in 1989 through
1995 and all remaining amounts will bewere returned in 1996. A summary of
deferred margins and Vogtle Surcharge as of December 31, 1995 and 1994 is 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
Operating revenues consist primarily of electricity sales pursuant to
long-term wholesale power contracts which Oglethorpe maintains with each of its
Members. These wholesale power contracts obligate each Member to pay Oglethorpe
for capacity and energy furnished in accordance with rates established by
Oglethorpe. Energy furnished is determined based on meter readings which are
conducted at the end of each month. Actual energy costs are compared, on a
monthly basis, to the billed energy costs, and an adjustment to revenues is made
such that energy revenues are equal to actual energy costs.
Revenues from Cobb EMC and Jackson EMC, two of Oglethorpe's Members,
accounted for 12.9% and 11.8% in 1997, 12.5% and 11.2% in 1996, and 11.3% and
10.4% in 1995, and 11.0% and 10.5% in 1994respectively, of Oglethorpe's total operating 41
revenues. In 1993, Cobb EMC accounted for 10.3% of Oglethorpe's total operating
revenues.
Sales to non-Members consist partly of revenues from energy sales to non-
Member utilities other than Georgia Power Company (GPC) and partly of capacity
and energy sales to GPC under terms of sell-back agreements entered into when
Oglethorpe purchased interests in certain of GPC's generation facilities.
Pursuant to these agreements, GPC purchased through 1995 from Oglethorpe a
declining fractional part of the capacity and energy during the first seven to
ten years of an applicable generating unit's commercial operation. The portion
of Oglethorpe's capacity and energy retained by GPC is shown as follows:
...................................................................................
Fractional Part of Capacity and Energy Retained
by GPC during Contract Year Ended May 31
Generating Unit 1996 1995 1994 1993
...................................................................................
Plant Scherer,
Unit No. 2 -- -- -- 6/60
Plant Vogtle,
Unit No. 1 -- -- 4/30 8/30
Plant Vogtle,
Unit No. 2 -- 4/30 8/30 11/30
...................................................................................
Pursuant to these sell-back agreements and to other contractual
arrangements with GPC, revenues from GPC accounted for approximately 6%, 8%,
and 15% of Oglethorpe's total operating revenues in 1995, 1994, and 1993,
respectively.
F. NUCLEAR FUEL COST
The cost of nuclear fuel, including a provision for the disposal of spent
fuel, is being amortized to fuel expense based on usage. The total nuclear fuel
expense for 1995, 19941997, 1996 and 19931995 amounted to $54,588,000, $55,229,000$47,123,000, $49,298,000 and
$49,647,000,$54,588,000, 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 arewere scheduled to
begin in 1998. However,1998; however, the actual yearDOE has stated that these servicespermanent nuclear waste storage
facilities are not available, and it is uncertain when they will begin is uncertain.be available.
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 from2008.
Activities for adding dry cask storage capacity at Plant Hatch by 2000 are in
2003 or from Plant Vogtle in 2009, alternative spent fuel storage
will be needed.progress.
The Energy Policy Act of 1992 requiresrequired that utilities with nuclear plants be
assessed over the next 15 years,a 15-year period an amount which will be used by DOE for the
decontamination and decommissioning of its nuclear fuel enrichment facilities.
The amount of each utility's assessment iswas based on its past purchases of
nuclear fuel enrichment services from DOE. Based on its ownership in Plants
Hatch and Vogtle, Oglethorpe has a remaining nuclear fuel asset of approximately
$16,200,000,$13,500,000, which is being amortized to nuclear fuel expense over the next 1210
years. Oglethorpe has also recorded net of
sell-back, an obligation to DOE which approximated
$13,000,000$10,600,000 at December 31, 1995.1997.
G. NUCLEAR DECOMMISSIONING
Oglethorpe's portion of the costs of decommissioning co-owned nuclear
facilities is estimated as follows:
...................................................................................HATCH HATCH VOGTLE VOGTLE
(DOLLARS IN THOUSANDS) Hatch Hatch Vogtle Vogtle
Unit No.UNIT NO. 1 Unit No.UNIT NO. 2 Unit No.UNIT NO. 1 Unit No.UNIT NO. 2
...................................................................................- ----------------------------------------------------------------- ----------- ---------- ----------- ----------
Year of site studystudy............................................... 1994 1994 1994 1994
Expected start date of decommissioningdecommissioning........................... 2014 2018 2027 2029
Decommissioning cost:
DiscountedDiscounted....................................................... $ 92,000 $109,000$ 109,000 $ 82,000 $106,000
Undiscounted 223,000 299,000 302,000 419,000
...................................................................................$ 106,000
Undiscounted..................................................... 157,000 207,000 198,000 271,000
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in regulatory requirements, changes in technology, and
changes in costs of labor, materials and equipment.
The annual provision for decommissioning for 1997, 1996 and 1995 1994was
$2,597,000, $2,597,000 and 1993 was
$4,156,000, $5,948,000 and $5,948,000, respectively. In developing the amount of
the annual provision for 19951997 and 1996,1998, the escalation rate was assumed to be
3.5%2.72% and return on trust assets was assumed to be 8%. Oglethorpe accounts for
this provision for decommissioning as depreciation expense with an offsetting
credit to a decommissioning reserve. Oglethorpe's management is of the opinion
that any changes in cost estimates of decommissioning willcan be
fully recovered in future
rates.
In compliance with a Nuclear Regulatory Commission (NRC) regulation,
Oglethorpe maintains an external trust fund to provide for a portion of the cost
of decommissioning its nuclear facilities. The NRC regulation requires funding
levels based on average expected cost to decommission only the radioactive
portions of a typical nuclear facility. Oglethorpe's decommissioning reserve
reflects its obligation to decommission both the radioactive and most of the
non-radioactive portions of its nuclear facilities.
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, realizedRealized investment earnings from the external trust fund, while increasing
the fund and interest income, also are applied to the decommissioning
48
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,
19941997,
1996 and 19931995 were as follows:
...................................................................................1997 1996 1995
1994 1993
...................................................................................----------- ----------- -----------
Steam productionproduction......................................................... 2.13% 2.47% 2.66%2.13% 2.13%
Nuclear productionproduction....................................................... 2.74% 2.73% 2.78%
2.84% 2.83%
Hydro productionproduction......................................................... 2.00% 2.00% 2.00%
Other productionproduction......................................................... 3.75% 2.42% 1.09%
Transmission3.75% 3.75%
Transmission............................................................. 2.75% 2.75% 2.75%
DistributionDistribution............................................................. 2.88% 2.88% 2.88%
GeneralGeneral.................................................................. 2.00-20.00% 2.00-20.00% 2.00-17.00%
...................................................................................2.00-20.00%
I. ELECTRIC PLANT
Electric plant is stated at original cost, which is the cost of the plant
when first dedicated to public service, plus the cost of any subsequent
additions. Cost includes an allowance for the cost of equity and debt funds used
during construction. The cost of equity and debt funds is calculated at the
embedded cost of all such funds. The plant acquisition adjustments represent the
excess of the cost of the plant to Oglethorpe over the original cost, less
accumulated depreciation at the time of acquisition, and are being amortized
over a ten-year period.
Maintenance and repairs of property and replacements and renewals of items
determined to be less than units of property are charged to expense.
Replacements and renewals of items considered to be units of property are
charged to the plant accounts. At the time properties are disposed of, the
original cost, plus cost of removal, less salvage of such property, is charged
to the accumulated provision for depreciation.
J. BOND, RESERVE AND CONSTRUCTION FUNDS:
Bond, reserve and construction funds for pollution control revenue bonds
(PCBs) are maintained as required by Oglethorpe's bond agreements. Bond funds
serve as payment clearing accounts, reserve funds maintain amounts equal to the
maximum annual debt service of each bond issue and construction funds hold bond
proceeds for which construction expenditures have not yet been made. As of
December 31, 19951997 and 1994,1996, substantially all of the funds were invested in U.S.
Government securities.
K. CASH AND TEMPORARY CASH INVESTMENTS
Oglethorpe considers all temporary cash investments purchased with a
maturity of three months or less to be cash equivalents. Temporary cash
investments with maturities of more than three months are classified as other
short-term investments.
At December 31, 1997, $12,167,000 was restricted by PCBs trust indentures
and was utilized in January 1998 for payment of principal on certain PCBs. Of
the amount reported as cash and temporary cash investments at December 31, 1996,
approximately $65,600,000 was restricted by RUS and was utilized by Oglethorpe
for the purpose of prepaying certain Federal Financing Bank (FFB) long-term debt
in March 1997.
L. INVENTORIES
Oglethorpe maintains inventories of fossil fuels for its generation plant
and spare parts for certain of its generation and transmission plant. These
inventories are stated at weighted average cost on the accompanying balance
sheets.
At December 31, 19951997 and 1994,1996, fossil fuels inventories were $12,296,000$7,288,000 and
$24,225,000,$23,062,000, respectively. Inventories for spare parts at December 31, 19951997 and
19941996 were $70,653,000$58,240,000 and $70,851,000,$66,763,000, respectively.
M. ENERGY COST RECOVERY
Oglethorpe's wholesale power rate sets forth the manner in which energyDEFERRED CHARGES
Prior to 1996, Oglethorpe expensed nuclear refueling outage costs as
incurred. In 1996, Oglethorpe began accounting for these costs on a
normalized basis. Under this method of accounting, refueling outage costs are
deferred and subsequently amortized to be recovered from its Members. The rate in effect for 1995, 1994
and 1993 provided that an energy rate be determined based on projectedexpense over the 18-month operating
cycle of each unit. Deferred nuclear outage 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 ofat December 31, 1994, an overcollection of $2,125,000 existed1997 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 Oglethorpewere $19,802,000 and will be collected from Members over the
next 12-month period.
N. DEFERRED CHARGES
Primarily as a result of its ownership of a majority interest in Rocky
Mountain, Oglethorpe determined that the Pickens County Pumped Storage
Hydroelectric Project was not needed within its present planning horizon.
Accordingly, Oglethorpe is amortizing the accumulated project costs in excess
of the value of the land purchased. The remaining unamortized project costs
of approximately $15,496,000 are reflected as deferred charges on the
accompanying balance sheets. Oglethorpe's Board of Directors has authorized
that these project costs be amortized and fully recovered through future
rates over a period of 15 years beginning in 1992.$12,961,000, respectively.
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$5,947,000 are reflected as deferred charges on the
accompanying balance sheets. In 1995, Oglethorpe's Board of Directors has authorized
that these project costs be amortized and fully recovered through future rates
over a period of 15 years beginning in 1995.
43that year.
49
O.N. DEFERRED CREDITS
In April 1982, Oglethorpe sold to three purchasers certain of the income tax
benefits associated with Scherer Unit No.1 and related common facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act of
1981. Oglethorpe received a total of approximately $110,000,000 from the safe
harbor lease transactions. Oglethorpe accounts for the proceedsnet benefits 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,December 1996 and January 1997, Oglethorpe sold to GPC a 24.45%entered into long-term lease
transactions for its 74.6% undivided ownership interest in the Plant Scherer common facilitiesRocky Mountain
Pumped Storage Hydroelectric Project (Rocky Mountain). The lease transactions
are characterized as required under the Plant Scherer Purchasea sale and Ownership Agreement to adjust its ownership in the Scherer units.lease-back for income tax purposes, but not for
financial reporting purposes. As a result of these leases, Oglethorpe realizedrecorded a
gain on the salenet benefit of $50,600,000. RUS and Oglethorpe's
Board of Directors approved a plan whereby this gain$95,560,000 which was deferred and wasis being amortized to income
over 60 months ending in September 1994.
P.the 30-year lease-back period. The lease transactions initially increased
Oglethorpe's Capitalization and Investments and funds by $57,495,000,
respectively (see Note 2 where discussed further).
O. REGULATORY ASSETS AND LIABILITIES
Oglethorpe is subject to the provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation."
Regulatory assets represent probable future revenues to Oglethorpe associated
with certain costs which will be recovered from Members through the rate-making
process. Regulatory liabilities represent probable future reduction in revenues
associated with amounts that are to be 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, 19951997 and 1994:1996:
...............................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...............................................................................1997 1996
- ------------------------------------------------------------------------------------------ ---------- ----------
Premium and loss on reacquired debt $200,794 $161,889debt....................................................... $ 196,583 $ 201,007
Deferred amortization of Scherer leasehold 87,134 80,132
Discontinued projects 24,305 26,342leasehold................................................ 96,303 90,717
Other regulatory assets 9,361 7,657
Saleassets................................................................... 38,318 29,934
Net benefit of 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
-------- --------
-------- --------
...............................................................................benefits................................................ (34,039) (42,049)
Net benefit of Rocky Mountain transactions................................................ (92,375) (70,701)
---------- ----------
$ 204,790 $ 208,908
---------- ----------
---------- ----------
In the event that Oglethorpe is no longer subject to the provisions of
Statement No. 71, Oglethorpe would be required to write off related regulatory
assets and liabilities. In addition, Oglethorpe would be required to determine
any impairment to other assets, including plant, and write down the assets, if
impaired, to their fair value.
Q.P. PRESENTATION
Certain prior year amounts have been reclassified to conform with current
year presentation.
50
2. FAIR VALUE OF FINANCIAL INSTRUMENTS:
A detail of the estimated fair values of Oglethorpe's financial instruments
as of December 31, 19951997 and 19941996 is as follows:
.....................................................................................1997 1996
-------------------------- --------------------------
FAIR FAIR
(DOLLARS IN THOUSANDS) 1995 1994
FAIR Fair
COST VALUE Cost Value
.....................................................................................COST VALUE
- --------------------------------------------------------- ------------ ------------ ------------ ------------
CASH AND TEMPORARY
CASH INVESTMENTS:
Commercial paperpaper....................................... $ 179,05562,772 $ 179,05562,772 $ 156,19252,700 $ 156,192
Repurchase agreement52,700
Certificates of deposit................................ -- -- 14,087 14,087
Certificates of deposit 20,000 20,000 20,000 20,00010,000 10,000
Cash and money market securities 2,096 2,096 363 363
---------- ---------- ---------- ----------
TOTALsecurities....................... 443 443 70,083 70,083
------------ ------------ ------------ ------------
TOTAL.................................................... $ 201,15163,215 $ 201,15163,215 $ 190,642132,783 $ 190,642
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------132,783
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
OTHER SHORT TERM INVESTMENTS:
Mutual fundsCommingled investment fund............................. $ 76,18097,092 $ 79,16597,021 $ --91,712 $ --
---------- ---------- ---------- ----------
TOTAL91,499
------------ ------------ ------------ ------------
TOTAL.................................................... $ 76,18097,092 $ 79,16597,021 $ --91,712 $ --
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------91,499
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
BOND, RESERVE AND CONSTRUCTION FUNDS:
U. S. Government securitiessecurities............................ $ 49,34820,542 $ 49,93220,505 $ 57,14136,505 $ 53,57335,873
Repurchase agreements 6,579 6,579 10,590 10,590
---------- ---------- ---------- ----------
TOTALagreements.................................. 12,655 12,656 18,082 18,082
------------ ------------ ------------ ------------
TOTAL.................................................... $ 55,92733,197 $ 56,51133,161 $ 67,73154,587 $ 64,163
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------53,955
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
DECOMMISSIONING FUND:
U. S. Government securitiessecurities............................ $ 23,08721,070 $ 23,56821,668 $ 36,66824,034 $ 35,51323,950
Foreign government securities.......................... 641 695 1,228 1,278
Commercial paper 4,036 4,036paper....................................... 5,507 5,506 -- --
Corporate bonds 5,875 6,073 4,548 4,388bonds........................................ 12,537 12,967 11,953 11,868
Equity securities 19,514 21,271 8,605 8,707securities...................................... 45,044 51,252 30,339 34,073
Asset-backed securities 12,484 12,614 3,754 3,672securities................................ 9,202 9,237 3,103 3,125
Other bonds............................................ -- -- 5,445 5,453
Cash and money market securities 6,937 6,930 6,884 6,884
---------- ---------- ---------- ----------
TOTALsecurities....................... 4,492 4,492 6,522 6,522
------------ ------------ ------------ ------------
TOTAL.................................................... $ 71,93398,493 $ 74,492105,817 $ 60,45982,624 $ 59,164
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------86,269
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
LONG-TERM DEBT $4,207,320 $4,506,925 $4,128,080 $4,107,751
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------DEBT........................................... $ 3,258,046 $ 3,497,842 $ 4,052,470 $ 4,162,670
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
INTEREST RATE SWAP$SWAP (UNREALIZED LOSS)..................... $ -- $ 52,089(38,349) $ -- $ 6,148
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
.....................................................................................(33,938)
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
The contractual maturities of debt securities available for sale at December
31, 19951997 and 1994,1996, regardless of their balance sheet classification, are as
follows:
.............................................................................................1997 1996
-------------------- --------------------
FAIR FAIR
(DOLLARS IN THOUSANDS) 1995 1994
FAIR Fair
COST VALUE Cost Value
.............................................................................................COST VALUE
- ---------------------------------------------------------------------- --------- --------- --------- ---------
Due within one yearyear................................................... $ 21,05014,147 $ 21,30014,158 $ 32,29233,944 $ 31,91633,819
Due after one year through five years 37,172 37,452 48,810 47,065years................................. 18,798 18,825 17,439 17,266
Due after five years through ten years 27,628 27,966 21,940 19,367years................................ 22,677 22,781 27,912 27,302
Due after ten years 11,523 12,049 9,659 9,388
-------- -------- -------- --------years................................................... 21,025 21,964 15,610 15,789
--------- --------- --------- ---------
$ 97,37376,647 $ 98,767 $112,701 $107,736
-------- -------- -------- --------
-------- -------- -------- --------
.............................................................................................77,728 $ 94,905 $ 94,176
--------- --------- --------- ---------
--------- --------- --------- ---------
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.
A portion (16.86%) of the interest rate swap arrangements was assumed by
GTC as part of the Corporate Restructuring. Under the interest rate swap
arrangements, Oglethorpe makes payments to the 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 (includes the portion assumed by GTC) and the fixed swap rate is
5.67% (the variable rate at December 31, 19951997 and 19941996 was 5.15%3.65% and 4.95%4. %
respectively). With respect to the Series 1994A notes, the notional principal
was $122,740,000 (includes the portion assumed by GTC) and the fixed swap rate
is 6.01% (the variable rate at December 31, 19951997 and 19941996 was 5.05%3.65% and 4.95%4.00%,
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.
TheOglethorpe's portion of the estimated fair value of
Oglethorpe's liability under the swap arrangements at
December 31, 19951997 and 19941996 was $52,089,000an unrealized loss of $38,349,000 and
$6,148,000, respectively. This amount represents$33,938,000, respectively, representing the 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 adopted51
Under Statement of Financial Accounting Standards No. 115, "Accounting for
Certain Investments in Debt and Equity Securities," as of
January 1, 1994. Under this Statement, investment securities held
by Oglethorpe are classified as either available-for-sale or held-to-maturity.
Available-for-sale securities are carried at market value with unrealized gains
and losses, net of any tax effect, added to or deducted from patronage capital.
Unrealized gains and losses from investment securities held in the
decommissioning fund, which are also classified as available-for-sale, are
directly added to or deducted from the decommissioning reserve. Held-to-maturity
securities are carried at cost. All realized and unrealized gains and losses are
determined using the specific identification method. Gross unrealized gains and
losses at December 31, 19951997 were $6,497,000$12,800,000 and $368,000,$5,583,000, respectively. Gross
unrealized gains and losses at December 31, 19941996 were $234,000$7,785,000 and $5,050,000,$4,985,000
respectively. For 19951997 and 1994,1996, proceeds from sales of available-for-sale
securities totaled $438,643,000$476,965,000 and $834,702,000,$425,772,000, respectively. Gross realized
gains and losses from the 19951997 sales were $5,098,000$11,415,000 and $1,308,000,$3,010,000,
respectively. Gross realized gains and losses from the 19941996 sales were
$1,099,000$6,410,000 and $4,776,000,$3,671,000, respectively.
Investments in associated organizations were as follows at December 31, 19951997
and 1994:1996:
...........................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...........................................................................1997 1996
- -------------------------------------------------------------------------------------------- --------- ---------
National Rural Utilities Cooperative Finance Corp. (CFC) $13,476 $13,476.................................... $ 13,476 $ 13,476
CoBank, ACB 2,132 3,690
Other 245 205
------- -------
Total $15,853 $17,371
------- -------
------- -------
...........................................................................ACB................................................................................. 1,955 1,664
Other....................................................................................... 509 239
--------- ---------
Total....................................................................................... $ 15,940 $ 15,379
--------- ---------
--------- ---------
The investments in these associated organizations are similar to
compensating bank balances in that they are required in order to maintain
current financing arrangements. Accordingly, there is no market for these
investments.
The deposit on the Rocky Mountain transactions (see Note 1 where discussed)
is invested in a guaranteed investment contract which will be held to maturity
(the end of the 30-year lease-back period). At maturity, Oglethorpe fully
intends to use the deposit to repurchase tax ownership and to retain all other
rights of ownership with respect to the plant. The deposit is carried at cost.
In addition, from the proceeds of the Rocky Mountain transactions,
Oglethorpe paid $640,611,000 to a financial institution. In return, this
financial institution undertook to pay a portion of Oglethorpe's lease
obligations. Both Oglethorpe's interest in this payment undertaking agreement
and the corresponding lease obligations have been extinguished for financial
reporting purposes.
3. INCOME TAXES
Oglethorpe is a not-for-profit membership corporation subject to Federal State of Georgia and
State of Alabamastate income taxes. For years 1981 and prior,
Oglethorpe claimed tax-exempt status under Section 501(c)(12) of the Internal
Revenue Code of 1954, as amended (the Code). In 1982, Oglethorpe reported as
a taxable entity as a result of income received by it from GPC under the
capacity and energy sell-back agreement applicable to Scherer Unit No. 1. In
connection with its 1985 tax return, Oglethorpe made an election under
Section 168(j)(4)(E)(ii) of the Code to remain taxable from 1985 until at
least 2005 without regard to the amount of its income from GPC or other
non-Members. As a taxable electric cooperative, Oglethorpe has annually
allocated its income and deductions between Member and non-Member activities.
Any Member taxable income has been offset with a patronage exclusion.
As of January 1, 1993,exclusion and member
loss carryforwards.
Oglethorpe prospectively adopted the provisions ofaccounts for its income taxes pursuant to Statement of Financial
Accounting Standards (SFAS) No. 109, "Accounting for
Income Taxes." In adopting SFAS No. 109, Oglethorpe recorded a $13,340,000
reduction in accumulated deferred income taxes and an increase in income from
the cumulative effect of a change in accounting principle.109. SFAS No. 109 requires the recognition of
deferred tax assets and liabilities for the expected future tax consequences of
events that have been included in the financial statements or tax returns.
Deferred tax assets and liabilities are
determined based on the differences between the financial and tax bases using
enacted tax rates in effect for the year in which the differences are
expected to reverse.
A detail of the provision for income taxes in 1995, 19941997, 1996 and 19931995 is shown
as follows:
...................................................................................
(DOLLARS IN THOUSANDS) 1997 1996 1995
1994 1993
...................................................................................- --------------------------------------------------------------------------------------- --------- --------- -------
Current
FederalFederal.............................................................................. $ (1,132) $ 3,525 $ --
State................................................................................ -- -- --
--------- --------- -------
(1,132) 3,525 --
--------- --------- -------
Deferred
Federal.............................................................................. 1,132 (3,525) --
State................................................................................ -- -- --
--------- --------- --------
1,132 (3,525) --
--------- --------- --------
Income taxes charged to operations..................................................... $ -- $ -- $ --
State -- -- 195
----- ----- -------
-- -- 195
----- ----- -------
Deferred
Federal -- -- 1,820
State -- -- (195)
----- ----- -------
-- -- 1,625
----- ----- -------
Income taxes charged
to operations $ -- $ -- $ 1,820
----- ----- -------
----- ----- -------
...................................................................................--------- --------- --------
--------- --------- --------
45
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:
...................................................................................1997 1996 1995
1994 1993
...................................................................................--------- --------- ---------
Statutory federal income tax raterate............... 35.0% 35.0% 35.0%
Patronage exclusionexclusion............................. (35.4)% (35.7%) (35.6%)
(35.4%) (35.1%)
OtherOther........................................... 0.4% 0.7% 0.6%
0.4% 0.1%
Effect of increase in statutory rate 0.0% 0.0% 12.8%
------ ------ --------------- --------- ---------
Effective income tax raterate....................... 0.0% 0.0% 12.8%
------ ------ ------
------ ------ ------
...................................................................................0.0%
--------- --------- ---------
--------- --------- ---------
52
The components of the net deferred tax liabilities as of December 31, 19951997
and 19941996 were as follows:
...........................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...........................................................................1997 1996
- ------------------------------------------- ----------- -----------
DEFERRED TAX ASSETS
Net operating losseslosses....................... $ 538,067444,590 $ 451,543473,114
Member loss carryforwards 342,370 366,417carryforwards.................. 189,414 328,912
Tax credits 252,680 252,701(alternative minimum tax and
other)................................... 243,707 256,205
Accounting for safe harbor leases 86,599 98,746
Patronage exclusions available 0 80,190Rocky Mountain
transactions............................. 213,575 233,045
Accounting for sale of income tax
benefits................................. 75,041 77,429
Accrued nuclear decommissioning expense 45,042 38,644expense.... 51,713 49,127
Accounting for asset dispositions 33,496 34,448
Other 18,277 18,061dispositions.......... 31,584 32,545
Other...................................... 2,742 3,318
----------- -----------
1,316,531 1,340,7501,252,366 1,453,695
Less: Valuation allowanceallowance.................. (241,483) (252,680) (252,701)
----------- -----------
1,063,851 1,088,0491,010,883 1,201,015
----------- -----------
DEFERRED TAX LIABILITIES
Depreciation (1,034,153) (1,062,233)Depreciation............................... (848,585) (1,008,714)
Accounting for Rocky Mountain
transactions............................. (145,805) (156,557)
Accounting for debt extinguishment (64,006) (61,003)
Other (31,202) (30,323)extinguishment......... (61,094) (64,841)
Other...................................... (18,516) (32,888)
----------- -----------
(1,129,361) (1,153,559)(1,074,000) (1,263,000)
----------- -----------
Net deferred tax liabilitiesliabilities............... $ (65,510) $ (65,510)(63,117) (61,985)
----------- -----------
----------- -----------
...........................................................................
As of December 31, 1995,1997, Oglethorpe has federal tax net operating loss
carryforwards (NOLs), alternative minimum tax credits (AMT) and unused general
business credits (consisting primarily of investment tax credits) as follows:
...........................................................................
(DOLLARS IN THOUSANDS)
...........................................................................
Expiration Date Tax Credits NOLs- -----------------------------------------------------------------------------------------
ALTERNATIVE
MINIMUM
EXPIRATION DATE TAX CREDITS TAX CREDITS NOLS
- ------------------------------------------------- ----------- ----------- ------------
1997 $ 11,197 $
1998............................................. --
1998 6,934 --
19991999............................................. -- 37,206 --
20002000............................................. -- 3,198 --
20012001............................................. -- 7,264 --
20022002............................................. -- 130,377 146,363
2003--
2003............................................. -- 652 253,665
2004250,461
2004............................................. -- 55,663 114,285
20052005............................................. -- 189 213,080
20062006............................................. -- -- 209,009
20072007............................................. -- -- 86,779
20082008............................................. -- -- 94,927
20092009............................................. -- -- 96,394
20102010............................................. -- 77,967
---------- ------------ 77,970
None............................................. 2,224 -- --
----------- ----------- ------------
$ 252,680 $1,292,469
---------- ----------
---------- ----------
...........................................................................2,224 $ 241,483 $1,142,905
----------- ----------- ------------
----------- ----------- ------------
Based on Oglethorpe's historical taxable transactions, the timing of the
reversal of existing temporary differences, future income, and tax planning
strategies, it is more likely than not that Oglethorpe's future taxable income
will be sufficient to realize the benefit of these NOLs before their respective
expiration dates. The NOLs expiration dates start in the year 2 3 and end in the
year 2010. However, as reflected in the above valuation allowance, it is more
likely than not that the tax credits will not be utilized before expiration. It
is more likely than not that the AMT credit will be utilized.
4. CAPITAL LEASES:
In December 1985, Oglethorpe sold and subsequently leased back from four
purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The gain
from the sale is being amortized over the 36-year term of the leases. The
minimum lease payments under the capital leases together with the present
value of net minimum lease payments as of December 31, 19951997 are as follows:
...........................................................................
YEAR ENDING DECEMBER 31, (DOLLARS IN THOUSANDS)
...........................................................................- --------------------------------------------- ----------------------
19961998................................... $ 39,293
1997 35,239
1998 37,302
19991999................................... 37,890
20002000................................... 37,755
2001-2021 606,8092001................................... 37,629
2002................................... 37,491
2003-2021.............................. 531,688
---------
Total minimum lease payments 794,288payments........... 719,755
Less: Amount representing interest (491,819)interest..... (424,682)
---------
Present value of net minimum
lease payments 302,469payments....................... 295,073
Less: Current portion (5,991)portion.................. (6,435)
---------
Long term balanceLong-term balance...................... $ 296,478288,638
---------
---------
...........................................................................
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. In
December 1997, Oglethorpe refinanced the debt supporting the Scherer Unit No. 2
lease. The refunded debt consisted of $143,200,000 in serial facility bonds with
a 9.70% fixed interest rate (pertaining to three of the lessors is financed at fixed interest rates
averaging 9.64%. As of December 31, 1995, thelessors) and $81,500,000
in bank debt with variable interest rates ranging from 6.4% to 6.9% (pertaining
to the remaining lessor). The debt was refinanced through a $224,700,000 issue
of serial facility bonds due June 30, 2011 with a 6.97% fixed interest rate. The
transaction costs related to this transaction are reported as deferred charges
on the balance sheet and are being amortized over the remaining life of the
debt of the remaining lessor ranged from 5.93% to 8.05% for an average rate
of 6.99%.leases. Oglethorpe's future rental payments
53
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 varyvaries
from the 11.05% debt rate assumed in the table.
The Scherer Unit No. 2 lease meets the definitional criteria to be reported
on Oglethorpe's balance sheets as a capital lease. For rate-making purposes,
however, Oglethorpe treats this lease as an operating lease; that is, Oglethorpe
considers the actual rental payment on the leased asset in its cost of service.
Oglethorpe's accounting treatment for this capital lease has been modified,
therefore, to reflect its rate-making treatment. Interest expense is applied to
the obligation under the capital lease; then, amortization of the leasehold is
recognized, such that interest and amortization equal the actual rental payment.
Through 1994, the level of actual rental payments was such that amortization of
the Scherer Unit No. 2 leasehold calculated in this manner was less than zero.
Thereafter, the scheduled cash rental payments increase
46
such that positive
amortization of the leasehold occurs and the entire cost of the leased asset is
recovered through the rate-making process. The difference in the amortization
recognized in this manner on the statements of revenues and expenses and the
straight-line amortization of the leasehold is reflected on Oglethorpe's balance
sheets as a deferred charge.
In 1991 and 1992, all four of the lessors received Notices of Proposed
Adjustments from the IRS proposing adjustments to the tax benefits claimed by
these lessors in connection with their purchase and ownership of an undivided
interest in Scherer Unit No 2. In 1994, the IRS issued a revised Notice of
Proposed Adjustments to one of the lessors which reduced the proposed
adjustments. During 1995, this lessor advised Oglethorpe that it had settled
this issue on the basis of the revised Notice of Proposed Adjustments.
Oglethorpe subsequently made a lump sum indemnity payment of $362,000 to the
lessor in order to compensate for the reduction in the lessor's tax benefits
resulting from the sale and leaseback transaction. The IRS has indicated that
it will take consistent positions with the other three lessors. If the IRS's
current positions regarding the sale and leaseback transactions were
ultimately upheld, Oglethorpe would be required to indemnify the other three
lessors. Oglethorpe's indemnification liability to the three lessors is
estimated to be approximately $1,150,000$1,391,000 as of December 31, 1995.1997. This
liability has been reflected on the accompanying balance sheet as of this
date.sheet.
5. LONG-TERM DEBT:
Long-term debt consists of mortgage notes payable to the United States of
America acting through the FFB and the RUS, mortgage notes issued in conjunction
with the sale by public authorities of pollution control revenue
bondsPCBs, and mortgage notes payable to
CoBank. Oglethorpe's headquarters facility is pledged as collateral for the
CoBank headquarters note; substantially all of the owned tangible and certain of
the intangible assets of Oglethorpe are pledged as collateral for the FFB and
RUS notes, the remaining CoBank notes and the notes issued in conjunction with
the sale of pollution control
revenue bonds.PCBs. The detail of the notes is included in the statements of
capitalization.
As part of the Corporate Restructuring effective April 1, 1997, 16.86% of
the then outstanding PCBs was assumed by GTC. Because Oglethorpe currentlywas not legally
released from its obligation to pay this debt, the entire debt is shown in the
Statement of Capitalization as a liability of Oglethorpe with an offsetting
amount reflecting the portion assumed by GTC.
In connection with the Corporate Restructuring in March 1997, Oglethorpe
defeased approximately $92,000,000 in principal amount of Series 1992 PCBs.
Initially these bonds have been defeased with the proceeds from the issuance of
approximately $92,000,000 in commercial paper. Oglethorpe has ten RUS-guaranteed FFB notesa plan in place to
refinance the commercial paper issuance with a medium-term loan in 1998 and
ultimately expects to refinance the loan with an issuance of PCBs at some point
in the future.
In connection with the Corporate Restructuring in March 1997, Oglethorpe
refinanced $216,925,000 (includes portion assumed by GTC) in principal amount of
Series 1992A PCBs through the issuance of Series 1997A PCBs which $3,253,636,000matured on
December 1, 1997, which in turn were refunded through the issuance of Series
1997B PCBs which will mature on May 28, 1998 (the Series 1997B Bonds).
Oglethorpe has a plan in place and $3,161,550,000 were outstanding at December 31, 1995is in the final stages of a debt offering to
refund the Series 1997B Bonds in March 1998 through the issuance of Series 1998A
and 1994, respectively, with rates ranging from 5.67% to 10.78%.
InSeries 1998B PCBs (the Series 1998 Bonds) having a January 1995, Oglethorpe prepaid two FFB advances totaling $29,940,000
of principal plus a premium equal to one year's interest of $3,163,000.1, 2019 maturity.
The premiumSeries 1998 Bonds will initially be issued as variable rate bonds and will
be supported by both a municipal bond insurance policy and bank liquidity
agreements. The unamortized transaction costs related to the 1997A PCBs are
reported as a deferred chargecharges on the balance sheet and will
beare being amortized over
22 years, the remainingtwenty-year life of the prepaid advances.
In January 1995, Oglethorpe refinanced in a non-cash transaction
$284,759,000 of FFB advances.In connection with this refinancing, a premium
of $44,870,000 was incurred. This premium was financed by adding the amount
to the outstanding balances of the refinanced advances for a total refunding
debt of $329,629,000. Additionally, a fee of $1,122,000 was paid in cash for
the ability to finance the premium. The combined premium and fee of
$45,992,000 is reported as a deferred charge on the balance sheets and will
be amortized over the remaining life of the refinanced advances. Oglethorpe
has the option to set the maturities for each advance for a term as short as
three months. As of December 31, 1995, the remaining maturities on these
advances ranged from three months to 21 months.Series 1998 Bonds.
In December 1995,1997, Oglethorpe completed a current refunding transaction
whereby $21,670,000$14,635,000 (includes portion assumed by GTC) of fixed rate pollution control revenue bondsPCBs were
54
issued. The proceeds of this transaction were used to retire $21,670,000$14,635,000 of
existing bonds.bonds in January 1998. At December 31, 1997 both the current and
existing bonds were reported as outstanding debt on the balance sheet. The
unamortized transaction costs related to this transaction total $287,000. This amount hashave been reported
as a deferred charge on the balance sheet and isare being amortized over the
life of the related bonds.
The proceeds from the December 1995, current refunding were held in debt
service reserve funds until the retirement of the bonds occurred in January
1996. At December 31, 1995, Oglethorpe accounted for the pending retirement
as an in-substance defeasance. Therefore, the cash held in debt service
reserve funds, bonds payable, and premium on reacquired debt are stated as
though the event of retiring the refunded bonds had occurred in 1995.
In January 1996, Oglethorpe completed note modifications pursuant to which
it repriced $89,447,000 of FFB advances. In connection with such
modification, Oglethorpe paid a premium of $9,332,000. These amounts will be
reported as deferred charges on the balance sheet, and will be amortized over
22 years, the longest remaining life of the subject advances.
The annual interest requirement for 1996, based upon all debt outstanding
at December 31, 1995, will1998 is estimated to be approximately $290,000,000.$242,000,000.
Maturities for the long-term debt through 20002002 are as follows:
...................................................................................
(DOLLARS IN THOUSANDS) 1996 1997 1998 1999 2000 ...................................................................................2001 2002
- ------------------------------------------------------ --------- ---------- ---------- ---------- ----------
FFB and RUSRUS........................................... $ 82,02669,432 $ 77,49972,662 $ 82,74478,952 $ 86,74384,470 $ 94,897
CoBank 478 489 502 516 532
1982 Bonds -- 6,675 -- -- --
1992A Bonds -- 5,070 5,330 5,615 5,925
1992 Bonds -- -- 2,085 2,240 2,405
1993A Bonds -- -- 2,265 2,410 2,595
1993B Bonds -- 9,810 6,490 6,695 7,770
1993Bonds 855 875 900 935 1,135
1994A Bonds -- -- -- -- 2,240
1994B Bonds -- 1,335 550 1,465 1,540
1994 Bonds 325 330 350 370 38589,199
CoBank................................................ 483 495 508 523 540
PCBs.................................................. 13,206 14,540 17,949 19,678 20,264
Capital Leases 5,991 2,795 5,143Leases........................................ 6,435 6,240 7,075 -------- -------- -------- -------- --------
Total7,775 8,544
--------- ---------- ---------- ---------- ----------
Total................................................. $ 89,675 $104,878 $106,359 $113,229 $126,499
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
...................................................................................89,556 $ 93,937 $ 104,484 $ 112,446 $ 118,547
--------- ---------- ---------- ---------- ----------
--------- ---------- ---------- ---------- ----------
Oglethorpe has a commercial paper program under which it may issue
commercial paper not to exceed a $300,000,000$280,000,000 balance outstanding at any time.
The commercial paper may be used as a source of short-term fundsfor working capital requirements and is not
intended for
any specific purpose.general corporate purposes. Oglethorpe's commercial paper is backed 100% by
committed lines of credit provided by a group of banks.
As of December 31, 1995 and 1994,1997, approximately $92,000,000 of commercial paper was
outstanding in connection with the defeasance of the Series 1992 PCBs discussed
above. There was no commercial paper was outstanding.outstanding at December 31, 1996.
Oglethorpe has arranged fora $50,000,000 uncommitted short-term linesline of
47
credit with CoBank and CFC
and a $30,000,000 committed line of credit with SunTrust Bank, Atlanta
(SunTrust). The CoBank line amounts to $70,000,000; the CFC line
amounts to $50,000,000; and the SunTrust line amounts to $30,000,000. The
maximum combined amount that can be outstanding under these
lines of credit and the commercial paper program at any one time totals
$370,000,000$330,000,000 due to certain restrictions contained in the CFC and SunTrust line of
credit agreements.agreement. No balance was outstanding on anyeither of these threetwo lines of
credit at either December 31, 19951997 or 1994.1996.
6. ELECTRIC PLANT AND RELATED AGREEMENTS:
Oglethorpe and GPCGeorgia Power Company (GPC) have entered into agreements
providing for the purchase and subsequent joint operation of certain of GPC's
electric generating plants
and transmission facilities.plants. A summary of Oglethorpe's plant investments and
related accumulated depreciation as of December 31, 19951997 is as follows:
...................................................................................
(DOLLARS IN THOUSANDS)
Accumulated
Plant Investment Depreciation
...................................................................................ACCUMULATED
PLANT INVESTMENT DEPRECIATION
- --------------------------------------------------------------------- ------------ ------------
In-service
Owned property
Vogtle Units No. 1 & No. 2 (NUCLEAR - 30%(NUCLEAR--30% OWNERSHIP) $2,779,362............. $2,781,172 $ 594,553736,999
Hatch Units No. 1 & No. 2 (NUCLEAR - 30%(NUCLEAR--30% OWNERSHIP) 516,154 198,082.............. 520,512 217,406
Wansley Units No. 1 & No. 2 (FOSSIL - 30%(FOSSIL--30% OWNERSHIP) 171,453 82,842............. 171,916 85,997
Scherer Unit No. 1 (FOSSIL - 60%(FOSSIL--60% OWNERSHIP) 429,553 184,513...................... 427,275 199,892
Rocky Mountain Units No. 1, No. 2 & No. 3
(HYDRO -(HYDRO-- 74.6% OWNERSHIP) 549,750 6,203..................................... 556,715 28,533
Tallassee (Harrison Dam) (HYDRO - 100%(HYDRO--100% OWNERSHIP) 9,282 1,641................. 9,270 1,975
Wansley (COMBUSTION TURBINE -
30%TURBINE-30% OWNERSHIP) 3,665 1,181
Transmission and distribution plant 823,087 176,553
Other 117,794 33,796...................... 3,655 1,236
Generation step-up substations.................................. 58,196 20,349
Other........................................................... 80,541 20,083
Property under capital lease
Scherer Unit No. 2 (FOSSIL - 60%(FOSSIL--60% LEASEHOLD) 299,113 83,067
---------- ----------........................ 300,815 99,817
------------ ------------
Total in-service $5,699,213 $1,362,431
---------- ----------
---------- ----------in-service..................................................... $4,910,067 $1,412,287
----------- ------------
----------- ------------
Construction work in progress
Generation improvementsimprovements........................................... $ 17,021
Transmission and distribution plant 18,258
Other 474
----------12,530
Other............................................................. 1,048
-----------
Total construction work in progressprogress.................................. $ 35,753
----------
----------
...................................................................................13,578
-----------
-----------
In 1988, Oglethorpe, acquired from GPC an undivided ownership interest in
the Rocky Mountain Project, a pumped storage hydroelectric facility (Rocky
Mountain). Under the Rocky Mountain agreements, Oglethorpe assumed
responsibility for construction of the facility, which was commenced by GPC.
Under the agreements, GPC retained its current investment in Rocky Mountain
with the ultimate ownership interests of Oglethorpe and GPC in the facility
based on the ratio of each party's direct construction costs to total project
direct construction costs with certain adjustments.
On June 1, 1995, Unit 3 and the completed Unit Common facilities were
declared to be in commercial operation by Oglethorpe. Unit 2 and Unit 1 were
declared to be in commercial operation on June 19, 1995 and July 24, 1995,
respectively. In accordance with the Rocky Mountain agreements, the final
ownership interests of Oglethorpe and GPC in Rocky Mountain is 74.6% and
25.4%, respectively. The final ownership interests in the project will be
applied to all future capital costs.
Oglethorpe is engaged in a continuous construction program and, as of December 31, 1995,1997, estimates property additions (including
capitalized interest)interest but excluding nuclear fuel) to be approximately $113,000,000$19,000,000
in 1996, $106,000,0001998, $17,000,000 in 19971999 and $103,000,000$15,000,000 in 1998,2000, primarily for replacements
and additions to generation
and transmission facilities.
Oglethorpe's proportionate share of direct expenses of joint operation of
the above plants is included in the corresponding operating expense captions
(e.g., fuel, production or depreciation) on the accompanying statements of
revenues and expenses.
55
7. EMPLOYEE BENEFIT PLANS:
Oglethorpe has a noncontributory defined benefit pension plan covering
substantially all employees. Oglethorpe's pension cost was approximately
$654,000 in 1997, $1,388,000 in 1996 and $1,954,000 in 1995, $1,262,000 in 1994 and $1,038,000 in 1993.1995. For 1995,
pension cost increased by $912,000 related to termination benefits. The
termination benefits resulted from an early retirement program undertaken in
the fourth quarter of 1995. Plan benefits are based on years of service and
the employee's compensation during the last ten years of employment.
Oglethorpe's funding policy is to contribute annually an amount not less than
the minimum required by the Internal Revenue Code and not more than the
maximum tax deductible amount.
The plan's funded status also reflects Oglethorpe's retention of the
unfunded pension liability for employees as of the date they were transferred
to Intellisource Services Solutions in February 1997.
The plan's pension cost recognized in 1997, 1996 and 1995 1994 and 1993 iswas shown as
follows:
...................................................................................
(DOLLARS IN THOUSANDS) 1997 1996 1995
1994 1993
...................................................................................- --------------------------------------------------------- ------- ------- -------
Pension cost was comprised of the
following
Service cost - benefitscost--benefits earned during the yearyear............ $ 913560 $ 1,0841,149 $ 884913
Interest cost on projected benefit obligationobligation............ 791 872 742 714 617
Actual return on plan assetsassets............................. (1,872) (984) (1,889) 387 (698)
Net amortization and deferraldeferral............................ 1,175 351 1,288 (911) 247
Net gain from a plan curtailment (12) (12)curtailment......................... -- -- (12)
------- ------- -------
Net pension costcost......................................... $ 1,042654 $ 1,2621,388 $ 1,038
-------1,042
------- ------- -------
------- ------- ...................................................................................-------
48
The plan's funded status in Oglethorpe's financial statements as of
December 31, 19951997 and 1994 were1996 was as follows:
...........................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...........................................................................1997 1996
- ---------------------------------------------------------------------- ---------- ---------
Actuarial present value of accumulated plan benefits
VestedVested.............................................................. $ 6,8687,197 $ 5,281
Nonvested 591 380
-------- --------7,554
Nonvested........................................................... 400 540
--------- ---------
$ 7,4597,597 $ 5,661
-------- --------
-------- --------8,094
--------- ---------
--------- ---------
Projected benefit obligation $(12,326)obligation.......................................... $ (9,276)(11,294) $ (13,211)
Plan assets at fair value 7,760 7,282
-------- --------value........................................... 9,568 9,218
Projected benefit obligation in excess of plan assets (4,566) (1,994)assets................. (1,726) (3,993)
Unrecognized net loss (gain) from past experience different
from that assumed and effects of changes in assumptions 223 (861)assumptions.............. (2,243) (880)
Prior service cost not yet recognized in net periodic pension cost 548 598cost.... 355 498
Unrecognized net asset at transition date being recognized
over 19 years (121) (133)
-------- --------years....................................................... (77) (109)
--------- ---------
Pension accrualaccrual....................................................... $ (3,916)(3,691) $ (2,390)
-------- --------
-------- --------
...........................................................................(4,484)
--------- ---------
--------- ---------
The discount rate and rate of increase in future compensation levels used
in determining the actuarial present value of the projected benefit
obligations shown above were 7.25% and 5.0% in 1995,1997, and 8.5%7.5% and 5.0% in
1994,1996, respectively. The expected long-term rate of return on plan assets was
8.5% in 19951997, 1996 and 8% in 1994 and 1993,1995 and the discount rate used in determining the
pension expense was 8.5% in 1995, 7.5% in 19941997, 7.25% in 1996 and 8.5% in 1993.1995.
Oglethorpe has a contributory employee thriftretirement savings plan covering
substantially all employees. Employee contributions to the plan may be
invested in one or more of threenine funds. The employee may contribute, subject
to IRS limitations,IRSlimitations, up to 16% of his annual compensation. Oglethorpe will
match the employee's contribution up to one-half of the first 6% of the
employee's annual compensation, as long as there is sufficient net margin to
do so. Oglethorpe's contributions to the plan were approximately $248,000 in
1997, $561,000 in 1996 and $589,000 in 1995,
$565,000 in 1994 and $503,000 in 1993.1995.
8. NUCLEAR INSURANCE:
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is a
member of Nuclear Mutual Limited (NML)Electric Insurance, Ltd. (NEIL), a mutual insurer
established to provide property damage insurance coverage in an amount up to
$500,000,000 for members' nuclear generating facilities. In the event that
losses exceed accumulated reserve funds, the members are subject to
retroactive assessments (in proportion to their participation in the mutual
insurer). The portion of the current maximum annual assessment for GPC that
would be payable by Oglethorpe, based on ownership share, adjusted for sell-back, is limited to
approximately $7,220,000$5,959,000 for each nuclear incident.
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is also a
member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer, and
Oglethorpe has
coverage under NEIL II, and NEIL III, which provideprovides insurance to cover decontamination,
debris removal and premature decommissioning as well as excess property
damage to nuclear generating facilities for an additional $2,250,000,000 for
losses in excess of the $500,000,000 NMLprimary coverage described above. Under
the NEIL policies, members are subject to retroactive assessments in
proportion to their participation if losses exceed the accumulated funds
available to the insurer under the policy. The portion of the current maximum
annual assessment for GPC that would be payable by Oglethorpe, based on
ownership share, adjusted for sell-back, is limited to approximately $13,980,000.$9,563,000.
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
56
dedicated first for the sole purpose of placing the reactor in a safe and
stable condition after an accident. Any remaining proceeds are next to be
applied toward the costs of decontamination and debris removal operations
ordered by the NRC, and any further remaining proceeds are to be paid either
to the company or to its bond trustees as may be appropriate under the
policies and applicable trust indentures.
The Price-Anderson Act, as amended in 1988, limits public liability
claims that could arise from a single nuclear incident to $8,900,000,000,
which amount is to be covered by private insurance and agreements of
indemnity with the NRC. Such private insurance (in the amount of $200,000,000
for each plant, the maximum amount currently available) is carried by GPC for
the benefit of all the co-owners of Plants Hatch and Vogtle. Agreements of
indemnity have been entered into by and between each of the co-owners and the
NRC. In the event of a nuclear incident involving any commercial nuclear
facility in the country involving total public liability in excess of
$200,000,000, a licensee of a nuclear power plant could be assessed a
deferred premium of up to $79,275,000 per incident for each licensed reactor
operated by it, but not more than $10,000,000 per reactor per incident to be
paid in a calendar year. On the basis of its sell-back adjusted ownership
interest in four nuclear reactors, Oglethorpe could be assessed a maximum of
$95,130,000 per incident, but not more than $12,000,000 in any one year.
Oglethorpe participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, Oglethorpe could be subject to a total
maximum assessment of $3,360,000.
All retrospective assessments, whether generated for liability or
property, may be subject to applicable state premium taxes.
9. POWER PURCHASE AND SALE AGREEMENTS:
Oglethorpe is utilizing long-term power marketer arrangements to reduce
the cost of power to the Members. Oglethorpe has entered into power marketer
agreements with LG&E Energy Marketing, Inc. (LEM) effective January 1, 1997,
for approximately 50% of the load requirements of the Members and with Morgan
Stanley, effective May 1, 1997, with respect to 50% of the Members' then
forecasted load requirements. These agreements extend through 2011 and into
2005, respectively. The LEM agreements are based on the actual requirements
of the Members during the contract term, whereas the Morgan Stanley agreement
represents a fixed supply obligation. Under these power marketer agreements,
Oglethorpe purchases energy at fixed prices covering a portion of the costs
of energy to its Members. LEM and Morgan Stanley, in turn, have certain
rights to market excess energy from the Oglethorpe system. All of
Oglethorpe's existing generating facilities and power purchase arrangements
are available for use by LEM and Morgan Stanley for the term of the
respective agreements. Oglethorpe continues to be responsible for all of the
costs of its system resources but receives payment from LEM and Morgan
Stanley for the use of the resources. The Morgan Stanley agreement requires
both Oglethorpe and Morgan Stanley to make minimum purchases from each other,
however, the net requirement between the parties is immaterial. Under the LEM
agreement there is no minimum purchase required.
Oglethorpe has entered into long-term power purchase agreements with GPC,
Big Rivers Electric Corporation (Big Rivers), and Entergy Power, Inc. (EPI).
Under the agreement with GPC, Oglethorpe will purchasepurchased on a take-or-pay basis
1,2501,000 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 August 31, 1998. Effective September 1, 1998,
Oglethorpe will purchase 500 MW of capacity through the period ending August
31, 1998. Effective September 1, 1999, Oglethorpe will purchase 250 MW of
capacity through the period ending December 31, 2003, subject to reductions
or extension with proper notice. The Big Rivers agreement commenced in August
1992 and is effective through July 2002. Oglethorpe is obligated under this
agreement to purchase on a take-or-pay basis 100 MW of firm capacity and
certain minimum energy amounts associated with that capacity. The EPI
agreement commenced in July 1992, has a term of ten years and represents a
take-or-pay commitment by Oglethorpe to purchase 100 MW of capacity.
Oglethorpe has a contract with Hartwell Energy Limited Partnership for
the purchase of approximately 300 MW of capacity for a 25-year period
commencing in April 1994.
Oglethorpe has entered into a short-term seasonal power purchase
agreement with Florida Power Corporation. Under the agreement, Oglethorpe
will purchasepurchased 50 MW of capacity on a take-or-pay basis for the period June 1,
1997 through September 30, 1997 and will purchase 275 MW for the period June
1, 1998 through September 30, 1998.
As of December 31, 1995,1997, 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 DecemberYEAR ENDING DECEMBER 31, (dollars in thousands)
...........................................................................(DOLLARS IN THOUSANDS)
- ---------------------------------------------------- ----------------------
19961998................................................ $ 149,835
1997 130,843
1998 119,948
1999 118,061
2000 121,179
...........................................................................111,494
1999................................................ 84,578
2000................................................ 69,075
2001................................................ 70,071
2002................................................ 57,875
57
Oglethorpe's power purchases from these agreements amounted to
approximately $175,818,000 in 1997, $190,760,000 in 1996 and $206,641,000 in
1995, $182,965,000 in 1994 and $192,059,000 in 1993.1995.
Oglethorpe has entered into an agreement with Alabama Electric
Cooperative to sell 100 MW of capacity for the period June 1998 through
December 2005.
10. SUBSEQUENT EVENT:
On January 3, 1996, Oglethorpe entered into a power supply swap agreement
with Enron Power Marketing Inc. (EPMI). The agreement, effective January 4,
1996 through April 30, 1996, requires EPMI to sell to Oglethorpe at a fixed
cost all the energy needed to serve the Members (approximately 5.2 million
megawatt-hours). Per the agreement, Oglethorpe is required to sell to EPMI at
cost, subject to certain cost limitations, all energy available from
Oglethorpe's total power resources. EPMI has the option to market any excess
energy that remains from Oglethorpe's total power resources. Oglethorpe is
considering a similar power supply swap for a longer term basis.
In order to provide its Members with greater flexibility for meeting their
power supply needs in an increasingly competitive utility environment, a plan
was approved by Oglethorpe's Board of Directors in December 1995 to divide
Oglethorpe into three specialized companies to respond to increasing
competition in the electric industry and related changes in law and
regulation. The December plan proposed the creation of a new transmission
company that would own and operate the transmission system and provides
services to the Members, and a new systems operations company that would own
and operate the systems operation services for the Members, Oglethorpe and
third parties. Oglethorpe would retain the generation business and would
operate as the power supplier for the Members. Oglethorpe is continuing to
develop and refine the restructuring plan, and subject to receiving
governmental and other third party approvals, the current target date for
full implementation of the restructuring is January 1, 1997.
11. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial information for 19951997 and 19941996 is as follows:
...........................................................................
First Second Third FourthFIRST SECOND THIRD FOURTH
(DOLLARS IN THOUSANDS) Quarter Quarter Quarter Quarter
...........................................................................QUARTER QUARTER QUARTER QUARTER
- ----------------------------------------- ----------- ----------- ----------- -----------
19951997
Operating revenues $257,547 $281,228 $317,536 $293,250revenues....................... $ 271,485 $ 242,876 $ 286,579 $ 246,912
Operating margin 68,682 82,048 82,949 74,998margin......................... 77,818 61,423 56,753 63,681
Net margin 8,462 20,292 10,656 (17,152)
1994margin............................... 9,436 5,510 (872) 8,331
1996
Operating revenues $267,618 $263,035 $266,818 $258,611revenues....................... $ 270,689 $ 275,228 $ 286,648 $ 268,872
Operating margin 81,882 75,704 68,087 61,734margin......................... 73,568 72,514 75,009 61,658
Net margin 20,184 13,511 4,386 (14,999)
...........................................................................margin............................... 8,988 4,732 12,508 (4,476)
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 highernegative net margin for the secondthird quarter 1995 comparedof 1997 reflects a $4,000,000
reduction in revenue requirement approved by Oglethorpe's Board of Directors.
Such reduction in revenues was implemented by reducing the capacity charges
billed to 1994
resulted from unbudgeted savings from the continued capitalization of costs
of Rocky Mountain due to the delayMembers in commercial operation from April 1995 to
June 1995.August 1997. The negative net marginsmargin for the fourth
quarter of 19951996 is consistent with expectations and 1994 were
primarily attributablereflects recognition of
certain nonrecurring expenses.
11. CORPORATE RESTRUCTURING
Oglethorpe and the Members completed on March 11, 1997, a Corporate
Restructuring in which Oglethorpe, effective April 1, 1997, was divided into
three specialized operating companies. Oglethorpe's transmission business was
sold to, and is now owned and operated by GTC. Oglethorpe's system operations
business was sold to, and is now owned and operated by GSOC. Oglethorpe
continues to own and operate its power supply business.
The total purchase price GTC and GSOC paid Oglethorpe for the
transmission and system operations business was approximately $717 million.
The following summarizes the assets and liabilities sold by Oglethorpe to GTC
and GSOC as a result of the restructuring:
ASSETS (DOLLARS IN THOUSANDS)
- ----------------------------------------------------------------------------
Plant in service.................................. $ 847,172
Accumulated depreciation.......................... (195,944)
Construction work in progress..................... 13,313
Plant acquisition adjustment...................... 3,887
Inventories....................................... 8,980
Prepayments....................................... 71
Premium on reacquired debt........................ 33,410
Deferred debt expense............................... 1,920
----------
TOTAL ASSETS SOLD................................. 712,809
Deferred gain on sale............................... 4,670
----------
TOTAL PURCHASE PRICE.............................. $ 717,479
----------
----------
EQUITY AND LIABILITIES
Long-term debt.................................... $ 686,054
Accounts payable.................................. 585
Accrued interest.................................. 121
Accrued pension cost.............................. 1,047
Deferred revenues................................. 310
----------
TOTAL LIABILITIES EXTINGUISHED.................. 688,117
Notes received from GSOC.......................... 4,822
Net cash received................................. 24,540
----------
TOTAL PURCHASE PRICE............................ $ 717,479
----------
----------
In addition, Oglethorpe also made a special patronage capital
distribution to the deferralMembers which was used by the Members to establish equity
in and to provide working capital to GTC.
The following unaudited pro forma statement of excess margins. For a discussionrevenues and expenses for
the year ended December 31, 1997 reflects the operations of Oglethorpe as
reported and restated, reflecting the exclusion of the amountstransmission and
system operations businesses as though the Corporate Restructuring had
occurred at the beginning of excess margins deferred, see Note 1.
501997.
58
This unaudited pro forma statement of revenues and expenses has been
prepared based on assumptions and estimates deemed appropriate and is
presented for illustrative purposes only and is not necessarily indicative of
results of operations which would have actually been reported had the
transaction occurred at the beginning of the period.
PRO FORMA STATEMENT OF REVENUES AND EXPENSES
(UNAUDITED)
FOR THE YEAR ENDED DECEMBER 31,1997
(dollars in thousands)
OGLETHORPE
OGLETHORPE PRO FORMA (POST-
HISTORICAL ADJUSTMENTS(1) RESTRUCTURING)
------------ -------------- --------------
OPERATING REVENUES:
Sales to Members............................ $ 1,000,319 $ (25,764) $ 974,555
Sales to non-Members........................ 47,533 (2,180) 45,353
----------- --------- -----------
TOTAL OPERATING REVENUES.................. 1,047,852 (27,944) 1,019,908
----------- --------- -----------
----------- --------- -----------
OPERATING EXPENSES:
Fuel........................................ 206,315 -- 206,315
Production.................................. 157,932 (2,968) 154,964
Purchased power............................. 266,875 (66) 266,809
Power delivery.............................. 4,032 (3,584) 448
Depreciation and amortization............... 126,730 (5,453) 121,277
Taxes other than income taxes............... 26,293 (1,855) 24,438
Income taxes................................ -- -- --
----------- --------- -----------
TOTAL OPERATING EXPENSES.................. 788,177 (13,926) 774,251
----------- --------- -----------
OPERATING MARGIN.............................. 259,675 (14,018) 245,657
----------- --------- -----------
OTHER INCOME (EXPENSE):
Interest income............................. 29,303 (139) 29,164
Amortization of net benefit of sale of
income tax benefits........................ 11,195 -- 11,195
Allowance for equity funds used during
construction............................... 157 (68) 89
Other....................................... 5,991 25 6,016
----------- --------- -----------
TOTAL OTHER INCOME........................ 46,646 (182) 46,464
----------- --------- -----------
INTEREST CHARGES:
Interest on long-term debt and other
obligations................................ 285,590 (12,073) 273,517
Allowance for debt funds used during
construction............................... (1,674) 161 (1,513)
----------- --------- -----------
NET INTEREST CHARGES...................... 283,916 (11,912) 272,004
----------- --------- -----------
NET MARGIN.................................... $ 22,405 $ (2,288) $ 20,117
----------- --------- -----------
----------- --------- -----------
- ------------------------
(1) IN ANTICIPATION OF THE CORPORATE RESTRUCTURING, OGLETHORPE BEGAN KEEPING
SEPARATE BOOKS AND RECORDS FOR GTC AND GSOC BEGINNING JANUARY 1, 1997.
THEREFORE, THE PRO FORMA ADJUSTMENTS REFLECT SEPARATELY IDENTIFIED
TRANSACTIONS AND SPECIFIC ALLOCATIONS.
59
REPORT OF MANAGEMENT
The management of Oglethorpe Power Corporation has prepared this report
and is responsible for the financial statements and related information.
These statements were prepared in accordance with generally accepted
accounting principles appropriate in the circumstances and necessarily
include amounts that are based on best estimates and judgments of management.
Financial information throughout this annual report is consistent with the
financial statements.
Oglethorpe maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and
records reflect only authorized transactions. Limitations exist in any system
of internal control based upon the recognition that the cost of the system
should not exceed its benefits. Oglethorpe believes that its system of
internal accounting control, together with the internal auditing function,
maintains appropriate cost/benefit relations.
Oglethorpe's system of internal controls is evaluated on an ongoing basis
by its qualified internal audit staff. The Corporation's independent public
accountants (Coopers & Lybrand L.L.P.) also consider certain elements of the
internal control system in order to determine their auditing procedures for
the purpose of expressing an opinion on the financial statements.
Coopers & Lybrand L.L.P. also provides an objective assessment of how
well management meets its responsibility for fair financial reporting.
Management believes that its policies and procedures provide reasonable
assurance that Oglethorpe's operations are conducted with a high standard of
business ethics. In management's opinion, the financial statements present
fairly, in all material respects, the financial position, results of
operations, and cash flows of Oglethorpe Power Corporation.Oglethorpe.
T. D. Kilgore
President and Chief Executive Officer
Eugen Heckl
Senior Vice President and
Chief Financial Officer
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Oglethorpe Power Corporation:
We have audited the accompanying balance sheetsheets and statementstatements of
capitalization of Oglethorpe Power Corporation (a Georgia corporation) as of
December 31, 19951997 and the related statements of revenues and expenses,
patronage capital, and cash flows for the year then ended. These financial
statements are the responsibility of Oglethorpe's management. Our
responsibility is to express an opinion on these financial statements based
on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Oglethorpe Power
Corporation as of December 31, 1995 and the results of its operations and its
cash flows for the year then ended in conformity with generally accepted
accounting principles.
Coopers & Lybrand L.L.P.
Atlanta, Georgia,
February 28, 1996.
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, 19941996 and the related statements of revenues and
expenses, patronage capital, and cash flows for each of the twothree years in
the period ended December 31, 1994.1997. These financial statements are the
responsibility of Oglethorpe's management. Our responsibility is to express
an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present
fairly, in all material respects, the financial position of Oglethorpe Power
Corporation as of December 31, 19941997 and 1996 and the results of its
operations and its cash flows for each of the twothree years in the period ended
December 31, 19941997, in conformity with generally accepted accounting
principles.
As explained in Note 2 of notes to financial statements, effective January
1, 1994, Oglethorpe Power Corporation changed its method of accounting for
certain investments in debt and equity securities. As explained in Note 3 of
notes to financial statements, effective January 1, 1993, Oglethorpe changed
its method of accounting for income taxes.
Arthur Andersen LLPCoopers & Lybrand L.L.P.
Atlanta, Georgia,
February 24, 1995.
5217, 1998.
60
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(A) IDENTIFICATION OF DIRECTORS:
Oglethorpe is governed by a Board of 39 Directors, 13 of whom are
elected each year for a three-year term. EachAs part of the 39 Members nominates one
Director who must also be on the Member's BoardCorporate Restructuring, Oglethorpe amended its Bylaws to
provide for an eleven member board of Directors. The Directors
are thendirectors consisting of six directors
elected byfrom 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(the "Member Directors"), four independent outside
directors (the "Outside Directors") and Oglethorpe's Bylaws, Alternate Directors may attend all Board meetings, but
can be counted for quorum purposes and can exercise the powers and duties of
a Director only during the period when the directorship for whom he is the
alternate is vacant or at any meeting of the Board of Directors when the
Director for whom he is the alternate is absent. The Board of Directors
generally meets monthly. For a discussion of the proposed changes in
Oglethorpe's governance structure in connection with the proposed
restructuring, see "OGLETHORPE POWER CORPORATION-Proposed Restructuring" in
Item 1.
Six standing committees are appointed by the Chairman of the Board
and include both Directors and Alternate Directors. Special committees, as
deemed necessary, are also appointed by the Chairman of the Board or the
Board of Directors. Committee recommendations and management
recommendations, subject to the approval of the Board of Directors, determine
the policies and activities of Oglethorpe.
The Directors and Alternate Directors of Oglethorpe are as follows:
ALTAMAHA EMC
Jmon Warnock--Director, age 70, is a farmer. He has served on the
Board of Directors of Oglethorpe since September 1974. His present term as a
Director will expire in March 1998. He is currently a member of the Finance
Committee of Oglethorpe. Mr. Warnock is the President of Altamaha EMC and a
Director of GEMC.
James D. Musgrove--Alternate Director, age 49, is the General
Manager of Altamaha EMC. He has served as an Alternate Director of
Oglethorpe since May 1989, with his present term to expire in March 1998.
Mr. Musgrove is a Director of Montgomery County Bankshares in Ailey, Georgia.
AMICALOLA EMC
Charles R. Fendley--Director, age 50, is a Vice President of Jasper
Yarn Processing, Inc., which processes yarn. He has served on the Board of
Directors of Oglethorpe since November 1993, with his present term to expire
in March 1998. Mr. Fendley is the President of Amicalola EMC. He is also a
Director of GEMC and a Director of Crescent Bank & Trust Co. in Jasper,
Georgia.
John S. Dean, Sr.--Alternate Director, age 56, has been General
Manager/Chief Executive Officer of Amicalola EMC since 1974. Prior to his
employment with Amicalola EMC, he was Controller of Pickens General Hospital.
He has served as an Alternate Director of Oglethorpe since 1975, with his
present term to expire in March 1998. He is currently a member of the
Finance Committee. Mr. Dean previously served on Oglethorpe's Operations
Review Committee and Executive Committee and served as Secretary-Treasurer of
Oglethorpe from March 1989 to March 1995. Currently, he is on the Board of
Directors of GRESCO, Southeastern Data Cooperative, Inc., Crescent Bank &
Trust Company, CoBank, and North Georgia Certified Development Corporation.
53
CANOOCHEE EMC
George C. Martin--Director, age 78, is the owner and operator of a
farm in Ellabell, Bryan County, Georgia where he raises beef cattle. He also
manages timberland in Bryan County, Georgia and rental properties in Savannah
and Pembroke, Georgia. Mr. Martin is President of Canoochee EMC. He has
served on the Board of Directors of Oglethorpe since March 1977, with his
present term to expire in March 1998. From March 1978 to March 1984, he
served as Vice President of Oglethorpe.
Donald F. Kennedy--Alternate Director, age 66, is the General
Manager of Canoochee EMC. He has served as an Alternate Director of
Oglethorpe since 1985, with his present term to expire in March 1998. Mr.
Kennedy is also a Director of the Tattnall Bank in Reidsville, Georgia.
CARROLL EMC
J. G. McCalmon--Director, age 78, is the owner of a farm in
Carrollton, Georgia, where he raises chickens and beef cattle. He has served
on the Board of Directors of Oglethorpe since September 1974, with his
present term to expire in March 1999. He currently serves as Vice Chairman
of the Human Resources Management Committee. He is Chairman of the Board of
Carroll EMC. Mr. McCalmon also serves on the Boards of Directors of GEMC,
the Farm Bureau, Carroll County Sales Barn, and the Carroll County Chamber
of Commerce.
Gary M. Bullock--Alternate Director. For a description of Mr.
Bullock's background and experience, see "Identification of Executive
Officers and Senior Executives" below.
CENTRAL GEORGIA EMC
D. A. Robinson, III--Director, age 55, is the owner and operator of
a dairy farm in Griffin, Georgia. He has served on the Board of Directors of
Oglethorpe since March 1984, and his present term will expire in March 1998.
He is a member of the Transmission Committee. Mr. Robinson serves as
Secretary-Treasurer of Central Georgia EMC.
George L. Weaver--Alternate Director, age 48, has been the
President of Central Georgia EMC since 1989. Prior to that time he was
General Manager, Manager of Accounting, and Financial Manager. He has served
as an Alternate Director of Oglethorpe since 1983, and his present term will
expire in March 1998. He is currently a member of the Finance Committee. He
is Vice President of the Board of Directors of Federated Rural Electric
Insurance Corporation in Shawnee Mission, Kansas and Chairman of the Board of
Directors of Southeastern Data Cooperative. Mr. Weaver is Chairman of the
Butts County Development Authority; Chairman of the Joint Development
Authority which encompasses Butts, Henry, Lamar, and Spalding Counties; and
Vice Chairman of the West Central Georgia Private Industry Council. He
serves on the Advisory Board of NationsBank of Georgia, N.A.
COASTAL EMC
James E. Estes--Director, age 60, has served on the Board of
Directors of Oglethorpe since March 1982, with his present term to expire in
March 1997. He currently serves as Chairman of the Wholesale Power Contract
Oversight Committee and is a member of the Executive Committee. He is also
Vice President of the Board of Directors of Coastal EMC. Mr. Estes operates
Estes Property Management, a commercial real estate management service in
Richmond Hill, Georgia; is President of Ways Company, Inc., a real estate
development company in Richmond Hill, Georgia; and is proprietor of Estes Tax
Service, an income tax service in Richmond Hill, Georgia.
Wayne Collins--Alternate Director, age 45, is the General Manager
of Coastal EMC and has served as an Alternate Director of Oglethorpe since
March 1977. His present term as an Alternate Director will expire in March
1997.
COBB EMC
Larry N. Chadwick--Director, age 55, is the owner of Chadwick's
Hardware in Woodstock, Georgia. He has served on the Board of Directors of
Oglethorpe since July 1989, with his present term to expire in March 1998.
He is currently a member of the Generation Committee. Mr. Chadwick is
Chairman of the Board of Cobb EMC.
54
Dwight Brown--Alternate Director, age 50, is President and Chief
Executive OfficerOfficer. Each Member Director must be a director or general manager of
Cobb EMC. He previously served as Vice Presidentan Oglethorpe Member. Five of Engineering and Operations for Cobb EMC. He has served as an Alternatethe six Member Directors must be located in each
of five geographical regions of the State of Georgia. The sixth Member Director
is elected statewide. None of Oglethorpe since October 1993, with his present term to expire in
March 1998. Mr. Brown currently servesthe four Outside Directors may be a director,
officer or employee of GTC, GSOC or any Member. All eleven directors are
nominated by representatives from each Member whose weighted nomination is based
on the Restructuring Advisory
Committee.
COLQUITT EMC
Simmie King--Director, age 52, isnumber of retail customers served by each Member. After nomination, the
owner and operatordirectors are elected by a majority vote of each Member, voting on a farm.
He has served onone-Member,
one-vote basis.
The Bylaws provide for staggering the Board of Directors of Oglethorpe since March 1991, with
his present term to expire in March 1999.
R. L. Gaston--Alternate Director, age 48, is the General Manager of
Colquitt EMC. From January 1985 to January 1990, he was Manager of
Engineering and Operations for Colquitt EMC. He has served as an Alternate
Director of Oglethorpe since February 1990, with his present term to expire
in March 1999. Mr. Gaston currently serves on the Restructuring Advisory
Committee.
COWETA-FAYETTE EMC
W. F. Farr--Director, age 83, is a banker. He has served on the
Board of Directors of Oglethorpe since March 1975, with his present term to
expire in March 1998. He is currently a memberterms of the Finance CommitteeMember Directors and
previously served as ChairmanOutside Directors by dividing the number of directors into three groups. As
noted below, some of the Human Resources Management Committee.
He has been Presidentdirectors were elected to an initial term of Coweta-Fayette EMC since 1974. He previously served
as Presidentone year,
some two years and some three years. As these initial terms expire, directors
will thereafter be elected for a term of the Fayette State Bank in Peachtree City, Georgia and as a
Director and Consultant for Citizens and Southern National Bank, South Metro
Board in Atlanta, Georgia. Since June 1985, Mr. Farr has been the owner and
President of Pioneer Financial Associates, Inc. in Peachtree City, Georgia.
Michael C. Whiteside--Alternate Director, age 53, has been General
Manager of Coweta-Fayette EMC since August 1983. He previously served as
Administrative Assistant of Coweta-Fayette EMC. He currently serves on the
Marketing Committee and the Restructuring Advisory Committee. Mr. Whiteside
has served as an Alternate Director of Oglethorpe since September 1983, with
his present term to expire in March 1998.
EXCELSIOR EMC
Vacant--Director
Gary T. Drake--Alternate Director, age 47, is the General Manager
of Excelsior EMC. He has served as an Alternate Director of Oglethorpe since
January 1979, with his present term to expire in March 1997. He was
Secretary-Treasurer of Oglethorpe from March 1984 through March 1989. He is
currently a member of the Generation Committee. Mr. Drake is also a Director
of GEMC.
FLINT EMC
Jeff S. Pierce, Jr.--Director, age 64, has served on the Board of
Directors of Oglethorpe since June 1992, with his present term to expire in
March 1997. He is a member of the Executive Committee. He has served as a
Director of Flint EMC since 1964. Mr. Pierce previously served 28 years as
Chief Executive Officer and as a Director for the First Federal Savings and
Loan Association in Warner Robins, Georgia. He is also a Director of GEMC.
Harold B. Smith--Alternate Director, age 60, has been employed as
General Manager of Flint EMC since November 1978. He has served as an
Alternate Director of Oglethorpe since 1978, with his present term to expire
in March 1997. He is currently a member of the Transmission Committee.
55
GRADY EMC
Donald C. Cooper--Director, age 65, is the owner, operator and
President of Cooper Farms, Inc., a farm in Grady County, Georgia where he
grows row crops and raises cattle. He has served on the Board of Directors
of Oglethorpe since March 1975, with his present term to expire in March
1999. He is currently a member of the Generation Committee.
Thomas A. Rosser--Alternate Director, age 48, has been employed as
General Manager of Grady EMC since January 1992. He has served as an
Alternate Director of Oglethorpe since January 1992, with his present term to
expire in March 1999.
GREYSTONE POWER CORPORATION, AN EMC
J. Calvin Earwood--Director. For a description of Mr. Earwood's
background and experience, see "Identification of Executive Officers and
Senior Executives" below.
Tim B. Clower--Alternate Director, age 59, is President and Chief
Executive Officer of GreyStone Power Corporation, an EMC. He has served as
an Alternate Director of Oglethorpe since September 1974, with his present
term to expire in March 1998. He is currently a member of the Marketing
Committee. Mr. Clower serves on the Boards of Directors of Citizens &
Merchants State Bank and GEMC Workers' Compensation Fund.
HABERSHAM EMC
Ray Meaders--Director, age 72, is the owner and operator of a farm
in Cleveland, Georgia. He has served as Director of Oglethorpe since August
1995, with his present term to expire in March 1999. He is currently a
member of the Marketing Committee. Mr. Meaders is also a Director of
Habersham EMC.
William E. Canup--Alternate Director, age 60, is the General
Manager of Habersham EMC. Mr. Canup was Manager of Engineering/Operations of
Habersham EMC from 1979 to 1984 and served as Assistant Manager of Habersham
EMC from 1984 to 1986. He has served as an Alternate Director of Oglethorpe
since July 1986, with his present term to expire in March 1999.
HART EMC
Mac F. Oglesby--Director, age 63, served as Assistant
Secretary-Treasurer of Hart EMC from July 1986 through December 1987, when he
was appointed President. He has served as a Director of Oglethorpe since
February 1987, with his present term to expire in March 1997. He is
currently a member of the Marketing Committee and the Wholesale Power
Contract Oversight Committee. Mr. Oglesby was a U.S. Postal Service Rural
Carrier for 30three years.
Grooms Johnson--Alternate Director, age 66, has been the General
Manager of Hart EMC since March 1991. Prior to that time, he served as
Assistant Manager of Hart EMC. He has served as an Alternate Director of
Oglethorpe since March 1991, with his present term to expire in March 1997.
Mr. Johnson is also a Director of Bank of Hartwell in Hartwell, Georgia.
IRWIN EMC
Benny W. Denham--Director. For a description of Mr. Denham's
background and experience, see "Identification of Executive Officers and
Senior Executives" below.
Harold Randall Crenshaw--Alternate Director, age 44, has been the
General Manager of Irwin EMC since February 1988. He has served as an
Alternate Director of Oglethorpe since February 1988, with his present term
to expire in March 1998. He is Chairman and past Vice Chairman of the
Finance Committee and also serves on the Restructuring Advisory Committee.
Mr. Crenshaw was Office Manager of Irwin EMC from 1974 to 1988.
56
JACKSON EMC
E. L. McLocklin--Director, age 83, is a cattle farmer. He is also
Chairman of the Board of Directors of Jackson EMC. He has served as a
Director of Oglethorpe since October 1989, with his present term to expire in
March 1999. Mr. McLocklin is currently a member of the Marketing Committee.
Randall Pugh--Alternate Director, age 52, is President and Chief
Executive Officer of Jackson EMC. From August 1984 to January 1988 he was
General Manager of Jackson EMC. He was also General Manager of Walton EMC
from 1977 to August 1984. He has served as an Alternate Director of
Oglethorpe since 1977. His present term as Alternate Director will expire in
March 1999. He is currently a member of the Finance Committee and the
Restructuring Advisory Committee. Mr. Pugh is also a Director of the First
National Bank of Jackson County in Jefferson, Georgia.
JEFFERSON EMC
Sam Rabun--Director, age 64, is part owner of a livestock farm. He
has served as a Director of Oglethorpe since March 1993, with his present
term to expire in March 1999. He is currently a member of the Executive
Committee. Mr. Rabun is the President of Jefferson EMC.
Kenneth Cook--Alternate Director, age 49, is the Executive Vice
President and General Manager of Jefferson EMC. He has served as the Manager
of Engineering since joining Jefferson EMC in 1986. He was previously
self-employed as a row-crop and livestock farmer. Mr. Cook has served as a
Director of Oglethorpe since February 1996, with his present term to expire
in March 1999. He served on the Board of Directors of Little Ocmulgee EMC
from 1979 to 1986 and on the Board of Directors of Oglethorpe from 1982 to
1986.
LAMAR EMC
E. J. Martin, Jr.--Director, age 68, is the owner of the Country
Kitchen restaurant in Barnesville, Georgia. He is a retired tax assessor and
appraiser for Lamar County. He has served on the Board of Directors of
Oglethorpe since March 1982, with his present term to expire in March 1997.
He is currently a member of the Human Resources Management Committee. Mr.
Martin is the President of Lamar EMC and a Director of GEMC.
J. Raleigh Henry--Alternate Director, age 45, is General Manager of
Lamar EMC. Prior to becoming General Manager, he served as Office Manager of
Lamar EMC. He has served as an Alternate Director of Oglethorpe since 1990,
with his present term to expire in March 1997.
LITTLE OCMULGEE EMC
Jim M. Knight--Director, age 60, is owner and manager of Knight
Farms. He has served on the Board of Directors of Oglethorpe since April
1994, with his present term to expire in March 1997. Mr. Knight is also a
Director of Little Ocmulgee EMC.
A. Arnold Horton--Alternate Director, age 49, is the General
Manager of Little Ocmulgee EMC. He previously served as Manager of
Engineering and Operations and has been with Little Ocmulgee EMC since 1983.
He has served as the Alternate Director of Oglethorpe since March 1993, with
his present term to expire in March 1997. Mr. Horton is a member of the
Transmission Committee.
MIDDLE GEORGIA EMC
Ronnie Fleeman--Director, age 61, is a self-employed land and
timber developer. He has served on the Board of Directors of Oglethorpe
since 1990, with his present term to expire in March 1998.
Charles Hugh Richardson--Alternate Director, age 42, has been
General Manager of Middle Georgia EMC since June 1983. From January 1983 to
June 1983, he was Acting General Manager of Middle Georgia EMC, and from
September 1976 to January 1983, he was Manager of Engineering at Middle
Georgia EMC. He has served as an Alternate Director of Oglethorpe since
1983, with his present term to expire in March 1998.
57
MITCHELL EMC
D. Lamar Cooper--Director, age 60, operates a dairy farm. He has
served on the Board of Directors of Oglethorpe since September 1974, with his
present term to expire in March 1999. He is currently a member of the
Generation Committee.
Edward A. Pritchett--Alternate Director, age 49, has served as
General Manager of Mitchell EMC since September 1995. Since that time he has
served as Alternate Director of Oglethorpe, with his present term to expire
in March 1999. Prior to that time, Mr. Pritchett served as Assistant General
Manager, Director of Finance and Administrative Services and Supervisor of
Data Processing for Mitchell EMC.
OCMULGEE EMC
Barry H. Martin--Director, age 47, is a farmer. He has served on
the Board of Directors of Oglethorpe since March 1983, with his present term
to expire in March 1997. Mr. Martin is the President of Ocmulgee EMC.
Dennis Grenade--Alternate Director, age 55, has been employed by
Ocmulgee EMC since December 1957. He has been General Manager since October
1987 and was previously Acting Manager and Manager of Operations. He has
served as an Alternate Director since October 1987, with his present term to
expire in March 1997. He is a member of the Transmission Committee.
OCONEE EMC
John B. Floyd, Jr.--Director, age 53, has served on the Board of
Directors of Oglethorpe since March 1980, with his present term to expire in
March 1999. He is currently a member of the Human Resources Management
Committee. Mr. Floyd is also the Vice Chairman of the Board of Oconee EMC.
Preston L. Johnson--Alternate Director, age 61, is President and
Chief Executive Officer of Oconee EMC. He has served as an Alternate
Director of Oglethorpe since September 1974, with his present term to expire
in March 1999. He was Secretary-Treasurer of Oglethorpe from September 1974
to March 1984.
OKEFENOKE RURAL EMC
Steve Rawl, Sr.--Director, age 49, has been President of Rawls,
Inc., a gift shop, since 1972. He has served as a Director of Oglethorpe
since September 1993, with his present term to expire in March 1997. He is
currently a member of the Finance Committee.
W. Don Holland--Alternate Director, age 45, is General Manager of
Okefenoke Rural EMC. He has served as an Alternate Director of Oglethorpe
since 1979, with his present term to expire in March 1997. He was formerly
General Manager of Little Ocmulgee EMC. He is currently Chairman of the
Transmission Committee and serves on the Restructuring Advisory Committee and
the Wholesale Power Contract Oversight Committee.
PATAULA EMC
James Grubbs--Director, age 73, is a farmer. He is involved with
fertilizer and chemical sales, and operates an air spray service and a peanut
purchasing plant. He has served on the Board of Directors of Oglethorpe
since March 1983, with his present term to expire in March 1999. Mr. Grubbs
is a member of the Transmission Committee.
Gary W. Wyatt--Alternate Director, age 43, is General Manager of
Pataula EMC. He has served as an Alternate Director of Oglethorpe since July
1986, with his present term to expire in March 1999. He currently serves as
Vice-Chairman of the Marketing Committee. Mr. Wyatt previously was
Operations Manager and Assistant Operations Superintendent of Coosa Valley
Electric Cooperative.
58
PLANTERS EMC
Sammy M. Jenkins--Director, age 69, is in the farm machinery
business and has been President of Jenkins Ford Tractor Co., Inc. since 1973.
He has served on the Board of Directors of Oglethorpe since March 1988, with
his present term to expire in March 1997. He was Vice Chairman of the Board
of Oglethorpe from March 1989 to March 1990. Mr. Jenkins currently serves as
Vice-Chairman of the Generation Committee and is a member of the Wholesale
Power Contract Oversight Committee.
Ellis H. Lovett--Alternate Director, age 60, is General Manager of
Planters EMC and has served as an Alternate Director of Oglethorpe since
1983. His present term as an Alternate Director will expire in March 1997.
He is currently a member of the Marketing Committee.
RAYLE EMC
J. M. Sherrer--Director, age 60, is the owner of a grocery,
hardware, gas and feed store. He has served on the Board of Directors of
Oglethorpe since September 1993, with his present term to expire in March
1997.
Wayne Poss--Alternate Director, age 50, has served as General
Manager of Rayle EMC since December 1992. Prior to that time, he served as
Manager of Engineering for Rayle EMC. He has served as an Alternate Director
of Oglethorpe since February 1993, with his present term to expire in March
1997. He is currently a member of the Generation Committee.
SATILLA RURAL EMC
Jack D. Vickers--Director, age 78, is the owner and operator of a
farm in Coffee County, Georgia. He has served on the Board of Directors of
Oglethorpe since March 1975, with his present term to expire in March 1997.
R. Lehman Lanier--Alternate Director, age 76, is President and
Chief Executive Officer of Satilla Rural EMC. He has served as an Alternate
Director of Oglethorpe since September 1974, with his present term to expire
in March 1997. He is currently a member of the Generation Committee. Mr.
Lanier is also a Director of Southeastern Data Cooperative, Inc.
SAWNEE EMC
C. W. Cox, Jr.--Director, age 68, is the owner of Cox Digging &
Grading, a general contracting sole proprietorship. He has served as a
member of the Board of Directors of Oglethorpe since February 1987, with his
present term to expire in March 1997. Mr. Cox is currently a member of the
Finance Committee.
Michael A. Goodroe--Alternate Director, age 39, is Executive Vice
President and General Manager of Sawnee EMC. He previously served as
Assistant General Manager of Sawnee EMC. He has served as an Alternate
Director of Oglethorpe since 1990, with his present term to expire in March
1997. He is a member of the Transmission Committee.
SLASH PINE EMC
Johnnie Crumbley--Director, age 73, is President of Slash Pine EMC.
He retired in 1982 from the Seaboard Coastline System. He has served as a
member of the Board of Directors of Oglethorpe since March 1978, with his
present term to expire in March 1999. He is also a Director of GEMC.
Edward Teston--Alternate Director, age 61, is Manager of Slash Pine
EMC. He has served as an Alternate Director of Oglethorpe since 1985, with
his present term to expire in March 1999.
SNAPPING SHOALS EMC
Jarnett W. Wigington--Director, age 63, is a self-employed
wallpapering contractor. He has served on the Board of Directors of
Oglethorpe since 1990, with his present term to expire in March 1997.
59
Randall G. Meadows--Alternate Director, age 51, is President/Chief
Executive Officer/Manager of Snapping Shoals EMC. He previously served as
Executive Vice President/Chief Operating Officer for Snapping Shoals EMC. He
has served as an Alternate Director of Oglethorpe since August 1995, with his
present term to expire in March 1997. Mr. Meadows currently serves on the
Restructuring Advisory Committee.
SUMTER EMC
Bob Jernigan--Director, age 68, has served as a Director of
Oglethorpe since March 1976, with his present term to expire in March 1999.
He served as Vice Chairman of the Board of Directors of Oglethorpe from March
1990 to March 1993. He is currently a member of the Transmission Committee.
Mr. Jernigan is the Chairman of the Board of Sumter EMC and a Director of
GEMC.
James T. McMillan--Alternate Director, age 46, is President and
Chief Executive Officer of Sumter EMC. He was appointed General Manager of
Sumter EMC in 1984. The General Manager title was changed to President/CEO
in 1994. Prior to that time, he served as Manager of the Staff Services
Department of Sumter EMC, Manager of the Construction and Maintenance
Department of Sumter EMC, and Manager of the Office Services Department of
Sumter EMC. He has served as an Alternate Director of Oglethorpe since 1984,
with his present term to expire in March 1999. Mr. McMillan currently serves
on the Generation Committee.
THREE NOTCH EMC
C. Willard Mims--Director, age 49, is a farmer. He has served on
the Board of Directors since 1991, with his present term to expire in March
1999. Mr. Mims is also a Director of GEMC.
Carlton O. Thomas--Alternate Director, age 48, has been General
Manager of Three Notch EMC since 1990. Prior to that time, he served as
Office Manager of Three Notch EMC. He has served as an Alternate Director of
Oglethorpe since 1990, with his present term to expire in March 1999. He
currently serves on the Transmission Committee. Mr. Thomas is also a
Director of First Federal Savings Bank of Southwest Georgia.
TRI-COUNTY EMC
Thomas Noles--Director, age 54, is a pharmacist. He has served on
the Board of Directors of Oglethorpe since September 1995, with his present
term to expire in March 1999.
Carol Robertson--Alternate Director, age 47, is the General Manager
of Tri-County EMC. She has served as an Alternate Director of Oglethorpe
since July 1988, with her present term to expire in March 1999. Ms. Robertson
currently serves on the Restructuring Advisory Committee.
TROUP EMC
Roy Tollerson, Jr.--Director, age 56, is the owner and operator of
Country Furniture. He has served on the Board of Directors of Oglethorpe
since March 1995, with his present term to expire in March 1998. Mr.
Tollerson is currently a member of the Marketing Committee.
Wayne Livingston--Alternate Director, age 44, has been the
Executive Vice President and General Manager of Troup EMC since August 1987.
Prior to that time, he was General Manager of Ocmulgee EMC. He has served as
an Alternate Director of Oglethorpe since 1978, with his present term to
expire in March 1998. Mr. Livingston currently serves on the Restructuring
Advisory Committee.
60
UPSON COUNTY EMC
Hubert Hancock--Director, age 79, has been President of the Upson
County EMC for the past 34 years. He has served as a Director of Oglethorpe
since September 1974, serving as Vice President from 1975 to 1978, as
President from March 1984 to July 1986, and as Chairman of the Board from
July 1986 to March 1989. His present term as Director expires in March 1998.
Mr. Hancock currently serves on the Executive Committee. Prior to his
involvement with Oglethorpe and Upson County EMC, he was a general farmer as
well as a peach farmer and cattle farmer. Mr. Hancock is also a Director of
West Central Georgia Bank in Thomaston, Georgia, and Chairman of Upson County
Hospital Authority.
John H. Brodnax--Alternate Director, age 48, was appointed General
Manager of Upson County EMC in 1995. Prior to that time he served as Office
Manager of Upson County EMC. Mr. Brodnax has served as Alternate Director of
Oglethorpe since 1995, with his present term to expire in 1998.
WALTON EMC
Hendrix B. Wiley, Jr.--Director, age 51, is a retired dairy farmer
and is currently self-employed in real estate. He has served on the Board of
Directors of Oglethorpe since August 1994, with his present term to expire in
March 1998. He currently serves on the Generation Committee. Mr. Wiley is
also a director of Walton EMC.
D. Ronnie Lee--Alternate Director, age 47, has been General Manager
of Walton EMC since August 1993. Prior to that time, he served as Manager of
Engineering and Operations from January 1979 to August 1993 for Walton EMC.
He has served as an Alternate Director of Oglethorpe since September 1993,
with his present term to expire in March 1998. Mr. Lee currently serves on
the Restructuring Advisory Committee.
WASHINGTON EMC
W. W. Archer--Director, age 64, is a self-employed insurance agent
and cattle farmer. He has served on Oglethorpe's Board of Directors since
September 1987, and his present term expires in March 1998. He is also a
Director of the Bank of Hancock County in Sparta, Georgia.
Robert S. Moore, Sr.--Alternate Director, age 66, has been General
Manager of Washington EMC since April 1982. Prior to that time, he was
Assistant General Manager of Washington EMC. He has served as an Alternate
Director of Oglethorpe since 1982, with his present term to expire in March
1998. He is currently a member of the Marketing Committee.
(B) IDENTIFICATION OF EXECUTIVE OFFICERS AND SENIOR EXECUTIVES:
Oglethorpe is managed and operated under the direction of a President and
Chief Executive Officer, who is appointed by the Board of Directors. The executive officersSenior
Officers and Directors of Oglethorpe and their principal
occupationssignificant employees of subsidiaries
of Oglethorpe are as follows:
NAME AGE POSITION
- ----------------------------------------------------- --- -----------------------------------------------------
J. Calvin Earwood.................................... 56 Chairman of the Board of Directors, Member Director,
Statewide
T. D. Kilgore........................................ 50 President and Chief Executive Officer and Director
Clarence D. Mitchell................................. 44 Senior Vice President, Power Supply
Thomas A. Smith...................................... 43 Senior Financial Officer
Nelson G. Hawk....................................... 48 President and Chief Executive Officer, EnerVision
Larry N. Chadwick.................................... 57 Member Director, Northwest Region
Benny W. Denham...................................... 67 Member Director, Southwest Region and Vice Chairman
Sammy M. Jenkins..................................... 71 Member Director, Southeast Region
Mac F. Oglesby....................................... 65 Member Director, Northeast Region and Treasurer
J. Sam L. Rabun...................................... 66 Member Director, Central Region
Ashley C. Brown...................................... 51 Outside Director
Newton A. Campbell................................... 69 Outside Director
Wm. Ronald Duffey.................................... 56 Outside Director
John S. Ranson....................................... 68 Outside Director
J. Calvin Earwood is the Chairman of the Board age 54,and is the Member Director
elected statewide. Mr. Earwood has served as a
principalan 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 Directoron the Board of Directors of
Oglethorpe
61
since March 1981, with his1981. His present term towill expire in March 1998. He is currently the Chairman of the
Executive Committee and a member of the Human Resources Management Committee.2000. He was previously
a member of the Operations Review Committee. From 1965 through 1982, Mr. Earwood
was a salesman and part owner of Builders Equipment Company. Since January 1983,
he has been the owner and President of Sunbelt Fasteners, Inc., which sells
specialty tools and fasteners to the commercial construction trade. He is also
Vice Chairman of the Board of Directors of both Community Trust Financial
Services and Community Trust Bank in Hiram, Georgia and a Director of GreyStone
Power Corporation.
Benny W. Denham, Vice Chairman ofT. D. Kilgore is the Board, age 65, has served as
a principal executive officer of Oglethorpe since March 1993. He has served
on the Board of Directors of Oglethorpe since December 1988, with
61
his present term to expire in March 1998. He is currently the Vice-Chairman
of the Executive Committee and was previously a member of the Power Planning
and Technical Advisory Committee. Mr. Denham is also a Director of Community
National Bank in Ashland, Georgia and a Director of Irwin EMC.
Gary M. Bullock, Secretary-Treasurer, age 54, has served as
Secretary-Treasurer of Oglethorpe since March 1995. He has served as an
Alternate Director of Oglethorpe since June 1978, with his present term to
expire in March 1999. He is currently a member of the Executive Committee
and the Restructuring Advisory Committee and was previously a member of the
Operations Committee. Mr. Bullock is President and Chief Executive Officer of Carroll EMC. Mr. Bullock is also the Secretary of Southeastern Data
Cooperative, Inc.Oglethorpe and serves on the Boards of Directors of the Georgia
Cooperative Council, the Federated Rural Electric Insurance Corporation, and
the Carrollton Federal Bank, F.S.B. in Carrollton, Georgia.
T. D. Kilgore, President and Chief Executive Officer, age 48,
has served as an executivea senior officer of Oglethorpe since July 1984 (from July 1984 to
July 1986, as Division Manager, Power Supply; July 1986 to July 1991, as Senior
Vice President, Power Supply; and since July 1991, as President and Chief
Executive Officer). Mr. Kilgore servedHe also currently serves as Executive Vice President of GEMC
from December 1991 to June 1992. He has served asthe President and Chief
Executive Officer and as a director of GEMC from June 1992 until October 1995.both GTC and GSOC. Mr. Kilgore has over
20 years of experience in the electric utility industry, including five years in
senior management positions with Arkansas Power & Light Co. and seven years as a
civilian employee with the Department of the Army in positions ranging from
reliability engineering to construction management. Mr. Kilgore has served on
various industry committees including Electric Power Research Institute's Board
of Directors and its Advanced Power Systems Division and Coal System Division
Advisory Committees. He has also served on the Boards of Directors of the U.S.
Committee for Energy Awareness, the Advanced Reactor Corporation, on the Edison
Electric Institute's Power Plant Availability Improvement Task Force and the
Nuclear Power Oversight Committee. Mr. Kilgore currently serves on the Board of
Directors of the Georgia Chamber of Commerce and on the National Rural Electric
Cooperative Association's Power and Generation Committee. Mr. Kilgore has a
BSBachelor of Science degree in mechanical engineeringMechanical Engineering from the University of
Alabama, where he has been recognized as a Distinguished Engineering Fellow, and
an MEa Masters of Engineering degree in industrial engineering from Texas A&M.
The senior executives assisting Mr. Kilgore, their areas of
responsibility and a brief summary of their experience are as follows:
Clarence D. Mitchell is the Senior Vice President, Power Supply and Group Executive, Generation,
age 42, has
served as an executivea senior officer of Oglethorpe since January 1995. Prior to that time,
Mr. Mitchell served as Assistant to the Senior Vice President for Generation
from February 1994 to December 1994; Manager of Corporate Planning from
September 1992 to January 1994; Manager of Construction from January 1992 to
August 1992; Program Director of Technical Services (environmental, survey and
mapping, land acquisition and R&D) from January 1989 to December 1991; and from
April 1981 to December 1988 held various positions in the generation area,
including supervisor, project engineer and generation engineer. Before coming to
Oglethorpe, Mr. Mitchell spent four years as a field engineer with General
Electric Company and worked various installation and maintenance projects
related to coal, nuclear, gas and oil-fired generation. Mr. Mitchell has an MSa
Masters of Science degree in Management from Georgia State University, a
BSBachelor of Science degree in Mechanical Engineering from Georgia Institute of
Technology and a BSBachelor of Science degree in Interdisciplinary Science from
Morehouse College. Mr. Mitchell is presently the Oglethorpe representative on
both the Nuclear Managing Board and the Plant Scherer Managing Board. For(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,2.) Mr. Mitchell also serves as a
Trustee of the Foundation of the Southern Polytechnic State University.
Thomas A. Smith is the Senior Financial Officer and has served as a senior
officer of Oglethorpe since August 1997. He previously served as Vice President,
and Group Executive, Transmission,
age 59, joinedFinance of Oglethorpe in January 1994 after 35 yearsfrom 1986 to 1990, Manager of utility
experience, including 20 years in management positions with Florida Power &
Light Company. Prior to coming to Oglethorpe, he served as Division
Commercial ManagerFinance from April 1973 to August 1983; as District General
Manager from August 1983 to July 1991;1986
and as DirectorManager, Financial Services from 1979 to 1983. From 1990 to 1997, Mr. Smith
was Senior Vice President of Transmission from
July 1991 to September 1993 with Florida Power & Light.the Rural Utility Banking Group of CoBank, where he
managed the bank's eastern division, rural utilities. Mr. SandersSmith is a Certified
Public Accountant, has a Bachelor'sMaster of Science degree in Industrial
EngineeringManagement-Finance from the Georgia Institute of Technology, a Master of Science
degree in Analytical Chemistry from Purdue University and has participateda Bachelor of Arts
degree in Harvard University's postgraduate Program
for Management Development. Mr. SandersMathematics and Chemistry from Catawba College.
Nelson G. Hawk is presently anthe President and Chief Executive Officer of EnerVision, a
wholly owned subsidiary of Oglethorpe representative on the Joint Committee. For information about the Joint
Committee, see "CO-OWNERS OF THE PLANTS AND THE PLANT ANDthat began operations as a marketing
services business in 1998. Prior to that time,
62
TRANSMISSION AGREEMENTS--The Joint Committee Agreement" in Item 1. Mr. Sanders is a member ofHawk was the Board of Trustees of Southern Tech Foundation, Inc.
Nelson G. Hawk,Senior Vice President and Group Executive, Marketing age
46, hasand served
as an executive ata senior officer of Oglethorpe, since February 1994, responsible for Market Planning, Economic
Development, Commercial/Industrial Marketing and Pricing, Commercial/Industrial
Services, and Residential Marketing.Marketing from February 1994 through December 1997.
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 BSBachelor of Science degree in
Electrical Engineering from the Georgia Institute of Technology and an MBAa Master of
Business Administration degree from Florida International University.
W. Clayton Robbins, Senior Vice President and Group Executive,
Support Services, age 49,Larry N. Chadwick is the Member Director from the Northwest Region. He has
been the owner of Chadwick's Hardware in Woodstock, Georgia since 1983. He has
served ason the Board of Directors of Oglethorpe since July 1989. His present term
will expire in March 1999. Mr. Chadwick is an executiveengineer, with experience in the
design of hydrogen gas plants. He is Chairman of the Board of Cobb EMC.
Benny W. Denham is the Vice Chairman of the Board and is the Member Director
from the Southwest Region. He has served on the Board of Directors of Oglethorpe
since December 1991 (from1988. His present term will expire in March 1998. He was
previously the Vice-Chairman of the Executive Committee and a member of the
Power Planning and Technical Advisory Committee. Mr. Denham has been co-owner of
Denham Farms in Turner County, Georgia since 1980. He served on the Turner
County Commission from 1980 to 1990, and was Chairman for six of those years.
Mr. Denham is a Director of Community National Bank in Ashburn, Georgia and a
Director of Irwin EMC.
Sammy M. Jenkins is the Member Director from the Southeast Region. He has
been a self-employed farmer for over 20 years. In addition, from 1973 to 1995,
he was President of Jenkins Ford Tractor Co., Inc., a seller of farm machinery.
He has served on the Board of Directors of Oglethorpe since March 1988. His
present term will expire in March 1999. He was Vice Chairman of the Board of
Oglethorpe from March 1989 to March 1990.
Mac F. Oglesby is the Member Director from the Northeast Region and the
Treasurer of Oglethorpe. He served as Assistant Secretary-Treasurer of the Board
of Directors of Hart EMC from July 1986 through December 19911987, when he was
appointed President of the Board. He has served on the Board of Directors of
Oglethorpe since February 1987. His present term will expire in March 2000. Mr.
Oglesby was a U.S. Postal Service Rural Carrier for 30 years until he retired in
1991.
J. Sam L. Rabun is the Member Director from the Central Region. He has been
the owner and operator of a farm in Jefferson County, Georgia since 1979. He is
also a 50% owner of R&R Livestock Farms, Inc. He has served on the Board of
Directors of Oglethorpe since March 1993. His present term will expire in March
1998. Mr. Rabun served as the President of the Board of Jefferson EMC from 1993
to February1996, was employed as General Manager from 1974 to 1979 and as Office Manager
and Accountant from 1970 to 1974.
Ashley C. Brown is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. His present term will expire in March
1999. He has been Executive Director of the Harvard Electricity Policy Group at
Harvard University's John F. Kennedy School of Government since 1993. In
addition, he is a consultant to the law firm of LeBouef, Lamb, Greene and
MacRae. From April 1983 through April 1993, Mr. Brown served as Commissioner of
the Public Utilities Commission of Ohio. Prior to his appointment to the Ohio
Commission, he was Coordinator and Counsel of the Montgomery County, Ohio, Fair
Housing Center. From 1979 to 1981, he was Managing Attorney for the Legal Aid
Society of
63
Dayton (Ohio), Inc. From 1977 to 1979, he was Legal Advisor of the Miami Valley
Regional Planning Commission in Dayton, Ohio. In addition, Mr. Brown has
extensive teaching experience in public schools and universities and has
published widely in the field of utility regulation. Mr. Brown has a law degree
from the University of Dayton School of Law, a Master of Arts degree from the
University of Cincinnati, and a Bachelor of Science degree from Bowling Green
State University.
Newton A. Campbell is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. His term will expire in March 2000. He
retired in January 1994 as Chairman and Chief Executive Officer of Burns &
McDonnell Engineering Company after serving 41 years with the firm. Mr. Campbell
directed the overall operations of Burns & McDonnell from 1982 until his
retirement. From 1976 through 1982, he served as Vice President Corporate Performance, and General
Manager of the Power Division, and was responsible for directing the company's
work in the planning and design of fossil fueled power generation facilities,
high voltage transmission systems, and other power related facilities. Mr.
Campbell has been involved in feasibility, planning and financial studies for
numerous new and existing public and privately owned electric utilities during
various phases of their organization and development. He also has considerable
experience in conceptual studies, design, and project management for large
electric utility generation, transmission, substation and distribution
facilities throughout the United States. Mr. Campbell received a Master of
Business Administration degree from the University of Missouri at Kansas City
with a concentration in finance. He also holds a Bachelor of Science degree in
Electrical Engineering from the University of Illinois. Mr. Campbell is a
Director of UMB Financial Corporation in Kansas City, Missouri.
Wm. Ronald Duffey is an Outside Director. He has served on the Board of
Directors of Oglethorpe since February 1994,March 1997. His term will expire in March 1998.
Mr. Duffey is the President and Chief Executive Officer and a director of
Peachtree National Bank in Peachtree City, Georgia, a wholly owned subsidiary of
Synovus Financial Corp. Prior to his employment in 1985 with Peachtree National
Bank, Mr. Duffey served as SeniorExecutive Vice President and Group Executive, Support Services). PriorMember of the Board of
Directors for First National Bank in Newnan, Georgia. He holds a Bachelor of
Business Administration from Georgia State College with a concentration in
finance and has completed banking courses at the Banking School of the South,
the American Bankers Association School of Bank Investments, and The Stonier
Graduate School of Banking, Rutgers University.
John S. Ranson is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. His term will expire in March 1999. He
has been the President of Ranson Municipal Consultants, L.L.C. in Wichita,
Kansas since 1994. From 1990 to that time,1994, Mr. Robbins served as
Department Manager, Project Services, from September 1986 to November 1988;
as Program Director, Marketing ResearchRanson was Chairman of Ranson Capital
Corp. an investment banking firm. Mr. Ranson has approximately 40 years
experience in the investment banking business. His public finance clients have
included the Kansas Local Utility Improvement Authority, the Kansas Municipal
Energy Agency, the Kansas Municipal Gas Agency, 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,the Kansas City (Kansas)
Board of Public Utilities. 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 degreeRanson received his Bachelor of Science in
Business Administration from the University of North Carolina at Charlotte.
Eugen Heckl, Senior Vice PresidentKansas (Lawrence, Kansas) and
Chief Financial Officer, age
61, has served as an executive of Oglethorpe since March 1975 (from March
1975 to July 1986, as senior finance and accounting executive; from July 1986
to February 1994 as Senior Vice President, Finance; and since February 1994,
as Senior Vice President and Chief Financial Officer). Mr. Heckl has over 30
years of experience, including ten years as a consultant and auditor to
electric utilities with Arthur Andersen & Co. and two years as
Secretary-Treasurer of Davis Brothers, Inc. Mr. Heckl is a Certified Public
Accountantattended the Navy Supply Corps School in Georgia and has a BS degree in accounting from Samford
University and an MBA degree from Emory University. Mr. Heckl has served as
a Director of the GEMC Federal Credit Union since 1983, and as its Chief
Financial Officer since 1984. Mr. Heckl has elected to retire from
Oglethorpe under the provisions of an early retirement program, effective no
later than September 11, 1996. However, Mr. Heckl may continue to provide
services to Oglethorpe on a contract basis after that date at the discretion
of the President and Chief Executive Officer.
G. Stanley Hill, Senior Vice President, External Affairs, age 60,
has served as an executive of Oglethorpe since October 1975 (from October
1975 to November 1988, as Director of Planning, Director of Power Supply and
Planning, Division Manager, Power Supply and Engineering, Division Manager,
Engineering, Senior Vice President, Planning and System Operations; from
November 1988 to November 1991, as Senior Vice President, Administration;
from November 1991 to February 1994, as Senior Vice President, Marketing and
Customer Service and since February 1994, as Senior Vice President and Staff
Executive, External Affairs). Mr. Hill has approximately 37 years experience
with electric utilities, including four years in the Engineering Department
of the South Carolina Public Service Authority and 11 years as engineer and
senior engineer with Southern Engineering Company of Georgia, a consulting
engineering firm. Mr. Hill is a registered Professional Engineer and a
certified Cogeneration Professional in Georgia and has a BS degree in
electrical engineering from Clemson University and an MBA degree from Georgia
State University. Mr. Hill is presently an Oglethorpe representative on the
Joint Committee. For information about the Joint Committee, see "CO-OWNERS
OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--The Joint Committee
Agreement" in Item 1. Mr. Hill has elected to retire from
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 Chief Executive Officer.Bayonne, New Jersey.
64
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth, for Oglethorpe's President and Chief
Executive Officer and the two other five most highly compensated senior
executives, all compensation paid or accrued for services rendered in all
capacities during the years ended December 31, 1995, 19941997, 1996 and 1993.1995. Amounts
included in the table under "Bonus" represent payments based on an incentive
compensation policy. All amounts paid under this policy are fully at risk each
year and are earned based upon the achievement of corporate goals and each
individual's contribution to achieving those goals. In conjunction with this
policy, base salaries are targeted below the market valuations for similar
positions and remain fairly stable unless the job content changes.
ANNUAL
COMPENSATION
NAME AND --------------------------------------- ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS(2)BONUS (1) COMPENSATION
- ----------------------------------------------------- ---- -------- --------- ----------------------- ------------
T. D. Kilgore 1995 $235,000 $10,000 $6,012(1)Kilgore...................... 1997 $300,368 $ 0 $6,316(2)
President and Chief Executive 1996 265,627 0 6,246
Officer 1994 224,997 0 6,758
1993 211,250 0 7,652
David L. Self1995 235,000 10,000 6,012
Nelson G. Hawk (3)................. 1997 155,210 N/A(4) 5,658(2)
President and Chief Executive 1996 142,535 16,530 5,246
Officer, EnerVision 1995 145,896 13,410 48,024(1)(3)140,000 10,899 4,589
Clarence D. Mitchell............... 1997 155,210 N/A(4) 3,774(2)
Sr. Vice President, and 1994 147,833 10,476 9,117
Group Executive, System Operations 1993 135,000 12,143 8,229
Eugen HecklPower Supply 1996 133,369 17,112 3,887
1995 142,114 13,174 7,651(1)
Sr. Vice President and Chief 1994 142,114 13,919 7,600
Financial Officer 1993 142,114 12,228 7,221
G. Stanley Hill 1995 140,000 11,088 7,204(1)
Sr. Vice President, External Affairs 1994 140,000 10,883 5,619
1993 140,000 12,580 7,001
W. Clayton Robbins 1995 142,310 10,631 4,716(1)
Sr. Vice President and 1994 140,366 11,946 4,986
Group Executive, Support Services 1993 128,000 12,461 4,582
Nelson G. Hawk (4) 1995 140,000 10,899 4,589(1)
Vice President and Group 1994 116,005 9,620 36,972(4)
Executive, Marketing 1993 N/A N/A N/A110,058 7,776 4,251
______________________- ------------------------------
(1) All executives listed above, except Mr. Kilgore, participate in an incentive
compensation program. Mr. Kilgore's compensation is governed solely by the
Board of Directors.
(2) Includes contributions made in 19951997 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. Kilgore, Self, Heckl, Hill,
RobbinsHawk and HawkMitchell of
$4,620, $3,034, $4,351, $3,975, $4,393$4,750, $4,750 and $3,789,$2,856, respectively; and insurance premiums paid on term
life insurance on behalf of Messrs. Kilgore, Self, Heckl, Hill, RobbinsHawk and HawkMitchell of $1,392, $6,641,
$3,300, $3,229, $323$1,566,
$908 and $800,$918, respectively.
(2) Mr. Kilgore is not(3) In connection with Oglethorpe's transfer of its marketing services business
to EnerVision, a participant in the incentive compensation program.
His compensation is governed solely by the Boardwholly owned subsidiary of Directors.
(3) Mr. Self elected to retire from Oglethorpe, under the provisions of an
early retirement program effective December 22, 1995. His 1995 compensation
includes severance benefits of $30,254 and payment of accrued vacation and
sick benefits of $8,095.
(4) Mr. Hawk joinedceased to
be an employee of Oglethorpe as of December 31, 1997. (See "OGLETHORPE POWER
CORPORATION--Corporate Restructuring" in February 1994. Mr. Hawk's 1994
compensation includes a sign-on bonus of $5,000Item 1 for further discussion.)
(4) Bonus amounts earned in 1997 by Messrs. Hawk and relocation costs of
$27,383.
65
Mitchell have not been
determined but are expected to be determined and paid in 1998.
PENSION PLAN TABLE
YEARS OF CREDITED SERVICE
---------------------------------------------------------------------------------
AVERAGE COMPENSATION 5 10 15 20 25
- -------------------- ------- ------- ----------------------------------------------------------------- --------- --------- --------- ---------- ---------
$ 50,000...................................... $12,823 $17,097 $21,371
75,000...................................... 20,323 27,097 33,871
100,000...................................... 27,823 37,097 46,371
125,000...................................... 35,323 47,097 58,871
150,000...................................... 42,823 57,097 71,371
175,000...................................... 50,323 67,097 83,871
200,000...................................... 57,823 77,097 96,371
225,000...................................... 65,323 87,097 108,871
250,000...................................... 72,823 97,097 120,00050,000.................................................. $ 4,179 $ 8,359 $ 12,538 $ 16,718 $ 20,897
75,000.................................................. 6,679 13,359 20,038 26,718 33,397
100,000.................................................. 9,179 18,359 27,538 36,718 45,897
125,000.................................................. 11,679 23,359 35,038 46,718 58,397
150,000.................................................. 14,179 28,359 42,538 56,718 70,897
175,000.................................................. 16,679 33,359 50,038 66,718 83,397
200,000.................................................. 19,179 38,359 57,538 76,718 95,897
225,000.................................................. 21,679 43,359 65,038 86,718 108,397
250,000.................................................. 24,179 48,359 72,538 96,718 120,897
275,000.................................................. 26,679 53,359 80,038 106,718 133,397
65
The preceding table shows estimated annual straight life annuity benefits
payable upon retirement to persons in specified compensation and
years-of-service classifications assuming such persons had attained age 65 and
retired during 1995.1997. For purposes of calculating pension benefits, compensation
is defined as total salary and bonus, as shown in the above Summary Compensation
Table. Because covered compensation changes each year, the estimated pension
benefits for the classifications above will also change in future years. The
above pension benefits are not subject to any deduction for Social Security or
other offset amounts.
As of December 31, 1995,1997, 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.......................................... 10Kilgore......................................................................... 13
Mr. Self............................................. 7Hawk............................................................................ 3
Mr. Heckl............................................ 19
Mr. Hill............................................. 19
Mr. Robbins.......................................... 9
Mr. Hawk............................................. 0.8Mitchell........................................................................ 16
COMPENSATION OF DIRECTORS
Under a policy adopted by the Board of Directors in March 1997, Oglethorpe
pays its Outside Directors a fee of $5,500 per diemBoard meeting for four meetings
in a year; a fee of $1,000 per Board meeting will be paid for the remaining
other Board meetings in a year. Outside Directors are also paid $1,000 per day
for attending committee meetings, annual meetings of the Members or other
official meetings of Oglethorpe. Member Directors are paid a fee of $1,000 per
Board meeting and $300 per day for attending committee meetings, annual meetings
of the Members or other official business of Oglethorpe. In addition, Oglethorpe
reimburses all Directors for out-of-pocket expenses incurred in attending a
meeting. All Directors are paid $50 per day when participating in meetings by
conference call. The Chairman of the Board is paid an additional 20% of his
Director's fee per Board meeting for time involved in preparing for the
meetings.
Prior to March 1997, Oglethorpe paid its Directors a fee of $200 for
meetings attended or $50 for participating in meetings conducted by conference call. Additionally,
Oglethorpe reimburses itscall, and
reimbursed 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 iswas 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.meetings.
EMPLOYMENT CONTRACTS
Effective January 1, 1996, Oglethorpe entered into an employment agreement
with its President and Chief Executive Officer. The term of the
agreement extends to
December 31, 1998, with certain automatic annual
extension provisions beyond that date unless either party gives notice of
termination 60 days prior to an extension.1999. 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 a severance payment equal to
all salary and benefits he would have received between the date of termination
to the end of the agreement. In addition, ifIf 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), asuch severance payment will not 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.
66
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
E. J. Martin, Jr., J. Calvin Earwood, John B. Floyd, Jr.,Newton A. Campbell and J. G.
McCalmon serveSam L. Rabun served as members
of the Oglethorpe Human Resources ManagementPower Corporation Compensation Committee which functions as Oglethorpe's compensation committee. J. Calvinin 1997. Mr. Earwood
has served as an executive officer of Oglethorpe since 1984 and has served as
the Chairman of the Board since 1989.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.T. D. Kilgore is the President and Chief Executive Officer and a Director of
Oglethorpe, GTC and GSOC. Oglethorpe made payments to GSOC for system operations
services in 1997 of approximately $4.9 million, which was 57% of GSOC's revenues
for 1997. Oglethorpe made payments to GTC for point-to-point transmission
service in 1997 of approximately $5.2 million, which was 6% of GTC's total
operating revenues for 1997. (See "OGLETHORPE POWER CORPORATION--Corporate
Restructuring" in Item 1.)
67
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Page
(A) LIST OF DOCUMENTS FILED AS A PART OF THIS REPORT.
(1) FINANCIAL STATEMENTS (Included under "Item 8. Financial
Statements and Supplementary Data")
Statements of Revenues and Expenses, For the Years
Ended December 31, 1995, 1994 and 1993........................ 36
Statements of Patronage Capital, For the Years Ended
December 31, 1995, 1994 and 1993.............................. 36
Balance Sheets, As of December 31, 1995 and 1994............... 37
Statements of Capitalization, As of December 31, 1995
and 1994...................................................... 39
Statements of Cash Flows, For the Years Ended December 31,
1995, 1994 and 1993........................................... 40
Notes to Financial Statements.................................. 41
Report of Management........................................... 51
Reports of Independent Public Accountants...................... 51
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, 1997, 1996 and 1995.................................................... 42
Statements of Patronage Capital, For the Years Ended
December 31, 1997, 1996 and 1995.......................................................... 42
Balance Sheets, As of December 31, 1997 and 1996............................................ 43
Statements of Capitalization, As of December 31, 1997
and 1996.................................................................................. 45
Statements of Cash Flows, For the Years Ended December 31,
1997, 1996 and 1995....................................................................... 46
Notes to Financial Statements............................................................... 47
Report of Management........................................................................ 60
Report of Independent Public Accountants.................................................... 60
(2) FINANCIAL STATEMENT SCHEDULES
None applicable.
(3) EXHIBITS
Exhibits marked with an asterisk (*) are hereby incorporated by reference to
exhibits previously filed by the Registrant as indicated in parentheses
following the description of the exhibit.
NUMBER DESCRIPTION
- ------ -----------
2.1 (1) -- Restructuring Agreement, dated March 29, 1996, by and among
Oglethorpe, Georgia Transmission Corporation (An
Electric Membership Corporation) and Georgia System Operations
Corporation.
*3(i)
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
*2.1 -- Second Amended and Restated Restructuring Agreement, dated February 24, 1997, by and
among Oglethorpe, Georgia Transmission Corporation (An Electric Membership
Corporation) and Georgia System Operations Corporation. (Filed as Exhibit 2.1 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*2.2 -- Member Agreement, dated August 1, 1996, by and among Oglethorpe, Georgia Transmission
Corporation (An Electric Membership Corporation), Georgia System Operations
Corporation and the Members of Oglethorpe. (Filed as Exhibit 2.2 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*3.1(a) -- Restated Articles of Incorporation of Oglethorpe, dated as of July 26, 1988. (Filed as
Exhibit 3.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988,
File No. 33-7591.)
*3.1(b) -- Amendment to Articles of Incorporation of Oglethorpe, dated as of March 11, 1997.
(Filed as Exhibit 3(i)(b) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*3(ii) -- Bylaws of Oglethorpe as amended November 8, 1993. (Filed as
Exhibit 3.2 to the Registrant's Form 10-Q for the quarterly period
ended September 30, 1993, File No. 33-7591.)
*4.1 -- Serial Facility Bond (included in Collateral Trust Indenture
listed as Exhibit 4.2).
68
*4.2 -- Collateral Trust Indenture, dated as of October 15, 1986,
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
*3.2 -- Bylaws of Oglethorpe, as amended on February 24, 1997, and effective as of March 11,
1997. (Filed as Exhibit 3(ii) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*4.1 -- Form of Serial Facility Bond Due June 30, 2011 (included in Collateral Trust Indenture
filed as Exhibit 4.2.)
*4.2 -- Collateral Trust Indenture, dated as of December 1, 1997, between OPC Scherer 1997
Funding Corporation Oglethorpe and Trust
Company Bank, a banking corporation, as Trustee. (Filed as
Exhibit 4.2 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)
*4.3 -- Refunding Lessor Notes. (Filed as Exhibit 4.3.1 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*4.4(a) -- Nonrecourse Promissory Secured Note, due June 30, 2011, from
Wilmington Trust Company and William J. Wade, as Owner Trustees,
to Columbia Bank for Cooperatives. (Filed as Exhibit 4.3.4 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*4.4(b) -- First Amendment to Nonrecourse Promissory Secured Note, dated as
of June 30, 1987, by Wilmington Trust Company and The Citizens and
Southern National Bank, as Owner Trustee under Trust Agreement No.
1 with IBM Credit Financing Corporation, to Columbia Bank for
Cooperatives. (Filed as Exhibit 4.3.4(a) to the Registrant's Form
10-K for the fiscal year ended December 31, 1987, File No.
33-7591.)
*4.5(a) -- Indenture of Trust, Deed to Secure Debt and Security Agreement
No. 2, dated December 30, 1985, between Wilmington Trust Company
and William J. Wade, as Owner Trustees under Trust Agreement No.
2 dated December 30, 1985, with Ford Motor Credit Company and The
First National Bank of Atlanta, as Indenture Trustee, together
with a Schedule identifying three other substantially identical
Indentures of Trust, Deeds to Secure Debt and Security
Agreements. (Filed as Exhibit 4.4(b) to the Registrant's Form
S-1 Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.5(b) -- First Supplemental Indenture of Trust, Deed to Secure Debt and
Security Agreement No. 2 (included as Exhibit A, Oglethorpe and SunTrust Bank, Atlanta, as Trustee. (Filed as
Exhibit 4.2 to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*4.3 -- Nonrecourse Promissory Lessor Note No. 2, with a Schedule identifying three other
substantially identical Nonrecourse Promissory Lessor Notes and any material
differences. (Filed as Exhibit 4.3 to the Registrant's Form S-4 Registration
Statement, File No. 333-42759.)
*4.4 -- Amended and Restated Indenture of Trust, Deed to Secure Debt and Security Agreement
No. 2, dated December 1, 1997, between Wilmington Trust Company and NationsBank, N.A.
collectively as Owner Trustee, under Trust Agreement No. 2, dated December 30, 1985,
with DFO Partnership, as assignee of Ford Motor Credit Company, and The Bank of New
York Trust Company of Florida, N.A. as Indenture Trustee, with a Schedule identifying
three other substantially identical Amended and Restated Indentures of Trust, Deeds to
Secure Debt and Security Agreements and any material differences. (Filed as Exhibit
4.4 to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*4.5(a) -- Lease Agreement No. 2 dated December 30, 1985, between Wilmington Trust Company and
William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Lessor, and Oglethorpe, Lessee, with a Schedule
identifying three other substantially identical Lease Agreements. (Filed as Exhibit
4.5(b) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*4.5(b) -- First Supplement to Lease Agreement No. 2 (included as Exhibit B to the Supplemental
Participation Agreement No. 2 listed as 10.1.1(b)).
*4.5(c) -- First Supplemental Indenture of Trust, Deed to Secure Debt and
Security Agreement No. 1, dated as of June 30, 1987, between
Wilmington Trust Company and The Citizens and Southern National
Bank, collectively as Owner Trustee under Trust Agreement No. 1
with IBM Credit Financing Corporation, and The First National
Bank of Atlanta, as Indenture Trustee. (Filed as Exhibit 4.4(c)
to the Registrant's Form 10-K for the fiscal year ended December
31, 1987, File No. 33-7591.)
*4.6(a) -- Lease Agreement No. 2 dated December 30, 1985, between Wilmington
Trust Company and William J. Wade, as Owner Trustees under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, Lessor, and Oglethorpe, Lessee, with a Schedule
identifying three other substantially identical Lease Agreements.
(Filed as Exhibit 4.5(b) to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.6(b) -- First Supplement To Lease Agreement No. 2 (included as Exhibit B
to the Supplemental Participation Agreement No. 2 listed as
10.1.1(b)).
*4.6(c) -- First Supplement to Lease Agreement No. 1, dated as of June 30, 1987, between The
Citizens and Southern National Bank as Owner Trustee under Trust Agreement No. 1 with
IBM Credit Financing Corporation, as Lessor, and Oglethorpe, as Lessee. (Filed as
Exhibit 4.5(c) to the Registrant's Form 10-K for the fiscal year ended December 31,
1987, File No. 33-7591.)
*4.5(d) -- Second Supplement to Lease Agreement No. 2, dated as of December 17, 1997, between
NationsBank, N.A., acting through its agent, The Bank of New York, as an Owner Trustee
under the Trust Agreement No. 2, dated December 30, 1985, among DFO Partnership, as
assignee of Ford Motor Credit Company, as the Owner Participant, and the Original
Trustee, as Lessor, and Oglethorpe, as Lessee, with a Schedule identifying three other
substantially identical Second Supplements to Lease Agreements and any material
differences. (Filed as Exhibit 4.5(d) to the Registrant's Form S-4 Registration
Statement, File No. 333-42759.)
69
*4.7(a) -- Amended and Consolidated Loan Contract dated as of June 1, 1984
between Oglethorpe and the United States of America, as amended
and supplemented, together with eleven notes executed and
delivered pursuant thereto. (Filed as Exhibit 4.6 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*4.7(b) -- Amendments, dated October 17, 1986, and January 9, 1987, to
Amended and Consolidated Loan Contract dated as of June 1, 1984
between Oglethorpe and the United States of America. (Filed as
Exhibit 4.6(a) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1986, File No. 33-7591.)
*4.7(c) -- Amendment, dated September 30, 1988, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(b) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1988, File No. 33-7591.)
*4.7(d) -- Amendment, dated March 20, 1990, to Amended and Consolidated Loan
Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(c) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1989, File No. 33-7591.)
*4.7(e) -- Amendment, dated July 1, 1991, to Amended and Consolidated Loan
Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(d) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1991, File No. 33-7591.)
*4.7(f) -- Amendment, dated April 6, 1992, to Amended and Consolidated Loan
Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(e) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1992, File No. 33-7591.)
*4.7(g) -- Amendment, dated June 12, 1992, to Amended and Consolidated Loan
Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(f) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1992, File No. 33-7591.)
*4.7(h) -- Amendment, dated October 20, 1992, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(g) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1992, File No. 33-7591.)
*4.7(i) -- Amendment, dated February 25, 1993, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(h) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1992, File No. 33-7591.)
*4.7(j) -- Amendment, dated August 26, 1993, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.7(j) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1993, File No. 33-7591.)
*4.7(k) -- Amendment, dated August 31, 1994, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.7(k) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1994,
NUMBER DESCRIPTION
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*4.6 -- Amended and Consolidated Loan Contract, dated as of March 1, 1997, between Oglethorpe
and the United States of America, together with four notes executed and delivered
pursuant thereto. (Filed as Exhibit 4.7 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*4.7.1(a) -- Indenture, dated as of March 1, 1997, made by Oglethorpe to SunTrust Bank, Atlanta, as
trustee. (Filed as Exhibit 4.8.1 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
*4.7.1(b) -- First Supplemental Indenture, dated as of October 1, 1997, made by Oglethorpe to
SunTrust Bank, Atlanta, as trustee, relating to the Series 1997B (Burke) Note. (Filed
as Exhibit 4.8.1(b) to the Registrant's Form 10-Q for the quarterly period ended
September 30, 1997, File No. 33-7591).
4.7.1(c) -- Second Supplemental Indenture, dated as of January 1, 1998, made by Oglethorpe to
SunTrust Bank, Atlanta, as trustee, relating to the Series 1997C (Burke) Assumption
Agreement.
4.7.1(d) -- Third Supplemental Indenture, dated as of January 1, 1998, made by Oglethorpe to
SunTrust Bank, Atlanta, as trustee, relating to the Series 1997A (Monroe) Assumption
Agreement.
*4.7.2 -- Security Agreement, dated as of March 1, 1997, made by Oglethorpe to SunTrust Bank,
Atlanta, as trustee. (Filed as Exhibit 4.8.2 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.
4.8.1(1) -- Loan Agreement, dated as of October 1, 1992, between Development Authority of Monroe
County and Oglethorpe relating to Development Authority of Monroe County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 1992A,
and six other substantially identical loan agreements.
4.8.2(1) -- Note, dated October 1, 1992, from Oglethorpe to Trust Company Bank, as trustee acting
pursuant to a Trust Indenture, dated as of October 1, 1992, between Development
Authority of Monroe County and Trust Company Bank, and six other substantially
identical notes.
4.8.3(1) -- Trust Indenture, dated as of October 1, 1992, between Development Authority of Monroe
County and Trust Company Bank, Trustee, relating to Development Authority of Monroe
County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project),
Series 1992A, and six other substantially identical trust indentures.
4.9.1(1) -- Loan Agreement, dated as of December 1, 1992, between Development Authority of Burke
County and Oglethorpe relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A, and one other substantially identical loan agreement.
4.9.2(1) -- Note, dated December 1, 1992, from Oglethorpe to Trust Company Bank, as trustee acting
pursuant to a Trust Indenture, dated as of December 1, 1992, between Development
Authority of Burke County and Trust Company Bank, and one other substantially
identical note.
70
*4.8.1(a) -- Mortgage and Security Agreement made by Oglethorpe to United
States of America dated as of January 8, 1975. (Filed as Exhibit
4.12(b) to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*4.8.1(b) -- Supplemental Mortgage made by Oglethorpe to United States of
America dated as of January 6, 1977. (Filed as Exhibit 4.12(a)
to the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.8.2(a) -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America and Trust
Company Bank, as trustee under certain indentures identified
therein, Mortgagees, dated as of November 1, 1978. (Filed as
Exhibit 4.11(c) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*4.8.2(b) -- Confirmation of Execution And Delivery of Notes And First
Amendment to Consolidated Mortgage and Security Agreement, dated
as of January 11, 1979. (Filed as Exhibit 4.11(b) to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*4.8.2(c) -- Supplement and Second Amendment to Consolidated Mortgage and
Security Agreement made by and among Oglethorpe, Mortgagor, and
United States of America and Trust Company Bank, as Trustee,
Mortgagees, dated April 30, 1980. (Filed as Exhibit 4.11(a) to
the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.8.3 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America and Trust
Company Bank, as trustee under certain indentures identified
therein, Mortgagees, dated as of September 15, 1982. (Filed as
Exhibit 4.10 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)
*4.8.4 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, Columbia
Bank for Cooperatives, and Trust Company Bank, as trustee under
certain indentures identified therein, Mortgagees, dated as of
June 1, 1984. (Filed as Exhibit 4.9 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.8.5 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, Columbia
Bank for Cooperatives, and Trust Company Bank, as trustee under
certain indentures identified therein, Mortgagees, dated as of
December 1, 1984. (Filed as Exhibit 4.8 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.8.6(a) -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, Columbia
Bank for Cooperatives, and Trust Company Bank, as trustee under
certain indentures identified therein, Mortgagees, dated as of
October 15, 1985. (Filed as Exhibit 4.7 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.8.6(b) -- First Supplement and Amendment to Consolidated Mortgage and
Security Agreement made by and among Oglethorpe, Mortgagor, and
United States of America, Columbia Bank for Cooperatives, and
Trust Company Bank, as trustee under certain indentures
identified therein, Mortgagees, dated as of November 1, 1988.
(Filed as Exhibit 4.7(a) to the Registrant's Form 10-K for the
fiscal year ended December 31, 1988,
NUMBER DESCRIPTION
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4.9.3(1) -- Trust Indenture, dated as of December 1, 1992, from Development Authority of Burke
County to Trust Company Bank, as trustee, relating to Development Authority of Burke
County Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A, and one other substantially identical trust indenture.
4.9.4(1) -- Interest Rate Swap Agreement, dated as of December 1, 1992, by and between Oglethorpe
and AIG Financial Products Corp. relating to Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1993A, and one other substantially identical agreement.
4.9.5(1) -- Liquidity Guaranty Agreement, dated as of December 1, 1992, by and between Oglethorpe
and AIG Financial Products Corp. relating to Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1993A, and one other substantially identical agreement.
4.9.6(1) -- Standby Bond Purchase Agreement, dated as of December 14, 1995, between Oglethorpe and
Canadian Imperial Bank of Commerce, New York Agency, relating to Development Authority
of Burke County Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1993A.
4.9.7(1) -- Standby Bond Purchase Agreement, dated as of November 30, 1994, between Oglethorpe and
Credit Local de France, Acting through its New York Agency, relating to the
Development Authority of Burke County Adjustable Tender Pollution Control Revenue
Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1994A.
4.10.1(1) -- Loan Agreement, dated as of October 1, 1996, between Development Authority of Burke
County and Oglethorpe relating to Development Authority of Burke County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1996, and
three other substantially identical loan agreements.
4.10.2(1) -- Note, dated October 1, 1996, from Oglethorpe to SunTrust Bank, Atlanta, as trustee
pursuant to an Indenture of Trust, dated as of October 1, 1996, between Development
Authority of Burke County and SunTrust Bank, Atlanta, and three other substantially
identical notes.
4.10.3(1) -- Indenture of Trust, dated as of October 1, 1996, between Development Authority of
Burke County and SunTrust Bank, Atlanta, as trustee, relating to Development Authority
of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1996, and three other substantially identical indentures.
*4.12.1 -- Indemnity Agreement, dated as of March 1, 1997, by and between Oglethorpe and Georgia
Transmission Corporation (An Electric Membership Corporation). (Filed as Exhibit
4.13.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File
No. 33-7591.)
*4.12.2 -- Indemnification Agreement, dated as of March 11, 1997, by Oglethorpe and Georgia
Transmission Corporation (An Electric Membership Corporation) for
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 21, 1990. (Filed as Exhibit
4.19(a) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*4.8.8 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, Credit Suisse, acting by and through its
New York branch, and Trust Company Bank, as trustee under certain
indentures identified therein, Mortgagees, dated as of April 1,
1992. (Filed as Exhibit 4.21 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1992, File No. 33-7591.)
*4.8.9 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, Credit Suisse, acting by and through its
New York branch, and Trust Company Bank, as trustee under certain
indentures identified therein, Mortgagees, dated as of October 1,
1992. (Filed as Exhibit 4.22 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1992, File No. 33-7591.)
*4.8.10 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, Credit Suisse, acting by and through its
New York branch, and Trust Company Bank, as trustee under certain
indentures identified therein, Mortgagees, dated as of December
1, 1992. (Filed as Exhibit 4.23 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1992, File No. 33-7591.)
*4.8.11 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, Credit Suisse, acting by and through its
New York branch, and Trust Company Bank, as trustee under certain
indentures identified therein, Mortgagees, dated as of September
1, 1993. (Filed as Exhibit 4.8.11 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1993, File No. 33-7591.)
*4.8.12 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, Credit Suisse, acting by and through its
New York branch, and Trust Company Bank, as trustee under certain
indentures identified therein, Mortgagees, dated as of September
1, 1994. (Filed as Exhibit 4.8.12 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1994, File No. 33-7591.)
4.9.1 (3) -- Loan Agreement, dated as of October 1, 1992, between Development
Authority of Monroe County and Oglethorpe relating to Development
Authority of Monroe County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Scherer Project), Series 1992A.
4.9.2 (3) -- Note, dated October 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated as
of October 1, 1992, between Development Authority of Monroe
County and Trust Company Bank.
4.9.3 (3) -- Trust Indenture, dated as of October 1, 1992, between Development
Authority of Monroe County and Trust Company Bank, Trustee,
relating to Development Authority of Monroe
72
County Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Scherer Project), Series 1992A.
4.10.1 (2) -- Loan Agreement, dated as of April 1, 1992, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Adjustable Tender Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1992A.
4.10.2 (2) -- Note, dated April 1, 1992, from Oglethorpe to Trust Company Bank,
as trustee acting pursuant to a Trust Indenture, dated as of
April 1, 1992, between Development Authority of Burke County and
Trust Company Bank.
4.10.3 (2) -- Trust Indenture, dated as of April 1, 1992, between Development
Authority of Burke County and Trust Company Bank, as trustee,
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1992A.
4.10.4(a) -- First Amended and Restated Letter of Credit Reimbursement
(2) Agreement, dated as of June 1, 1992, between Credit Suisse and
Oglethorpe relating to an Irrevocable Letter of Credit issued in
connection with the Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe
Power Corporation Vogtle Project), Series 1992A.
4.10.4(b) -- First Amendment to First Amended and Restated Letter of Credit
(2) Reimbursement Agreement, dated September 15, 1993, between
Oglethorpe and Credit Suisse.
4.10.4(c) -- Second Amendment to First Amended and Restated Letter of Credit
(2) Reimbursement Agreement, dated August 1, 1994, between Oglethorpe
and Credit Suisse.
4.10.4(d) -- Third Amendment to First Amended and Restated Letter of Credit
(2) Reimbursement Agreement, dated April 15, 1995, between
Oglethorpe and Credit Suisse.
4.11.1 (4) -- Loan Agreement, dated as of December 1, 1992, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Adjustable Tender Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A.
4.11.2 (4) -- Note, dated December 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated as
of December 1, 1992, between Development Authority of Burke
County and Trust Company Bank.
4.11.3 (4) -- Trust Indenture, dated as of December 1, 1992, from Development
Authority of Burke County to Trust Company Bank, as trustee,
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1993A.
4.11.4 (4) -- Interest Rate Swap Agreement, dated as of December 1, 1992, by
and between Oglethorpe and AIG Financial Products Corp. relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A.
4.11.5 (4) -- Liquidity Guaranty Agreement, dated as of December 1, 1992, by
and between Oglethorpe and AIG Financial Products Corp. relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A.
73
4.11.6 (2) -- Standby Bond Purchase Agreement, dated as of December 14, 1995,
between Oglethorpe and Canadian Imperial Bank of Commerce, New
York Agency, relating to Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe
Power Corporation Vogtle Project), Series 1993A.
4.11.7 (2) -- Standby Bond Purchase Agreement, dated as of November 30, 1994,
between Oglethorpe and Credit Local de France, Acting through its
New York Agency, relating to the Development Authority of Burke
County Adjustable Tender Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1994A.
4.12.1 (4) -- Loan Agreement, dated as of December 1, 1995, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1995.
4.12.2 (4) -- Indenture of Trust, dated as of December 1, 1995, between
Development Authority of Burke County and SunTrust Bank, Atlanta,
as trustee, relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1995.
*4.13.1 -- Loan Agreement, Loan No. T-840901, between Oglethorpe and
Columbia Bank for Cooperatives, dated as of September 14, 1984.
(Filed as Exhibit 4.14.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.13.2 -- Promissory Note, Loan No. T-840901, in the original principal
amount of $8,995,000 from Oglethorpe to Columbia Bank for
Cooperatives, dated as of November 1, 1984. (Filed as Exhibit
4.14.2 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*4.14.1 -- Loan Agreement, Loan No. T-831222, between Oglethorpe and
Columbia Bank for Cooperatives, dated as of December 30, 1983.
(Filed as Exhibit 4.16.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.14.2 -- Promissory Note, Loan No. T-831222, in the original principal
amount of $2,376,000 from Oglethorpe to Columbia Bank for
Cooperatives, dated as of June 1, 1984. (Filed as Exhibit 4.16.2
to the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.15.1 -- Loan Agreement, Loan No. T-830404, between Oglethorpe and
Columbia Bank for Cooperatives, dated as of April 29, 1983.
(Filed as Exhibit 4.18.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.15.2 -- Promissory Note, Loan No. T-830404-1, in the original principal
amount of $9,935,000, from Oglethorpe to Columbia Bank for
Cooperatives, dated as of April 29, 1983. (Filed as Exhibit
4.18.2 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*4.15.3
NUMBER DESCRIPTION
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the benefit of the United States of America. (Filed as Exhibit 4.13.2 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
4.13.1(1) -- Master Loan Agreement, dated as of March 1, 1997, between Oglethorpe and CoBank, ACB,
MLA No. 0459.
4.13.2(1) -- Consolidating Supplement, dated as of March 1, 1997, between Oglethorpe and CoBank,
ACB, relating to Loan No. ML0459T1.
4.13.3(1) -- Promissory Note, dated March 1, 1997, in the original principal amount of
$7,102,740.26, from Oglethorpe to CoBank, ACB, relating to Loan No. ML0459T1.
4.13.4(1) -- Consolidating Supplement, dated as of March 1, 1997, between Oglethorpe and CoBank,
ACB, relating to Loan No. ML0459T2.
4.13.5(1) -- Promissory Note, dated March 1, 1997, in the original principal amount of
$1,856,475.12, made by Oglethorpe to CoBank, ACB, relating to Loan No. ML0459T2.
*4.14.1 -- Loan Agreement, Loan No. T-830404, between Oglethorpe and Columbia Bank for
Cooperatives, dated as of April 29, 1983. (Filed as Exhibit 4.18.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*4.14.2 -- Promissory Note, Loan No. T-830404-1, in the original principal amount of $9,935,000,
from Oglethorpe to Columbia Bank for Cooperatives, dated as of April 29, 1983. (Filed
as Exhibit 4.18.2 to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*4.14.3 -- Security Deed and Security Agreement, dated April 29, 1983, between Oglethorpe and
Columbia Bank for Cooperatives. (Filed as Exhibit 4.18.3 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.1.1(a) -- Participation Agreement No. 2 among Oglethorpe as Lessee,
Wilmington Trust Company as Owner Trustee, The First National
Bank of Atlanta as Indenture Trustee, Columbia Bank for
Cooperatives as Loan Participant and Ford Motor Credit Company as
Owner Participant,
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.)
*4.15 -- Exchange and Registration Rights Agreement, dated December 17, 1997, by and among
Oglethorpe, OPC Scherer 1997 Funding Corporation A, and Goldman, Sachs & Co. as
representative of the purchasers identified therein. (Filed as Exhibit 4.15 to the
Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*10.1.1(a) -- Participation Agreement No. 2 among Oglethorpe as Lessee, Wilmington Trust Company as
Owner Trustee, The First National Bank of Atlanta as Indenture Trustee, Columbia Bank
for Cooperatives as Loan Participant and Ford Motor Credit Company as Owner
Participant, dated December 30, 1985, together with a Schedule identifying three other
substantially identical Participation Agreements. (Filed as Exhibit 10.1.1(b) to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.1(b) -- Supplemental Participation Agreement No. 2. (Filed as Exhibit 10.1.1(a) to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.1(c)-- Supplemental Participation Agreement No. 1, dated as of June 30, 1987, among
Oglethorpe as Lessee, IBM Credit Financing Corporation as Owner Participant,
Wilmington Trust Company and The Citizens and Southern National Bank as Owner Trustee,
The First National Bank of Atlanta, as Indenture Trustee, and
Columbia Bank for Cooperatives, as Loan Participant. (Filed as
Exhibit 10.1.1(c) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1987, File No. 33-7591.)
*10.1.2 -- 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
72
NUMBER DESCRIPTION
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Columbia Bank for Cooperatives, as Loan Participant. (Filed as Exhibit 10.1.1(c) to
the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No.
33-7591.)
*10.1.1(d) -- Second Supplemental Participation Agreement No. 2, dated as of December 17, 1997,
among Oglethorpe as Lessee, DFO Partnership, as assignee of Ford Motor Credit Company,
as Owner Participant, Wilmington Trust Company and NationsBank, N.A. as Owner Trustee,
The Bank of New York Trust Company of Florida, N.A. as Indenture Trustee, CoBank, ACB
as Loan Participant, OPC Scherer Funding Corporation, as Original Funding Corporation,
OPC Scherer 1997 Funding Corporation A, as Funding Corporation, and SunTrust Bank,
Atlanta, as Original Collateral Trust Trustee and Collateral Trust Trustee, with a
Schedule identifying three substantially identical Second Supplemental Participation
Agreements and any material differences. (Filed as Exhibit 10.1.1(d) to Registrant's
Form S-4 Registration Statement, File No. 333-4275.)
*10.1.2 -- General Warranty Deed and Bill of Sale No. 2 between Oglethorpe, Grantor, and
Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement
No. 2, dated December 30, 1985, with Ford Motor Credit Company, Grantee, together with
a Schedule identifying three substantially identical General Warranty Deeds and Bills
of Sale. (Filed as Exhibit 10.1.2 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591.)
*10.1.3(a) -- Supporting Assets Lease No. 2, dated December 30, 1985, between Oglethorpe, Lessor,
and Wilmington Trust Company and William J. Wade, as Owner Trustees, under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Lessee,
together with a Schedule identifying three substantially identical Supporting Assets
Leases. (Filed as Exhibit 10.1.3 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591.)
*10.1.3(b) -- First Amendment to Supporting Assets Lease No. 2, dated as of November 19, 1987,
together with a Schedule identifying three substantially identical First Amendments to
Supporting Assets Leases. (Filed as Exhibit 10.1.3(a) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1987, File No. 33-7591.)
*10.1.4(a) -- Supporting Assets Sublease No. 2, dated December 30, 1985, between Wilmington Trust
Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2 dated
December 30, 1985, with Ford Motor Credit Company, Sublessor, and Oglethorpe,
Sublessee, together with a Schedule identifying three substantially identical
Supporting Assets Subleases. (Filed as Exhibit 10.1.4 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.1.4(b) -- First Amendment to Supporting Assets Sublease No. 2, dated as of November 19, 1987,
together with a Schedule identifying three substantially identical First Amendments to
Supporting Assets Subleases. (Filed as Exhibit 10.1.4(a) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1987, File No. 33-7591.)
*10.1.5(a) -- Tax Indemnification Agreement No. 2, dated December 30, 1985, between Ford Motor
Credit Company, Owner Participant, and Oglethorpe, Lessee, together with a Schedule
identifying three substantially identical Tax Indemnification
73
NUMBER DESCRIPTION
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Agreements. (Filed as Exhibit 10.1.5 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.1.5(b) -- Amendment No. 1 to the Tax Indemnification Agreement No. 2, dated December 17, 1997,
between DFO Partnership, as assignee of Ford Motor Credit Company, as Owner
Participant, and Oglethorpe, as Lessee, with a Schedule identifying three
substantially identical Amendments No. 1 to the Tax Indemnification Agreements and any
material differences. (Filed as Exhibit 10.1.5(b) to the Registrant's Form S-4
Registration Statement, File No. 333-42759.)
*10.1.6 -- Assignment of Interest in Ownership Agreement and Operating Agreement No. 2, dated
December 30, 1985, between Oglethorpe, Assignor, and Wilmington Trust Company and
William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Assignee, together with Schedule identifying
three substantially identical Assignments of Interest in Ownership Agreement and
Operating Agreement. (Filed as Exhibit 10.1.6 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.1.7 -- Consent, Amendment and Assumption No. 2 dated December 30, 1985, among Georgia Power
Company and Oglethorpe and Municipal Electric Authority of Georgia and City of Dalton,
Georgia and Gulf Power Company and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor
Credit Company, together with a Schedule identifying three substantially identical
Consents, Amendments and Assumptions. (Filed as Exhibit 10.1.9 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.1.7(a) -- Amendment to Consent, Amendment and Assumption No. 2, dated as of August 16, 1993,
among Oglethorpe, Georgia Power Company, Municipal Electric Authority of Georgia, City
of Dalton, Georgia, Gulf Power Company, Jacksonville Electric Authority, Florida Power
& Light Company and Wilmington Trust Company and NationsBank of Georgia, N.A., as
Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor
Credit Company, together with a Schedule identifying three substantially identical
Amendments to Consents, Amendments and Assumptions. (Filed as Exhibit 10.1.9(a) to the
Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No.
33-7591.)
*10.2.1 -- Section 168 Agreement and Election dated as of April 7, 1982, between Continental
Telephone Corporation and Oglethorpe. (Filed as Exhibit 10.2 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591.)
*10.2.2 -- Section 168 Agreement and Election dated as of April 9, 1982, between National Service
Industries, Inc. and Oglethorpe. (Filed as Exhibit 10.3 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*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.)
*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.)
74
NUMBER DESCRIPTION
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*10.3.1(a) -- Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation
Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of
Georgia and City of Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit
10.6.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.3.1(b) -- Amendment to Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia, dated as of December 30, 1985.
(Filed as Exhibit 10.1.8 to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.3.1(c) -- Amendment Number Two to the Plant Robert W. Scherer Units Numbers One and Two Purchase
and Ownership Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of July
1, 1986. (Filed as Exhibit 10.6.1(a) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1987, File No. 33-7591.)
*10.3.1(d) -- Amendment Number Three to the Plant Robert W. Scherer Units Numbers One and Two
Purchase and Ownership Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 1, 1988. (Filed as Exhibit 10.6.1(b) to the Registrant's Form 10-Q for
the quarterly period ended September 30, 1993, File No. 33-7591.)
*10.3.1(e) -- Amendment Number Four to the Plant Robert W. Scherer Units Number One and Two Purchase
and Ownership Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of
December 31, 1990. (Filed as Exhibit 10.6.1(c) to the Registrant's Form 10-Q for the
quarterly period ended September 30, 1993, File No. 33-7591.)
*10.3.2(a) -- Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia
Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton,
Georgia, dated as of May 15, 1980. (Filed as Exhibit 10.6.2 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591.)
*10.3.2(b) -- Amendment to Plant Robert W. Scherer Units Numbers One and Two Operating Agreement
among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and
City of Dalton, Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.7 to
the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
75
NUMBER DESCRIPTION
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*10.3.2(c) -- Amendment Number Two to the Plant Robert W. Scherer Units Numbers One and Two
Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia, dated as of December 31, 1990.
(Filed as Exhibit 10.6.2(a) to the Registrant's Form 10-Q for the quarterly period
ended September 30, 1993, File No. 33-7591.)
*10.3.3 -- Plant Scherer Managing Board Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia, City of Dalton, Georgia, Gulf Power Company,
Florida Power & Light Company and Jacksonville Electric Authority, dated as of
December 31, 1990. (Filed as Exhibit 10.6.3 to the Registrant's Form 10-Q for the
quarterly period ended September 30, 1993, File No. 33-7591.)
*10.4.1(a) -- Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation
Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of
Georgia and City of Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit
10.7.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.4.1(b) -- Amendment Number One, dated January 18, 1977, to the Alvin W. Vogtle Nuclear Units
Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton,
Georgia. (Filed as Exhibit 10.7.3 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1986, File No. 33-7591.)
*10.4.1(c) -- Amendment Number Two, dated February 24, 1977, to the Alvin W. Vogtle Nuclear Units
Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton,
Georgia. (Filed as Exhibit 10.7.4 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1986, File No. 33-7591.)
*10.4.2 -- Alvin W. Vogtle Nuclear Units Numbers One and Two Operating Agreement among Georgia
Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton,
Georgia, dated as of August 27, 1976. (Filed as Exhibit 10.7.2 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.5.1 -- Plant Hal Wansley Purchase and Ownership Participation Agreement between Georgia Power
Company and Oglethorpe, dated as of March 26, 1976. (Filed as Exhibit 10.8.1 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.5.2(a) -- Plant Hal Wansley Operating Agreement between Georgia Power Company and Oglethorpe,
dated as of March 26, 1976. (Filed as Exhibit 10.8.2 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.5.2(b) -- Amendment, dated as of January 15, 1995, to the Plant Hal Wansley Operating Agreements
by and among Georgia Power Company, Oglethorpe, Municipal Electric Authority of
Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.5.2(a) to the Registrant's
Form 10-Q for the quarterly period ended September 30, 1996, File No. 33-7591.)
*10.5.3 -- Plant Hal Wansley Combustion Turbine Agreement between Georgia Power Company and
Oglethorpe, dated as of August 2, 1982 and Amendment No. 1, dated October 20, 1982.
(Filed as Exhibit 10.18 to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
76
NUMBER DESCRIPTION
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*10.6.1 -- Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement between
Georgia Power Company and Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit
10.9.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.6.2 -- Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia Power Company and
Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit 10.9.2 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.7.1 -- Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement,
dated as of November 18, 1988, by and between Oglethorpe and Georgia Power Company.
(Filed as Exhibit 10.22.1 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1988, File No. 33-7591.)
*10.7.2 -- Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement, dated as of
November 18, 1988, by and between Oglethorpe and Georgia Power Company. (Filed as
Exhibit 10.22.2 to the Registrant's Form 10-K for the fiscal year ended December 31,
1988, File No. 33-7591.)
*10.8.1 -- Amended and Restated Wholesale Power Contract, dated as of August 1, 1996, between
Oglethorpe and Altamaha Electric Membership Corporation and all schedules thereto,
together with a Schedule identifying 37 other substantially identical Amended and
Restated Wholesale Power Contracts, and an additional Amended and Restated Wholesale
Power Contract that is not substantially identical. (Filed as Exhibit 10.8.1 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.2 -- Amended and Restated Supplemental Agreement, dated as of August 1, 1996, by and
between Oglethorpe, Altamaha Electric Membership Corporation and the United States of
America, together with a Schedule identifying 38 other substantially identical Amended
and Restated Supplemental Agreements. (Filed as Exhibit 10.8.2 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.3 -- Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as
of January 1, 1997, by and among Georgia Power Company, Oglethorpe and Altamaha
Electric Membership Corporation, together with a Schedule identifying 38 other
substantially identical Supplemental Agreements. (Filed as Exhibit 10.8.3 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.4 -- Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as
of March 1, 1997, by and between Oglethorpe and Altamaha Electric Membership
Corporation, together with a Schedule identifying 36 other substantially identical
Supplemental Agreements, and an additional Supplemental Agreement that is not
substantially identical. (Filed as Exhibit 10.8.4 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.5 -- Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as
of March 1, 1997, by and between Oglethorpe and Coweta-Fayette Electric Membership
Corporation, together with a Schedule identifying 1 other substantially identical
Supplemental Agreement. (Filed as Exhibit 10.8.5 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
77
NUMBER DESCRIPTION
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*10.8.6 -- Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as
of May 1, 1997 by and between Oglethorpe and Altamaha Electric Membership Corporation,
together with a Schedule identifying 38 other substantially identical Supplemental
Agreements. (Filed as Exhibit 10.8.6 to the Registrant's Form 10-Q for the quarterly
period ended June 30, 1997, File No. 33-7591.)
*10.9(a) -- Joint Committee Agreement among Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and the City of Dalton, Georgia, dated as of August 27, 1976.
(Filed as Exhibit 10.14(b) to the Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.9(b) -- First Amendment to Joint Committee Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and the City of Dalton, Georgia, dated as of
June 19, 1978. (Filed as Exhibit 10.14(a) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.10 -- Letter of Commitment (Firm Power Sale) Under Service Schedule J-- Negotiated
Interchange Service between Alabama Electric Cooperative, Inc. and Oglethorpe, dated
March 31, 1994. (Filed as Exhibit 10.11(b) to the Registrant's Form 10-Q for the
quarter ended June 30, 1994, File No. 33-7591.)
*10.11.1 -- Assignment of Power System Agreement and Settlement Agreement, dated January 8, 1975,
by Georgia Electric Membership Corporation to Oglethorpe. (Filed as Exhibit 10.20.1 to
the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.11.2 -- Power System Agreement, dated April 24, 1974, by and between Georgia Electric
Membership Corporation and Georgia Power Company. (Filed as Exhibit 10.20.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.11.3 -- Settlement Agreement, dated April 24, 1974, by and between Georgia Power Company,
Georgia Municipal Association, Inc., City of Dalton, Georgia Electric Membership
Corporation and Crisp County Power Commission. (Filed as Exhibit 10.20.3 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.12 -- Long-Term Firm Power Purchase Agreement between Big Rivers Electric Corporation and
Oglethorpe, dated as of December 17, 1990. (Filed as Exhibit 10.24.3 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1990, File No. 33-7591.)
*10.13 -- 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.)
10.14 -- Revised and Restated Coordination Services Agreement between and among Georgia Power
Company, Oglethorpe and Georgia System Operations Corporation, dated as of September
10, 1997.
*10.15 -- 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.)
*10.16 -- 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.)
78
NUMBER DESCRIPTION
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*10.17 -- 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.)
*10.18 -- 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.)
*10.19 -- 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).
*10.20(3) -- Employment Agreement between Oglethorpe and T. D. Kilgore, dated as of December 20,
1995. (Filed as Exhibit 10.28 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1995, File No. 33-7591.)
*10.21(2) -- Power Purchase and Sale Agreement among LG&E Power Marketing Inc., LG&E Energy Corp.
and Oglethorpe, dated as of November 19, 1996. (Filed as Exhibit 10.30 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.22(2) -- Power Purchase and Sale Agreement among LG&E Power Marketing Inc., LG&E Power Inc. and
Oglethorpe, dated as of January 1, 1997. (Filed as Exhibit 10.31 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.1 -- Participation Agreement (P1), dated as of December 30, 1996, among Oglethorpe, Rocky
Mountain Leasing Corporation, Fleet National Bank, as Owner Trustee, SunTrust Bank,
Atlanta, as Co-Trustee, the Owner Participant named therein and Utrecht-America
Finance Co., as Lender, together with a Schedule identifying five other substantially
identical Participation Agreements. (Filed as Exhibit 10.32.1 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.2 -- Rocky Mountain Head Lease Agreement (P1), dated as of December 30, 1996, between
Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Rocky Mountain Head Lease Agreements.
(Filed as Exhibit 10.32.2 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.23.3 -- Ground Lease Agreement (P1), dated as of December 30, 1996, between Oglethorpe and
SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other
substantially identical Ground Lease Agreements. (Filed as Exhibit 10.32.3 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.4 -- Rocky Mountain Agreements Assignment and Assumption Agreement (P1), dated as of
December 30, 1996, between Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other substantially identical Rocky Mountain
Agreements Assignment and Assumption Agreements. (Filed as Exhibit 10.32.4 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
79
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
*10.23.5 -- Facility Lease Agreement (P1), dated as of December 30, 1996, between SunTrust Bank,
Atlanta, as Co-Trustee and Rocky Mountain Leasing Corporation, together with a
Schedule identifying five other substantially identical Facility Lease Agreements.
(Filed as Exhibit 10.32.5 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.23.6 -- Ground Sublease Agreement (P1), dated as of December 30, 1996, between SunTrust Bank,
Atlanta, as Co-Trustee and Rocky Mountain Leasing Corporation, together with a
Schedule identifying five other substantially identical Ground Sublease Agreements.
(Filed as Exhibit 10.32.6 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.23.7 -- Rocky Mountain Agreements Re-assignment and Assumption Agreement (P1), dated as of
December 30, 1996, between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain
Leasing Corporation, together with a Schedule identifying five other substantially
identical Rocky Mountain Agreements Re-assignment and Assumption Agreements. (Filed as
Exhibit 10.32.7 to the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.23.8 -- Facility Sublease Agreement (P1), dated as of December 30, 1996, between Oglethorpe
and Rocky Mountain Leasing Corporation, together with a Schedule identifying five
other substantially identical Facility Sublease Agreements. (Filed as Exhibit 10.32.8
to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.23.9 -- Ground Sub-sublease Agreement (P1), dated as of December 30, 1996, between Rocky
Mountain Leasing Corporation and Oglethorpe, together with a Schedule identifying five
other substantially identical Ground Sub-sublease Agreements. (Filed as Exhibit
10.32.9 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
*10.23.10 -- Rocky Mountain Agreements Second Re-assignment and Assumption Agreement (P1), dated as
of December 30, 1996, between Rocky Mountain Leasing Corporation and Oglethorpe,
together with a Schedule identifying five other substantially identical Rocky Mountain
Agreements Second Re-assignment and Assumption Agreements. (Filed as Exhibit 10.32.10
to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.23.11 -- Payment Undertaking Agreement (P1), dated as of December 30, 1996, between Rocky
Mountain Leasing Corporation and Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A.,
New York Branch, as the Bank, together with a Schedule identifying five other
substantially identical Payment Undertaking Agreements. (Filed as Exhibit 10.32.11 to
the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.23.12 -- Payment Undertaking Pledge Agreement (P1), dated as of December 30, 1996, between
Rocky Mountain Leasing Corporation, Fleet National Bank, as Owner Trustee, and
SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other
substantially identical Payment Undertaking Pledge Agreements. (Filed as Exhibit
10.32.12 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
80
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
*10.23.13 -- Equity Funding Agreement (P1), dated as of December 30, 1996, between Rocky Mountain
Leasing Corporation, AIG Match Funding Corp., the Owner Participant named therein,
Fleet National Bank, as Owner Trustee, and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other substantially identical Equity Funding
Agreements. (Filed as Exhibit 10.32.13 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.23.14 -- Equity Funding Pledge Agreement (P1), dated as of December 30, 1996, between Rocky
Mountain Leasing Corporation and SunTrust Bank, Atlanta, as Co-Trustee, together with
a Schedule identifying five other substantially identical Equity Funding Pledge
Agreements. (Filed as Exhibit 10.32.14 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.23.15 -- Deed to Secure Debt, Assignment of Surety Bond and Security Agreement (P1), dated as
of December 30, 1996, between Rocky Mountain Leasing Corporation, SunTrust Bank,
Atlanta, as Co-Trustee, together with a Schedule identifying five other substantially
identical Collateral Assignment, Assignment of Surety Bond and Security Agreements.
(Filed as Exhibit 10.32.15 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.23.16 -- Subordinated Deed to Secure Debt and Security Agreement (P1), dated as of December 30,
1996, among Oglethorpe, AMBAC Indemnity Corporation and SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other substantially identical
Subordinated Deed to Secure Debt and Security Agreements. (Filed as Exhibit 10.32.16
to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.23.17 -- Tax Indemnification Agreement (P1), dated as of December 30, 1996, between Oglethorpe
and the Owner Participant named therein, together with a Schedule identifying five
other substantially identical Tax Indemnification Agreements. (Filed as Exhibit
10.32.17 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
*10.23.18 -- Consent No. 1, dated as of December 30, 1996, among Georgia Power Company, Oglethorpe,
SunTrust Bank, Atlanta, as Co-Trustee, and Fleet National Bank, as Owner Trustee,
together with a Schedule identifying five other substantially identical Consents.
(Filed as Exhibit 10.32.18 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.23.19(a) -- OPC Intercreditor and Security Agreement No. 1, dated as of December 30, 1996, among
the United States of America, acting through the Administrator of the Rural Utilities
Service, SunTrust Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing Corporation,
SunTrust Bank, Atlanta, as Co-Trustee, Fleet National Bank, as Owner Trustee,
Utrecht-America Finance Co., as Lender and AMBAC Indemnity Corporation, together with
a Schedule identifying five other substantially identical Intercreditor and Security
Agreements. (Filed as Exhibit 10.32.19 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
81
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
*10.23.19(b) -- Supplement to OPC Intercreditor and Security Agreement No. 1, dated as of March 1,
1997, among the United States of America, acting through the Administrator of the
Rural Utilities Service, SunTrust Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing
Corporation, SunTrust Bank, Atlanta, as Co-Trustee, Fleet National Bank, as Owner
Trustee, Utrecht-America Finance Co., as Lender and AMBAC Indemnity Corporation,
together with a Schedule identifying five other substantially identical Supplements to
OPC Intercreditor and Security Agreements. (Filed as Exhibit 10.32.19(b) to the
Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*10.24.1 -- Member Transmission Service Agreement, dated as of March 1, 1997, by and between
Oglethorpe and Georgia Transmission Corporation (An Electric Membership Corporation).
(Filed as Exhibit 10.33.1 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.24.2 -- Generation Services Agreement, dated as of March 1, 1997, by and between Oglethorpe
and Georgia System Operations Corporation. (Filed as Exhibit 10.33.2 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.24.3 -- Operation Services Agreement, dated as of March 1, 1997, by and between Oglethorpe and
Georgia System Operations Corporation. (Filed as Exhibit 10.33.3 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.25(2) -- Power Purchase and Sale Agreement between Morgan Stanley Capital Group Inc. and
Oglethorpe, dated as of April 7, 1997. (Filed as Exhibit 10.34 to the Registrant's
Form 10-Q for the quarterly period ended March 30, 1997, File No. 33-7591.)
21.1 -- Rocky Mountain Leasing Corporation, a Delaware corporation.
27.1 -- Financial Data Schedule (for SEC use only).
- ------------------------
(1) Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this document(s) is not filed
herewith; however the registrant hereby agrees that such document(s) will be
provided to the Registrant'sCommission upon request.
(2) Certain portions of this document have been omitted as confidential and
filed separately with the Commission.
(3) Indicates a management contract or compensatory arrangement required to be
filed as an exhibit to this Report.
(B) REPORTS ON FORM 8-K.
No reports on Form S-1 Registration
Statement, File No. 33-7591,8-K were filed on October 9, 1986.)
*10.1.6 -- Assignment of Interest in Ownership Agreement and Operating
Agreement No. 2, datedby Oglethorpe for the quarter ended
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,
7531, 1997.
82
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 10.1.6SIGNATURES
Pursuant to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filedrequirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed 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
Authorityits behalf by the undersigned, thereunto duly authorized, on the 11th day of
Georgia and City of Dalton, Georgia and Gulf Power
Company and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, together with a Schedule
identifying three substantially identical Consents, Amendments
and Assumptions. (Filed as Exhibit 10.1.9March, 1998.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
By: /s/ J. CALVIN EARWOOD
-----------------------------------------
J. CALVIN EARWOOD
Chairman of the Board
Pursuant to the Registrant's
Form S-1 Registration Statement, File No. 33-7591,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,
- ------------------------------ Director (Principal March 11, 1998
J. CALVIN EARWOOD Executive Officer)
President and Chief
/s/ T. D. KILGORE Executive Officer
- ------------------------------ (Principal Executive March 11, 1998
T. D. KILGORE Officer)
/s/ MAC F. OGLESBY Treasurer, Director
- ------------------------------ (Principal Financial March 11, 1998
MAC F. OGLESBY Officer)
/s/ THOMAS A. SMITH Senior Financial Officer
- ------------------------------ (Principal Financial March 11, 1998
THOMAS A. SMITH Officer)
/s/ ROBERT D. STEELE
- ------------------------------ Controller March 11, 1998
ROBERT D. STEELE
/s/ ASHLEY C. BROWN
- ------------------------------ Director March 11, 1998
ASHLEY C. BROWN
/s/ NEWTON A. CAMPBELL
- ------------------------------ Director March 11, 1998
NEWTON A. CAMPBELL
83
SIGNATURE TITLE DATE
- ------------------------------ -------------------------- -------------------
/s/ LARRY N. CHADWICK
- ------------------------------ Director March 11, 1998
LARRY N. CHADWICK
/s/ BENNY W. DENHAM
- ------------------------------ Director March 11, 1998
BENNY W. DENHAM
/s/ WM. RONALD DUFFEY
- ------------------------------ Director March 11, 1998
WM. RONALD DUFFEY
/s/ SAMMY M. JENKINS
- ------------------------------ Director March 11, 1998
SAMMY M. JENKINS
/s/ J. SAM L. RABUN
- ------------------------------ Director March 11, 1998
J. SAM L. RABUN
/s/ JOHN S. RANSON
- ------------------------------ Director March 11, 1998
JOHN S. RANSON
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.
85
EXHIBIT INDEX
Exhibits marked with an asterisk (*) are hereby incorporated by reference to
exhibits previously filed by the Registrant as indicated in parentheses
following the description of the exhibit.
NUMBER DESCRIPTION
- -------------- -------------------------------------------------------------------------------------------------
*2.1 -- Second Amended and Restated Restructuring Agreement, dated February 24, 1997, by and among
Oglethorpe, Georgia Transmission Corporation (An Electric Membership Corporation) and Georgia
System Operations Corporation. (Filed as Exhibit 2.1 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*2.2 -- Member Agreement, dated August 1, 1996, by and among Oglethorpe,
*3.1(a) -- Restated Articles of Incorporation of Oglethorpe, dated as of July 26, 1988. (Filed as Exhibit
3.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.)
*3.1(b) -- Amendment to Articles of Incorporation of Oglethorpe, dated as of March 11, 1997. (Filed as
Exhibit 3(i)(b) to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File
No. 33-7591.)
*3.2 -- Bylaws of Oglethorpe, as amended on February 24, 1997, and effective as of March 11, 1997. (Filed
as Exhibit 3(ii) to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File
No. 33-7591.)
*4.1 -- Form of Serial Facility Bond Due June 30, 2011 (included in Collateral Trust Indenture filed as
Exhibit 4.2.)
*4.2 -- Collateral Trust Indenture, dated as of December 1, 1997, between OPC Scherer 1997 Funding
Corporation A, Oglethorpe and SunTrust Bank, Atlanta, as Trustee. (Filed as Exhibit 4.2 to the
Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*4.3 -- Nonrecourse Promissory Lessor Note No. 2, with a Schedule identifying three other substantially
identical Nonrecourse Promissory Lessor Notes and any material differences. (Filed as Exhibit 4.3
to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*4.4 -- Amended and Restated Indenture of Trust, Deed to Secure Debt and Security Agreement No. 2, dated
December 1, 1997, between Wilmington Trust Company and NationsBank, N.A. collectively as Owner
Trustee, under Trust Agreement No. 2, dated December 30, 1985, with DFO Partnership, as assignee
of Ford Motor Credit Company, and The Bank of New York Trust Company of Florida, N.A. as
Indenture Trustee, with a Schedule identifying three other substantially identical Amended and
Restated Indentures of Trust, Deeds to Secure Debt and Security Agreements and any material
differences. (Filed as Exhibit 4.4 to the Registrant's Form S-4 Registration Statement, File No.
333-42759.)
*4.5(a) -- Lease Agreement No. 2 dated December 30, 1985, between Wilmington Trust Company and William J.
Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor
Credit Company, Lessor, and Oglethorpe, Lessee, with a Schedule identifying three other
substantially identical Lease Agreements. (Filed as Exhibit 4.5(b) to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*4.5(b) -- First Supplement to Lease Agreement No. 2 (included as Exhibit B to the Supplemental
Participation Agreement No. 2 listed as 10.1.1(b)).
*4.5(c) -- First Supplement to Lease Agreement No. 1, dated as of June 30, 1987, between The Citizens and
Southern National Bank as Owner Trustee under Trust Agreement No. 1 with IBM Credit Financing
Corporation, as Lessor, and Oglethorpe, as Lessee. (Filed as Exhibit 4.5(c) to the Registrant's
Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.)
*4.5(d) -- Second Supplement to Lease Agreement No. 2, dated as of December 17, 1997, between NationsBank,
N.A., acting through its agent, The Bank of New York, as an Owner Trustee under the Trust
Agreement No. 2, dated December 30, 1985, among DFO Partnership, as assignee of Ford Motor Credit
Company, as the Owner Participant, and the Original Trustee, as Lessor, and Oglethorpe, as
Lessee, with a Schedule identifying three other substantially identical Second Supplements to
Lease Agreements and any material differences. (Filed as Exhibit 4.5(d) to the Registrant's Form
S-4 Registration Statement, File No. 333-42759.)
*4.6 -- Amended and Consolidated Loan Contract, dated as of March 1, 1997, between Oglethorpe and the
United States of America, together with four notes executed and delivered pursuant thereto.
(Filed as Exhibit 4.7 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
*4.7.1(a) -- Indenture, dated as of March 1, 1997, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee.
(Filed as Exhibit 4.8.1 to the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*4.7.1(b) -- First Supplemental Indenture, dated as of October 1, 1997, made by Oglethorpe to SunTrust Bank,
Atlanta, as trustee, relating to the Series 1997B (Burke) Note. (Filed as Exhibit 4.8.1(b) to the
Registrant's Form 10-Q for the quarterly period ended September 30, 1997, File No. 33-7591).
4.7.1(c) -- Second Supplemental Indenture, dated as of January 1, 1998, made by Oglethorpe to SunTrust Bank,
Atlanta, as trustee, relating to the Series 1997C (Burke) Assumption Agreement.
4.7.1(d) -- Third Supplemental Indenture, dated as of January 1, 1998, made by Oglethorpe to SunTrust Bank,
Atlanta, as trustee, relating to the Series 1997A (Monroe) Assumption Agreement.
*4.7.2 -- Security Agreement, dated as of March 1, 1997, made by Oglethorpe to SunTrust Bank, Atlanta, as
trustee. (Filed as Exhibit 4.8.2 to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
4.8.1(1) -- Loan Agreement, dated as of October 1, 1992, between Development Authority of Monroe County and
Oglethorpe relating to Development Authority of Monroe County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Scherer Project), Series 1992A, and six other substantially
identical loan agreements.
2
4.8.2(1) -- Note, dated October 1, 1992, from Oglethorpe to Trust Company Bank, as trustee acting pursuant to
a Trust Indenture, dated as of October 1, 1992, between Development Authority of Monroe County
and Trust Company Bank, and six other substantially identical notes.
4.8.3(1) -- Trust Indenture, dated as of October 1, 1992, between Development Authority of Monroe County and
Trust Company Bank, Trustee, relating to Development Authority of Monroe County Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 1992A, and six other
substantially identical trust indentures.
4.9.1(1) -- Loan Agreement, dated as of December 1, 1992, between Development Authority of Burke County and
Oglethorpe relating to Development Authority of Burke County Adjustable Tender Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and one other
substantially identical loan agreement.
4.9.2(1) -- Note, dated December 1, 1992, from Oglethorpe to Trust Company Bank, as trustee acting pursuant
to a Trust Indenture, dated as of December 1, 1992, between Development Authority of Burke County
and Trust Company Bank, and one other substantially identical note.
4.9.3(1) -- Trust Indenture, dated as of December 1, 1992, from Development Authority of Burke County to
Trust Company Bank, as trustee, relating to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A , and
one other substantially identical trustindenture.
4.9.4(1) -- Interest Rate Swap Agreement, dated as of December 1, 1992, by and between Oglethorpe and AIG
Financial Products Corp. relating to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and
one other substantially identical agreement.
4.9.5(1) -- Liquidity Guaranty Agreement, dated as of December 1, 1992, by and between Oglethorpe and AIG
Financial Products Corp. relating to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and
one other substantially identical agreement.
4.9.6(1) -- Standby Bond Purchase Agreement, dated as of December 14, 1995, between Oglethorpe and Canadian
Imperial Bank of Commerce, New York Agency, relating to Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A.
4.9.7(1) -- Standby Bond Purchase Agreement, dated as of November 30, 1994, between Oglethorpe and Credit
Local de France, Acting through its New York Agency, relating to the Development Authority of
Burke County Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1994A.
4.10.1(1) -- Loan Agreement, dated as of October 1, 1996, between Development Authority of Burke County and
Oglethorpe relating to Development Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1996, and three other substantially
identical loan agreements.
3
4.10.2(1) -- Note, dated October 1, 1996, from Oglethorpe to SunTrust Bank, Atlanta, as trustee pursuant to an
Indenture of Trust, dated as of October 1, 1996, between Development Authority of Burke County
and SunTrust Bank, Atlanta, and three other substantially identical notes.
4.10.3(1) -- Indenture of Trust, dated as of October 1, 1996, between Development Authority of Burke County
and SunTrust Bank, Atlanta, as trustee, relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1996, and
three other substantially identical indentures.
*4.12.1 -- Indemnity Agreement, dated as of March 1, 1997, by and between Oglethorpe and Georgia
Transmission Corporation (An Electric Membership Corporation). (Filed as Exhibit 4.13.1 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*4.12.2 -- Indemnification Agreement, dated as of March 11, 1997, by Oglethorpe and Georgia Transmission
Corporation (An Electric Membership Corporation) for the benefit of the United States of America.
(Filed as Exhibit 4.13.2 to the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
4.13.1(1) -- Master Loan Agreement, dated as of March 1, 1997, between Oglethorpe and CoBank, ACB, MLA
No. 0459.
4.13.2(1) -- Consolidating Supplement, dated as of March 1, 1997, between Oglethorpe and CoBank, ACB, relating
to Loan No. ML0459T1.
4.13.3(1) -- Promissory Note, dated March 1, 1997, in the original principal amount of $7,102,740.26, from
Oglethorpe to CoBank, ACB, relating to Loan No. ML0459T1.
4.13.4(1) -- Consolidating Supplement, dated as of March 1, 1997, between Oglethorpe and CoBank, ACB, relating
to Loan No. ML0459T2.
4.13.5(1) -- Promissory Note, dated March 1, 1997, in the original principal amount of $1,856,475.12, made by
Oglethorpe to CoBank, ACB, relating to Loan No. ML0459T2.
*4.14.1 -- Loan Agreement, Loan No. T-830404, between Oglethorpe and Columbia Bank for Cooperatives, dated
as of April 29, 1983. (Filed as Exhibit 4.18.1 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*4.14.2 -- Promissory Note, Loan No. T-830404-1, in the original principal amount of $9,935,000, from
Oglethorpe to Columbia Bank for Cooperatives, dated as of April 29, 1983. (Filed as Exhibit
4.18.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*4.14.3 -- Security Deed and Security Agreement, dated April 29, 1983, between Oglethorpe and Columbia Bank
for Cooperatives. (Filed as Exhibit 4.18.3 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)
*4.15 -- Exchange and Registration Rights Agreement, dated December 17, 1997, by and among Oglethorpe, OPC
Scherer 1997 Funding Corporation A, and Goldman, Sachs & Co. as representative of the purchasers
identified therein. (Filed as Exhibit 4.15 to the Registrant's Form S-4 Registration Statement,
File No. 333-42759.)
4
*10.1.1(a) -- Participation Agreement No. 2 among Oglethorpe as Lessee, Wilmington Trust Company as Owner
Trustee, The First National Bank of Atlanta as Indenture Trustee, Columbia Bank for Cooperatives
as Loan Participant and Ford Motor Credit Company as Owner Participant, dated December 30, 1985,
together with a Schedule identifying three other substantially identical Participation
Agreements. (Filed as Exhibit 10.1.1(b) to the Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.1.1(b) -- Supplemental Participation Agreement No. 2. (Filed as Exhibit 10.1.1(a) to the Registrant's Form
S-1 Registration Statement, File No. 33-7591.)
*10.1.1(c) -- Supplemental Participation Agreement No. 1, dated as of June 30, 1987, among Oglethorpe as
Lessee, IBM Credit Financing Corporation as Owner Participant, Wilmington Trust Company and The
Citizens and Southern National Bank as Owner Trustee, The First National Bank of Atlanta, as
Indenture Trustee, and Columbia Bank for Cooperatives, as Loan Participant. (Filed as Exhibit
10.1.1(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No.
33-7591.)
*10.1.1(d) -- Second Supplemental Participation Agreement No. 2, dated as of December 17, 1997, among
Oglethorpe as Lessee, DFO Partnership, as assignee of Ford Motor Credit Company, as Owner
Participant, Wilmington Trust Company and NationsBank, N.A. as Owner Trustee, The Bank of New
York Trust Company of Florida, N.A. as Indenture Trustee, CoBank, ACB as Loan Participant, OPC
Scherer Funding Corporation, as Original Funding Corporation, OPC Scherer 1997 Funding
Corporation A, as Funding Corporation, and SunTrust Bank, Atlanta, as Original Collateral Trust
Trustee and Collateral Trust Trustee, with a Schedule identifying three substantially identical
Second Supplemental Participation Agreements and any material differences. (Filed as Exhibit
10.1.1(d) to Registrant's Form S-4 Registration Statement, File No. 333-4275.)
*10.1.2 -- General Warranty Deed and Bill of Sale No. 2 between Oglethorpe, Grant or, and Wilmington Trust
Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Grantee, together with a Schedule identifying three
substantially identical General Warranty Deeds and Bills of Sale. (Filed as Exhibit 10.1.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.3(a) -- Supporting Assets Lease No. 2, dated December 30, 1985, between Oglethorpe, Lessor, and
Wilmington Trust Company and William J. Wade, as Owner Trustees, under Trust Agreement No. 2,
dated December 30, 1985, with Ford Motor Credit Company, Lessee, together with a Schedule
identifying three substantially identical Supporting Assets Leases. (Filed as Exhibit 10.1.3 to
the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.3(b) -- First Amendment to Supporting Assets Lease No. 2, dated as of November 19, 1987, together with a
Schedule identifying three substantially identical First Amendments to Supporting Assets Leases.
(Filed as Exhibit 10.1.3(a) to the Registrant's Form 10-K for the fiscal year ended December 31,
1987, File No. 33-7591.) 5
5
*10.1.4(a) -- Supporting Assets Sublease No. 2, dated December 30, 1985, between Wilmington Trust Company and
William J. Wade, as Owner Trustees under Trust Agreement No. 2 dated December 30, 1985, with Ford
Motor Credit Company, Sublessor, and Oglethorpe, Sublessee, together with a Schedule identifying
three substantially identical Supporting Assets Subleases. (Filed as Exhibit 10.1.4 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.4(b) -- First Amendment to Supporting Assets Sublease No. 2, dated as of November 19, 1987, together with
a Schedule identifying three substantially identical First Amendments to Supporting Assets
Subleases. (Filed as Exhibit 10.1.4(a) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1987, File No. 33-7591.)
*10.1.5(a) -- Tax Indemnification Agreement No. 2, dated December 30, 1985, between Ford Motor Credit Company,
Owner Participant, and Oglethorpe, Lessee, together with a Schedule identifying three
substantially identical Tax Indemnification Agreements. (Filed as Exhibit 10.1.5 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.5(b) -- Amendment No. 1 to the Tax Indemnification Agreement No. 2, dated December 17, 1997, between DFO
Partnership, as assignee of Ford Motor Credit Company, as Owner Participant, and Oglethorpe, as
Lessee, with a Schedule identifying three substantially identical Amendments No. 1 to the Tax
Indemnification Agreements and any material differences. (Filed as Exhibit 10.1.5(b) to the
Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*10.1.6 -- Assignment of Interest in Ownership Agreement and Operating Agreement No. 2, dated December 30,
1985, between Oglethorpe, Assignor, and Wilmington Trust Company and William J. Wade, as Owner
Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company,
Assignee, together with Schedule identifying three substantially identical Assignments of
Interest in Ownership Agreement and Operating Agreement. (Filed as Exhibit 10.1.6 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.7 -- Consent, Amendment and Assumption No. 2 dated December 30, 1985, among Georgia Power Company and
Oglethorpe and Municipal Electric Authority of Georgia and City of Dalton, Georgia and Gulf Power
Company and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement
No. 2, dated December 30, 1985, with Ford Motor Credit Company, together with a Schedule
identifying three substantially identical Consents, Amendments and Assumptions. (Filed as Exhibit
10.1.9 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.7(a)-- Amendment to Consent, Amendment and Assumption No. 2, dated as of August 16, 1993, among
Oglethorpe, Georgia Power Company, Municipal Electric Authority of Georgia, City of Dalton,
Georgia, Gulf Power Company, Jacksonville Electric Authority, Florida Power & Light Company and
Wilmington Trust Company and NationsBank of Georgia, N.A., as Owner Trustees under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, together with a
Schedule identifying three substantially identical Amendments to Consents, Amendments and
Assumptions. (Filed as Exhibit 10.1.9(a) to the Registrant's Form 10-Q for the quarterly period
ended September 30, 1993, File No. 33-7591.)
*10.2.1 -- Section 168 Agreement and Election dated as of April 7, 1982,
between Continental Telephone Corporation and Oglethorpe. (Filed
as Exhibit 10.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, 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.
6
*10.2.1 -- Section 168 Agreement and Election dated as of April 7, 1982, between Continental Telephone
Corporation and Oglethorpe. (Filed as Exhibit 10.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.2.2 -- Section 168 Agreement and Election dated as of April 9, 1982, between National Service
Industries, Inc. and Oglethorpe. (Filed as Exhibit 10.3 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*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.)
*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.)
*10.3.1(a) -- Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement
among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit 10.6.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.3.1(b) -- Amendment to Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of
Georgia and City of Dalton, Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.8 to
the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.3.1(c)-- Amendment Number Two to the Plant Robert W. Scherer Units Numbers One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia, dated as of
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, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia, dated as of August 1, 1988. (Filed as Exhibit
10.6.1(b) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File
No. 33-7591.)
*10.3.1(e) -- Amendment Number Four to the Plant Robert W. Scherer Units Number One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia, dated as of December 31, 1990. (Filed as
Exhibit 10.6.1(c) to the Registrant's Form 10-Q for the quarterly period ended September 30,
1993, File No. 33-7591.)
*10.3.2(a) -- Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated
as of May 15, 1980. (Filed as Exhibit 10.6.2 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591.)
*10.3.1(d)-- Amendment Number Three to the Plant Robert W. Scherer Units
Numbers One and Two Purchase and Ownership Participation
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 1, 1988. (Filed as Exhibit 10.6.1(b)
7
*10.3.2(b) -- Amendment to Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia
Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia,
dated as of December 30, 1985. (Filed as Exhibit 10.1.7 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.3.2(c) -- Amendment Number Two to the Plant Robert W. Scherer Units Numbers One and Two Operating Agreement
among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of December 31, 1990. (Filed as Exhibit 10.6.2(a) to the Registrant's
Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.)
*10.3.3 -- Plant Scherer Managing Board Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia, City of Dalton, Georgia, Gulf Power Company, Florida Power & Light
Company and Jacksonville Electric Authority, dated as of December 31, 1990. (Filed as Exhibit
10.6.3 to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No.
33-7591.)
*10.4.1(a) -- Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation Agreement
among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit 10.7.1 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591.)
*10.4.1(b) -- Amendment Number One, dated January 18, 1977, to the Alvin W. Vogtle Nuclear Units Numbers One
and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.7.3 to
the Registrant's Form 10-K for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.1(c) -- Amendment Number Two, dated February 24, 1977, to the Alvin W. Vogtle Nuclear Units Numbers One
and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.7.4 to
the Registrant's Form 10-K for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.2 -- Alvin W. Vogtle Nuclear Units Numbers One and Two Operating Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 27, 1976. (Filed as Exhibit 10.7.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.5.1 -- Plant Hal Wansley Purchase and Ownership Participation Agreement between Georgia Power Company
and Oglethorpe, dated as of March 26, 1976. (Filed as Exhibit 10.8.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.5.2(a) -- Plant Hal Wansley Operating Agreement between Georgia Power Company and Oglethorpe, dated as of
March 26, 1976. (Filed as Exhibit 10.8.2 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591.)
*10.3.1(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,
8
*10.5.2(b) -- Amendment, dated as of January 15, 1995, to the Plant Hal Wansley Operating Agreements by and
among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia. (Filed as Exhibit 10.5.2(a) to the Registrant's Form 10-Q for the quarterly
period ended September 30, 1996, File No. 33-7591.)
*10.5.3 -- Plant Hal Wansley Combustion Turbine Agreement between Georgia Power Company and Oglethorpe,
dated as of August 2, 1982 and Amendment No. 1, dated October 20, 1982. (Filed as Exhibit 10.18
to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.6.1 -- Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement between Georgia Power
Company and Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit 10.9.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.6.2 -- Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia Power Company and Oglethorpe,
dated as of January 6, 1975. (Filed as Exhibit 10.9.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.7.1 -- Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement, dated as
of November 18, 1988, by and between Oglethorpe and Georgia Power Company. (Filed as Exhibit
10.22.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No.
33-7591.)
*10.7.2 -- Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement, dated as of November 18,
1988, by and between Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.2 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.)
*10.8.1 -- Amended and Restated Wholesale Power Contract, dated as of August 1, 1996, between Oglethorpe and
Altamaha Electric Membership Corporation and all schedules thereto, together with a Schedule
identifying 37 other substantially identical Amended and Restated Wholesale Power Contracts, and
an additional Amended and Restated Wholesale Power Contract that is not substantially identical.
(Filed as Exhibit 10.8.1 to the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.8.2 -- Amended and Restated Supplemental Agreement, dated as of August 1, 1996, by and between
Oglethorpe, Altamaha Electric Membership Corporation and the United States of America, together
with a Schedule identifying 38 other substantially identical Amended and Restated Supplemental
Agreements. (Filed as Exhibit 10.8.2 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.8.3 -- Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as of January
1, 1997, by and among Georgia Power Company, Oglethorpe and Altamaha Electric Membership
Corporation, together with a Schedule identifying 38 other substantially identical Supplemental
Agreements. (Filed as Exhibit 10.8.3 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.3.2(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.)
77
*10.4.2 -- Alvin W. Vogtle Nuclear Units Numbers One and Two Operating
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 27, 1976. (Filed as Exhibit 10.7.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*10.5.1 -- Plant Hal Wansley Purchase and Ownership Participation Agreement
between Georgia Power Company and Oglethorpe, dated as of March
26, 1976. (Filed as Exhibit 10.8.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*10.5.2 -- Plant Hal Wansley Operating Agreement between Georgia Power
Company and Oglethorpe, dated as of March 26, 1976. (Filed as
Exhibit 10.8.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.5.3 -- Plant Hal Wansley Combustion Turbine Agreement between Georgia
Power Company and Oglethorpe, dated as of August 2, 1982 and
Amendment No. 1, dated October 20, 1982. (Filed as Exhibit 10.18
to the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.6.1 -- Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation
Agreement between Georgia Power Company and Oglethorpe, dated as
of January 6, 1975. (Filed as Exhibit 10.9.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.6.2 -- Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia
Power Company and Oglethorpe, dated as of January 6, 1975.
(Filed as Exhibit 10.9.2 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*10.7.1 -- Rocky Mountain Pumped Storage Hydroelectric Project Ownership
Participation Agreement, dated as of November 18, 1988, by and
between Oglethorpe and Georgia Power Company. (Filed as Exhibit
10.22.1 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1988, File No. 33-7591.)
*10.7.2 -- Rocky Mountain Pumped Storage Hydroelectric Project Operating
Agreement, dated as of November 18, 1988, by and between
Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.2
to the Registrant's Form 10-K for the fiscal year ended December
31, 1988, File No. 33-7591.)
*10.8.1(a)-- Wholesale Power Contract dated September 5, 1974, between
Oglethorpe and Planters Electric Membership Corporation and all
schedules thereto, the Supplemental Agreement dated September 5,
1974, between Oglethorpe and Planters Electric Membership
Corporation, relating to such Wholesale Power Contract, and
Amendment No. 1 to Wholesale Power Contract dated May 12, 1980,
between Oglethorpe and Planters Electric Membership Corporation,
together with a Schedule identifying 37 other substantially
identical Wholesale Power Contracts, and an additional Wholesale
Power Contract that is not substantially identical (filed
herewith to reflect update to Schedule A to Wholesale Power
Contract). (Filed as Exhibit 10.10 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*10.8.1(b)-- Amended and Consolidated Wholesale Power Contract, dated as of
December 1, 1988, between Oglethorpe and Planters Electric
Membership Corporation and all schedules thereto, and the
Amended and Consolidated Supplemental Agreement, dated
December 1, 1988, between Oglethorpe and Planters Electric
Membership Corporation, together with a Schedule identifying 37
other substantially identical Wholesale Power Contracts, and an
additional
78
Wholesale Power Contract that is not substantially identical.
(Filed as Exhibit 10.10(a) to the Registrant's Form 10-K for
the fiscal year ended December 31, 1988, File No. 33-7591.)
*10.9 -- Transmission Facilities Operation and Maintenance Contract
between Georgia Power Company and Oglethorpe dated as of June 9,
1986. (Filed as Exhibit 10.13 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*10.10(a) -- Joint Committee Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and the City
of Dalton, Georgia, dated as of August 27, 1976. (Filed as
Exhibit 10.14(b) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.10(b) -- First Amendment to Joint Committee Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia and
the City of Dalton, Georgia, dated as of June 19, 1978. (Filed
as Exhibit 10.14(a) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.11 -- Interconnection Agreement between Oglethorpe and Alabama Electric
Cooperative, Inc., dated as of November 12, 1990. (Filed as
Exhibit 10.16(a) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1990, File No. 33-7591.)
*10.11(a) -- Amendment No. 1 to Interconnection Agreement between Alabama
Electric Cooperative, Inc. and Oglethorpe, dated as of April 22,
1994. (Filed as Exhibit 10.11(a) to the Registrant's Form 10-Q
for the quarter ended June 30, 1994, File No. 33-7591.)
*10.11(b) -- Letter of Commitment (Firm Power Sale) Under Service Schedule J -
Negotiated Interchange Service between Alabama Electric
Cooperative, Inc. and Oglethorpe, dated March 31, 1994. (Filed
as Exhibit 10.11(b) to the Registrant's Form 10-Q for the quarter
ended June 30, 1994, File No. 33-7591.)
*10.12 -- Oglethorpe Deferred Compensation Plan for Key Employees, as
Amended and Restated January, 1987. (Filed as Exhibit 10.19 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1986, File No. 33-7591.)
*10.13.1 -- Assignment of Power System Agreement and Settlement Agreement,
dated January 8, 1975, by Georgia Electric Membership Corporation
to Oglethorpe. (Filed as Exhibit 10.20.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.13.2 -- Power System Agreement, dated April 24, 1974, by and between
Georgia Electric Membership Corporation and Georgia Power
Company. (Filed as Exhibit 10.20.2 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*10.13.3 -- Settlement Agreement, dated April 24, 1974, by and between
Georgia Power Company, Georgia Municipal Association, Inc., City
of Dalton, Georgia Electric Membership Corporation and Crisp
County Power Commission. (Filed as Exhibit 10.20.3 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*10.14 -- Distribution Facilities Joint Use Agreement between Oglethorpe
and Georgia Power Company, dated as of May 12, 1986. (Filed as
Exhibit 10.21 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1986, File No. 33-7591.)
*10.15.1 -- Long Term Firm Power Purchase Agreement, dated as of July 19,
1989, by and between Oglethorpe and Big Rivers Electric
Corporation. (Filed as Exhibit 10.24.1 to the Registrant's Form
10-K for the fiscal year ended December 31, 1989, File No.
33-7591.)
79
*10.15.2 -- Coordination Services Agreement, dated as of August 21, 1989, by
and between Oglethorpe and Georgia Power Company. (Filed as
Exhibit 10.24.2 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1989, File No. 33-7591.)
*10.15.3 -- Long Term
*10.8.4 -- Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as of March 1,
1997, by and between Oglethorpe and Altamaha Electric Membership Corporation, together with a
Schedule identifying 36 other substantially identical Supplemental Agreements, and an additional
Supplemental Agreement that is not substantially identical. (Filed as Exhibit 10.8.4 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.5 -- Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as of March 1,
1997, by and between Oglethorpe and Coweta-Fayette Electric Membership Corporation, together with
a Schedule identifying 1 other substantially identical Supplemental Agreement. (Filed as Exhibit
10.8.5 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.8.6 -- Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as of May 1,
1997 by and between Oglethorpe and Altamaha Electric Membership Corporation, together with a
Schedule identifying 38 other substantially identical Supplemental Agreements. (Filed as Exhibit
10.8.6 to the Registrant's Form 10-Q for the quarterly period ended June 30, 1997, File No.
33-7591.)
*10.9(a) -- Joint Committee Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and the City of Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit
10.14(b) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.9(b) -- First Amendment to Joint Committee Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and the City of Dalton, Georgia, dated as of June 19, 1978. (Filed
as Exhibit 10.14(a) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.10 -- Letter of Commitment (Firm Power Sale) Under Service Schedule J--Negotiated Interchange Service
between Alabama Electric Cooperative, Inc. and Oglethorpe, dated March 31, 1994. (Filed as
Exhibit 10.11(b) to the Registrant's Form 10-Q for the quarter ended June 30, 1994, File No.
33-7591.)
*10.11.1 -- Assignment of Power System Agreement and Settlement Agreement, dated January 8, 1975, by Georgia
Electric Membership Corporation to Oglethorpe. (Filed as Exhibit 10.20.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.11.2 -- Power System Agreement, dated April 24, 1974, by and between Georgia Electric Membership Corporation
and Georgia Power Company. (Filed as Exhibit 10.20.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.11.3 -- Settlement Agreement, dated April 24, 1974, by and between Georgia Power Company, Georgia
Municipal Association, Inc., City of Dalton, Georgia Electric Membership Corporation and Crisp
County Power Commission. (Filed as Exhibit 10.20.3 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.12 -- Long-Term Firm Power Purchase Agreement between Big Rivers Electric Corporation and Oglethorpe,
dated as of December 17, 1990. (Filed as Exhibit 10.24.3 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1990, File No. 33-7591.)
*10.15.4 -- Interchange Agreement between Oglethorpe and Big Rivers Electric
Corporation, dated as of November 12, 1990. (Filed as Exhibit
10.24.4
10
*10.13 -- 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.)
10.14 -- Revised and Restated Coordination Services Agreement between and among Georgia Power Company,
Oglethorpe and Georgia System Operations Corporation, dated as of September 10, 1997.
*10.15 -- 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.)
*10.16 -- 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.)
*10.17 -- 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.)
*10.18 -- 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.)
*10.19 -- 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).
*10.20(3) -- Employment Agreement between Oglethorpe and T. D. Kilgore, dated as of December 20, 1995. (Filed
as Exhibit 10.28 to the Registrant's Form 10-K for the fiscal year ended December 31, 1995, File
No. 33-7591.)
*10.21(2) -- Power Purchase and Sale Agreement among LG&E Power Marketing Inc., LG&E Energy Corp. and
Oglethorpe, dated as of November 19, 1996. (Filed as Exhibit 10.30 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.22(2) -- Power Purchase and Sale Agreement among LG&E Power Marketing Inc., LG&E Power Inc. and
Oglethorpe, dated as of January 1, 1997. (Filed as Exhibit 10.31 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.1 -- Participation Agreement (P1), dated as of December 30, 1996, among Oglethorpe, Rocky Mountain
Leasing Corporation, Fleet National Bank, as Owner Trustee, SunTrust Bank, Atlanta, as
Co-Trustee, the Owner Participant named therein and Utrecht-America Finance Co., as Lender,
together with a Schedule identifying five other substantially identical Participation Agreements.
(Filed as Exhibit 10.32.1 to the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*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,
11
*10.23.2 -- Rocky Mountain Head Lease Agreement (P1), dated as of December 30, 1996, between Oglethorpe and
SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other
substantially identical Rocky Mountain Head Lease Agreements. (Filed as Exhibit 10.32.2 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.3 -- Ground Lease Agreement (P1), dated as of December 30, 1996, between Oglethorpe and SunTrust Bank,
Atlanta, as Co-Trustee, together with a Schedule identifying five other substantially identical
Ground Lease Agreements. (Filed as Exhibit 10.32.3 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.23.4 -- Rocky Mountain Agreements Assignment and Assumption Agreement (P1), dated as of December 30,
1996, between Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Rocky Mountain Agreements Assignment and
Assumption Agreements. (Filed as Exhibit 10.32.4 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.23.5 -- Facility Lease Agreement (P1), dated as of December 30, 1996, between SunTrust Bank, Atlanta, as
Co-Trustee and Rocky Mountain Leasing Corporation, together with a Schedule identifying five
other substantially identical Facility Lease Agreements. (Filed as Exhibit 10.32.5 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.6 -- Ground Sublease Agreement (P1), dated as of December 30, 1996, between SunTrust Bank, Atlanta, as
Co-Trustee and Rocky Mountain Leasing Corporation, together with a Schedule identifying five
other substantially identical Ground Sublease Agreements. (Filed as Exhibit 10.32.6 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.7 -- Rocky Mountain Agreements Re-assignment and Assumption Agreement (P1), dated as of December 30,
1996, between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain Leasing Corporation,
together with a Schedule identifying five other substantially identical Rocky Mountain Agreements
Re-assignment and Assumption Agreements. (Filed as Exhibit 10.32.7 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.8 -- Facility Sublease Agreement (P1), dated as of December 30, 1996, between Oglethorpe and Rocky
Mountain Leasing Corporation, together with a Schedule identifying five other substantially
identical Facility Sublease Agreements. (Filed as Exhibit 10.32.8 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.9 -- Ground Sub-sublease Agreement (P1), dated as of December 30, 1996, between Rocky Mountain Leasing
Corporation and Oglethorpe, together with a Schedule identifying five other substantially
identical Ground Sub-sublease Agreements. (Filed as Exhibit 10.32.9 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
*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,
*10.23.10 -- Rocky Mountain Agreements Second Re-assignment and Assumption Agreement (P1), dated as of
December 30, 1996, between Rocky Mountain Leasing Corporation and Oglethorpe, together with a
Schedule identifying five other substantially identical Rocky Mountain Agreements Second
Re-assignment and Assumption Agreements. (Filed as Exhibit 10.32.10 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.11 -- Payment Undertaking Agreement (P1), dated as of December 30, 1996, between Rocky Mountain Leasing
Corporation and Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A., New York Branch, as the
Bank, together with a Schedule identifying five other substantially identical Payment Undertaking
Agreements. (Filed as Exhibit 10.32.11 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.23.12 -- Payment Undertaking Pledge Agreement (P1), dated as of December 30, 1996, between Rocky Mountain
Leasing Corporation, Fleet National Bank, as Owner Trustee, and SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other substantially identical Payment
Undertaking Pledge Agreements. (Filed as Exhibit 10.32.12 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.13 -- Equity Funding Agreement (P1), dated as of December 30, 1996, between Rocky Mountain Leasing
Corporation, AIG Match Funding Corp., the Owner Participant named therein, Fleet National Bank,
as Owner Trustee, and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying
five other substantially identical Equity Funding Agreements. (Filed as Exhibit 10.32.13 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.14 -- Equity Funding Pledge Agreement (P1), dated as of December 30, 1996, between Rocky Mountain
Leasing Corporation and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Equity Funding Pledge Agreements. (Filed as
Exhibit 10.32.14 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File
No. 33-7591.)
*10.23.15 -- Deed to Secure Debt, Assignment of Surety Bond and Security Agreement (P1), dated as of December
30, 1996, between Rocky Mountain Leasing Corporation, SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other substantially identical Collateral Assignment,
Assignment of Surety Bond and Security Agreements. (Filed as Exhibit 10.32.15 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.16 -- Subordinated Deed to Secure Debt and Security Agreement (P1), dated as of December 30, 1996,
among Oglethorpe, AMBAC Indemnity Corporation and SunTrust Bank, Atlanta, as Co-Trustee, together
with a Schedule identifying five other substantially identical Subordinated Deed to Secure Debt
and Security Agreements. (Filed as Exhibit 10.32.16 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.23.17 -- Tax Indemnification Agreement (P1), dated as of December 30, 1996, between Oglethorpe and the
Owner Participant named therein, together with a Schedule identifying five other substantially
identical Tax Indemnification Agreements. (Filed as Exhibit 10.32.17 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.18 -- Revised and Restated Integrated Transmission System Agreement
between Oglethorpe and Georgia Power Company, dated as of
November 12, 1990. (Filed as Exhibit 10.27 to the Registrant's
Form 8-K, filed January 4, 1991, File No. 33-7591.)
*10.19 -- ITSA, Power Sale and Coordination Umbrella Agreement between
Oglethorpe and Georgia Power Company, dated as of November 12,
1990. (Filed as Exhibit 10.28 to the Registrant's Form 8-K,
filed January 4, 1991, File No. 33-7591.)
*10.20 -- Amended and Restated Nuclear Managing Board Agreement among
Georgia Power Company, Oglethorpe Power Corporation, Municipal
Electric Authority of Georgia and City of Dalton, Georgia dated
as of July 1, 1993. (Filed as Exhibit 10.36 to the Registrant's
10-Q for the quarterly period ended September 30, 1993, File No.
33-7591.)
*10.21 -- Supplemental Agreement by and among Oglethorpe, Tri-County
Electric Membership Cooperation and Georgia Power Company, dated
as of November 12, 1990, together with a Schedule identifying 38
other substantially identical Supplemental Agreements. (Filed as
Exhibit 10.30 to the Registrant's Form 8-K, filed January 4,
1991, File No. 33-7591.)
*10.22 -- Unit Capacity and Energy Purchase Agreement between Oglethorpe
and Entergy Power Incorporated, dated as of October 11, 1990.
(Filed as Exhibit 10.31 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1990, File No. 33-7591.)
*10.23 -- Interchange Agreement between Oglethorpe and Arkansas Power &
Light Company, Louisiana Power & Light Company, Mississippi Power
& Light Company, New Orleans Public Service, Inc., Energy
Services, Inc., dated as of November 12, 1990. (Filed as Exhibit
10.32 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*10.24 -- Interchange Agreement between Oglethorpe and Seminole Electric
Cooperative, Inc., dated as of November 12, 1990. (Filed as
Exhibit 10.33 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1990, File No. 33-7591.)
80
13
*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)
*10.23.18 -- Consent No. 1, dated as of December 30, 1996, among Georgia Power Company, Oglethorpe, SunTrust
Bank, Atlanta, as Co-Trustee, and Fleet National Bank, as Owner Trustee, together with a Schedule
identifying five other substantially identical Consents. (Filed as Exhibit 10.32.18 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23.19(a) -- OPC Intercreditor and Security Agreement No. 1, dated as of December 30, 1996, among the United
State of America, acting through the Administrator of the Rural Utilities Service, SunTrust Bank,
Atlanta, Oglethorpe, Rocky Mountain Leasing Corporation, SunTrust Bank, Atlanta, as Co-Trustee,
Fleet National Bank, as Owner Trustee, Utrecht-America Finance Co., as Lender and AMBAC Indemnity
Corpoation, together with a Schedule identifying five other substantially identical Intercreditor
and Security Agreements. (Filed as Exhibit 10.32.19 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
10.23.19(b) -- Supplement to OPC Intercreditor and Security Agreement No. 1, dated as of March 1, 1997, among the
United States of America, acting through the Administrator of the Rural Utilities Service, SunTrust
Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing Corporation, SunTrust Bank, Atlanta, as Co-Trustee,
Fleet National Bank, as Owner Trustee, Utrecht-America Finance Co., as Lender and AMBAC Indemnity
Corporation, together with a Schedule identifying five other substantially identical Supplements to OPC
Intercreditor and Security Agreements. (Filed as Exhibit 10.32.19(b) to the Registrant's Form S-4
Registration Statement, File No. 333-42759.)
*10.24.1 -- Member Transmission Service Agreement, dated as of March 1, 1997, by and between Oglethorpe and
Georgia Transmission Corporation (An Electric Membership Corporation). (Filed as Exhibit 10.33.1
to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.24.2 -- Generation Services Agreement, dated as of March 1, 1997, by and between Oglethorpe and Georgia
System Operations Corporation. (Filed as Exhibit 10.33.2 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.24.3 -- Operation Services Agreement, dated as of March 1, 1997, by and between Oglethorpe and Georgia
System Operations Corporation. (Filed as Exhibit 10.33.3 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.25(2) -- Power Purchase and Sale Agreement between Morgan Stanley Capital Group Inc. and Oglethorpe, dated
as of April 7, 1997. (Filed as Exhibit 10.34 to the Registrant's Form 10-Q for the quarterly
period ended March 30, 1997, File No. 33-7591.)
21.1 -- Rocky Mountain Leasing Corporation, a Delaware corporation.
27.1 -- Financial Data Schedule (for SEC use only).
10.27 (5) -- Master Power Purchase and Sale Agreement between Enron Power
Marketing, Inc. and Oglethorpe, dated as of January 3, 1996.
10.28 (6) -- Employment Agreement between Oglethorpe and T. D. Kilgore, dated
as of December 20, 1995.
22.1 -- Subsidiary of Oglethorpe (not included because the subsidiary
does not constitute a "significant subsidiary" under Rule 1-02(v)
of Regulation S-X).
27.1 -- Financial Data Schedule (for SEC use only)
_________________
- ------------------------
(1) Pursuant to 17 C.F.R. 229.601(b)(2), the schedules and exhibits to this
document are identified on a list of schedules and exhibits included
within this document and are not filed herewith; however the registrant
hereby agrees that such schedules and exhibits will be provided to the
Commission upon request.
(2) Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this documentdocument(s) is not filed
herewith; however the registrant hereby agrees that such documentdocument(s) will be
provided to the Commission upon request.
(3) For the reason stated in footnote (2), this document and eight other
substantially identical documents are not filed as exhibits to this
Registration Statement.
(4) For the reason stated in footnote (2), this document and another
substantially identical document are not filed as exhibits to this
Registration Statement.
(5) Certain portions of this document have been omitted as confidential and
filed separately with the Commission.
(6)(3) Indicates a management contract or compensatory plan or arrangement required to be
filed as an exhibit to this form pursuant to Item 14(c)
of this report.
All other schedules and exhibits are omitted because of the absence of
the conditions under which they are required or because the required
information is included in the financial statements and related notes to
financial statements.
(B) REPORTS ON FORM 8-K.
No reports on Form 8-K were filed by Oglethorpe for the quarter ended
December 31, 1995.
81
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized, on the 1st day
of April 1996.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION &
TRANSMISSION CORPORATION)
By: /s/ J. CALVIN EARWOOD
----------------------------------------
J. Calvin EARWOOD, CHAIRMAN OF THE BOARD
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
Signature Title Date
/s/ J. CALVIN EARWOOD Chairman of the Board, April 1, 1996
- -------------------------- Director (Principal Executive
J. CALVIN EARWOOD Officer)
/s/ T. D. KILGORE President and Chief Executive April 1, 1996
- -------------------------- Officer (Principal Executive
T. D. KILGORE Officer)
/s/ GARY M. BULLOCK Secretary-Treasurer (Principal April 1, 1996
- -------------------------- Financial Officer)
GARY M. BULLOCK
/s/ EUGEN HECKL Senior Vice President and Chief April 1, 1996
- -------------------------- Financial Officer (Principal
EUGEN HECKL Financial Officer)
/s/ LARRY N. BROWNLEE Controller April 1, 1996
- -------------------------- (Principal Accounting Officer)
LARRY N. BROWNLEE
/s/ JMON WARNOCK Director April 1, 1996
- --------------------------
JMON WARNOCK
/s/ CHARLES R. FENDLEY Director April 1, 1996
- --------------------------
CHARLES R. FENDLEY
/s/ GEORGE C. MARTIN Director April 1, 1996
- --------------------------
GEORGE C. MARTIN
/s/ J. G. MCCALMON Director April 1, 1996
- --------------------------
J. G. MCCALMON
82
/s/ D. A. ROBINSON, III Director April 1, 1996
- --------------------------
D. A. ROBINSON, III
/s/ JAMES E. ESTES Director April 1, 1996
- --------------------------
JAMES E. ESTES
/s/ LARRY N. CHADWICK Director April 1, 1996
- --------------------------
LARRY N. CHADWICK
/s/ SIMMIE KING Director April 1, 1996
- --------------------------
SIMMIE KING
/s/ W. F. FARR Director April 1, 1996
- --------------------------
W. F. FARR
/s/ GARY T. DRAKE Alternate Director April 1, 1996
- --------------------------
GARY T. DRAKE
/s/ JEFF S. PIERCE, JR. Director April 1, 1996
- --------------------------
JEFF S. PIERCE, JR.
/s/ DONALD C. COOPER Director April 1, 1996
- --------------------------
DONALD C. COOPER
/s/ RAY MEADERS Director April 1, 1996
- --------------------------
RAY MEADERS
/s/ MAC F. OGLESBY Director April 1, 1996
- --------------------------
MAC F. OGLESBY
/s/ BENNY W. DENHAM Director April 1, 1996
- --------------------------
BENNY W. DENHAM
/s/ E. L. MCLOCKLIN Director April 1, 1996
- --------------------------
E. L. MCLOCKLIN
/s/ SAM RABUN Director April 1, 1996
- --------------------------
SAM RABUN
/s/ E. J. MARTIN, JR. Director April 1, 1996
- --------------------------
E. J. MARTIN, JR.
/s/ JIM M. KNIGHT Director April 1, 1996
- --------------------------
JIM M. KNIGHT
/s/ RONNIE FLEEMAN Director April 1, 1996
- --------------------------
RONNIE FLEEMAN
/s/ D. LAMAR COOPER Director April 1, 1996
- --------------------------
D. LAMAR COOPER
83
/s/ BARRY H. MARTIN Director April 1, 1996
- --------------------------
BARRY H. MARTIN
/s/ JOHN B. FLOYD, JR. Director April 1, 1996
- --------------------------
JOHN B. FLOYD, JR.
/s/ STEVE RAWL, SR. Director April 1, 1996
- --------------------------
STEVE RAWL, SR.
/s/ JAMES GRUBBS Director April 1, 1996
- --------------------------
JAMES GRUBBS
/s/ SAMMY M. JENKINS Director April 1, 1996
- --------------------------
SAMMY M. JENKINS
/s/ J. M. SHERRER Director April 1, 1996
- --------------------------
J. M. SHERRER
/s/ JACK D. VICKERS Director April 1, 1996
- --------------------------
JACK D. VICKERS
/s/ C. W. COX, JR. Director April 1, 1996
- --------------------------
C. W. COX, JR.
/s/ JOHNNIE CRUMBLEY Director April 1, 1996
- --------------------------
JOHNNIE CRUMBLEY
/s/ JARNETT W. WIGINGTON Director April 1, 1996
- --------------------------
JARNETT W. WIGINGTON
/s/ BOB JERNIGAN Director April 1, 1996
- --------------------------
BOB JERNIGAN
/s/ C. WILLARD MIMS Director April 1, 1996
- --------------------------
C. WILLARD MIMS
/s/ THOMAS NOLES Director April 1, 1996
- --------------------------
THOMAS NOLES
/s/ ROY TOLLERSON, JR. Director April 1, 1996
- --------------------------
ROY TOLLERSON, JR.
/s/ HUBERT HANCOCK Director April 1, 1996
- --------------------------
HUBERT HANCOCK
/s/ HENDRIX B. WILEY, JR. Director April 1, 1996
- --------------------------
HENDRIX B. WILEY, JR.
/s/ W. W. ARCHER Director April 1, 1996
- --------------------------
W. W. ARCHER
84
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO
SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES
PURSUANT TO SECTION 12 OF THE ACT.
The registrant is a membership corporation and has no authorized or
outstanding equity securities. Proxies are not solicited from the holders of
Oglethorpe's public bonds. No annual report or proxy material has been sent
to such bondholders.
85
Report.
14