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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
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FORM 10-K
(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
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 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
------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes _X_ No___
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
State the aggregate market value of the voting and non-voting common equity
held by non-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
1997 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
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ITEM PAGE
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<C> <S> <C>
PART I
1 Business........................................................................................... 1
Oglethorpe Power Corporation..................................................................... 1
The Members...................................................................................... 9
Member Requirements and Power Supply Resources................................................... 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 Agreements................................................. 25
3 Legal Proceedings.................................................................................. 28
4 Submission of Matters to a Vote of Security Holders................................................ 28
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters.............................. 29
6 Selected Financial Data............................................................................ 29
7 Management's Discussion and Analysis of Financial Condition and Results of Operations.............. 30
7A Quantitative and Qualitative Disclosures About Market Risk......................................... 41
8 Financial Statements and Supplementary Data........................................................ 41
9 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure............... 61
PART III
10 Directors and Executive Officers of the Registrant................................................. 61
11 Executive Compensation............................................................................. 65
12 Security Ownership of Certain Beneficial Owners and Management..................................... 67
13 Certain Relationships and Related Transactions..................................................... 67
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K................................... 68
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SELECTED DEFINITIONS
When used herein the following terms will have the meanings indicated below:
<TABLE>
<CAPTION>
TERM MEANING
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<S> <C>
ADSCR Annual Debt Service Coverage Ratio
AFUDC Allowance For Funds Used During Construction
BPSA Block Power Sale Agreement
CFC National Rural Utilities Cooperative Finance Corporation
DSC Debt Service Coverage Ratio
EMC Electric Membership Corporation
EPI Entergy Power, Inc.
FERC Federal Energy Regulatory Commission
FFB Federal Financing Bank
GPC Georgia Power Company
GPSC Georgia Public Service Commission
GSOC Georgia System Operations Corporation
GTC Georgia Transmission Corporation (An Electric Membership Corporation)
ITS Integrated Transmission System
ITSA Revised and Restated Integrated Transmission System Agreement
kWh Kilowatt-hours
LEM LG&E Energy Marketing Inc.
MEAG Municipal Electric Authority of Georgia
MFI Margins for Interest
MW Megawatts
MWh Megawatt-hours
NRC Nuclear Regulatory Commission
PCBs Pollution Control Revenue Bonds
PCR Percentage Capacity Responsibility
PPA Prior Period Adjustment
PURPA Public Utility Regulatory Policies Act
RUS Rural Utilities Service
SEPA Southeastern Power Administration
SONOPCO Southern Nuclear Operating Company
TIER Times Interest Earned Ratio
TVA Tennessee Valley Authority
</TABLE>
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PART I
ITEM 1. BUSINESS
OGLETHORPE POWER CORPORATION
GENERAL
Oglethorpe Power Corporation (An Electric Membership Corporation)
("Oglethorpe") is a Georgia electric membership corporation incorporated in 1974
and headquartered in metropolitan Atlanta. Oglethorpe is owned by 39 retail
electric distribution cooperative members (the "Members"), who, in turn, are
owned by their retail consumers. Oglethorpe is the largest electric cooperative
in the United States in terms of operating revenues, assets, kWh sales and,
through the Members, consumers served. Oglethorpe and its subsidiary,
EnerVision, Inc., Tailored Energy Solutions ("EnerVision"), have approximately
170 employees.
As with cooperatives generally, Oglethorpe operates on a not-for-profit
basis. Oglethorpe's principal business is providing wholesale electric power 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 customer base of the Members consists of
residential, commercial and industrial consumers within specific geographic
areas. The Members serve approximately 1.2 million electric consumers (meters)
representing approximately 2.8 million people. For 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 its 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 the members, are held for the accounts
of the members and returned to them 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 cooperative's loan and security agreements.
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. Oglethorpe's transmission
business was sold to and is now owned and operated by Georgia Transmission
Corporation (An Electric Membership 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.
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Oglethorpe and the 39 Members are the owners 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 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 was used by the Members to
establish equity in and to provide initial working capital to GTC. GTC now
provides transmission services to the Members, Oglethorpe and third parties. GTC
succeeded to all of Oglethorpe's rights and obligations with respect to the
Integrated Transmission System ("ITS"). (See "Relationship with GTC" herein for
further discussion of the ITS.)
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 totaled approximately $9.4 million and was paid by
(i) GSOC's assumption of Oglethorpe's obligations under an existing note held by
the RUS, (ii) delivery of a purchase money note payable to Oglethorpe, and (iii)
the assumption of certain other liabilities of Oglethorpe. GSOC now operates the
system control center and provides system operations services to the Members,
Oglethorpe and GTC.
Oglethorpe continues 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 with an 11-member board of
directors consisting of six directors elected from the Members, four independent
outside directors and Oglethorpe's President and Chief Executive Officer. This
smaller board replaced Oglethorpe's former 39-member board comprised of
directors nominated from and by each Member. (See "DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT" in Item 10 for further information.)
Contemporaneously with the Corporate Restructuring, Oglethorpe replaced its
prior Consolidated Mortgage and Security Agreement, dated as of September 1,
1994, by and among 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 lien 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.)
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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 joint and several basis to pay rates sufficient to pay all the
costs of owning and operating Oglethorpe's power supply business. (See
"Wholesale Power Contracts" herein.) Oglethorpe supplies capacity and energy to
the Members from 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 2.1 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 the 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 having an interest only in Scherer
Unit No. 1 and Scherer 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 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 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 Capital Group Inc. ("Morgan Stanley") effective May 1, 1997, with
respect to 50% of the forecasted load requirements of the Members. The LEM
agreements are based on the actual requirements of the Members during the
contract term, whereas the Morgan Stanley agreement represents
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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 the 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 pursuant 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 contracted to purchase 275 MW of peaking
capacity from Florida Power Corporation during the summer of 1998. (See "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES--Power Purchase and Sale Arrangements.")
WHOLESALE POWER CONTRACTS
In connection with the Corporate Restructuring, Oglethorpe and 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 take 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 service 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 Member under its Wholesale
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 the
Member's electric system.
See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES" for a description of
the Members' demand and energy requirements and the related power supply
resources. See also
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"MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--Power Marketing
Arrangements--RELATED AGREEMENTS" regarding supplemental agreements to the
Wholesale Power Contracts relating to the 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, 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, all costs associated with decommissioning or
otherwise retiring any generating facility, to provide for the establishment and
maintenance of reasonable reserves, and to enable Oglethorpe to comply with all
financial requirements under the Mortgage Indenture. (See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--General--RATES AND FINANCIAL COVERAGE REQUIREMENTS" in Item 7.)
Under the 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 Mortgage
Indenture or by a lien equal or prior to 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 Charges"), plus any
amount included in net margins for accruals for federal or state income taxes
imposed on income after deduction of interest expense. 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 such losses or expenditures. "MFI
Ratio" is the ratio of MFI to total Interest Charges for a given period. (See
"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
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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.
Under the terms of Oglethorpe's prior RUS Mortgage, 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 federal or state agency or authority, including the
Georgia Public Service Commission (the "GPSC").
For information regarding future rates, see "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--General--RATES AND
FINANCIAL COVERAGE REQUIREMENTS" in Item 7.
RELATIONSHIP WITH GTC
Oglethorpe and the 39 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 GTC to earn sufficient margins to
satisfy the requirements of its new mortgage indenture, which is substantially
similar to Oglethorpe's Mortgage Indenture.
The GTC transmission tariff and associated 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 order 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
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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 governed by the
Revised and Restated Integrated Transmission System Agreement with GPC (the
"ITSA"), which was assigned to GTC in connection with the Corporate
Restructuring. The ITSA provides for the transmission and distribution of
electric energy in the State of Georgia, other than in certain counties, and for
bulk power transactions, through use of the ITS. The ITS 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 GSOC. GSOC now owns and
operates the system control center and provides system operations services to
the Members, Oglethorpe and GTC. GTC has contracted with GSOC to provide certain
transmission system operation services including reliability monitoring,
switching operations, and the real-time management of the transmission system.
7
<PAGE>
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 suppliers
of purchased power, and Oglethorpe is one of GPC's largest customers. All of
Oglethorpe's co-owned generating facilities, except Rocky Mountain, are operated
by GPC on behalf of itself as a co-owner and as agent for the other co-owners.
GPC and Oglethorpe, through the Members, are 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"). For further information regarding the relationships and
agreements with GPC, see "THE MEMBERS--Service Area and Competition," "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES--Power Purchase and Sale
Arrangements--POWER PURCHASES FROM GPC," "--Power Purchase and Sale
Arrangements--OTHER POWER PURCHASES," "GENERATING FACILITIES-- Fuel Supply" in
Item 2, "CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--Co-Owners of the
Plants--GEORGIA POWER COMPANY" and "--The Plant Agreements" in Item 2.
RELATIONSHIP WITH RUS
Historically, federal loan programs administered by RUS have provided the
principal source of financing for electric cooperatives. Loans guaranteed by RUS
and made by FFB have been a major source of funding for Oglethorpe. 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 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 Mortgage
Indenture improves Oglethorpe's ability to borrow funds in the public capital
markets. (See "THE MEMBERS--Members' Relationship with RUS" for a discussion of
the impact of changes in the RUS lending program on the Members.)
RELATIONSHIP WITH INTELLISOURCE
In conjunction with the Corporate Restructuring and as a part of its
continuing efforts to reduce costs, effective February 1, 1997, Oglethorpe
implemented a business alliance with Intellisource, Inc., a national provider of
outsourcing services. Pursuant to an agreement with Intellisource, approximately
150 support services division employees of Oglethorpe in the areas 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 managers and employees of Oglethorpe's former
support services division.
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THE MEMBERS
SERVICE AREA AND COMPETITION
The Members are listed below and include 39 of the 42 electric distribution
cooperatives in the State of Georgia.
<TABLE>
<S> <C> <C>
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
</TABLE>
The Members serve approximately 1.2 million electric consumers (meters)
representing approximately 2.8 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, encompassing 150 of the State's 159 counties.
Sales by the Members in 1997 amounted to approximately 20 million megawatt-hours
("MWh"), with approximately 72% to residential consumers, 26% to commercial and
industrial consumers and 2% to other consumers. 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 1995 through 1997 of 6% in number of
consumers and 5% in MWh 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.
With limited exceptions, the Members have the exclusive right to provide retail
electric service in their respective territories, which are predominately
outside of the municipal 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 reassign territory only if it determines that an electric
supplier has breached the tenets of public convenience and necessity. The GPSC
may transfer service for specific premises only if: (i) 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) the 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.
Since 1973, unlike in the electric utility industry in general, the
Territorial Act has allowed limited competition among electric utilities in
Georgia by allowing the owner of any new facility located outside of 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
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<PAGE>
actively engaged in competition with other retail electric suppliers for these
new commercial and industrial loads. The number of commercial and industrial
loads served by the Members continues to increase annually. While the
competition for 900 kilowatt loads represents only limited competition in
Georgia, 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 Contracts provide that a Member may 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 otherwise dispose of all or substantially all of its assets to any
person, whether in a single transaction or series of transactions, unless
either: (i) the transaction is approved by Oglethorpe or (ii) other specified
conditions are satisfied including, but not limited to, an assumption agreement
by the transferee, satisfactory to Oglethorpe, containing an assumption by the
transferee of the performance and observance of every covenant and condition of
the Member under the Wholesale Power Contract, and certifications of accountants
as to certain specified financial requirements of the transferee (taking into
account the transfer).
COOPERATIVE STRUCTURE
The Members 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 (provided that equity is at least 20% in the case of Members, if any, that
have the new form of RUS loan documents). (See "Members' Relationship with RUS"
herein.)
Oglethorpe is a membership corporation, and the Members are not subsidiaries
of Oglethorpe. Except with respect to the obligations of the Members under each
Member's Wholesale Power Contract with Oglethorpe and Oglethorpe's rights under
such contracts to receive payment for power and energy supplied, Oglethorpe has
no legal interest in, or obligations in respect of, any of the assets,
liabilities, equity, revenues or margins of the Members. (See "OGLETHORPE POWER
CORPORATION-- 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 are, however, pledged under
their respective RUS mortgages 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. The RUS mortgages of such Members require them to
design rates with a view to maintaining an average Times Interest
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<PAGE>
Earned Ratio ("TIER") of not less than 1.50 and an average Debt Service Coverage
Ratio ("DSC") of not less than 1.25 for the two highest out of every three
successive years.
Although the setting of the rates of the Members is not subject to approval
by any federal or state agency or authority other than RUS, the Territorial Act
prohibits the Members from unreasonable discrimination in the setting of rates,
charges, service rules or regulations and requires the Members to obtain GPSC
approval of long-term borrowings.
Snapping Shoals EMC, Mitchell EMC, Troup EMC, Walton EMC and Cobb EMC have
prepaid their RUS indebtedness and are no longer RUS borrowers. Each of these
Members now 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 regulation by FERC under the Federal Power Act.
MEMBERS' RELATIONSHIP WITH RUS
Through 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. The Rural Electrification Loan
Restructuring Act of 1993 eliminated the long-standing 5% loan program and
substituted a new program, the interest rates for which are based on rates being
paid on municipal bonds with comparable maturities. Certain borrowers with
either low consumer density or higher-than-average rates and lower-than-average
consumer income are still eligible for special loans at 5%. The President's
budget proposal for fiscal year 1999 includes a 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.
MEMBERS' RELATIONSHIP WITH GTC AND GSOC
For information about the Members' relationship with GTC and GSOC, see
"OGLETHORPE POWER CORPORATION--Relationship with GTC" and "--Relationship with
GSOC."
CONTRACTS WITH SEPA
In addition to energy received from Oglethorpe under the 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.
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<PAGE>
Pursuant 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 RESOURCES--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
<PAGE>
MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES
GENERAL
Oglethorpe supplies capacity and energy to the Members from a combination of
owned and leased generating plants and from power purchased under long-term
contracts with other power suppliers and power 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 energy delivered to the Members, in
part by giving certain dispatch rights to the power marketers. (See "Power
Marketer Arrangements" herein.)
MEMBER DEMAND AND ENERGY REQUIREMENTS
The following table shows the aggregate peak demand and energy requirements
of the Members for the years 1995 through 1997, and also shows the amounts of
such requirements supplied by Oglethorpe 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.
<TABLE>
<CAPTION>
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)
----------------- --------------- --------------- ------------- ------------- -----------
<S> <C> <C> <C> <C> <C> <C>
1995.............................. 4,850 4,308 542 19,403,703 18,442,153 961,550
1996.............................. 5,045 4,503 542 20,793,864 19,807,101 986,763
1997.............................. 5,252 4,729 523 21,648,366 20,664,786 983,580
</TABLE>
- ------------------------
(1) System peak demand of the Members measured at the Members' delivery points
(net of system 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 losses.
In 1997, Cobb EMC and Jackson EMC accounted for approximately 12.9% and
11.8% of Oglethorpe's total revenues, respectively. None of the other Members
accounted for as much as 10% of Oglethorpe's total revenues in 1997. Due to
greater than average growth rates, certain of Oglethorpe's customers, including
its larger customers such as Cobb EMC and Jackson EMC, have historically
accounted for an increasing percentage of Oglethorpe's total revenues. However,
under the 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 power 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
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<PAGE>
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 upgrades to these
resources. LEM pays Oglethorpe the costs associated with the 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 (primarily nuclear
units). Oglethorpe is also obligated to make available the same share of all
other
14
<PAGE>
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., 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
accordance therewith, files reports and other information with the Commission.
RELATED AGREEMENTS
Oglethorpe has contracted with GTC to provide available transmission
services to deliver to the border of the ITS any energy sold to 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 purchases 750 MW of capacity and associated energy from GPC on a
take-or-pay basis under the Block Power Sale Agreement ("BPSA"), which extends
through December 31, 2003. The capacity purchases under the BPSA are from four
Component Blocks (as defined in the BPSA), composed of two 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, 1998 and September 1, 1999.
Also, pursuant to its long-term power marketer agreements with LEM, Oglethorpe
has committed to continue reducing its purchases from GPC as permitted under the
BPSA and thus will no longer purchase any energy under the BPSA effective
September 1, 2001. (See "Power Marketer Arrangements--LEM AGREEMENTS" herein for
a discussion of the LEM agreement.)
15
<PAGE>
OTHER POWER PURCHASES
Oglethorpe purchases 100 MW of capacity from each of EPI and Big Rivers,
under agreements extending through June and July 2002, respectively. The
availability of capacity under the EPI contract is dependent on the availability
of two specific generating units available to EPI. The Tennessee Valley
Authority ("TVA") provides the transmission service to deliver the power from
the Big Rivers electric system to the ITS. TVA and Southern Company Services, as
agent for Alabama Power Company and Mississippi Power Company, provide the
transmission service necessary to deliver the power from EPI to the ITS. (See
Note 9 of Notes to Financial Statements in Item 8.)
Oglethorpe also has a contract through 2019 to purchase approximately 300 MW
of capacity from Hartwell, a partnership owned 50% by NGC Corporation and 50% by
American National Power, Inc., a subsidiary of National Power, 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. 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 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 historically made all purchases the
Members would have otherwise been required to make under PURPA and Oglethorpe
was relieved of its obligation to sell certain services to "qualifying
facilities" so long as the Members make those sales. Oglethorpe historically
provided the Members with the necessary services to fulfill these sale
obligations. Purchases by Oglethorpe from such qualifying facilities provided
0.2% of Oglethorpe's energy requirements for the Members in 1997. As a result of
the Corporate Restructuring, the Members may make such purchases in the future
instead of Oglethorpe.
Finally, Oglethorpe has contracted with Florida Power Corporation to
purchase 275 MW of peaking capacity during the summer of 1998.
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. During the term of the power marketer agreements, LEM and Morgan Stanley
will be responsible for supplying Oglethorpe with sufficient power to fulfill
these power sales.
OTHER POWER SYSTEM ARRANGEMENTS
Oglethorpe has interchange, transmission and/or short-term capacity and
energy purchase or sale agreements with over 60 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. The
development of and access to the ITS and the interconnections with other
utilities are key elements in Oglethorpe's ability to make off-system sales and
purchases through its transmission contract 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
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<PAGE>
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
<PAGE>
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 REGULATION
GENERAL
As is typical for electric utilities, Oglethorpe is subject to various
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 into the air and discharges of other pollutants,
including heat, into waters of the United States. Oglethorpe is also subject to
federal, state and local waste disposal requirements that regulate the manner of
transportation, storage and disposal of various types of waste.
In general, environmental requirements are becoming increasingly stringent.
New requirements may substantially increase the cost of electric service, by
requiring changes in the design or operation of existing facilities or 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 Oglethorpe's
units will always remain subject to the regulations currently in effect or will
always be in compliance with future regulations.
Compliance with environmental standards 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
<PAGE>
condition. Oglethorpe's direct capital costs to achieve compliance with current
environmental requirements are expected to be minimal for 1998, 1999 and 2000.
As further discussed below, however, capital costs to achieve compliance with
potential future environmental requirements could be significant.
CLEAN AIR ACT
Environmental 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. One of the principal purposes of the
1990 Amendments is to improve air quality by reducing the emissions of sulfur
dioxide and nitrogen oxides from affected utility units, which include the
coal-fired units that generate electric power at Plants Wansley and Scherer.
These sulfur dioxide reductions are being imposed through a sulfur dioxide
emission allowance trading program. 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. Allowances are issued by the U.S. Environmental Protection Agency
("EPA") to impose limited reductions on certain affected units in Phase I
(1995-1999) and more stringent reductions on all affected units in Phase II
(after the year 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
compliance at Plants Wansley and Scherer, including the use of emission
allowances (issued, banked or purchased, if needed), fuel-switching or
installation of flue gas desulfurization equipment.
A number of recently finalized regulations, proposed regulations, petitions
and on-going studies could result in more stringent controls on all emissions,
including utility emissions. The most significant of these appear to be the
following. First, because nitrogen oxides are considered to be a precursor to
ozone, coupled with the fact that metropolitan Atlanta is classified as a
"serious nonattainment area" under the one hour ozone National 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 both standards are now being made.
Third, EPA has issued a proposed regulation for the regional control of ozone
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 any source
that emits nitrogen oxides or sulfur dioxide and that 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 significantly contributing to ozone nonattainment 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 possible
that a new short-term standard for sulfur dioxide could be established. Finally,
the 1990 Amendments require that several studies be conducted regarding the
health effects from power plant emissions of certain hazardous air pollutants.
These studies, which have now been completed, indicate that further research is
needed before decisions can be made on whether additional controls of utility
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--
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Power Marketer Arrangements.") Because of the uncertainty associated with these
various developments, Oglethorpe cannot now predict the effect that any of these
potential requirements may have on the operations of Plants Wansley and/or
Scherer.
Compliance with the requirements of the Clean Air Act may also require
increased capital or operating expenses on the part of GPC. Any increases in
GPC's capital or operating expenses may cause an increase in the cost of power
purchased from GPC. (See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--Power
Purchase and Sale Arrangements--POWER PURCHASES FROM GPC.")
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 Nuclear
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. 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 the 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 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., not mixed with other wastes. Pursuant to court order, EPA
has until the Spring of 1999 to classify co-managed utility wastes as either
20
<PAGE>
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, the Endangered Species Act, the
Comprehensive Environmental Response, Compensation and Liability Act, the
Emergency Planning and Community Right to Know Act, and to the regulations
implementing these statutes. Oglethorpe does not believe that compliance with
these statutes and regulations will have a material impact on its financial
condition or results of operations. Changes to any of these laws, some of which
are being reviewed by Congress, could affect many areas of Oglethorpe's
operations. Although compliance with new environmental legislation could have a
significant impact on Oglethorpe, those impacts cannot be fully determined at
this time and would depend in part on the final legislation and the development
of implementing regulations.
The scientific community, regulatory agencies and the electric utility
industry are continuing to examine the issues of global warming and the possible
health effects of electromagnetic fields. While no definitive scientific
conclusions have been reached, 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.
OTHER INFORMATION
Information with respect to fuel supply for Oglethorpe's plants is set forth
under the caption "GENERATING FACILITIES--Fuel Supply" included in Item 2 and is
incorporated herein by reference.
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ITEM 2. PROPERTIES
GENERATING FACILITIES
GENERAL
The following table sets forth certain information with respect to the
generating facilities in which Oglethorpe currently has ownership or leasehold
interests, all of which are in commercial operation. 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.")
<TABLE>
<CAPTION>
OGLETHORPE'S
SHARE OF
NAMEPLATE COMMERCIAL LICENSE
TYPE OF PERCENTAGE CAPACITY OPERATION EXPIRATION
FACILITIES FUEL INTEREST(1) (MW) DATE DATE
- -------------------------------------------------- --------- ----------- ------------ ------------- -----------
<S> <C> <C> <C> <C> <C>
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
------------
------------
</TABLE>
- ------------------------------
(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 Nuclear Regulatory
Commission and to hydroelectric plants by FERC.
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PLANT PERFORMANCE
The following table sets forth certain operating performance information of
each of the major generating facilities in which Oglethorpe currently has
ownership or leasehold interests:
<TABLE>
<CAPTION>
EQUIVALENT AVAILABILITY(1) CAPACITY
FACTOR(2)
------------------------------------- -----------
<S> <C> <C> <C> <C>
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
<CAPTION>
<S> <C> <C>
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
</TABLE>
- ------------------------------
(1) Equivalent Availability is a measure of the percentage of time that a unit
was available to generate if called upon, adjusted for periods when the unit
is partially derated from the "maximum dependable capacity" rating.
(2) Capacity Factor is a measure of the output of a unit as a percentage of the
maximum output, based on the "maximum dependable capacity" rating, over the
period of measure.
(3) 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 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 Plant Scherer and Wansley ownership and operating 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
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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 ownership 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 will 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 responsibility to procure
nuclear fuel for Plants Hatch and Vogtle. GPC has contracted with Southern
Nuclear Operating Company ("SONOPCO"), a subsidiary of The 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 expected to be adequate to satisfy current and future nuclear generation
requirements.
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<PAGE>
CO-OWNERS OF THE PLANTS AND THE PLANT 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 operating agent for each of the other plants. (See
"The Plant Agreements" herein.)
<TABLE>
<CAPTION>
NUCLEAR COAL-FIRED
-------------------- --------------------------------------------
PLANT PLANT PLANT SCHERER UNITS
HATCH VOGTLE WANSLEY NO. 1 & NO. 2
-------------------- -------------------- -------------------- --------------------
% MW(1) % MW(1) % MW(1) % MW(1)
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Oglethorpe..... 30.0 489 30.0 696 30.0 519 60.0(2) 982
GPC............ 50.1 817 45.7 1,060 53.5 926 8.4 137
MEAG........... 17.7 288 22.7 527 15.1 261 30.2 494
Dalton......... 2.2 36 1.6 37 1.4 24 1.4 23
-------- -------- -------- -------- -------- -------- -------- --------
Total.......... 100.0 1,630 100.0 2,320 100.0 1,730 100.0 1,636
-------- -------- -------- -------- -------- -------- -------- --------
-------- -------- -------- -------- -------- -------- -------- --------
<CAPTION>
PUMPED
STORAGE
------------------------
ROCKY
MOUNTAIN
------------------------ TOTAL
% MW(1) MW(1)
---------- ---------- --------
<S> <C> <C> <C>
Oglethorpe..... 74.61 (2) 633 3,319
GPC............ 25.39 215 3,155
MEAG........... -- -- 1,570
Dalton......... -- -- 120
---------- ----- --------
Total.......... 100.00 848 8,164
---------- ----- --------
---------- ----- --------
</TABLE>
- ------------------------------
(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--
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 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.
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
<PAGE>
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 Ownership Agreements and
Operating Agreements relating to Plants Hatch and Wansley are two-party
agreements between Oglethorpe and GPC. The Ownership Agreements and Operating
Agreements relating to Plants Vogtle and Scherer are agreements among
Oglethorpe, GPC, MEAG and Dalton. The parties to each Ownership Agreement and
Operating Agreement are referred to as "Participants" with respect to each such
agreement.
SALE AND LEASEBACK TRANSACTIONS. In 1985, in four 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 (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.
In 1990, the co-owners of Plants Hatch and Vogtle entered into the Nuclear
Managing Board Agreement which amended the Plant Hatch and Plant Vogtle
Ownership and Operating Agreements, primarily with respect to GPC's reporting
requirements, but did not alter GPC's role as agent with respect to the nuclear
plants. In 1993, the co-owners entered into the Amended and Restated Nuclear
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, provides for increased rights for the co-owners regarding certain
decisions and allows 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
<PAGE>
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
amendments to the Plant Scherer Ownership and Operating Agreements, the
co-owners of Plant Scherer entered into the Plant Scherer Managing Board
Agreement which provides for a managing board (the "Plant Scherer Managing
Board") to coordinate the implementation and administration of the Plant Scherer
Ownership and Operating Agreements and provides for increased rights for the
co-owners regarding certain decisions, but does not alter GPC's role as agent
with respect to Plant Scherer.
The Operating Agreements provide that Oglethorpe is entitled to a percentage
of the net capacity and net energy output of each plant or unit equal to its
percentage undivided interest owned or leased in such plant or unit. GPC, as
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, 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.
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 (the "Co-Owners"). Pursuant to Rocky Mountain Pumped Storage
Hydroelectric Ownership Participation Agreement, by and between Oglethorpe and
GPC (the "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 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
<PAGE>
agent, sole authority and responsibility for the management, control,
maintenance and operation of Rocky Mountain.
In general, each Co-Owner is responsible for payment of its respective
ownership share of all Operating Costs and Pumping Energy Costs (as defined in
the Rocky Mountain Operating Agreement) as well as costs incurred as the result
of any separate schedule or independent dispatch. A Co-Owner's share of net
available capacity and net energy is the same as its respective ownership
interest under the Rocky Mountain Ownership Agreement. Oglethorpe and GPC have
each elected to schedule separately their respective ownership interests. The
Rocky Mountain Operating Agreement will terminate in 2035. The 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 operate Rocky
Mountain during the leaseback 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 penalties
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 use of the TVA-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 and for any resulting effect on reliability or increase in the cost of
power.
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
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.
28
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
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.
<TABLE>
<CAPTION>
(DOLLARS IN
THOUSANDS)
1997 1996 1995 1994 1993
------------ ------------ -------------------- ------------ ------------
<S> <C> <C> <C> <C> <C>
OPERATING REVENUES:
Sales to Members............ $ 1,000,319 $ 1,023,094 $ 1,030,797 $ 930,875 $ 899,720
Sales to non-Members........ 47,533 78,343 118,764 125,207 200,940
------------ ------------ ----------- ------------ ------------
TOTAL OPERATING REVENUES...... 1,047,852 1,101,437 1,149,561 1,056,082 1,100,660
------------ ------------ ----------- ------------ ------------
OPERATING EXPENSES:
Fuel........................ 206,315 206,524 219,062 203,444 176,342
Production.................. 157,932 150,787 155,549 153,174 150,027
Purchased power............. 266,875 229,089 264,844 227,477 271,970
Depreciation and
amortization.............. 126,730 163,130 139,024 131,056 128,060
Taxes....................... 26,293 30,262 27,561 24,741 25,148
Other operating expenses.... 4,032 38,896 34,844 28,783 24,821
------------ ------------ ----------- ------------ ------------
TOTAL OPERATING EXPENSES...... 788,177 818,688 840,884 768,675 776,368
------------ ------------ ----------- ------------ ------------
OPERATING MARGIN.............. 259,675 282,749 308,677 287,407 324,292
OTHER INCOME, NET............. 46,646 65,334 33,710 40,795 38,741
NET INTEREST CHARGES.......... (283,916) (326,331) (320,129) (305,120) (350,652)
------------ ------------ ----------- ------------ ------------
MARGIN BEFORE CUMULATIVE
EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE........ 22,405 21,752 22,258 23,082 12,381
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING FOR INCOME
TAXES..................... -- -- -- -- 13,340
------------ ------------ ----------- ------------ ------------
NET MARGIN.................... $ 22,405 $ 21,752 $ 22,258 $ 23,082 $ 25,721
------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ------------ ------------
ELECTRIC PLANT, NET:
In service.................. $ 3,588,204 $ 4,345,200 $ 4,436,009 $ 3,980,439 $ 4,054,956
Construction work in
progress.................. 13,578 31,181 35,753 538,789 450,965
------------ ------------ ----------- ------------ ------------
$ 3,601,782 $ 4,376,381 $ 4,471,762 $ 4,519,228 $ 4,505,921
------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ------------ ------------
TOTAL ASSETS.................. $ 4,509,857 $ 5,362,175 $ 5,438,496 $ 5,346,330 $ 5,323,890
------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ------------ ------------
CAPITALIZATION:
Long-term debt.............. $ 3,258,046 $ 4,052,470 $ 4,207,320 $ 4,128,080 $ 4,058,251
Obligation under capital
leases.................... 288,638 293,682 296,478 303,749 303,458
Other obligations........... 52,176 41,685 -- -- --
Patronage capital and
membership fees............. 330,509 356,229 338,891 309,496 289,982
------------ ------------ ----------- ------------ ------------
$ 3,929,369 $ 4,744,066 $ 4,842,689 $ 4,741,325 $ 4,651,691
------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ------------ ------------
PROPERTY ADDITIONS............ $ 63,527 $ 93,704 $ 138,921 $ 206,345 $ 235,285
------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ------------ ------------
ENERGY SUPPLY (MEGAWATT-
HOURS):
Generated................... 17,722,059 17,866,143 18,402,839 16,924,038 14,575,920
Purchased................... 6,377,643 6,606,931 5,738,634 4,381,087 7,620,815
------------ ------------ ----------- ------------ ------------
Available for sale.......... 24,099,702 24,473,074 24,141,473 21,305,125 22,196,735
------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ------------ ------------
MEMBER REVENUE PER KWH SOLD... 4.83 cents 5.11 cents 5.53 cents 5.65 cents 5.47 cents
------------ ------------ ----------- ------------ ------------
------------ ------------ ----------- ------------ ------------
</TABLE>
29
<PAGE>
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. Retained net margins are designated on Oglethorpe's
balance sheets as patronage capital, which is allocated to each of the Members
on the basis of its electricity purchases from Oglethorpe. Since its formation
in 1974, Oglethorpe has generated a positive net margin in each year.
Oglethorpe's equity ratio (patronage capital and membership fees divided by
total capitalization) increased from 7.5% at December 31, 1996 to 8.4% at
December 31, 1997.
In connection with the Corporate Restructuring, Oglethorpe made a $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 from $356 million at
December 31, 1996, to $331 million at December 31, 1997.
Patronage capital constitutes the principal equity of Oglethorpe. Any
distributions of patronage capital are subject to the discretion of the Board
of Directors, subject to Indenture rerquirements. Under the Indenture, 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 Members if, at the time thereof or after 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
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
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 REGULATION
Pursuant to the Amended and Restated Wholesale Power Contracts between
Oglethorpe and each of 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, to establish and maintain reasonable 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 established to recover actual fuel and variable
operations and maintenance costs.
In 1995, Oglethorpe implemented two new 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 1995 and introduced
some variability and uncertainty as to the level of revenues and margins to be
received. Due to extreme weather conditions and other factors, the 1995 rates
options produced $2.5 million of revenues in excess
30
<PAGE>
of budgeted amounts. Such excess amounts were returned to the Members in 1996.
Under a capacity rate mechanism effective throughout 1996, each Member was
responsible for an assigned share of fixed costs based on an agreed-upon
allocation. Under this approach, capacity costs were collected in equal monthly
amounts. This interim rate mechanism was extended through March 31, 1997 until a
new rate schedule became effective under the Wholesale Power Contracts on April
1, 1997, in connection with the Corporate Restructuring. This new rate schedule
implements on a long-term basis the assignment of responsibility for fixed
costs. The monthly charges for capacity and other non-energy charges are based
on a rate formula using the Oglethorpe budget. 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
margins (after certain defined adjustments), (ii) Interest Charges and (iii)
any amount included in net 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 such losses or expenditures.
The rate schedule 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 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 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 federal or state agency or authority,
including the Georgia Public Service Commission.
Prior to 1997, Oglethorpe utilized a Times Interest Earned Ratio ("TIER") as
the basis for establishing its annual net margin goal. Under Oglethorpe's prior
mortgage, Oglethorpe was required to implement rates that were 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 1995 and 1996, and such TIER was achieved in each year. In addition to
the TIER requirement under the prior mortgage, Oglethorpe was also required
under the prior mortgage to implement rates designed to maintain a Debt Service
Coverage Ratio ("DSC") of not less than 1.0 and an Annual Debt Service Coverage
Ratio ("ADSCR") of not less than 1.25. Oglethorpe always met or exceeded the
TIER, DSC and ADSCR requirements 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 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 (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
<PAGE>
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 prior mortgage (excluding interest charged to construction).
RESULTS OF OPERATIONS
HISTORICAL FACTORS AFFECTING FINANCIAL PERFORMANCE
Oglethorpe has utilized 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 Members 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 this 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 Members and with 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 term 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
<PAGE>
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 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:
<TABLE>
<CAPTION>
KILOWATT-HOURS CENTS PER
(IN THOUSANDS) KILOWATT-HOUR
------------------- -------------------
<S> <C> <C>
1997..... 20,664,786 4.83(1)
1996..... 19,807,101 5.11
1995..... 18,442,153 5.53
</TABLE>
- ------------------------
(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:
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ----------
<S> <C> <C> <C>
(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
--------- --------- ----------
--------- --------- ----------
</TABLE>
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 Oglethorpe. Oglethorpe sells for its own account any energy
available from the portion of its resources dedicated to Morgan 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 power 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
<PAGE>
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
<PAGE>
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
retention 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
<PAGE>
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.
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES
(DOLLARS IN THOUSANDS)
------------------------------------------------------------
GENERATING NUCLEAR GENERAL
YEAR PLANT(1) FUEL PLANT AFUDC(2) TOTAL
- -------------------------- ----------- ---------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C>
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
--------- ---------- --------- --------- ----------
--------- ---------- --------- --------- ----------
</TABLE>
- ------------------------
(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 and 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 consistently 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):
<TABLE>
<CAPTION>
SHORT-TERM CREDIT FACILITIES AMOUNT
- ---------------------------------------------------------- --------------
<S> <C>
Commercial Paper.......................................... $ 280,000,000
Committed lines of credit: SunTrust Bank.................. 30,000,000
Uncommitted lines of credit: CFC.......................... 50,000,000
</TABLE>
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
<PAGE>
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 to reduce the average
interest rate on Oglethorpe's total 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 annual 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 preserve 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
year 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 future.
Also, 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 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 these two swap transactions.
In connection with GTC's assumption of liability on a portion of the PCBs
pursuant to the Corporate 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 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, 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
<PAGE>
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 Fixed Rate.
Under the terms of the swap agreements, AIG-FP has limited rights to
terminate the swaps only upon the occurrence of specified events of default
or a reduction in ratings on Oglethorpe's PCBs, without credit enhancement,
to a level that is below investment grade. Oglethorpe estimates that its
maximum aggregate liability (net of GTC's assumed percentage) for termination
payments under both swap arrangements had such payments been due on December
31, 1997 would have been approximately $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 principal amount of 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 lien 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
<PAGE>
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." Note 1 of
Notes to Financial Statements sets forth the regulatory assets and
liabilities reflected on Oglethorpe's balance sheet as of December 31, 1997.
Regulatory assets represent probable future revenues to 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 SFAS No. 71, Oglethorpe would be required to write off
regulatory assets and liabilities. In addition, Oglethorpe would be required
to determine any
39
<PAGE>
impairment to other assets, including plant, and write down the assets, if
impaired, to their fair value.
At this time, Oglethorpe cannot predict the outcome of the various
developments that may lead to 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 an offsetting asset for differences in the timing of
recognition of the costs of decommissioning for financial reporting and
ratemaking 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 due to available amounts
that have been placed in reserves for this purpose.
INFLATION
As with utilities generally, inflation has the effect of increasing the
cost of Oglethorpe's operations and construction program. Operating and
construction costs have been less affected by inflation over the last few
years because rates of inflation have been relatively low.
YEAR 2000 ISSUE
Many information systems have been designed to function based on years
that begin with "19". Oglethorpe expects that by the year 2000 it will have
adapted its systems, 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 business and (ii) Oglethorpe's future liquidity requirements and
capital resources. These forward-looking statements are based largely on
Oglethorpe's expectations and are subject to a number of risks and
uncertainties, certain of which are beyond Oglethorpe's control. For factors
that could cause actual results to differ materially from those anticipated
by these forward-looking statements, see "Competition" herein and "CERTAIN
FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY" in Item 1. In light of these
risks and uncertainties, there can be no assurance that events anticipated by
the forward-looking statements contained in this Annual Report will in fact
transpire.
40
<PAGE>
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Not Applicable.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
-----
<S> <C>
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
</TABLE>
41
<PAGE>
STATEMENTS OF REVENUE AND EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
<TABLE>
<CAPTION>
(dollars in thousands)
1997 1996 1995
------------ ------------ ------------
<S> <C> <C> <C> <C>
OPERATING REVENUES (NOTE 1):
Sales to Members.......................................... $ 1,000,319 $ 1,023,094 $ 1,030,797
Sales to non-Members...................................... 47,533 78,343 118,764
------------ ------------ ------------
TOTAL OPERATING REVENUES.................................... 1,047,852 1,101,437 1,149,561
------------ ------------ ------------
OPERATING EXPENSES:
Fuel...................................................... 206,315 206,524 219,062
Production................................................ 157,932 150,787 155,549
Purchased power (Note 9).................................. 266,875 229,089 264,844
Power delivery............................................ 4,032 18,216 17,520
Depreciation and amortization............................. 126,730 163,130 139,024
Taxes other than income taxes............................. 26,293 30,262 27,561
Income taxes (Note 3)..................................... -- -- --
Other operating expenses.................................. -- 20,680 17,324
------------ ------------ ------------
TOTAL OPERATING EXPENSES.................................... 788,177 818,688 840,884
------------ ------------ ------------
OPERATING MARGIN............................................ 259,675 282,749 308,677
------------ ------------ ------------
OTHER INCOME (EXPENSE):
Interest income........................................... 29,303 23,485 18,031
Amortization of deferred gains (Notes 1 and 4)............ 2,441 2,341 2,341
Amortization of net benefit of sale of income tax benefits
(Note 1)................................................ 11,195 8,054 8,043
Amortization of deferred margins (Note 1)................. -- 32,047 15,959
Deferred margins (Note 1)................................. -- -- (14,282)
Allowance for equity funds used during construction
(Note 1)................................................ 157 238 1,715
Other..................................................... 3,550 (831) 1,903
------------ ------------ ------------
TOTAL OTHER INCOME.......................................... 46,646 65,334 33,710
------------ ------------ ------------
INTEREST CHARGES:
Interest on long-term debt and capital leases............. 261,290 308,013 317,968
Other interest............................................ 13,845 10,006 12,979
Allowance for debt funds used during construction
(Note 1)................................................ (1,674) (2,576) (21,114)
Amortization of debt discount and expense................. 10,455 10,888 10,296
------------ ------------ ------------
NET INTEREST CHARGES........................................ 283,916 326,331 320,129
------------ ------------ ------------
NET MARGIN.................................................. $ 22,405 $ 21,752 $ 22,258
------------ ------------ ------------
------------ ------------ ------------
</TABLE>
STATEMENTS OF PATRONAGE CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
<TABLE>
<CAPTION>
(dollars in thousands)
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Patronage capital and membership fees--beginning of year (Note 1)............ $ 356,229 $ 338,891 $ 309,496
Net margin................................................................... 22,405 21,752 22,258
Special 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
---------- ---------- ----------
Patronage capital and membership fees-end of year............................ $ 330,509 $ 356,229 $ 338,891
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
The accompanying notes are an integral part of these financial statements.
42
<PAGE>
BALANCE SHEETS
DECEMBER 31, 1997 AND 1996
<TABLE>
<CAPTION>
(dollars in thousands)
ASSETS 1997 1996
------------ ------------
<S> <C> <C>
ELECTRIC PLANT (NOTES 1, 4 AND 6):
In service............................................................ $ 4,910,067 $ 5,742,597
Less: Accumulated provision for depreciation.......................... (1,412,287) (1,488,272)
------------ ------------
3,497,780 4,254,325
Nuclear fuel, at amortized cost....................................... 90,424 86,722
Plant acquisition adjustments, at amortized cost...................... -- 4,153
Construction work in 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....................... 33,161 53,955
Investment in associated organizations, at 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)................. 63,215 132,783
Other short-term investments, at market............................... 97,021 91,499
Receivables........................................................... 105,993 113,289
Inventories, at average cost (Note 1)................................. 65,528 89,825
Prepayments and other current assets.................................. 12,530 14,625
------------ ------------
344,287 442,021
------------ ------------
DEFERRED CHARGES:
Premium and loss on reacquired debt, being amortized (Note 5)......... 196,583 201,007
Deferred amortization of Scherer leasehold (Note 4)................... 96,303 90,717
Deferred debt expense, being amortized................................ 15,345 21,703
Other (Note 1)........................................................ 43,823 33,058
------------ ------------
352,054 346,485
------------ ------------
$ 4,509,857 $ 5,362,175
------------ ------------
------------ ------------
</TABLE>
The accompanying notes are an integral part of these financial statements.
43
<PAGE>
<TABLE>
<CAPTION>
(dollars in thousands)
EQUITY AND LIABILITIES 1997 1996
------------ ------------
<S> <C> <C>
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS):
Patronage capital and membership fees (Note 1)...................................... $ 330,509 $ 356,229
Long-term debt...................................................................... 3,258,046 4,052,470
Obligation under capital leases (Note 4)............................................ 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............................... 89,556 159,622
Accounts payable.................................................................... 51,103 42,891
Accrued interest.................................................................... 12,961 15,931
Accrued and withheld taxes.......................................................... 517 4,940
Other current liabilities........................................................... 8,428 14,022
------------ ------------
162,565 237,406
------------ ------------
DEFERRED CREDITS AND OTHER LIABILITIES:
Gain on sale of plant, being amortized (Note 4)..................................... 60,756 58,527
Net benefit of sale of income tax benefits, being amortized (Note 1)................ 34,039 42,049
Net benefit of Rocky Mountain transactions, being amortized (Note 1)................ 92,375 70,701
Accumulated deferred income taxes (Note 3).......................................... 63,117 61,985
Decommissioning reserve (Note 1).................................................... 142,354 124,468
Other............................................................................... 25,282 22,973
------------ ------------
417,923 380,703
------------ ------------
COMMITMENTS AND CONTINGENCIES (NOTES 4 AND 9)
$ 4,509,857 $ 5,362,175
------------ ------------
------------ ------------
</TABLE>
44
<PAGE>
STATEMENTS OF CAPITALIZATION
DECEMBER 31, 1997 AND 1996
<TABLE>
<CAPTION>
(dollars in
thousands)
<S> <C> <C>
1997 1996
--------- ---------
LONG-TERM DEBT (NOTE 5):
Mortgage notes payable to the Federal Financing Bank (FFB) at
interest rates varying from 5.27% to 8.43% (average rate of 6.89%
at December 31, 1997) due in quarterly installments through
2023............................................................. $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..... 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 1996
Adjustable rate bonds, 3.90% to May 1998, due in 2017.......... 37,885 37,885
CoBank, ACB notes payable:
- Headquarters note payable: fixed at 6.46% through August 1998,
due in quarterly installments through January 1, 2009.......... 4,380 4,672
- Transmission note payable: fixed at 6.78% through February
1998; due in bimonthly installments through November 1, 2018... 1,844 2,237
- Transmission note payable: fixed at 6.61% through February
1998; due in bimonthly installments through September 1,
2019........................................................... 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.................................... -- (766)
--------- ---------
Total long-term debt, net.......................................... 3,341,167 4,208,005
Less:Long-term debt due within one year............................ (83,121) (155,535)
--------- ---------
TOTAL LONG-TERM DEBT, EXCLUDING AMOUNT DUE WITHIN ONE YEAR........... 3,258,046 4,052,470
OBLIGATION UNDER CAPITAL LEASES, LONG-TERM (NOTE 4).................. 288,638 293,682
OBLIGATION UNDER ROCKY MOUNTAIN TRANSACTIONS, LONG-TERM (NOTE 1)..... 52,176 41,685
PATRONAGE CAPITAL AND MEMBERSHIP FEES (NOTE 1)....................... 330,509 356,229
--------- ---------
TOTAL CAPITALIZATION................................................. $3,929,369 $4,744,066
--------- ---------
--------- ---------
</TABLE>
The accompanying notes are an integral part of these financial statements.
45
<PAGE>
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS)
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net margin........................................................................ $ 22,405 $ 21,752 $ 22,258
--------- --------- ---------
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization................................................. 171,573 196,593 196,920
Net benefit of Rocky Mountain transactions.................................... 21,673 70,701 --
Interest on decommissioning reserve........................................... 12,113 7,167 9,951
Amortization of deferred gains................................................ (2,441) (2,341) (2,341)
Deferred margins and amortization of deferred margins......................... -- (32,047) (1,677)
Amortization of net benefit of sale of income tax benefits.................... (11,195) (8,145) (8,043)
Allowance for equity funds used during construction........................... (157) (238) (1,715)
Deferred income taxes......................................................... 1,132 (3,525) --
Option payment on power swap agreement........................................ (2,042) (3,750) --
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................................................................... 7,297 (13,731) (10,686)
Inventories................................................................... 15,316 (6,875) 12,127
Prepayments and other current assets.......................................... 2,025 (299) 532
Accounts payable.............................................................. 8,797 (5,964) (4,066)
Accrued interest.............................................................. (2,850) (75,165) (8,914)
Accrued and withheld taxes.................................................... (4,423) 3,155 219
Other current liabilities..................................................... 2,903 (3,985) (169)
--------- --------- ---------
Total adjustments................................................................. 219,718 121,538 182,125
--------- --------- ---------
NET CASH PROVIDED BY OPERATING ACTIVITIES........................................... 242,123 143,290 204,383
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions.............................................................. (63,527) (93,704) (138,921)
Activity in decommissioning fund--Purchases..................................... (435,799) (327,233) (410,597)
--Proceeds...................................... 419,930 316,542 399,077
Activity in bond, reserve and construction funds--Purchases..................... (35,646) (107,890) (27,762)
--Proceeds...................... 57,035 109,230 39,566
Activity in other short-term investments--Purchases............................. (5,380) (15,532) (76,180)
Increase (decrease) in investment in associated organizations................... (561) 474 1,518
Net cash received in Corporate Restructuring (Note 11).......................... 24,540 -- --
--------- --------- ---------
NET CASH USED IN INVESTING ACTIVITIES............................................... (39,408) (118,113) (213,299)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Debt proceeds, net.............................................................. 5,671 2,243 132,874
Debt payments................................................................... (229,242) (95,367) (108,481)
Return of Vogtle surcharge...................................................... -- -- (3,320)
Special patronage capital distribution.......................................... (48,863) -- --
Other......................................................................... 151 (421) (1,648)
--------- --------- ---------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES................................. (272,283) (93,545) 19,425
--------- --------- ---------
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS...................... (69,568) (68,368) 10,509
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR............................ 132,783 201,151 190,642
--------- --------- ---------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR.................................. $ 63,215 $ 132,783 $ 201,151
--------- --------- ---------
--------- --------- ---------
CASH PAID FOR:
Interest (net of amounts capitalized)........................................... $ 277,294 $ 383,440 $ 308,797
Income taxes.................................................................... 830 -- --
</TABLE>
The accompanying notes are an integral part of these financial statements.
46
<PAGE>
NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1997, 1996 AND 1995
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. BUSINESS DESCRIPTION
Oglethorpe Power Corporation (Oglethorpe) is an electric membership
corporation incorporated in 1974 and headquartered in suburban Atlanta.
Oglethorpe provides wholesale electric service, on a not-for-profit basis, to 39
of Georgia's 42 Electric Membership Corporations (EMCs). These 39 electric
distribution cooperatives (Members) in turn distribute energy on a retail basis
to approximately 2.8 million people across two-thirds of the State. Oglethorpe
is the nation's largest electric cooperative in terms of operating revenues,
assets, kilowatt-hour sales and, through its Members, consumers served.
Oglethorpe owns or leases undivided interests in thirteen generating units
totaling 3,335 megawatts (MW) of capacity. Oglethorpe also purchases a total of
1,250 MW of power pursuant to power purchase agreements. In addition Oglethorpe
has contracted to purchase 435 MW of peaking 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 electric industry.
Oglethorpe's transmission business was sold to, and is now owned and operated by
Georgia Transmission 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).
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, 1997 and 1996
and the reported amounts of revenues and expenses for each of the three years
ending December 31, 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.
Any distributions of patronage capital are subject to the discretion of
the Board of Directors, subject to Indenture requirements. Under the Mortgage
Indenture, Oglethorpe is prohibited from making any distribution of patronage
capital to the Members 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 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 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.
D. MARGIN POLICY
Under Oglethorpe's prior RUS mortgage, Oglethorpe's margin policy was based
on the provision of a Times Interest Earned Ratio (TIER) established annually by
the Oglethorpe Board of Directors. Pursuant to this policy, the annual net
margin goal for 1996 and 1995 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
<PAGE>
annual margin goals be deferred and used to mitigate rate increases associated
with Plant Vogtle and Rocky Mountain. In addition, during 1986 and 1987,
Oglethorpe's wholesale electric rate to its Members provided for a one mill per
kilowatt-hour charge (Vogtle Surcharge), also to be used to mitigate the effect
of Plant Vogtle on rates.
Pursuant to rate actions by Oglethorpe's Board of Directors, specified
amounts of deferred margins and Vogtle Surcharge were returned in 1989 through
1995 and all remaining amounts were returned in 1996.
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, respectively, of Oglethorpe's total operating revenues.
F. NUCLEAR FUEL COST
The cost of nuclear fuel, including a provision for the disposal of spent
fuel, is being amortized to fuel expense based on usage. The total nuclear fuel
expense for 1997, 1996 and 1995 amounted to $47,123,000, $49,298,000 and
$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 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.
The Plant Hatch spent fuel storage is expected to be sufficient into 2003. The
Plant Vogtle spent fuel storage is expected to be sufficient into 2008.
Activities for adding dry cask storage capacity at Plant Hatch by 2000 are in
progress.
The Energy Policy Act of 1992 required that utilities with nuclear plants be
assessed over a 15-year period an amount which will be used by DOE for the
decontamination and decommissioning of its nuclear fuel enrichment facilities.
The amount of each utility's assessment was based on its past purchases of
nuclear fuel enrichment services from DOE. Based on its ownership in Plants
Hatch and Vogtle, Oglethorpe has a remaining nuclear fuel asset of approximately
$13,500,000, which is being amortized to nuclear fuel expense over the next 10
years. Oglethorpe has also recorded an obligation to DOE which approximated
$10,600,000 at December 31, 1997.
G. NUCLEAR DECOMMISSIONING
Oglethorpe's portion of the costs of decommissioning co-owned nuclear
facilities is estimated as follows:
<TABLE>
<CAPTION>
HATCH HATCH VOGTLE VOGTLE
(DOLLARS IN THOUSANDS) UNIT NO. 1 UNIT NO. 2 UNIT NO. 1 UNIT NO. 2
- ----------------------------------------------------------------- ----------- ---------- ----------- ----------
<S> <C> <C> <C> <C>
Year of site study............................................... 1994 1994 1994 1994
Expected start date of decommissioning........................... 2014 2018 2027 2029
Decommissioning cost:
Discounted....................................................... $ 92,000 $ 109,000 $ 82,000 $ 106,000
Undiscounted..................................................... 157,000 207,000 198,000 271,000
</TABLE>
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in regulatory requirements, changes in technology, and
changes in costs of labor, materials and equipment.
The annual provision for decommissioning for 1997, 1996 and 1995 was
$2,597,000, $2,597,000 and $4,156,000, respectively. In developing the amount of
the annual provision for 1997 and 1998, the escalation rate was assumed to be
2.72% and return on trust assets was assumed to be 8%. Oglethorpe accounts for
this provision for decommissioning as depreciation expense with an offsetting
credit to a decommissioning reserve. Oglethorpe's management is of the opinion
that any changes in cost estimates of decommissioning can be recovered in future
rates.
In compliance with a Nuclear Regulatory Commission (NRC) regulation,
Oglethorpe maintains an external trust fund to provide for a portion of the cost
of decommissioning its nuclear facilities. The NRC regulation requires funding
levels based on average expected cost to decommission only the radioactive
portions of a typical nuclear facility. Oglethorpe's decommissioning reserve
reflects its obligation to decommission both the radioactive and most of the
non-radioactive portions of its nuclear facilities.
Realized investment earnings from the external trust fund, while increasing
the fund and interest income, also are applied to the decommissioning
48
<PAGE>
reserve and charged to interest expense. Interest income earned from the
external trust fund is offset by the recognition of interest expense such
that there is no effect on Oglethorpe's net margin.
H. DEPRECIATION
Depreciation is computed on additions when they are placed in service using
the composite straight-line method. Annual depreciation rates in effect in 1997,
1996 and 1995 were as follows:
<TABLE>
<CAPTION>
1997 1996 1995
----------- ----------- -----------
<S> <C> <C> <C>
Steam production......................................................... 2.13% 2.13% 2.13%
Nuclear production....................................................... 2.74% 2.73% 2.78%
Hydro production......................................................... 2.00% 2.00% 2.00%
Other production......................................................... 3.75% 3.75% 3.75%
Transmission............................................................. 2.75% 2.75% 2.75%
Distribution............................................................. 2.88% 2.88% 2.88%
General.................................................................. 2.00-20.00% 2.00-20.00% 2.00-20.00%
</TABLE>
I. ELECTRIC PLANT
Electric plant is stated at original cost, which is the cost of the plant
when first dedicated to public service, plus the cost of any subsequent
additions. Cost includes an allowance for the cost of equity and debt funds used
during construction. The cost of equity and debt funds is calculated at the
embedded cost of all such funds. The plant acquisition adjustments represent the
excess of the cost of the plant to Oglethorpe over the original cost, less
accumulated depreciation at the time of acquisition, and are being amortized
over a ten-year period.
Maintenance and repairs of property and replacements and renewals of items
determined to be less than units of property are charged to expense.
Replacements and renewals of items considered to be units of property are
charged to the plant accounts. At the time properties are disposed of, the
original cost, plus cost of removal, less salvage of such property, is charged
to the accumulated provision for depreciation.
J. BOND, RESERVE AND CONSTRUCTION FUNDS:
Bond, reserve and construction funds for pollution control 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, 1997 and 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, 1997 and 1996, fossil fuels inventories were $7,288,000 and
$23,062,000, respectively. Inventories for spare parts at December 31, 1997 and
1996 were $58,240,000 and $66,763,000, respectively.
M. DEFERRED CHARGES
Prior to 1996, Oglethorpe expensed nuclear refueling outage costs as
incurred. In 1996, Oglethorpe began accounting for these costs on a
normalized basis. Under this method of accounting, refueling outage costs are
deferred and subsequently amortized to expense over the 18-month operating
cycle of each unit. Deferred nuclear outage costs at December 31, 1997 and
1996 were $19,802,000 and $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 $5,947,000 are reflected as deferred charges on the
accompanying balance sheets. In 1995, Oglethorpe's Board of Directors authorized
that these project costs be amortized and fully recovered through future rates
over a period of 15 years beginning in that year.
49
<PAGE>
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 net benefits as a
deferred credit and is amortizing the amount over the 20-year term of the
leases.
In December 1996 and January 1997, Oglethorpe entered into long-term lease
transactions for its 74.6% undivided ownership interest in the Rocky Mountain
Pumped Storage Hydroelectric Project (Rocky Mountain). The lease transactions
are characterized as a sale and lease-back for income tax purposes, but not for
financial reporting purposes. As a result of these leases, Oglethorpe recorded a
net benefit of $95,560,000 which was deferred and is being amortized to income
over 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, 1997 and 1996:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996
- ------------------------------------------------------------------------------------------ ---------- ----------
<S> <C> <C>
Premium and loss on reacquired debt....................................................... $ 196,583 $ 201,007
Deferred amortization of Scherer leasehold................................................ 96,303 90,717
Other regulatory assets................................................................... 38,318 29,934
Net benefit of sale of income tax benefits................................................ (34,039) (42,049)
Net benefit of Rocky Mountain transactions................................................ (92,375) (70,701)
---------- ----------
$ 204,790 $ 208,908
---------- ----------
---------- ----------
</TABLE>
In the event that Oglethorpe is no longer subject to the provisions of
Statement No. 71, Oglethorpe would be required to write off related regulatory
assets and liabilities. In addition, Oglethorpe would be required to determine
any impairment to other assets, including plant, and write down the assets, if
impaired, to their fair value.
P. PRESENTATION
Certain prior year amounts have been reclassified to conform with current
year presentation.
50
<PAGE>
2. FAIR VALUE OF FINANCIAL INSTRUMENTS:
A detail of the estimated fair values of Oglethorpe's financial instruments
as of December 31, 1997 and 1996 is as follows:
<TABLE>
<CAPTION>
1997 1996
-------------------------- --------------------------
FAIR FAIR
(DOLLARS IN THOUSANDS) COST VALUE COST VALUE
- --------------------------------------------------------- ------------ ------------ ------------ ------------
<S> <C> <C> <C> <C>
CASH AND TEMPORARY
CASH INVESTMENTS:
Commercial paper....................................... $ 62,772 $ 62,772 $ 52,700 $ 52,700
Certificates of deposit................................ -- -- 10,000 10,000
Cash and money market securities....................... 443 443 70,083 70,083
------------ ------------ ------------ ------------
TOTAL.................................................... $ 63,215 $ 63,215 $ 132,783 $ 132,783
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
OTHER SHORT TERM INVESTMENTS:
Commingled investment fund............................. $ 97,092 $ 97,021 $ 91,712 $ 91,499
------------ ------------ ------------ ------------
TOTAL.................................................... $ 97,092 $ 97,021 $ 91,712 $ 91,499
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
BOND, RESERVE AND CONSTRUCTION FUNDS:
U. S. Government securities............................ $ 20,542 $ 20,505 $ 36,505 $ 35,873
Repurchase agreements.................................. 12,655 12,656 18,082 18,082
------------ ------------ ------------ ------------
TOTAL.................................................... $ 33,197 $ 33,161 $ 54,587 $ 53,955
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
DECOMMISSIONING FUND:
U. S. Government securities............................ $ 21,070 $ 21,668 $ 24,034 $ 23,950
Foreign government securities.......................... 641 695 1,228 1,278
Commercial paper....................................... 5,507 5,506 -- --
Corporate bonds........................................ 12,537 12,967 11,953 11,868
Equity securities...................................... 45,044 51,252 30,339 34,073
Asset-backed securities................................ 9,202 9,237 3,103 3,125
Other bonds............................................ -- -- 5,445 5,453
Cash and money market securities....................... 4,492 4,492 6,522 6,522
------------ ------------ ------------ ------------
TOTAL.................................................... $ 98,493 $ 105,817 $ 82,624 $ 86,269
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
LONG-TERM DEBT........................................... $ 3,258,046 $ 3,497,842 $ 4,052,470 $ 4,162,670
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
INTEREST RATE SWAP (UNREALIZED LOSS)..................... $ -- $ (38,349) $ -- $ (33,938)
------------ ------------ ------------ ------------
------------ ------------ ------------ ------------
</TABLE>
The contractual maturities of debt securities available for sale at December
31, 1997 and 1996, regardless of their balance sheet classification, are as
follows:
<TABLE>
<CAPTION>
1997 1996
-------------------- --------------------
FAIR FAIR
(DOLLARS IN THOUSANDS) COST VALUE COST VALUE
- ---------------------------------------------------------------------- --------- --------- --------- ---------
<S> <C> <C> <C> <C>
Due within one year................................................... $ 14,147 $ 14,158 $ 33,944 $ 33,819
Due after one year through five years................................. 18,798 18,825 17,439 17,266
Due after five years through ten years................................ 22,677 22,781 27,912 27,302
Due after ten years................................................... 21,025 21,964 15,610 15,789
--------- --------- --------- ---------
$ 76,647 $ 77,728 $ 94,905 $ 94,176
--------- --------- --------- ---------
--------- --------- --------- ---------
</TABLE>
Oglethorpe uses the methods and assumptions described below to estimate the
fair value of each class of financial instruments. For cash and temporary cash
investments, the carrying amount approximates fair value because of the
short-term maturity of those instruments. The fair value of Oglethorpe's
long-term debt and the swap arrangements is estimated based on the quoted market
prices for the same or similar issues or on the current rates offered to
Oglethorpe for debt of similar maturities.
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 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, 1997 and 1996 was 3.65% and 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, 1997 and 1996 was 3.65% and 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.
Oglethorpe's portion of the estimated fair value of the swap arrangements at
December 31, 1997 and 1996 was an unrealized loss of $38,349,000 and
$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.
51
<PAGE>
Under Statement of Financial Accounting Standards No. 115, "Accounting for
Certain Investments in Debt and Equity Securities," 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, 1997 were $12,800,000 and $5,583,000, respectively. Gross
unrealized gains and losses at December 31, 1996 were $7,785,000 and $4,985,000
respectively. For 1997 and 1996, proceeds from sales of available-for-sale
securities totaled $476,965,000 and $425,772,000, respectively. Gross realized
gains and losses from the 1997 sales were $11,415,000 and $3,010,000,
respectively. Gross realized gains and losses from the 1996 sales were
$6,410,000 and $3,671,000, respectively.
Investments in associated organizations were as follows at December 31, 1997
and 1996:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996
- -------------------------------------------------------------------------------------------- --------- ---------
<S> <C> <C>
National Rural Utilities Cooperative Finance Corp. (CFC).................................... $ 13,476 $ 13,476
CoBank, ACB................................................................................. 1,955 1,664
Other....................................................................................... 509 239
--------- ---------
Total....................................................................................... $ 15,940 $ 15,379
--------- ---------
--------- ---------
</TABLE>
The investments in these associated organizations are similar to
compensating bank balances in that they are required in order to maintain
current financing arrangements. Accordingly, there is no market for these
investments.
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 and
state income taxes. As a taxable electric cooperative, Oglethorpe has annually
allocated its income and deductions between Member and non-Member activities.
Any Member taxable income has been offset with a patronage exclusion and member
loss carryforwards.
Oglethorpe accounts for its income taxes pursuant to Statement of Financial
Accounting Standards (SFAS) No. 109. SFAS No. 109 requires the recognition of
deferred tax assets and liabilities for the expected future tax consequences of
events that have been included in the financial statements or tax returns.
A detail of the provision for income taxes in 1997, 1996 and 1995 is shown
as follows:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996 1995
- --------------------------------------------------------------------------------------- --------- --------- -------
<S> <C> <C> <C>
Current
Federal.............................................................................. $ (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..................................................... $ -- $ -- $ --
--------- --------- --------
--------- --------- --------
</TABLE>
The difference between the statutory federal income tax rate on income
before income taxes and Oglethorpe's effective income tax rate is summarized as
follows:
<TABLE>
<CAPTION>
1997 1996 1995
--------- --------- ---------
<S> <C> <C> <C>
Statutory federal income tax rate............... 35.0% 35.0% 35.0%
Patronage exclusion............................. (35.4)% (35.7%) (35.6%)
Other........................................... 0.4% 0.7% 0.6%
--------- --------- ---------
Effective income tax rate....................... 0.0% 0.0% 0.0%
--------- --------- ---------
--------- --------- ---------
</TABLE>
52
<PAGE>
The components of the net deferred tax liabilities as of December 31, 1997
and 1996 were as follows:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996
- ------------------------------------------- ----------- -----------
<S> <C> <C>
DEFERRED TAX ASSETS
Net operating losses....................... $ 444,590 $ 473,114
Member loss carryforwards.................. 189,414 328,912
Tax credits (alternative minimum tax and
other)................................... 243,707 256,205
Accounting for Rocky Mountain
transactions............................. 213,575 233,045
Accounting for sale of income tax
benefits................................. 75,041 77,429
Accrued nuclear decommissioning expense.... 51,713 49,127
Accounting for asset dispositions.......... 31,584 32,545
Other...................................... 2,742 3,318
----------- -----------
1,252,366 1,453,695
Less: Valuation allowance.................. (241,483) (252,680)
----------- -----------
1,010,883 1,201,015
----------- -----------
DEFERRED TAX LIABILITIES
Depreciation............................... (848,585) (1,008,714)
Accounting for Rocky Mountain
transactions............................. (145,805) (156,557)
Accounting for debt extinguishment......... (61,094) (64,841)
Other...................................... (18,516) (32,888)
----------- -----------
(1,074,000) (1,263,000)
----------- -----------
Net deferred tax liabilities............... $ (63,117) (61,985)
----------- -----------
----------- -----------
</TABLE>
As of December 31, 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:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS)
- -----------------------------------------------------------------------------------------
ALTERNATIVE
MINIMUM
EXPIRATION DATE TAX CREDITS TAX CREDITS NOLS
- ------------------------------------------------- ----------- ----------- ------------
<S> <C> <C> <C>
1998............................................. -- 6,934 --
1999............................................. -- 37,206 --
2000............................................. -- 3,198 --
2001............................................. -- 7,264 --
2002............................................. -- 130,377 --
2003............................................. -- 652 250,461
2004............................................. -- 55,663 114,285
2005............................................. -- 189 213,080
2006............................................. -- -- 209,009
2007............................................. -- -- 86,779
2008............................................. -- -- 94,927
2009............................................. -- -- 96,394
2010............................................. -- -- 77,970
None............................................. 2,224 -- --
----------- ----------- ------------
$ 2,224 $ 241,483 $1,142,905
----------- ----------- ------------
----------- ----------- ------------
</TABLE>
Based on Oglethorpe's historical taxable transactions, the timing of the
reversal of existing temporary differences, future income, and tax planning
strategies, it is more likely than not that Oglethorpe's future taxable income
will be sufficient to realize the benefit of 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, 1997 are as follows:
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, (DOLLARS IN THOUSANDS)
- --------------------------------------------- ----------------------
<S> <C>
1998................................... $ 37,302
1999................................... 37,890
2000................................... 37,755
2001................................... 37,629
2002................................... 37,491
2003-2021.............................. 531,688
---------
Total minimum lease payments........... 719,755
Less: Amount representing interest..... (424,682)
---------
Present value of net minimum
lease payments....................... 295,073
Less: Current portion.................. (6,435)
---------
Long-term balance...................... $ 288,638
---------
---------
</TABLE>
The capital leases provide that Oglethorpe's rental payments vary to the
extent of interest rate changes associated with the debt used by the lessors to
finance their purchase of undivided ownership shares in Scherer Unit No. 2. 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) 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
leases. Oglethorpe's future rental payments
53
<PAGE>
under its leases will vary from amounts shown in the table above to the extent
that the actual interest rates associated with the debt of the lessors varies
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 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 $1,391,000 as of December 31, 1997. This
liability has been reflected on the accompanying balance 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 PCBs, 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 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 was 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 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 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 matured 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 is in the final stages of a debt offering to
refund the Series 1997B Bonds in March 1998 through the issuance of Series 1998A
and Series 1998B PCBs (the Series 1998 Bonds) having a January 1, 2019 maturity.
The Series 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 deferred charges on the balance sheet and are being amortized over
the twenty-year life of the Series 1998 Bonds.
In December 1997, Oglethorpe completed a current refunding transaction
whereby $14,635,000 (includes portion assumed by GTC) of PCBs were
54
<PAGE>
issued. The proceeds of this transaction were used to retire $14,635,000 of
existing 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 have been reported
as a deferred charge on the balance sheet and are being amortized over the
life of the related bonds.
The annual interest requirement for 1998 is estimated to be $242,000,000.
Maturities for the long-term debt through 2002 are as follows:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1998 1999 2000 2001 2002
- ------------------------------------------------------ --------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C>
FFB and RUS........................................... $ 69,432 $ 72,662 $ 78,952 $ 84,470 $ 89,199
CoBank................................................ 483 495 508 523 540
PCBs.................................................. 13,206 14,540 17,949 19,678 20,264
Capital Leases........................................ 6,435 6,240 7,075 7,775 8,544
--------- ---------- ---------- ---------- ----------
Total................................................. $ 89,556 $ 93,937 $ 104,484 $ 112,446 $ 118,547
--------- ---------- ---------- ---------- ----------
--------- ---------- ---------- ---------- ----------
</TABLE>
Oglethorpe has a commercial paper program under which it may issue
commercial paper not to exceed a $280,000,000 balance outstanding at any time.
The commercial paper may be used for working capital requirements and for
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, 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 outstanding at December 31, 1996.
Oglethorpe has a $50,000,000 uncommitted short-term line of credit with CFC
and a $30,000,000 committed line of credit with SunTrust Bank, Atlanta
(SunTrust). The maximum combined amount that can be outstanding under these
lines of credit and the commercial paper program at any one time totals
$330,000,000 due to certain restrictions contained in the SunTrust line of
credit agreement. No balance was outstanding on either of these two lines of
credit at either December 31, 1997 or 1996.
6. ELECTRIC PLANT AND RELATED AGREEMENTS:
Oglethorpe and Georgia Power Company (GPC) have entered into agreements
providing for the purchase and subsequent joint operation of certain of GPC's
electric generating plants. A summary of Oglethorpe's plant investments and
related accumulated depreciation as of December 31, 1997 is as follows:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS)
ACCUMULATED
PLANT INVESTMENT DEPRECIATION
- --------------------------------------------------------------------- ------------ ------------
<S> <C> <C>
In-service
Owned property
Vogtle Units No. 1 & No. 2 (NUCLEAR--30% OWNERSHIP)............. $2,781,172 $ 736,999
Hatch Units No. 1 & No. 2 (NUCLEAR--30% OWNERSHIP).............. 520,512 217,406
Wansley Units No. 1 & No. 2 (FOSSIL--30% OWNERSHIP)............. 171,916 85,997
Scherer Unit No. 1 (FOSSIL--60% OWNERSHIP)...................... 427,275 199,892
Rocky Mountain Units No. 1, No. 2 & No. 3
(HYDRO-- 74.6% OWNERSHIP)..................................... 556,715 28,533
Tallassee (Harrison Dam) (HYDRO--100% OWNERSHIP)................. 9,270 1,975
Wansley (COMBUSTION TURBINE-30% OWNERSHIP)...................... 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% LEASEHOLD)........................ 300,815 99,817
------------ ------------
Total in-service..................................................... $4,910,067 $1,412,287
----------- ------------
----------- ------------
Construction work in progress
Generation improvements........................................... $ 12,530
Other............................................................. 1,048
-----------
Total construction work in progress.................................. $ 13,578
-----------
-----------
</TABLE>
Oglethorpe, as of December 31, 1997, estimates property additions (including
capitalized interest but excluding nuclear fuel) to be approximately $19,000,000
in 1998, $17,000,000 in 1999 and $15,000,000 in 2000, primarily for replacements
and additions to generation 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
<PAGE>
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. 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 was shown as
follows:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996 1995
- --------------------------------------------------------- ------- ------- -------
<S> <C> <C> <C>
Service cost--benefits earned during the year............ $ 560 $ 1,149 $ 913
Interest cost on projected benefit obligation............ 791 872 742
Actual return on plan assets............................. (1,872) (984) (1,889)
Net amortization and deferral............................ 1,175 351 1,288
Net gain from a plan curtailment......................... -- -- (12)
------- ------- -------
Net pension cost......................................... $ 654 $ 1,388 $ 1,042
------- ------- -------
------- ------- -------
</TABLE>
The plan's funded status in Oglethorpe's financial statements as of
December 31, 1997 and 1996 was as follows:
<TABLE>
<CAPTION>
(DOLLARS IN THOUSANDS) 1997 1996
- ---------------------------------------------------------------------- ---------- ---------
<S> <C> <C>
Actuarial present value of accumulated plan benefits
Vested.............................................................. $ 7,197 $ 7,554
Nonvested........................................................... 400 540
--------- ---------
$ 7,597 $ 8,094
--------- ---------
--------- ---------
Projected benefit obligation.......................................... $ (11,294) $ (13,211)
Plan assets at fair value........................................... 9,568 9,218
Projected benefit obligation in excess of plan assets................. (1,726) (3,993)
Unrecognized net loss (gain) from past experience different
from that assumed and effects of changes in assumptions.............. (2,243) (880)
Prior service cost not yet recognized in net periodic pension cost.... 355 498
Unrecognized net asset at transition date being recognized
over 19 years....................................................... (77) (109)
--------- ---------
Pension accrual....................................................... $ (3,691) $ (4,484)
--------- ---------
--------- ---------
</TABLE>
The discount rate and rate of increase in future compensation levels used
in determining the actuarial present value of the projected benefit
obligations shown above were 7.25% and 5.0% in 1997, and 7.5% and 5.0% in
1996, respectively. The expected long-term rate of return on plan assets was
8.5% in 1997, 1996 and 1995 and the discount rate used in determining the
pension expense was 7.5% in 1997, 7.25% in 1996 and 8.5% in 1995.
Oglethorpe has a contributory employee retirement savings plan covering
substantially all employees. Employee contributions to the plan may be
invested in one or more of nine funds. The employee may contribute, subject
to 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.
8. NUCLEAR INSURANCE:
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is a
member of Nuclear 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, is limited to
approximately $5,959,000 for each nuclear incident.
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, has
coverage under NEIL II, which provides 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 primary 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, is limited to approximately $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
<PAGE>
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.
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 purchased on a take-or-pay basis
1,000 megawatts (MW) of capacity through the period ending August 31, 1997.
Effective September 1, 1997, Oglethorpe will purchase 750 MW of capacity
through the period ending August 31, 1998. Effective September 1, 1998,
Oglethorpe will purchase 500 MW of capacity through the period ending 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
purchased 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, 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:
<TABLE>
<CAPTION>
YEAR ENDING DECEMBER 31, (DOLLARS IN THOUSANDS)
- ---------------------------------------------------- ----------------------
<S> <C>
1998................................................ $ 111,494
1999................................................ 84,578
2000................................................ 69,075
2001................................................ 70,071
2002................................................ 57,875
</TABLE>
57
<PAGE>
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.
Oglethorpe has entered into an agreement with Alabama Electric
Cooperative to sell 100 MW of capacity for the period June 1998 through
December 2005.
10. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial information for 1997 and 1996 is as follows:
<TABLE>
<CAPTION>
FIRST SECOND THIRD FOURTH
(DOLLARS IN THOUSANDS) QUARTER QUARTER QUARTER QUARTER
- ----------------------------------------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
1997
Operating revenues....................... $ 271,485 $ 242,876 $ 286,579 $ 246,912
Operating margin......................... 77,818 61,423 56,753 63,681
Net margin............................... 9,436 5,510 (872) 8,331
1996
Operating revenues....................... $ 270,689 $ 275,228 $ 286,648 $ 268,872
Operating margin......................... 73,568 72,514 75,009 61,658
Net margin............................... 8,988 4,732 12,508 (4,476)
</TABLE>
Oglethorpe's business is influenced by seasonal weather conditions. The
negative net margin for the third quarter of 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 Members in August 1997. The negative net margin for the fourth
quarter of 1996 is consistent with expectations and reflects 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:
<TABLE>
<CAPTION>
ASSETS (DOLLARS IN THOUSANDS)
- ----------------------------------------------------------------------------
<S> <C>
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
----------
----------
</TABLE>
In addition, Oglethorpe also made a special patronage capital
distribution to the Members which was used by the Members to establish equity
in and to provide working capital to GTC.
The following unaudited pro forma statement of revenues and expenses for
the year ended December 31, 1997 reflects the operations of Oglethorpe as
reported and restated, reflecting the exclusion of the transmission and
system operations businesses as though the Corporate Restructuring had
occurred at the beginning of 1997.
58
<PAGE>
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)
<TABLE>
<CAPTION>
OGLETHORPE
OGLETHORPE PRO FORMA (POST-
HISTORICAL ADJUSTMENTS(1) RESTRUCTURING)
------------ -------------- --------------
<S> <C> <C> <C>
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
----------- --------- -----------
----------- --------- -----------
</TABLE>
- ------------------------
(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
<PAGE>
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.
T. D. Kilgore
President and Chief Executive Officer
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Oglethorpe Power Corporation:
We have audited the accompanying balance sheets and statements of
capitalization of Oglethorpe Power Corporation (a Georgia corporation) as of
December 31, 1997 and 1996 and the related statements of revenues and
expenses, patronage capital, and cash flows for each of the three years in
the period ended December 31, 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, 1997 and 1996 and the results of its
operations and its cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting
principles.
Coopers & Lybrand L.L.P.
Atlanta, Georgia,
February 17, 1998.
60
<PAGE>
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
As part of the Corporate Restructuring, Oglethorpe amended its Bylaws to
provide for an eleven member board of directors consisting of six directors
elected from the Members (the "Member Directors"), four independent outside
directors (the "Outside Directors") and Oglethorpe's President and Chief
Executive Officer. Each Member Director must be a director or general manager of
an Oglethorpe Member. Five of the 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 the 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 number of retail customers served by each Member. After nomination, the
directors are elected by a majority vote of each Member, voting on a one-Member,
one-vote basis.
The Bylaws provide for staggering the terms of the Member Directors and
Outside Directors by dividing the number of directors into three groups. As
noted below, some of the directors were elected to an initial term of one year,
some two years and some three years. As these initial terms expire, directors
will thereafter be elected for a term of three years.
Oglethorpe is managed and operated under the direction of a President and
Chief Executive Officer, who is appointed by the Board of Directors. The Senior
Officers and Directors of Oglethorpe and significant employees of subsidiaries
of Oglethorpe are as follows:
<TABLE>
<CAPTION>
NAME AGE POSITION
- ----------------------------------------------------- --- -----------------------------------------------------
<S> <C> <C>
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
</TABLE>
J. Calvin Earwood is the Chairman of the Board and is the Member Director
elected statewide. Mr. Earwood has served as an 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 on the Board of Directors of
Oglethorpe
61
<PAGE>
since March 1981. His present term will expire in March 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.
T. D. Kilgore is the President and Chief Executive Officer of Oglethorpe and
has served as a 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). He also currently serves as the President and Chief
Executive Officer and as a director of 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
Bachelor of Science degree in Mechanical Engineering from the University of
Alabama, where he has been recognized as a Distinguished Engineering Fellow, and
a Masters of Engineering degree in industrial engineering from Texas A&M.
Clarence D. Mitchell is the Senior Vice President, Power Supply and has
served as a 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 a
Masters of Science degree in Management from Georgia State University, a
Bachelor of Science degree in Mechanical Engineering from Georgia Institute of
Technology and a Bachelor 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
information about the Managing Boards see "CO-OWNERS OF THE PLANTS AND THE PLANT
AGREEMENTS--The Plant Agreements" in Item 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,
Finance of Oglethorpe from 1986 to 1990, Manager of Finance from 1983 to 1986
and Manager, Financial Services from 1979 to 1983. From 1990 to 1997, Mr. Smith
was Senior Vice President of the Rural Utility Banking Group of CoBank, where he
managed the bank's eastern division, rural utilities. Mr. Smith is a Certified
Public Accountant, has a Master of Science degree in Industrial
Management-Finance from the Georgia Institute of Technology, a Master of Science
degree in Analytical Chemistry from Purdue University and a Bachelor of Arts
degree in Mathematics and Chemistry from Catawba College.
Nelson G. Hawk is the President and Chief Executive Officer of EnerVision, a
wholly owned subsidiary of Oglethorpe that began operations as a marketing
services business in 1998. Prior to that time,
62
<PAGE>
Mr. Hawk was the Senior Vice President and Group Executive, Marketing and served
as a senior officer of Oglethorpe, responsible for Market Planning, Economic
Development, Commercial/Industrial Marketing and Pricing, Commercial/Industrial
Services, and Residential 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
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 Bachelor of Science degree in
Electrical Engineering from the Georgia Institute of Technology and a Master of
Business Administration degree from Florida International University.
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 on the Board of Directors of Oglethorpe since July 1989. His present term
will expire in March 1999. Mr. Chadwick is an engineer, 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 1988. 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 1987, 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 1996, 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
<PAGE>
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 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 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 Executive Vice President and Member 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 1994, Mr. Ranson 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 the Kansas City (Kansas)
Board of Public Utilities. Mr. Ranson received his Bachelor of Science in
Business Administration from the University of Kansas (Lawrence, Kansas) and
attended the Navy Supply Corps School in Bayonne, New Jersey.
64
<PAGE>
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, 1997, 1996 and 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.
<TABLE>
<CAPTION>
ANNUAL
COMPENSATION
NAME AND -------------------- ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS (1) COMPENSATION
- ----------------------------------- ---- -------- ---------- ------------
<S> <C> <C> <C> <C>
T. D. Kilgore...................... 1997 $300,368 $ 0 $6,316(2)
President and Chief Executive 1996 265,627 0 6,246
Officer 1995 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 140,000 10,899 4,589
Clarence D. Mitchell............... 1997 155,210 N/A(4) 3,774(2)
Sr. Vice President, Power Supply 1996 133,369 17,112 3,887
1995 110,058 7,776 4,251
</TABLE>
- ------------------------------
(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 1997 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. Kilgore, Hawk and Mitchell of
$4,750, $4,750 and $2,856, respectively; and insurance premiums paid on term
life insurance on behalf of Messrs. Kilgore, Hawk and Mitchell of $1,566,
$908 and $918, respectively.
(3) In connection with Oglethorpe's transfer of its marketing services business
to EnerVision, a wholly owned subsidiary of Oglethorpe, Mr. Hawk ceased to
be an employee of Oglethorpe as of December 31, 1997. (See "OGLETHORPE POWER
CORPORATION--Corporate Restructuring" in Item 1 for further discussion.)
(4) Bonus amounts earned in 1997 by Messrs. Hawk and Mitchell have not been
determined but are expected to be determined and paid in 1998.
PENSION PLAN TABLE
<TABLE>
<CAPTION>
YEARS OF CREDITED SERVICE
------------------------------------------------------
AVERAGE COMPENSATION 5 10 15 20 25
- ---------------------------------------------------------- --------- --------- --------- ---------- ---------
<S> <C> <C> <C> <C> <C>
$ 50,000.................................................. $ 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
</TABLE>
65
<PAGE>
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 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, 1997, the years of credited service under the Pension
Plan for the individuals listed in the Summary Compensation Table are as
follows:
<TABLE>
<CAPTION>
YEARS OF
NAME CREDITED SERVICE
- ------------------------------------------------------------------------------------ -------------------
<S> <C> <C>
Mr. Kilgore......................................................................... 13
Mr. Hawk............................................................................ 3
Mr. Mitchell........................................................................ 16
</TABLE>
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 Board 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 by conference call, and
reimbursed Directors for out-of-pocket expenses incurred in attending a meeting.
The Chairman of the Board was 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 meetings.
EMPLOYMENT CONTRACTS
Effective January 1, 1996, Oglethorpe entered into an employment agreement
with its President and Chief Executive Officer. The agreement extends to
December 31, 1999. Pursuant to the agreement, Mr. Kilgore's base salary and
bonus will be determined by Oglethorpe's Board, with annual base salary being at
least $240,000. Under the agreement, if Oglethorpe terminates Mr. Kilgore's
employment without cause, he will be entitled to a severance payment equal to
all salary and benefits he would have received between the date of termination
to the end of the agreement. If Oglethorpe terminates Mr. Kilgore's employment
without cause or meaningfully reduces his stated duties or prerogatives within
three months prior to or 24 months subsequent to a Change in Control of
Oglethorpe (as defined in the agreement), such severance payment will not be
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
<PAGE>
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
J. Calvin Earwood, Newton A. Campbell and J. Sam L. Rabun served as members
of the Oglethorpe Power Corporation Compensation Committee in 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
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
<PAGE>
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
<TABLE>
<CAPTION>
PAGE
---------
<S> <C> <C>
(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
</TABLE>
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.
<TABLE>
<CAPTION>
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
<S> <C> <C>
*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.)
</TABLE>
68
<PAGE>
<TABLE>
<CAPTION>
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
<S> <C> <C>
*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.)
</TABLE>
69
<PAGE>
<TABLE>
<CAPTION>
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
<S> <C> <C>
*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.
</TABLE>
70
<PAGE>
<TABLE>
<CAPTION>
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
<S> <C> <C>
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
</TABLE>
71
<PAGE>
<TABLE>
<CAPTION>
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
<S> <C> <C>
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.)
*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
</TABLE>
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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
</TABLE>
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NUMBER DESCRIPTION
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<S> <C> <C>
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.)
</TABLE>
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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.)
</TABLE>
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NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
<S> <C> <C>
*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.)
</TABLE>
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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.)
</TABLE>
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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.)
</TABLE>
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- ----------------------- --------------------------------------------------------------------------------------
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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.)
</TABLE>
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NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
<S> <C> <C>
*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.)
</TABLE>
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NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
<S> <C> <C>
*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.)
</TABLE>
81
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<TABLE>
<CAPTION>
NUMBER DESCRIPTION
- ----------------------- --------------------------------------------------------------------------------------
<S> <C> <C>
*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).
</TABLE>
- ------------------------
(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 Commission 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 8-K were filed by Oglethorpe for the quarter ended
December 31, 1997.
82
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 11th day of
March, 1998.
<TABLE>
<S> <C> <C>
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
By: /s/ J. CALVIN EARWOOD
-----------------------------------------
J. CALVIN EARWOOD
Chairman of the Board
</TABLE>
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- ------------------------------ -------------------------- -------------------
<C> <S> <C>
/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
</TABLE>
83
<PAGE>
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- ------------------------------ -------------------------- -------------------
<C> <S> <C>
/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
</TABLE>
84
<PAGE>
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(D) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT.
The registrant is a membership corporation and has no authorized or outstanding
equity securities. Proxies are not solicited from the holders of Oglethorpe's
public bonds. No annual report or proxy material has been sent to such
bondholders.
85
<PAGE>
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.
<TABLE>
<CAPTION>
NUMBER DESCRIPTION
- -------------- -------------------------------------------------------------------------------------------------
<S> <C> <C>
*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.)
</TABLE>
<PAGE>
<TABLE>
<S> <C> <C>
*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.
</TABLE>
2
<PAGE>
<TABLE>
<S> <C> <C>
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.
</TABLE>
3
<PAGE>
<TABLE>
<S> <C> <C>
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.)
</TABLE>
4
<PAGE>
<TABLE>
<S> <C> <C>
*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
</TABLE>
5
<PAGE>
<TABLE>
<S> <C> <C>
*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.)
</TABLE>
6
<PAGE>
<TABLE>
<S> <C> <C>
*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 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.)
</TABLE>
7
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*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.)
</TABLE>
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*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.)
</TABLE>
9
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*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.)
</TABLE>
10
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*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.)
</TABLE>
11
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*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.)
</TABLE>
12
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*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.)
</TABLE>
13
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*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).
</TABLE>
- ------------------------
(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 Commission 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.
14
<PAGE>
EXHIBIT 4.7.1(c)
PURSUANT TO SECTION 44-14-35.1 OF OFFICIAL CODE OF GEORGIA ANNOTATED, THIS
INSTRUMENT EMBRACES, COVERS AND CONVEYS SECURITY TITLE TO AFTER-ACQUIRED
PROPERTY OF THE GRANTOR
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION),
GRANTOR,
to
SUNTRUST BANK, ATLANTA,
TRUSTEE
SECOND SUPPLEMENTAL
INDENTURE
Relating to the
Series 1997C (Burke) Note
Dated as of January 1, 1998
FIRST MORTGAGE OBLIGATIONS
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
<PAGE>
THIS SECOND SUPPLEMENTAL INDENTURE, dated as of January 1, 1998, is
between OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP CORPORATION), an
electric membership corporation organized and existing under the laws of the
State of Georgia, as Grantor (hereinafter called the "Company"), and SUNTRUST
BANK, ATLANTA, a banking corporation organized and existing under the laws of
the State of Georgia, as Trustee (in such capacity, the "Trustee").
WHEREAS, the Company has heretofore executed and delivered to the
Trustee an Indenture, dated as of March 1, 1997 (hereinafter called the
"Original Indenture") for the purpose of securing its Existing Obligations
and providing for the authentication and delivery of Additional Obligations
by the Trustee from time to time under the Original Indenture (capitalized
terms used herein shall have the meanings ascribed to them in the Original
Indenture as provided in Section 2.1 hereof);
WHEREAS, the Development Authority of Burke County (the "Burke
Authority") issued $199,690,000 in aggregate principal amount of Development
Authority of Burke County Adjustable Tender Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1993A (the "Series
1993A Bonds"), of which $2,265,000 in principal amount is subject to
mandatory sinking fund redemption on January 1, 1998 (the "1993A Sinking Fund
Maturities");
WHEREAS, the Burke Authority loaned the proceeds from the sale of the
Series 1993A Bonds to the Company, with such loan being evidenced by that
certain Series 1993A Note, dated as of December 1, 1992 (the "Series 1993A
Note"), from the Company to SunTrust Bank, Atlanta, formerly known as Trust
Company Bank, as trustee (in such capacity, the "Series 1993A Trustee"), as
assignee and pledgee of the Burke Authority pursuant to the Trust Indenture,
dated as of December 1, 1992 (the "Series 1993A Indenture"), between the
Burke Authority and the Series 1993A Trustee;
WHEREAS, the Burke Authority issued $155,610,000 in aggregate principal
amount of Development Authority of Burke County Pollution Control Revenue
Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993B (the
"Series 1993B Bonds"), of which $6,490,000 in aggregate principal amount
matures on January 1, 1998 (the "1993B Maturities");
WHEREAS, the Burke Authority loaned the proceeds from the sale of the
Series 1993B Bonds to the Company, with such loan being evidenced by that
certain Series 1993B Note, dated as of September 1, 1993 (the "Series 1993B
Note"), from the Company to SunTrust Bank, Atlanta, formerly known as Trust
Company Bank, as trustee (in such capacity, the "Series 1993B Trustee"), as
assignee and pledgee of the Burke Authority pursuant to the Trust Indenture,
dated as of September 1, 1993 (the "Series 1993B Indenture"), between the
Burke Authority and the Series 1993B Trustee;
WHEREAS, the Burke Authority issued $13,720,000 in aggregate principal
amount of Development Authority of Burke County Pollution Control Revenue
Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1994B (the
"Series 1994B Bonds"; the Series 1993A Bonds, the
<PAGE>
Series 1993B Bonds, and the Series 1994B Bonds, collectively, the
"Outstanding Bonds"), of which $550,000 in aggregate principal amount matures
on January 1, 1998 (the "1994B Maturities"; the 1993A Sinking Fund
Maturities, the 1993B Maturities and the 1994B Maturities, collectively, the
"1998 Maturities");
WHEREAS, the Burke Authority loaned the proceeds from the sale of the
Series 1994B Bonds to the Company, with such loan being evidenced by that
certain Series 1994B Note, dated as of September 1, 1994 (the "Series 1994B
Note"; the Series 1993A Note, the Series 1993B Note and the Series 1994B
Note, collectively, the "Outstanding Notes"), from the Company to SunTrust
Bank, Atlanta, formerly known as Trust Company Bank, as trustee (in such
capacity, the "Series 1994B Trustee"), as assignee and pledgee of the Burke
Authority pursuant to the Trust Indenture, dated as of September 1, 1994 (the
"Series 1994B Indenture"), between the Burke Authority and the Series 1994B
Trustee;
WHEREAS, on December 10, 1997, the Burke Authority issued $9,305,000 in
aggregate principal amount of Development Authority of Burke County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series
1997C (the "Series 1997C (Burke) Bonds"), the proceeds from the sale of which
were loaned to the Company pursuant to that certain Loan Agreement, dated as
of December 1, 1997 (the "Series 1997C (Burke) Loan Agreement"), between the
Burke Authority and the Company to refund the 1998 Maturities and to make the
related payments due on the Outstanding Notes;
WHEREAS, the Company's obligation to repay the loan of the proceeds of
the Series 1997C (Burke) Bonds is evidenced by that certain Series 1997C
(Burke) Note, dated as of December 1, 1997 (the "Unsecured Note"), from the
Company to SunTrust Bank, Atlanta, as trustee (in such capacity, the "Series
1997C (Burke) Trustee"), as assignee and pledgee of the Burke Authority
pursuant to the Indenture of Trust, dated as of December 1, 1997 (the "Series
1997C (Burke) Indenture"), between the Burke Authority and the Series 1997C
(Burke) Trustee;
WHEREAS, as permitted by Section 4.9 of the Series 1997C (Burke) Loan
Agreement, the Company desires to deliver to the Series 1997C (Burke) Trustee
a promissory note secured under the Indenture (as hereinafter defined) in
substitution for the Unsecured Note;
WHEREAS, the Company desires to execute and deliver this Second
Supplemental Indenture, in accordance with the provisions of the Original
Indenture, for the purpose of providing for the creation and designation of
that certain Series 1997C (Burke) Note, dated the date of its authentication
(the "Series 1997C (Burke) Note"), from the Company to the Series 1997C
(Burke) Trustee, as assignee and pledgee of the Burke Authority pursuant to
the Series 1997C (Burke) Indenture, as an Additional Obligation and
specifying the form and provisions of the Series 1997C (Burke) Note (the
Original Indenture, as heretofore and hereby supplemented and modified, being
herein sometimes called the "Indenture");
2
<PAGE>
WHEREAS, pursuant to Section 4.9 of the Series 1997C (Burke) Loan
Agreement, upon the authentication of the Series 1997C (Burke) Note by the
Trustee, the Series 1997C (Burke) Note will be delivered to the Series 1997C
(Burke) Trustee in substitution for the Unsecured Note;
WHEREAS, Section 12.1 of the Original Indenture provides that, without
the consent of the Holders of any of the Obligations at the time Outstanding,
the Company, when authorized by a Board Resolution, and the Trustee, may
enter into supplemental indentures for the purposes and subject to the
conditions set forth in said Section 12.1; and
WHEREAS, all acts and proceedings required by law and by the Articles of
Incorporation and Bylaws of the Company necessary to secure the payment of
the principal of (and premium, if any) and interest on the Series 1997C
(Burke) Note, to make the Series 1997C (Burke) Note to be issued hereunder,
when executed by the Company, authenticated and delivered by the Trustee and
duly issued, the valid, binding and legal obligation of the Company, and to
constitute the Indenture a valid and binding lien for the security of the
Series 1997C (Burke) Note, in accordance with its terms, have been done and
taken; and the execution and delivery of this Second Supplemental Indenture
has been in all respects duly authorized;
NOW, THEREFORE, THIS SECOND SUPPLEMENTAL INDENTURE WITNESSES, that, to
secure the payment of the principal of (and premium, if any) and interest on
the Outstanding Secured Obligations, including, when issued, the Series 1997C
(Burke) Note, to confirm the lien of the Indenture upon the Trust Estate,
including property purchased, constructed or otherwise acquired by the
Company since the date of execution of the Original Indenture, to secure
performance of the covenants therein and herein contained, to declare the
terms and conditions on which the Series 1997C (Burke) Note is secured, and
in consideration of the premises thereof and hereof, the Company by these
presents does grant, bargain, sell, alienate, remise, release, convey,
assign, transfer, mortgage, hypothecate, pledge, set over and confirm to the
Trustee, and its successors and assigns in the trust created thereby and
hereby, in trust, all property, rights, privileges and franchises (other than
Excepted Property or Excludable Property) of the Company of the character
described in the Granting Clauses of the Original Indenture, including all
such property, rights, privileges and franchises acquired since the date of
execution of the Original Indenture, including, without limitation, all
property described in Exhibit A attached hereto, subject to all exceptions,
reservations and matters of the character therein referred to, and does grant
a security interest therein for the purposes expressed herein and in the
Original Indenture subject in all cases to Sections 5.2 and 11.2 B of the
Original Indenture and to the rights of the Company under the Original
Indenture, including the rights set forth in Article V thereof; but expressly
excepting and excluding from the lien and operation of the Indenture all
properties of the character specifically excepted as "Excepted Property" or
"Excludable Property" in the Original Indenture to the extent contemplated
thereby.
PROVIDED, HOWEVER, that if, upon the occurrence of an Event of Default
under the Original Indenture, the Trustee, or any separate trustee or
co-trustee appointed under Section 9.14 of the Original Indenture or any
receiver appointed pursuant to statutory provision or order of court,
3
<PAGE>
shall have entered into possession of all or substantially all of the Trust
Estate, all the Excepted Property described or referred to in Paragraphs A
through H, inclusive, of "Excepted Property" in the Original Indenture then
owned or thereafter acquired by the Company, shall immediately, and, in the
case of any Excepted Property described or referred to in Paragraphs I, J, L,
N and P of "Excepted Property" in the Original Indenture (excluding the
property described in Section 2 of Exhibit B in the Original Indenture), upon
demand of the Trustee or such other trustee or receiver, become subject to
the lien of the Indenture to the extent permitted by law, and the Trustee or
such other trustee or receiver may, to the extent permitted by law, at the
same time likewise take possession thereof, and whenever all Events of
Default shall have been cured and the possession of all or substantially all
of the Trust Estate shall have been restored to the Company, such Excepted
Property shall again be excepted and excluded from the lien of the Indenture
to the extent and otherwise as hereinabove set forth and as set forth in the
Original Indenture.
The Company may, however, pursuant to the Granting Clause Third of the
Original Indenture, subject to the lien of the Indenture any Excepted
Property or Excludable Property, whereupon the same shall cease to be
Excepted Property or Excludable Property.
TO HAVE AND TO HOLD all such property, rights, privileges and franchises
hereby and hereafter (by Supplemental Indenture or otherwise) granted,
bargained, sold, alienated, remised, released, conveyed, assigned,
transferred, mortgaged, hypothecated, pledged, set over or confirmed as
aforesaid, or intended, agreed or covenanted so to be, together with all the
tenements, hereditaments and appurtenances thereto appertaining (said
properties, rights, privileges and franchises, including any cash and
securities hereafter deposited or required to be deposited with the Trustee
(other than any such cash which is specifically stated in the Original
Indenture not to be deemed part of the Trust Estate) being part of the Trust
Estate), unto the Trustee, and its successors and assigns in the trust herein
created, forever.
SUBJECT, HOWEVER, to (i) Permitted Exceptions (as defined in Section 1.1
of the Original Indenture) and (ii) to the extent permitted by Section 13.6
of the Original Indenture as to property hereafter acquired (a) any duly
recorded or perfected prior mortgage or other lien that may exist thereon at
the date of the acquisition thereof by the Company and (b) purchase money
mortgages, other purchase money liens, chattel mortgages, conditional sales
agreements or other title retention agreements created by the Company at the
time of acquisition thereof.
BUT IN TRUST, NEVERTHELESS, with power of sale, for the equal and
proportionate benefit and security of the Holders from time to time of all
the Outstanding Secured Obligations without any priority of any such
Obligation over any other such Obligation and for the enforcement of the
payment of such Obligations in accordance with their terms.
UPON CONDITION that, until the happening of an Event of Default and
subject to the provisions of Article V of the Original Indenture, and not in
limitation of the rights elsewhere provided in the Original Indenture,
including the rights set forth in Article V of the Original
4
<PAGE>
Indenture, the Company shall be permitted to (i) possess and use the Trust
Estate, except cash, securities, Designated Qualifying Securities and other
personal property deposited, or required to be deposited, with the Trustee,
(ii) explore for, mine, extract, separate and dispose of coal, ore, gas, oil
and other minerals, and harvest standing timber, and (iii) receive and use
the rents, issues, profits, revenues and other income, products and proceeds
of the Trust Estate.
THE INDENTURE, INCLUDING THIS SECOND SUPPLEMENTAL INDENTURE, is intended
to operate and is to be construed as a deed passing title to the Trust Estate
and is made under the provisions of the existing laws of the State of Georgia
relating to deeds to secure debt, and not as a mortgage or deed of trust, and
is given to secure the Outstanding Secured Obligations. Should the
indebtedness secured by the Indenture be paid according to the tenor and
effect thereof when the same shall become due and payable and should the
Company perform all covenants herein contained in a timely manner, then the
Indenture shall be canceled and surrendered.
AND IT IS HEREBY COVENANTED AND DECLARED that the Series 1997C (Burke)
Note is to be authenticated and delivered and the Trust Estate is to be held
and applied by the Trustee, subject to the covenants, conditions and trusts
set forth herein and in the Original Indenture, and the Company does hereby
covenant and agree to and with the Trustee, for the equal and proportionate
benefit of all Holders of the Outstanding Secured Obligations, as follows:
ARTICLE I
THE SERIES 1997C (BURKE) NOTE AND
CERTAIN PROVISIONS RELATING THERETO
Section 1.1 Authorization and Terms of the Series 1997C (Burke) Note.
There shall be created and established an Additional Obligation in the
form of a promissory note known as and entitled the "Series 1997C (Burke)
Note" (hereinafter referred to as the "Series 1997C (Burke) Note"), the form,
terms and conditions of which shall be substantially as set forth in this
Section and Section 1.2. The aggregate principal face amount of the Series
1997C (Burke) Note which shall be authenticated and delivered and Outstanding
at any one time is limited to $9,305,000.
The Series 1997C (Burke) Note shall be dated the date of its
authentication. The Series 1997C (Burke) Note shall mature on January 1,
2018 and shall bear interest from the date of its authentication to the date
of its maturity at rates calculated as provided for in the form of note
prescribed by Section 1.2. The Series 1997C (Burke) Note shall be
authenticated and delivered to, and made payable to, SunTrust Bank, Atlanta,
as trustee (in such capacity, the "Series 1997C (Burke) Trustee"), as
assignee and pledgee of the Development Authority of Burke County (the "Burke
Authority") pursuant to the Series 1997C (Burke) Indenture.
5
<PAGE>
All payments made on the Series 1997C (Burke) Note shall be made to the
Series 1997C (Burke) Trustee at its principal office in Atlanta, Georgia in
lawful money of the United States of America which will be immediately
available on the date payment is due.
Section 1.2 Form of the Series 1997C (Burke) Note.
The Series 1997C (Burke) Note and the Series 1997C (Burke) Trustee's
authentication certificate to be executed on the Series 1997C (Burke) Note
shall be substantially in the form of Exhibit B attached hereto, with such
appropriate insertions, omissions, substitutions and other variations as are
required or permitted in the Original Indenture.
Section 1.3 Substitution of the Series 1997C (Burke) Note for
the Unsecured Note.
Upon its authentication, the Series 1997C (Burke) Note shall be
delivered to the Series 1997C (Burke) Trustee in substitution for the
Unsecured Note in accordance with Section 4.9 of the Series 1997C (Burke)
Loan Agreement. Thereafter, the Series 1997C (Burke) Note shall evidence the
loan theretofore evidenced by the Unsecured Note.
ARTICLE II
MISCELLANEOUS
Section 2.1 This Second Supplemental Indenture is executed and shall
be construed as an indenture supplemental to the Original Indenture, and
shall form a part thereof, and the Original Indenture, as heretofore
supplemented and as hereby supplemented and modified, is hereby confirmed.
Except to the extent inconsistent with the express terms hereof, all of the
provisions, terms, covenants and conditions of the Original Indenture shall
be applicable to the Series 1997C (Burke) Note to the same extent as if
specifically set forth herein. All capitalized terms used in this Second
Supplemental Indenture shall have the same meanings ascribed to them in the
Original Indenture, except in cases where the context clearly indicates
otherwise.
Section 2.2 All recitals in this Second Supplemental Indenture are
made by the Company only and not by the Trustee; and all of the provisions
contained in the Original Indenture, in respect of the rights, privileges,
immunities, powers and duties of the Trustee shall be applicable in respect
hereof as fully and with like effect as if set forth herein in full.
Section 2.3 Whenever in this Second Supplemental Indenture any of the
parties hereto is named or referred to, this shall, subject to the provisions
of Articles IX and XI of the Original Indenture, be deemed to include the
successors and assigns of such party, and all the covenants and agreements in
this Second Supplemental Indenture contained by or on behalf of the Company,
or by or on behalf of the Trustee shall, subject as aforesaid, bind and inure
to the respective benefits of the respective successors and assigns of such
parties, whether so expressed or not.
6
<PAGE>
Section 2.4 Nothing in this Second Supplemental Indenture, expressed
or implied, is intended, or shall be construed, to confer upon, or to give
to, any person, firm or corporation, other than the parties hereto and the
Holders of the Outstanding Secured Obligations, any right, remedy or claim
under or by reason of this Second Supplemental Indenture or any covenant,
condition, stipulation, promise or agreement hereof, and all the covenants,
conditions, stipulations, promises and agreements in this Second Supplemental
Indenture contained by or on behalf of the Company shall be for the sole and
exclusive benefit of the parties hereto, and of the Holders of Outstanding
Secured Obligations.
Section 2.5 This Second Supplemental Indenture may be executed in
several counterparts, each of such counterparts shall for all purposes be
deemed to be an original, and all such counterparts, or as many of them as
the Company and the Trustee shall preserve undestroyed, shall together
constitute but one and the same instrument.
Section 2.6 To the extent permitted by applicable law, this Second
Supplemental Indenture shall be deemed to be a Security Agreement and
Financing Statement whereby the Company grants to the Trustee a security
interest in all of the Trust Estate that is personal property or fixtures
under the Uniform Commercial Code, as adopted or hereafter adopted in one or
more of the states in which any part of the properties of the Company are
situated. The mailing address of the Company,
as debtor is: 2100 East Exchange Place
P. O. Box 1349
Tucker, Georgia 30085-1349,
and the mailing address of the Trustees, as secured party is:
SunTrust Bank, Atlanta
58 Edgewood Avenue, Room 400A
Atlanta, Georgia 30303
[Signatures on Next Page.]
7
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Second Supplemental
Indenture to be duly executed under seal as of the day and year first above
written.
Company: OGLETHORPE POWER
CORPORATION (AN ELECTRIC
MEMBERSHIP CORPORATION), an electric
membership corporation organized under the
laws of the State of Georgia
2100 East Exchange Place
P. O. Box 1349
Tucker, Georgia 30085-1349
By: /s/ T. D. Kilgore
-----------------------
T. D. Kilgore
President and Chief Executive Officer
Signed, sealed and Attest: /s/ Patricia N. Nash
delivered by the Company -------------------------
in the presence of: Patricia N. Nash
Secretary
/s/ Kathy C. Joiner
- -----------------------
Witness
/s/ Thomas J. Brendiar
- --------------------------
Notary Public [CORPORATE SEAL]
(Notarial Seal)
My commission expires: November 14, 2000
---------------------------
[Signatures Continued on Next Page.]
<PAGE>
[Signatures Continued from Previous Page.]
Trustee: SUNTRUST BANK, ATLANTA
a banking corporation organized and existing
under the laws of the State of Georgia
By: /s/ Phillip D. DeMouey
--------------------------
Signed, sealed and delivered Name: Phillip D. DeMouey
by the Trustee in the Title: Assistant Vice President
presence of:
By: /s/ Ronald C. Painter
---------------------------
/s/ Brian Womble Name: Ronald C. Painter
- ------------------------- Title: Vice President
Witness
/s/ Teresa R. Turner
- -----------------------------
Notary Public [BANK SEAL]
(Notarial Seal)
My commission expires: April 3, 2001
-------------------
<PAGE>
Exhibit A
All property of the Company in the Counties of Appling, Ben Hill, Burke,
Carroll, Clarke, Cobb, DeKalb, Floyd, Fulton, Heard, Jackson, Monroe, and
Toombs, State of Georgia, including, without limitation, the properties more
specifically described below:
No additional properties to be specifically described.
A-1
<PAGE>
Exhibit B
[Form of Series 1997C (Burke) Note]
THIS NOTE IS NON-TRANSFERABLE EXCEPT AS MAY BE REQUIRED TO EFFECT ANY
TRANSFER TO ANY SUCCESSOR TRUSTEE UNDER THE INDENTURE OF TRUST, DATED AS OF
DECEMBER 1, 1997, AS SUPPLEMENTED, BETWEEN THE DEVELOPMENT AUTHORITY OF BURKE
COUNTY AND SUNTRUST BANK, ATLANTA, AS TRUSTEE.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
SERIES 1997C (BURKE) NOTE DATE: January 14, 1998
(VOGTLE PROJECT)
OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP CORPORATION)
("Oglethorpe"), an electric membership corporation organized and existing
under the laws of the State of Georgia, for value received and in
consideration of the agreement of the Development Authority of Burke County
(the "Burke Authority") to issue $9,305,000 in aggregate principal amount of
Development Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1997C (the "Series
1997C (Burke) Bonds"), hereby promises to pay to SunTrust Bank, Atlanta (the
"Series 1997C (Burke) Trustee"), as assignee and pledgee of the Burke
Authority, acting pursuant to the Indenture of Trust, dated as of December 1,
1997, from the Burke Authority to the Series 1997C Trustee (the "Series 1997C
Indenture"), or its successor in trust, the principal sum of $9,305,000,
together with interest and prepayment premium (if any) thereon as follows:
(1) on or before each Interest Payment Date (as defined in the
Indenture), a sum which will equal the interest on the Series 1997C (Burke)
Bonds which will become due on such Interest Payment Date on the Series 1997C
(Burke) Bonds; and
(2) on or before each January 1, commencing January 1, 1998, a sum
which will equal the principal amount of the Series 1997C (Burke) Bonds which
will become due (whether at maturity or otherwise) on the next succeeding
annual principal payment date on the Series 1997C (Burke) Bonds; and
(3) on or before any redemption date for the Series 1997C (Burke)
Bonds, a sum equal to the principal of, redemption premium (if any) and
interest on, the Series 1997C (Burke) Bonds which are to be redeemed on such
date; and
B-1
<PAGE>
(4) on or before each date on which the Series 1997C (Burke) Bonds
are required to be purchased pursuant to Section 4.01, 4.02 or 4.04 of the
Indenture, a sum equal to the purchase price of all Series 1997C (Burke)
Bonds required to be purchased on such date.
This Note is issued in substitution for and supersedes and replaces that
certain Series 1997C (Burke) Note, dated as of December 1, 1997, by
Oglethorpe to the Series 1997C (Burke) Trustee which was executed and
delivered contemporaneously with the initial issuance of the Series 1997C
(Burke) Bonds. This Note evidences the Loan (as defined in the Agreement
hereinafter referred to) of the Burke Authority to Oglethorpe and the
obligation to repay the same and shall be governed by and shall be payable in
accordance with the terms, conditions and provisions of the Loan Agreement,
dated as of December 1, 1997 (the "Agreement"), between the Burke Authority
and Oglethorpe, pursuant to which the Burke Authority has agreed to loan to
Oglethorpe the proceeds from the sale of the Series 1997C (Burke) Bonds.
This Note is a duly authorized obligation of Oglethorpe issued under and
equally and ratably secured by the Indenture, dated as of March 1, 1997 (the
"Original Mortgage Indenture"), between Oglethorpe, as grantor, and SunTrust
Bank, Atlanta, as trustee (in such capacity, the "Mortgage Indenture
Trustee"), as supplemented by the First Supplemental Indenture, dated as of
October 1, 1997 (the "First Supplemental Indenture"), the Second Supplemental
Indenture, dated as of January 1, 1998 (the "Second Supplemental Indenture")
and the Third Supplemental Indenture, dated as of January 1, 1998 (the "Third
Supplemental Indenture"), between Oglethorpe and the Mortgage Indenture
Trustee (the Original Indenture, as supplemented, the "Mortgage Indenture").
Reference is hereby made to the Mortgage Indenture for a statement of the
description of the properties thereby mortgaged, pledged and assigned, the
nature and extent of the security and the respective rights, limitations of
rights, duties and immunities thereunder of Oglethorpe, the Mortgage
Indenture Trustee and the holder of this Note and of the terms upon which
this Note is authenticated and delivered. This Note is created by the Second
Supplemental Indenture and designated as the "Series 1997C (Burke) Note".
All payments hereon are to be made to the Series 1997C Trustee at its
principal office in Atlanta, Georgia, in lawful money of the United States of
America which will be immediately available on the day payment is due. As
set forth in Section 4.6 of the Agreement, the obligation of Oglethorpe to
make the payments required hereunder shall be absolute and unconditional.
Oglethorpe shall be entitled to certain credits against payments
required to be made hereunder as provided in Section 4.3 of the Agreement.
This Note may be prepaid upon the terms and conditions set forth in
Article V of the Agreement.
If the Series 1997C Trustee shall accelerate payment of the Series 1997C
(Burke) Bonds, all payments on this Note shall be declared due and payable in
the manner and with the effect provided
B-2
<PAGE>
in the Agreement. The Agreement provides that, under certain conditions,
such declaration shall be rescinded by the Series 1997C Trustee.
No recourse shall be had for the payments required hereby or for any
claim based herein or in the Agreement or in the Mortgage Indenture against
any officer, director or member, past, present or future, of Oglethorpe as
such, either directly or through Oglethorpe, or under any constitution
provision, statute or rule of law or by the enforcement of any assessment or
by any legal or equitable proceedings or otherwise.
This Note shall not be entitled to any benefit under the Mortgage
Indenture and shall not become valid or obligatory for any purposes until the
Mortgage Indenture Trustee shall have signed the form of authentication
certificate endorsed hereon.
This Note shall be governed by and construed in accordance with the laws
of the State of Georgia.
IN WITNESS WHEREOF, Oglethorpe has caused this Note to be executed in
its corporate name by its President and Chief Executive Officer and attested
by its Secretary and its corporate seal to be hereunto affixed.
OGLETHORPE POWER CORPORATION (AN
ELECTRIC MEMBERSHIP CORPORATION)
By:
--------------------------
T. D. Kilgore
President and Chief Executive Officer
(SEAL)
Attest:
- ------------------------
Patricia N. Nash
Secretary
B-3
<PAGE>
TRUSTEE'S CERTIFICATE OF AUTHENTICATION
This is one of the Obligations of the series designated therein referred
to in the within mentioned Indenture.
SUNTRUST BANK, ATLANTA, as Trustee
By:
--------------------------
Authorized Signatory
<PAGE>
EXHIBIT 4.7.1(d)
PURSUANT TO SECTION 44-14-35.1 OF OFFICIAL CODE OF GEORGIA ANNOTATED, THIS
INSTRUMENT EMBRACES, COVERS AND CONVEYS SECURITY TITLE TO AFTER-ACQUIRED
PROPERTY OF THE GRANTOR
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION),
GRANTOR,
to
SUNTRUST BANK, ATLANTA,
TRUSTEE
THIRD SUPPLEMENTAL
INDENTURE
Relating to the
Series 1997A (Monroe) Note
Dated as of January 1, 1998
FIRST MORTGAGE OBLIGATIONS
- -------------------------------------------------------------------------------
- -------------------------------------------------------------------------------
<PAGE>
THIS THIRD SUPPLEMENTAL INDENTURE, dated as of January 1, 1998, is
between OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP CORPORATION), an
electric membership corporation organized and existing under the laws of the
State of Georgia, as Grantor (hereinafter called the "Company"), and SUNTRUST
BANK, ATLANTA, a banking corporation organized and existing under the laws of
the State of Georgia, as Trustee (in such capacity, the "Trustee").
WHEREAS, the Company has heretofore executed and delivered to the
Trustee an Indenture, dated as of March 1, 1997 (hereinafter called the
"Original Indenture") for the purpose of securing its Existing Obligations
and providing for the authentication and delivery of Additional Obligations
by the Trustee from time to time under the Original Indenture (capitalized
terms used herein shall have the meanings ascribed to them in the Original
Indenture as provided in Section 2.1 hereof);
WHEREAS, the Development Authority of Monroe County (the "Monroe
Authority") issued $143,710,000 in aggregate principal amount of Development
Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Scherer Project), Series 1992A (the "Series 1992A Bonds"), of
which $5,330,000 in aggregate principal amount matures on January 1, 1998
(the "Series 1992A Maturities");
WHEREAS, the Monroe Authority loaned the proceeds from the sale of the
Series 1992A Bonds to the Company, with such loan being evidenced by that
certain Series 1992A Note, dated as of October 1, 1992 (the "Series 1992A
Note"), from the Company to SunTrust Bank, Atlanta, as trustee (in such
capacity, the "Series 1992A Trustee"), as assignee and pledgee of the Monroe
Authority pursuant to the Trust Indenture, dated as of October 1, 1992 (the
"Series 1992A Indenture), between the Monroe Authority and the Series 1992A
Trustee;
WHEREAS, on December 10, 1997, the Monroe Authority issued $5,330,000 in
aggregate principal amount of Development Authority of Monroe County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer
Project), Series 1997A (the "Series 1997A (Monroe) Bonds"), the proceeds from
the sale of which were loaned to the Company pursuant to that certain Loan
Agreement, dated as of December 1, 1997 (the "Series 1997A (Monroe) Loan
Agreement,"), between the Monroe Authority and the Company to refund the
Series 1992A Maturities and to make the related payments on the Series 1992A
Note;
WHEREAS, the Company's obligation to repay the loan of the proceeds of
the Series 1997A (Monroe) Bonds is evidenced by that certain Series 1997A
(Monroe) Note, dated as of December 1, 1997 (the "Unsecured Note"), from the
Company to SunTrust Bank, Atlanta, as trustee (in such capacity, the "Series
1997A (Monroe) Trustee"), as assignee and pledgee of the Monroe Authority
pursuant to the Indenture of Trust, dated as of December 1, 1997 (the "Series
1997A (Monroe) Indenture"), between the Monroe Authority and the Series 1997A
(Monroe) Trustee;
<PAGE>
WHEREAS, as permitted by Section 4.9 of the Series 1997A (Monroe) Loan
Agreement, the Company desires to deliver to the Series 1997A (Monroe)
Trustee a promissory note secured under the Indenture (as hereinafter
defined) in substitution for the Unsecured Note;
WHEREAS, the Company desires to execute and deliver this Third
Supplemental Indenture, in accordance with the provisions of the Original
Indenture, for the purpose of providing for the creation and designation of
that certain Series 1997A (Monroe) Note, dated the date of its authentication
(the "Series 1997A (Monroe) Note"), from the Company to the Series 1997A
(Monroe) Trustee, as assignee and pledgee of the Monroe Authority pursuant to
the Series 1997A (Monroe) Indenture, as an Additional Obligation and
specifying the form and provisions of the Series 1997A (Monroe) Note (the
Original Indenture, as heretofore and hereby supplemented and modified, being
herein sometimes called the "Indenture");
WHEREAS, pursuant to Section 4.9 of the Series 1997A (Monroe) Loan
Agreement, upon the authentication of the Series 1997A (Monroe) Note by the
Trustee, the Series 1997A (Monroe) Note will be delivered to the Series 1997A
(Monroe) Trustee in substitution for the Unsecured Note;
WHEREAS, Section 12.1 of the Original Indenture provides that, without
the consent of the Holders of any of the Obligations at the time Outstanding,
the Company, when authorized by a Board Resolution, and the Trustee, may
enter into supplemental indentures for the purposes and subject to the
conditions set forth in said Section 12.1; and
WHEREAS, all acts and proceedings required by law and by the Articles of
Incorporation and Bylaws of the Company necessary to secure the payment of
the principal of (and premium, if any) and interest on the Series 1997A
(Monroe) Note, to make the Series 1997A (Monroe) Note to be issued hereunder,
when executed by the Company, authenticated and delivered by the Trustee and
duly issued, the valid, binding and legal obligation of the Company, and to
constitute the Indenture a valid and binding lien for the security of the
Series 1997A (Monroe) Note, in accordance with its terms, have been done and
taken; and the execution and delivery of this Third Supplemental Indenture
has been in all respects duly authorized;
NOW, THEREFORE, THIS THIRD SUPPLEMENTAL INDENTURE WITNESSES, that, to
secure the payment of the principal of (and premium, if any) and interest on
the Outstanding Secured Obligations, including, when issued, the Series 1997A
(Monroe) Note, to confirm the lien of the Indenture upon the Trust Estate,
including property purchased, constructed or otherwise acquired by the
Company since the date of execution of the Original Indenture, to secure
performance of the covenants therein and herein contained, to declare the
terms and conditions on which the Series 1997A (Monroe) Note is secured, and
in consideration of the premises thereof and hereof, the Company by these
presents does grant, bargain, sell, alienate, remise, release, convey,
assign, transfer, mortgage, hypothecate, pledge, set over and confirm to the
Trustee, and its successors and assigns in the trust created thereby and
hereby, in trust, all property, rights, privileges and franchises (other than
Excepted Property or Excludable Property) of the Company of the character
described in the Granting Clauses of the Original Indenture, including all
such property,
2
<PAGE>
rights, privileges and franchises acquired since the date of execution of the
Original Indenture, including, without limitation, all property described in
Exhibit A attached hereto, subject to all exceptions, reservations and
matters of the character therein referred to, and does grant a security
interest therein for the purposes expressed herein and in the Original
Indenture subject in all cases to Sections 5.2 and 11.2 B of the Original
Indenture and to the rights of the Company under the Original Indenture,
including the rights set forth in Article V thereof; but expressly excepting
and excluding from the lien and operation of the Indenture all properties of
the character specifically excepted as "Excepted Property" or "Excludable
Property" in the Original Indenture to the extent contemplated thereby.
PROVIDED, HOWEVER, that if, upon the occurrence of an Event of Default
under the Original Indenture, the Trustee, or any separate trustee or
co-trustee appointed under Section 9.14 of the Original Indenture or any
receiver appointed pursuant to statutory provision or order of court, shall
have entered into possession of all or substantially all of the Trust Estate,
all the Excepted Property described or referred to in Paragraphs A through H,
inclusive, of "Excepted Property" in the Original Indenture then owned or
thereafter acquired by the Company, shall immediately, and, in the case of
any Excepted Property described or referred to in Paragraphs I, J, L, N and P
of "Excepted Property" in the Original Indenture (excluding the property
described in Section 2 of Exhibit B in the Original Indenture), upon demand
of the Trustee or such other trustee or receiver, become subject to the lien
of the Indenture to the extent permitted by law, and the Trustee or such
other trustee or receiver may, to the extent permitted by law, at the same
time likewise take possession thereof, and whenever all Events of Default
shall have been cured and the possession of all or substantially all of the
Trust Estate shall have been restored to the Company, such Excepted Property
shall again be excepted and excluded from the lien of the Indenture to the
extent and otherwise as hereinabove set forth and as set forth in the
Original Indenture.
The Company may, however, pursuant to the Granting Clause Third of the
Original Indenture, subject to the lien of the Indenture any Excepted
Property or Excludable Property, whereupon the same shall cease to be
Excepted Property or Excludable Property.
TO HAVE AND TO HOLD all such property, rights, privileges and franchises
hereby and hereafter (by Supplemental Indenture or otherwise) granted,
bargained, sold, alienated, remised, released, conveyed, assigned,
transferred, mortgaged, hypothecated, pledged, set over or confirmed as
aforesaid, or intended, agreed or covenanted so to be, together with all the
tenements, hereditaments and appurtenances thereto appertaining (said
properties, rights, privileges and franchises, including any cash and
securities hereafter deposited or required to be deposited with the Trustee
(other than any such cash which is specifically stated in the Original
Indenture not to be deemed part of the Trust Estate) being part of the Trust
Estate), unto the Trustee, and its successors and assigns in the trust herein
created, forever.
SUBJECT, HOWEVER, to (i) Permitted Exceptions (as defined in Section 1.1
of the Original Indenture) and (ii) to the extent permitted by Section 13.6
of the Original Indenture as to property hereafter acquired (a) any duly
recorded or perfected prior mortgage or other lien that may
3
<PAGE>
exist thereon at the date of the acquisition thereof by the Company and (b)
purchase money mortgages, other purchase money liens, chattel mortgages,
conditional sales agreements or other title retention agreements created by
the Company at the time of acquisition thereof.
BUT IN TRUST, NEVERTHELESS, with power of sale, for the equal and
proportionate benefit and security of the Holders from time to time of all
the Outstanding Secured Obligations without any priority of any such
Obligation over any other such Obligation and for the enforcement of the
payment of such Obligations in accordance with their terms.
UPON CONDITION that, until the happening of an Event of Default and
subject to the provisions of Article V of the Original Indenture, and not in
limitation of the rights elsewhere provided in the Original Indenture,
including the rights set forth in Article V of the Original Indenture, the
Company shall be permitted to (i) possess and use the Trust Estate, except
cash, securities, Designated Qualifying Securities and other personal
property deposited, or required to be deposited, with the Trustee, (ii)
explore for, mine, extract, separate and dispose of coal, ore, gas, oil and
other minerals, and harvest standing timber, and (iii) receive and use the
rents, issues, profits, revenues and other income, products and proceeds of
the Trust Estate.
THE INDENTURE, INCLUDING THIS THIRD SUPPLEMENTAL INDENTURE, is intended
to operate and is to be construed as a deed passing title to the Trust Estate
and is made under the provisions of the existing laws of the State of Georgia
relating to deeds to secure debt, and not as a mortgage or deed of trust, and
is given to secure the Outstanding Secured Obligations. Should the
indebtedness secured by the Indenture be paid according to the tenor and
effect thereof when the same shall become due and payable and should the
Company perform all covenants herein contained in a timely manner, then the
Indenture shall be canceled and surrendered.
AND IT IS HEREBY COVENANTED AND DECLARED that the Series 1997A (Monroe)
Note is to be authenticated and delivered and the Trust Estate is to be held
and applied by the Trustee, subject to the covenants, conditions and trusts
set forth herein and in the Original Indenture, and the Company does hereby
covenant and agree to and with the Trustee, for the equal and proportionate
benefit of all Holders of the Outstanding Secured Obligations, as follows:
ARTICLE I
THE SERIES 1997A (MONROE) NOTE AND
CERTAIN PROVISIONS RELATING THERETO
Section 1.1 Authorization and Terms of the Series 1997A (Monroe) Note.
There shall be created and established an Additional Obligation in the
form of a promissory note known as and entitled the "Series 1997A (Monroe)
Note" (hereinafter referred to as the "Series 1997A (Monroe) Note"), the
form, terms and conditions of which shall be substantially as set forth
4
<PAGE>
in this Section and Section 1.2. The aggregate principal face amount of the
Series 1997A (Monroe) Note which shall be authenticated and delivered and
Outstanding at any one time is limited to $5,330,000.
The Series 1997A (Monroe) Note shall be dated the date of its
authentication. The Series 1997A (Monroe) Note shall mature on January 1,
2018 and shall bear interest from the date of its authentication to the date
of its maturity at rates calculated as provided for in the form of note
prescribed in Section 1.2. The Series 1997A (Monroe) Note shall be
authenticated and delivered to, and made payable to, SunTrust Bank, Atlanta,
as trustee (in such capacity, the "Series 1997A (Monroe) Trustee"), as
assignee and pledgee of the Development Authority of Monroe County (the
"Monroe Authority") pursuant to the Series 1997A (Monroe) Indenture.
All payments made on the Series 1997A (Monroe) Note shall be made to the
Series 1997A (Monroe) Trustee at its principal office in Atlanta, Georgia in
lawful money of the United States of America which will be immediately
available on the date payment is due.
Section 1.2 Form of the Series 1997A (Monroe) Note.
The Series 1997A (Monroe) Note and the Series 1997A (Monroe) Trustee's
authentication certificate to be executed on the Series 1997A (Monroe) Note
shall be substantially in the form of Exhibit B attached hereto, with such
appropriate insertions, omissions, substitutions and other variations as are
required or permitted in the Original Indenture.
Section 1.3 Substitution of the Series 1997A (Monroe) Note for the
Unsecured Note.
Upon its authentication, the Series 1997A (Monroe) Note shall be
delivered to the Series 1997A (Monroe) Trustee in substitution for the
Unsecured Note in accordance with Section 4.9 of the Series 1997A (Monroe)
Loan Agreement. Thereafter, the Series 1997A (Monroe) Note shall evidence
the loan theretofore evidenced by the Unsecured Note.
ARTICLE II
MISCELLANEOUS
Section 2.1 This Third Supplemental Indenture is executed and shall
be construed as an indenture supplemental to the Original Indenture, and
shall form a part thereof, and the Original Indenture, as heretofore
supplemented and as hereby supplemented and modified, is hereby confirmed.
Except to the extent inconsistent with the express terms hereof, all of the
provisions, terms, covenants and conditions of the Original Indenture shall
be applicable to the Series 1997A (Monroe) Note to the same extent as if
specifically set forth herein. All capitalized terms used in this Third
Supplemental Indenture shall have the same meanings ascribed to them in the
Original Indenture, except in cases where the context clearly indicates
otherwise.
5
<PAGE>
Section 2.2 All recitals in this Third Supplemental Indenture are
made by the Company only and not by the Trustee; and all of the provisions
contained in the Original Indenture, in respect of the rights, privileges,
immunities, powers and duties of the Trustee shall be applicable in respect
hereof as fully and with like effect as if set forth herein in full.
Section 2.3 Whenever in this Third Supplemental Indenture any of the
parties hereto is named or referred to, this shall, subject to the provisions
of Articles IX and XI of the Original Indenture, be deemed to include the
successors and assigns of such party, and all the covenants and agreements in
this Third Supplemental Indenture contained by or on behalf of the Company,
or by or on behalf of the Trustee shall, subject as aforesaid, bind and inure
to the respective benefits of the respective successors and assigns of such
parties, whether so expressed or not.
Section 2.4 Nothing in this Third Supplemental Indenture, expressed
or implied, is intended, or shall be construed, to confer upon, or to give
to, any person, firm or corporation, other than the parties hereto and the
Holders of the Outstanding Secured Obligations, any right, remedy or claim
under or by reason of this Third Supplemental Indenture or any covenant,
condition, stipulation, promise or agreement hereof, and all the covenants,
conditions, stipulations, promises and agreements in this Third Supplemental
Indenture contained by or on behalf of the Company shall be for the sole and
exclusive benefit of the parties hereto, and of the Holders of Outstanding
Secured Obligations.
Section 2.5 This Third Supplemental Indenture may be executed in
several counterparts, each of such counterparts shall for all purposes be
deemed to be an original, and all such counterparts, or as many of them as
the Company and the Trustee shall preserve undestroyed, shall together
constitute but one and the same instrument.
Section 2.6 To the extent permitted by applicable law, this Third
Supplemental Indenture shall be deemed to be a Security Agreement and
Financing Statement whereby the Company grants to the Trustee a security
interest in all of the Trust Estate that is personal property or fixtures
under the Uniform Commercial Code, as adopted or hereafter adopted in one or
more of the states in which any part of the properties of the Company are
situated. The mailing address of the Company,
as debtor is: 2100 East Exchange Place
P. O. Box 1349
Tucker, Georgia 30085-1349,
and the mailing address of the Trustees, as secured party is:
SunTrust Bank, Atlanta
58 Edgewood Avenue, Room 400A
Atlanta, Georgia 30303
6
<PAGE>
IN WITNESS WHEREOF, the parties hereto have caused this Third
Supplemental Indenture to be duly executed under seal as of the day and year
first above written.
Company: OGLETHORPE POWER
CORPORATION (AN ELECTRIC
MEMBERSHIP CORPORATION), an electric
membership corporation organized under
the laws of the State of Georgia
2100 East Exchange Place
P. O. Box 1349
Tucker, Georgia 30085-1349
By: /s/ T. D. Kilgore
--------------------
T. D. Kilgore
President and Chief Executive Officer
Signed, sealed and delivered Attest: /s/ Patricia N. Nash
by the Company in the presence of: ------------------------
Patricia N. Nash
Secretary
/s/ Kathy C. Joiner
- -------------------------
Witness
/s/ Thomas J. Brendiar
- -------------------------
Notary Public
[CORPORATE SEAL]
(Notarial Seal)
My commission expires: November 14, 2000
----------------------
[Signatures Continued on Next Page.]
<PAGE>
[Signatures Continued from Previous Page.]
Trustee: SUNTRUST BANK, ATLANTA
a banking corporation organized and existing
under the laws of the State of Georgia
By: /s/ Phillip D. DeMouey
-----------------------
Signed, sealed and delivered Name: Phillip D. DeMouey
by the Trustee in the Title: Assistant Vice President
presence of:
By: /s/ Ronald C. Painter
------------------------
/s/ Brian Womble Name: Ronald C. Painter
- ------------------- Title: Vice President
Witness
/s/ Teresa R. Turner
- ---------------------
Notary Public
[BANK SEAL]
(Notarial Seal)
My commission expires: April 3, 2001
----------------
<PAGE>
Exhibit A
All property of the Company in the Counties of Appling, Ben Hill,
Monroe, Carroll, Clarke, Cobb, DeKalb, Floyd, Fulton, Heard, Jackson, Monroe,
and Toombs, State of Georgia, including, without limitation, the properties
more specifically described below:
No additional properties to be specifically described.
A-1
<PAGE>
Exhibit B
[Form of Series 1997A (Monroe) Note]
THIS NOTE IS NON-TRANSFERABLE EXCEPT AS MAY BE REQUIRED TO EFFECT ANY
TRANSFER TO ANY SUCCESSOR TRUSTEE UNDER THE INDENTURE OF TRUST, DATED AS OF
DECEMBER 1, 1997, AS SUPPLEMENTED, BETWEEN THE DEVELOPMENT AUTHORITY OF
MONROE COUNTY AND SUNTRUST BANK, ATLANTA, AS TRUSTEE.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
SERIES 1997A (MONROE) NOTE DATE: January 14, 1998
(SCHERER PROJECT)
OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP CORPORATION)
("Oglethorpe"), an electric membership corporation organized and existing
under the laws of the State of Georgia, for value received and in
consideration of the agreement of the Development Authority of Monroe County
(the "Monroe Authority") to issue $9,305,000 in aggregate principal amount of
Development Authority of Monroe County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Scherer Project), Series 1997A (the "Series
1997A (Monroe) Bonds"), hereby promises to pay to SunTrust Bank, Atlanta (the
"Series 1997A (Monroe) Trustee"), as assignee and pledgee of the Monroe
Authority, acting pursuant to the Indenture of Trust, dated as of December 1,
1997, from the Monroe Authority to the Series 1997A Trustee (the "Series
1997A Indenture"), or its successor in trust, the principal sum of
$9,305,000, together with interest and prepayment premium (if any) thereon as
follows:
(1) on or before each Interest Payment Date (as defined in
the Indenture), a sum which will equal the interest on the Series 1997A
(Monroe) Bonds which will become due on such Interest Payment Date on the
Series 1997A (Monroe) Bonds; and
(2) on or before each January 1, commencing January 1, 1998,
a sum which will equal the principal amount of the Series 1997A (Monroe)
Bonds which will become due (whether at maturity or otherwise) on the next
succeeding annual principal payment date on the Series 1997A (Monroe) Bonds;
and
(3) on or before any redemption date for the Series 1997A
(Monroe) Bonds, a sum equal to the principal of, redemption premium (if any)
and interest on, the Series 1997A (Monroe) Bonds which are to be redeemed on
such date; and
B-1
<PAGE>
(4) on or before each date on which the Series 1997A (Monroe)
Bonds are required to be purchased pursuant to Section 4.01, 4.02 or 4.04 of
the Indenture, a sum equal to the purchase price of all Series 1997A (Monroe)
Bonds required to be purchased on such date.
This Note is issued in substitution for and supersedes and replaces that
certain Series 1997A (Monroe) Note, dated as of December 1, 1997, by
Oglethorpe to the Series 1997A (Monroe) Trustee which was executed and
delivered contemporaneously with the initial issuance of the Series 1997A
(Monroe) Bonds. This Note evidences the Loan (as defined in the Agreement
hereinafter referred to) of the Monroe Authority to Oglethorpe and the
obligation to repay the same and shall be governed by and shall be payable in
accordance with the terms, conditions and provisions of the Loan Agreement,
dated as of December 1, 1997 (the "Agreement"), between the Monroe Authority
and Oglethorpe, pursuant to which the Monroe Authority has agreed to loan to
Oglethorpe the proceeds from the sale of the Series 1997A (Monroe) Bonds.
This Note is a duly authorized obligation of Oglethorpe issued under and
equally and ratably secured by the Indenture, dated as of March 1, 1997 (the
"Original Mortgage Indenture"), between Oglethorpe, as grantor, and SunTrust
Bank, Atlanta, as trustee (in such capacity, the "Mortgage Indenture
Trustee"), as supplemented by the First Supplemental Indenture, dated as of
October 1, 1997 (the "First Supplemental Indenture"), the Second Supplemental
Indenture, dated as of January 1, 1998 (the "Second Supplemental Indenture")
and the Third Supplemental Indenture, dated as of January 1, 1998 (the "Third
Supplemental Indenture"), between Oglethorpe and the Mortgage Indenture
Trustee (the Original Indenture, as supplemented, the "Mortgage Indenture").
Reference is hereby made to the Mortgage Indenture for a statement of the
description of the properties thereby mortgaged, pledged and assigned, the
nature and extent of the security and the respective rights, limitations of
rights, duties and immunities thereunder of Oglethorpe, the Mortgage
Indenture Trustee and the holder of this Note and of the terms upon which
this Note is authenticated and delivered. This Note is created by the Third
Supplemental Indenture and designated as the "Series 1997A (Monroe) Note".
All payments hereon are to be made to the Series 1997A Trustee at its
principal office in Atlanta, Georgia, in lawful money of the United States of
America which will be immediately available on the day payment is due. As
set forth in Section 4.6 of the Agreement, the obligation of Oglethorpe to
make the payments required hereunder shall be absolute and unconditional.
Oglethorpe shall be entitled to certain credits against payments
required to be made hereunder as provided in Section 4.3 of the Agreement.
This Note may be prepaid upon the terms and conditions set forth in
Article V of the Agreement.
If the Series 1997A Trustee shall accelerate payment of the Series 1997A
(Monroe) Bonds, all payments on this Note shall be declared due and payable
in the manner and with the effect
B-2
<PAGE>
provided in the Agreement. The Agreement provides that, under certain
conditions, such declaration shall be rescinded by the Series 1997A Trustee.
No recourse shall be had for the payments required hereby or for any
claim based herein or in the Agreement or in the Mortgage Indenture against
any officer, director or member, past, present or future, of Oglethorpe as
such, either directly or through Oglethorpe, or under any constitution
provision, statute or rule of law or by the enforcement of any assessment or
by any legal or equitable proceedings or otherwise.
This Note shall not be entitled to any benefit under the Mortgage
Indenture and shall not become valid or obligatory for any purposes until the
Mortgage Indenture Trustee shall have signed the form of authentication
certificate endorsed hereon.
This Note shall be governed by and construed in accordance with the laws
of the State of Georgia.
B-3
<PAGE>
IN WITNESS WHEREOF, Oglethorpe has caused this Note to be executed in
its corporate name by its President and Chief Executive Officer and attested
by its Secretary and its corporate seal to be hereunto affixed.
OGLETHORPE POWER CORPORATION (AN
ELECTRIC MEMBERSHIP CORPORATION)
By:
---------------------------
T. D. Kilgore
President and Chief Executive Officer
(SEAL)
Attest:
- -----------------------------
Patricia N. Nash
Secretary
B-4
<PAGE>
TRUSTEE'S CERTIFICATE OF AUTHENTICATION
This is one of the Obligations of the series designated therein referred
to in the within mentioned Indenture.
SUNTRUST BANK, ATLANTA, as Trustee
By:
--------------------------------
Authorized Signatory
B-5
<PAGE>
EXHIBIT 10.14
REVISED AND RESTATED
COORDINATION SERVICES AGREEMENT
Between and Among
Georgia Power Company,
Oglethorpe Power Corporation and
Georgia System Operations Corporation
Dated September 10, 1997
<PAGE>
TABLE OF CONTENTS
RECITALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
ARTICLE I. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
RELATIONSHIP OF THE PARTIES. . . . . . . . . . . . . . . . . . . . . . . . . 2
ARTICLE II . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
DEFINITIONS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
(1) Actual Hourly Facility Generation . . . . . . . . . . . . . . . . . 3
(2) Actual Hourly OPC Resources Utilization . . . . . . . . . . . . . . 4
(3) Actual Hourly Resource Utilization. . . . . . . . . . . . . . . . . 4
(4) Affiliate . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4
(5) Available Capability. . . . . . . . . . . . . . . . . . . . . . . . 4
(6) Available Capability Schedule . . . . . . . . . . . . . . . . . . . 5
(7) Block Power Sale Agreement or BPSA. . . . . . . . . . . . . . . . . 5
(8) Block Resource. . . . . . . . . . . . . . . . . . . . . . . . . . . 5
(9) Control Area Services . . . . . . . . . . . . . . . . . . . . . . . 5
(10) Day. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
(11) Delivery Point . . . . . . . . . . . . . . . . . . . . . . . . . . 6
(12) Dynamic Scheduling or Dynamically Scheduled. . . . . . . . . . . . 6
(13) Effective Date . . . . . . . . . . . . . . . . . . . . . . . . . . 6
(14) Electric Membership Corporations or EMCs . . . . . . . . . . . . . 6
(15) Energy Imbalance Service . . . . . . . . . . . . . . . . . . . . . 7
(16) Federal Power Act. . . . . . . . . . . . . . . . . . . . . . . . . 7
(17) FERC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
(18) Hour . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
(19) IIC. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
(20) Interest Rate. . . . . . . . . . . . . . . . . . . . . . . . . . . 7
(21) ITS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
(22) Joint Committee. . . . . . . . . . . . . . . . . . . . . . . . . . 8
(23) Joint-Owned Facility . . . . . . . . . . . . . . . . . . . . . . . 8
(24) Joint Ownership Agreements . . . . . . . . . . . . . . . . . . . . 8
(25) Level A. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10
(26) Level A to B-1 Loss Factors. . . . . . . . . . . . . . . . . . . .10
(27) Level A to B-2 Loss Factors. . . . . . . . . . . . . . . . . . . .10
(28) Level B-1. . . . . . . . . . . . . . . . . . . . . . . . . . . . .10
(29) Level B-1 to B-2 Loss Factors. . . . . . . . . . . . . . . . . . .10
(30) Level B-2. . . . . . . . . . . . . . . . . . . . . . . . . . . . .10
(31) Level D. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11
(32) Level D to B-1 Loss Factors. . . . . . . . . . . . . . . . . . . .11
(33) Marginal Replacement Fuel Cost . . . . . . . . . . . . . . . . . .11
(34) Maximum Utilization Level. . . . . . . . . . . . . . . . . . . . .11
(35) Month. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11
(36) Monthly CSA Administration Fee . . . . . . . . . . . . . . . . . .12
(37) Monthly CSA Implementation Fee . . . . . . . . . . . . . . . . . .12
i
<PAGE>
(38) NERC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12
(39) Non-Territorial Control Area Services. . . . . . . . . . . . . . .12
(40) Nuclear Resource . . . . . . . . . . . . . . . . . . . . . . . . .12
(41) OPC-Controllable-ITS Resource. . . . . . . . . . . . . . . . . . .13
(42) OPC Non-Territorial Load . . . . . . . . . . . . . . . . . . . . .14
(43) OPC Off-System Resource. . . . . . . . . . . . . . . . . . . . . .14
(44) OPC Off-System Transaction . . . . . . . . . . . . . . . . . . . .14
(45) OPC Operational Deficiency . . . . . . . . . . . . . . . . . . . .15
(46) OPC Resource . . . . . . . . . . . . . . . . . . . . . . . . . . .15
(47) OPC Territorial Load . . . . . . . . . . . . . . . . . . . . . . .15
(48) OPC Total Load Requirements. . . . . . . . . . . . . . . . . . . .16
(49) Open Access Transmission Tariff of Southern Companies. . . . . . .16
(50) Party. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16
(51) Peaking Block Resource . . . . . . . . . . . . . . . . . . . . . .16
(52) Prudent Utility Practice . . . . . . . . . . . . . . . . . . . . .16
(53) Pseudo CT Resource . . . . . . . . . . . . . . . . . . . . . . . .17
(54) Pseudo CT Resource Heat Rate . . . . . . . . . . . . . . . . . . .17
(55) Pseudo Energy. . . . . . . . . . . . . . . . . . . . . . . . . . .17
(56) Pseudo Energy Purchase . . . . . . . . . . . . . . . . . . . . . .18
(57) Pseudo Energy Sale . . . . . . . . . . . . . . . . . . . . . . . .18
(58) Pseudo Schedule[ing] and Dispatch. . . . . . . . . . . . . . . . .18
(59) Quarter Hour . . . . . . . . . . . . . . . . . . . . . . . . . . .18
(60) Real-Time. . . . . . . . . . . . . . . . . . . . . . . . . . . . .18
(61) Revised ITSA . . . . . . . . . . . . . . . . . . . . . . . . . . .18
(62) SEPA . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18
(63) SEPA Resource. . . . . . . . . . . . . . . . . . . . . . . . . . .19
(64) SERC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19
(65) Southern Companies . . . . . . . . . . . . . . . . . . . . . . . .19
(66) Southern Control Area. . . . . . . . . . . . . . . . . . . . . . .19
(67) Southern Dispatch. . . . . . . . . . . . . . . . . . . . . . . . .19
(68) Southern Sub-Region. . . . . . . . . . . . . . . . . . . . . . . .20
(69) Steam Block Resource . . . . . . . . . . . . . . . . . . . . . . .20
(70) System Marginal Cost . . . . . . . . . . . . . . . . . . . . . . .20
(71) Term . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20
(72) Territorial Control Area Services. . . . . . . . . . . . . . . . .20
(73) Territorial Marginal Cost. . . . . . . . . . . . . . . . . . . . .20
(74) Umbrella Agreement . . . . . . . . . . . . . . . . . . . . . . . .21
(75) Utilization. . . . . . . . . . . . . . . . . . . . . . . . . . . .21
(76) Week . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21
(77) Year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .21
ARTICLE III. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .22
OPERATING OBLIGATIONS OF THE PARTIES . . . . . . . . . . . . . . . . . . . .22
3.1 Basic Operation and Maintenance Obligations.. . . . . . . . . . . .22
3.2 Obligations Under Future Standards. . . . . . . . . . . . . . . . .22
3.3 System Security and Integrity.. . . . . . . . . . . . . . . . . . .27
3.4 Supply Deficiencies.. . . . . . . . . . . . . . . . . . . . . . . .27
3.5 Power Flows.. . . . . . . . . . . . . . . . . . . . . . . . . . . .28
3.6 Survival. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29
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ARTICLE IV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29
OPC-CONTROLLABLE-ITS RESOURCES . . . . . . . . . . . . . . . . . . . . . . .29
4.1 Energy Utilization. . . . . . . . . . . . . . . . . . . . . . . . .29
4.2 Transmission Responsibility.. . . . . . . . . . . . . . . . . . . .29
ARTICLE V. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30
BLOCK RESOURCES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30
5.1 Dispatch. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30
5.2 Changes in Schedules. . . . . . . . . . . . . . . . . . . . . . . .30
5.3 Energy Utilization. . . . . . . . . . . . . . . . . . . . . . . . .30
5.4 Emergency Decommitment. . . . . . . . . . . . . . . . . . . . . . .30
5.5 Operability of Article. . . . . . . . . . . . . . . . . . . . . . .31
ARTICLE VI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31
SEPA RESOURCES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31
6.1 Dispatch. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .31
6.2 Energy Utilization. . . . . . . . . . . . . . . . . . . . . . . . .31
6.3 Operability of Article. . . . . . . . . . . . . . . . . . . . . . .31
ARTICLE VII. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .32
NUCLEAR RESOURCES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .32
7.1 Delivery of and Payment for Energy. . . . . . . . . . . . . . . . .32
7.2 Energy Utilization. . . . . . . . . . . . . . . . . . . . . . . . .32
7.3 Informational Available Capability and Energy Schedules.. . . . . .32
ARTICLE VIII . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .33
OPC OFF-SYSTEM TRANSACTIONS. . . . . . . . . . . . . . . . . . . . . . . . .33
8.1 Coordinate with Georgia Power.. . . . . . . . . . . . . . . . . . .33
8.2 Minimum Scheduling Notice.. . . . . . . . . . . . . . . . . . . . .33
8.3 Energy Utilization. . . . . . . . . . . . . . . . . . . . . . . . .34
8.4 Load Responsibility.. . . . . . . . . . . . . . . . . . . . . . . .34
8.5 Oglethorpe Power's Information Obligations. . . . . . . . . . . . .34
8.6 Transmission Responsibility.. . . . . . . . . . . . . . . . . . . .35
8.7 Indemnification.. . . . . . . . . . . . . . . . . . . . . . . . . .35
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ARTICLE IX . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .35
MUTUAL BUY/SELL TRANSACTIONS . . . . . . . . . . . . . . . . . . . . . . . .35
ARTICLE X. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36
PSEUDO CT RESOURCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . .36
10.1 Available Capability Schedule. . . . . . . . . . . . . . . . . . .36
10.2 Changes to Available Capability Schedule.. . . . . . . . . . . . .36
10.3 Hourly Utilization Schedule. . . . . . . . . . . . . . . . . . . .37
10.4 Changes to Utilization Schedule. . . . . . . . . . . . . . . . . .37
10.5 Pseudo CT Resource Test Energy.. . . . . . . . . . . . . . . . . .38
10.6 Pricing of Pseudo Energy Sales and Purchases.. . . . . . . . . . .39
ARTICLE XI . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .40
TERRITORIAL CONTROL AREA SERVICES. . . . . . . . . . . . . . . . . . . . . .40
11.1 Availability.. . . . . . . . . . . . . . . . . . . . . . . . . . .40
11.2 Scheduling, System Control and Dispatch Service. . . . . . . . . .41
11.3 Reactive Supply and Voltage Control From Generation Sources
Service.. . . . . . . . . . . . . . . . . . . . . . . . . . .42
11.4 Regulation and Frequency Response Service. . . . . . . . . . . . .43
11.5 Operating Reserve - Spinning Reserve Service.. . . . . . . . . . .46
11.6 Operating Reserve - Supplemental Reserve Service.. . . . . . . . .50
11.7 Short-Term Purchase Of Territorial Control Area Services.. . . . .54
ARTICLE XII. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .56
ENERGY IMBALANCE SERVICE . . . . . . . . . . . . . . . . . . . . . . . . . .56
12.1 Energy Imbalance.. . . . . . . . . . . . . . . . . . . . . . . . .56
12.2 Inadvertent Energy Bandwidth.. . . . . . . . . . . . . . . . . . .56
12.3 Back-Up Capacity Charge. . . . . . . . . . . . . . . . . . . . . .57
12.4 Commitment Cost. . . . . . . . . . . . . . . . . . . . . . . . . .57
12.5 Credit for Hourly Surplus Energy.. . . . . . . . . . . . . . . . .58
12.6 Payment for Hourly Deficit Energy. . . . . . . . . . . . . . . . .59
ARTICLE XIII . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .59
OPERATIONAL DEFICIENCY . . . . . . . . . . . . . . . . . . . . . . . . . . .59
13.1 Operational Responsibility.. . . . . . . . . . . . . . . . . . . .59
13.2 Oglethorpe Power's Real-Time Information Obligations.. . . . . . .59
13.3 Determination of OPC Operational Deficiency. . . . . . . . . . . .61
13.4 Corrective Action to Eliminate an OPC Operational
Deficiency. . . . . . . . . . . . . . . . . . . . . . . . . .61
13.5 No Liability; Indemnity. . . . . . . . . . . . . . . . . . . . . .62
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ARTICLE XIV. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .63
NON-TERRITORIAL CONTROL AREA SERVICES. . . . . . . . . . . . . . . . . . . .63
14.1 Load Within Southern Control Area. . . . . . . . . . . . . . . . .63
14.2 Other Loads. . . . . . . . . . . . . . . . . . . . . . . . . . . .64
ARTICLE XV . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .65
CONFIDENTIALITY OF DATA. . . . . . . . . . . . . . . . . . . . . . . . . . .65
15.1 Information Obligations; Confidentiality of Data.. . . . . . . . .65
15.2 Information Related To Supply Deficiencies.. . . . . . . . . . . .66
15.3 Information Related To Block and CT Resources. . . . . . . . . . .67
15.4 Information Related To Off-System Transactions.. . . . . . . . . .67
15.5 Information Related To Territorial Control Area
Services/Energy Imbalance Service.. . . . . . . . . . . . . .67
15.6 Information Related To Real-Time and Revenue Meter Data. . . . . .69
15.7 Information Related To Non-Territorial Control Area
Services. . . . . . . . . . . . . . . . . . . . . . . . . . .71
ARTICLE XVI. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .71
IMPLEMENTATION AND ADMINISTRATION FEES . . . . . . . . . . . . . . . . . . .71
16.1 CSA Implementation Fee.. . . . . . . . . . . . . . . . . . . . . .71
16.2 CSA Administration Fee.. . . . . . . . . . . . . . . . . . . . . .72
ARTICLE XVII . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .72
BILLING AND COLLECTIONS. . . . . . . . . . . . . . . . . . . . . . . . . . .72
17.1 Billing and Payment. . . . . . . . . . . . . . . . . . . . . . . .72
17.2 Billing Disputes and Final Accounting. . . . . . . . . . . . . . .74
17.3 Availability of Records. . . . . . . . . . . . . . . . . . . . . .77
17.4 Failure to Make Payments.. . . . . . . . . . . . . . . . . . . . .77
ARTICLE XVIII. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .78
TERM OF AGREEMENT. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .78
18.1 Term.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .78
18.2 Extension of the Term. . . . . . . . . . . . . . . . . . . . . . .79
18.3 FERC Changes; Rights to Terminate. . . . . . . . . . . . . . . . .82
ARTICLE XIX. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .84
MISCELLANEOUS PROVISIONS . . . . . . . . . . . . . . . . . . . . . . . . . .84
19.1 Approvals. . . . . . . . . . . . . . . . . . . . . . . . . . . . .84
19.2 Assignment.. . . . . . . . . . . . . . . . . . . . . . . . . . . .84
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19.3 Georgia Power's Agent. . . . . . . . . . . . . . . . . . . . . . .86
19.4 Cooperation. . . . . . . . . . . . . . . . . . . . . . . . . . . .86
19.5 No Partnership.. . . . . . . . . . . . . . . . . . . . . . . . . .86
19.6 Successors and Assigns.. . . . . . . . . . . . . . . . . . . . . .87
19.7 No Third Party Benefit.. . . . . . . . . . . . . . . . . . . . . .87
19.8 No Consequential Damages.. . . . . . . . . . . . . . . . . . . . .87
19.9 No Affiliate Liability.. . . . . . . . . . . . . . . . . . . . . .87
19.10 Disclaimers of Warranty.. . . . . . . . . . . . . . . . . . . . .88
19.11 Supply Constancy. . . . . . . . . . . . . . . . . . . . . . . . .89
19.12 Time of Essence; No Waiver. . . . . . . . . . . . . . . . . . . .89
19.13 Amendments. . . . . . . . . . . . . . . . . . . . . . . . . . . .89
19.14 Superseding Effect. . . . . . . . . . . . . . . . . . . . . . . .90
19.15 Notice. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .90
19.16 Counterparts. . . . . . . . . . . . . . . . . . . . . . . . . . .91
19.17 Article and Section Headings. . . . . . . . . . . . . . . . . . .91
19.18 Including.. . . . . . . . . . . . . . . . . . . . . . . . . . . .91
19.19 Governing Law.. . . . . . . . . . . . . . . . . . . . . . . . . .91
19.20 Section 206 Rights. . . . . . . . . . . . . . . . . . . . . . . .91
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List of Exhibits
Exhibit A
Member Systems
Oglethorpe Power Corporation
Georgia Transmission Corporation
Georgia System Operations Corporation
Exhibit B
Commitment Cost Rate
Exhibit C
Regulation Energy Variance Rates
Exhibit D
Regulation and Spinning Reserve Requirements Rates
Exhibit E
Supplemental Reserve Requirements Rates
Exhibit F
Short Term Control Area Services Rates
<PAGE>
REVISED AND RESTATED
COORDINATION SERVICES AGREEMENT
This REVISED AND RESTATED COORDINATION SERVICES AGREEMENT (the
"Agreement") is entered into as of this 10th day of September, 1997, between
and among GEORGIA POWER COMPANY, a corporation organized and existing under
the laws of the State of Georgia ("Georgia Power"), OGLETHORPE POWER
CORPORATION (AN ELECTRIC MEMBERSHIP CORPORATION), organized and existing
under the laws of the state of Georgia ("Oglethorpe Power" or "OPC"), and
GEORGIA SYSTEM OPERATIONS CORPORATION, a non-profit corporation organized and
existing under the laws of the state of Georgia ("GSOC").
RECITALS
WHEREAS, Georgia Power currently provides certain control area
services, scheduling services and other services to Oglethorpe Power pursuant
to that certain Coordination Services Agreement ("CSA") dated November 12,
1990; and provides a fixed quantity of capacity to Oglethorpe Power pursuant
to that certain Block Power Sale Agreement ("BPSA") dated November 12, 1990,
both of which are presently on file with the Federal Energy Regulatory
Commission ("FERC");
WHEREAS, Oglethorpe Power has implemented a restructuring plan
whereby the prior operations of Oglethorpe Power have been divided into three
specialized companies: a generation company (which retains the name of
Oglethorpe Power or OPC), a transmission company, Georgia Transmission
Corporation ("GTC"), and a system operating company, GSOC, which provides
system operations functions for the generation and transmission resources of
Oglethorpe Power, the Georgia Transmission Corporation and the members of
Oglethorpe Power;
<PAGE>
WHEREAS, Georgia Power, Oglethorpe Power and GSOC have entered into
a "Memorandum of Understanding For a Revised and Restated Coordination
Services Agreement" dated March 6, 1997, which reflects the Parties' desire
to establish a new service relationship that comports with and accommodates
Oglethorpe Power's restructuring plan by, among other things, (1) revising
the provisions of the CSA relating to the scheduling of resources and the
provision of control area services and (2) recognizing the relationship among
Oglethorpe Power, GTC, GSOC and Georgia Power as regards the services
provided under this Agreement;
WHEREAS, Georgia Power, Oglethorpe Power and GSOC desire to
implement their new service relationship by entering into this Agreement,
which, upon its effectiveness, shall supersede the CSA in its entirety.
NOW, THEREFORE, for and in consideration of the premises and the
mutual undertakings herein contained and for other good and valuable
consideration, the terms and sufficiency of which are hereby acknowledged,
Georgia Power, Oglethorpe Power and GSOC hereby agree as follows:
ARTICLE I
RELATIONSHIP OF THE PARTIES
(a) The Parties agree that all actions undertaken or representations
made by GSOC or any of its Affiliates in connection with or related to this
Agreement shall be as agent for Oglethorpe Power, and that Oglethorpe Power,
as principal, shall be fully liable for any acts, failures to act,
representations or omissions of GSOC or any of its Affiliates which in any
way harm Georgia Power or Georgia Power's Affiliates. Any references in this
Agreement to (i) facilities owned or controlled by Oglethorpe Power, (ii)
transactions undertaken by Oglethorpe Power, (iii) the performance of
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Oglethorpe Power, or (iv) loads of Oglethorpe Power shall include, as
appropriate, the facilities, transactions, performance and/or loads of one or
more of GTC, GSOC or the EMCs.
(b) The Parties agree that all actions undertaken or representations
made by Southern Company Services, Inc. ("SCS") or any of its Affiliates in
connection with or related to this Agreement shall be as agent for Georgia
Power, and that Georgia Power, as principal, shall be fully liable for any
acts, failures to act, representations or omissions of SCS or any of its
Affiliates which in any way harm Oglethorpe Power or Oglethorpe Power's
Affiliates.
ARTICLE II
DEFINITIONS
In addition to the initially capitalized terms and phrases defined in
the preamble of this Agreement, the following initially capitalized terms and
phrases as and when used in this Agreement shall have the respective meanings
set forth below.
(1) "Actual Hourly Facility Generation" - means the amount of energy, in
megawatt hours (MWH), net of station service energy, which is
actually generated during any one Hour by the generation facility
associated with the Pseudo CT Resource and delivered to Level B-1, as
adjusted for losses using Level A to B-1 Loss Factors, as
appropriate. During periods in which the amount determined pursuant
to the previous sentence is negative, the Actual Hourly Facility
Generation associated with such Pseudo CT Resource shall nevertheless
be deemed to be zero megawatt hours (MWH).
(2) "Actual Hourly OPC Resources Utilization" - for a given Hour of the
Term, means the sum, in megawatt hours (MWH), of the Actual Hourly
Resource Utilization during such Hour of each of the OPC Resources.
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<PAGE>
(3) "Actual Hourly Resource Utilization" - of a given OPC Resource during
a given Hour of the Term, means the amount of energy, in
megawatt-hours (MWH), that Oglethorpe Power is deemed to have utilized
during such Hour from such OPC Resource, as such amount of energy is
determined pursuant to Articles IV, V, VI, VII, VIII and X and
adjusted for losses to Level B-1 as appropriate.
(4) "Affiliate" - of any specified corporation, means any other entity
directly or indirectly controlling or controlled by or under direct or
indirect common control with such specified corporation. For purposes
of this definition, "control" when used with respect to any entity
means the power to direct the management and policies of such entity,
directly or indirectly, whether through the ownership of voting
securities, by contract or otherwise; and the terms "controlling" and
"controlled" have meanings correlative to the foregoing. "Affiliates"
- of any specified corporation means, collectively, more than one (1)
Affiliate of the specified corporation. For purposes of this
Agreement, Oglethorpe Power, GSOC, GTC and the EMCs (and any
successors thereto) shall be deemed Affiliates.
(5) "Available Capability" - means the level of maximum possible output at
that time associated with a resource that is not unavailable due to
outages or deratings (as defined by NERC), or transmission constraints
(as defined by NERC).
(6) "Available Capability Schedule" - means the list of hourly Pseudo CT
Resource Available Capability provided to Oglethorpe Power by Georgia
Power pursuant to Article X of this Agreement.
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<PAGE>
(7) "Block Power Sale Agreement" or "BPSA" - means that certain Block
Power Sale Agreement between Georgia Power and Oglethorpe Power dated
as of November 12, 1990.
(8) "Block Resource" - means the generation capability associated with any
one (1) of the Component Blocks, as defined in the BPSA. "Block
Resources" - means, collectively, more than one Block Resource.
(9) "Control Area Services" - means those services which are necessary (a)
to effectuate energy deliveries under this Agreement and (b) to
maintain the integrity of the ITS and the Southern Control Area
pursuant to this Agreement. Control Area Services shall include the
following for purposes of this Agreement:
a. Scheduling, System Control and Dispatch Service
b. Reactive Supply and Voltage Control From Generation Sources
Service
c. Regulation and Frequency Response Service
d. Operating Reserve - Spinning Reserve Service
e. Operating Reserve - Supplemental Reserve Service.
(10) "Day" - means a calendar day, commencing at one (1) minute prior to
12:01 a.m. (Birmingham, Alabama prevailing time) of each such calendar
day and ending at one (1) minute after 11:59 p.m. (Birmingham, Alabama
prevailing time) of such calendar day.
(11) "Delivery Point" - means any point on Oglethorpe Power's system at
which Oglethorpe Power takes energy off of the ITS, directly or
indirectly, as contemplated by virtue of Oglethorpe Power's and its
Affiliates' ownership of a portion of the ITS
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pursuant to the provisions of the Revised ITSA. "Delivery Points" -
means, collectively, more than one (1) Delivery Point.
(12) "Dynamic Scheduling" or "Dynamically Scheduled" - with respect to this
Agreement, means that Oglethorpe Power has the contractual right to
provide a Dynamic Schedule (as defined by NERC's "Terms Used in the
Policies") for an OPC-Controllable-ITS Resource or an OPC
Non-Territorial Load, where (i) such resource or load is physically
located in a control area immediately adjacent to the ITS, or (ii)
such resource is located within the ITS but is operated by a person or
entity engaged in the selling of wholesale power to persons or
entities other than Oglethorpe Power; provided, however, that such
Dynamic Scheduling must be performed in accordance with appropriate
industry standards and procedures and Oglethorpe Power must pay all
reasonable costs associated with such Dynamic Scheduling.
(13) "Effective Date" - has the meaning given in Section 18.1 of this
Agreement.
(14) "Electric Membership Corporations" or "EMCs" - means any one or more
of those electric membership corporations, identified in Exhibit "A"
attached hereto and incorporated herein by this reference (for so long
as and to the extent that such EMC or its successor remains a member
of Oglethorpe Power); "Electric Membership Corporation" or "EMC" -
means any one of the Electric Membership Corporations.
(15) "Energy Imbalance Service" - means the service rendered to Oglethorpe
Power by Georgia Power which matches Actual Hourly OPC Resources
Utilization and OPC Total Load Requirements on an hourly basis and
provides any necessary back-up power to Oglethorpe Power to maintain
such balance. Energy Imbalance Service
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<PAGE>
shall incorporate a Back-Up Capacity Charge, (Section 12.3), a
Commitment Cost (Section 12.4), a Credit for Hourly Surplus Energy
(Section 12.5), and a Payment for Hourly Deficit Energy (Section
12.6).
(16) "Federal Power Act" - means the Federal Power Act, 16 U.S.C.A Sections
791a-828c (West 1985 & Supp. 1990), as the same may hereafter be
amended from time to time.
(17) "FERC" - means the Federal Energy Regulatory Commission or any
governmental authority succeeding to the powers and functions thereof
under the Federal Power Act.
(18) "Hour" - means one (1) of the twenty-four (24) clock hours of a Day.
"Hourly" - has a meaning correlative to that of Hour.
(19) "IIC" - means that certain document, The Southern Company System
Intercompany Interchange Contract dated October 31, 1988, among
Georgia Power and certain of its Affiliates, accepted in FERC Docket
No. ER89-48-000, as the same has been and may hereafter be amended, or
any successor contract among Georgia Power and its Affiliates for
coordinated operations.
(20) "Interest Rate" - means the rate per annum equal to the lesser of:
(i) the highest interest rate allowed by law, in accordance with
O.C.G.A. Section 7-4-2(a)(1) (Supp. 1989); or
(ii) two (2) percent plus the prime rate, as stated in the Wall
Street Journal on the date payment is due.
(21) "ITS" - means the "Integrated Transmission System" as such term is
defined in the Revised ITSA.
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(22) "Joint Committee" - means the Joint Committee for Planning and
Operations established under that certain Joint Committee Agreement
among Georgia Power, Oglethorpe Electric Membership Corporation
(Oglethorpe Power's predecessor) and certain other entities, dated as
of August 27, 1976, as amended.
(23) "Joint-Owned Facility" - means any one (1) of the following generation
facilities, each of which is jointly owned by Oglethorpe Power,
Georgia Power and in some cases certain other entities pursuant to the
respective Joint Ownership Agreements associated therewith: Plant
Robert W. Scherer Unit No. 1, Plant Robert W. Scherer Unit No. 2,
Plant Hal Wansley Unit No. 1, Plant Hal Wansley Unit No. 2, Plant Hal
Wansley Unit No. 5A (combustion turbine), Rocky Mountain Pumped
Storage Hydroelectric Generation Facility ("Rocky Mountain"), Edwin I.
Hatch Nuclear Plant Unit No. 1, Edwin I. Hatch Nuclear Plant Unit No.
2, Plant Alvin W. Vogtle Unit No. 1 and Plant Alvin W. Vogtle Unit No.
2. "Joint-Owned Facilities" - means, collectively, more than one (1)
Joint-Owned Facility.
(24) "Joint Ownership Agreements" - associated with a given Joint-Owned
Facility, means the following contracts, as they may be amended from
time to time:
(i) in the case of the Rocky Mountain Pumped Storage Hydroelectric
Generation Facility, that certain Rocky Mountain Pumped Storage
Hydroelectric Project Ownership Participation Agreement dated as
of November 18, 1988; that certain Rocky Mountain Pumped Storage
Hydroelectric Project Operating Agreement dated as of
November 18, 1988; and that certain Rocky Mountain Pumped Storage
Hydroelectric Plant Coordination Procedures Agreement dated as of
May 31, 1995;
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(ii) in the case of the Nuclear Resource associated with Edwin I.
Hatch Nuclear Plant Unit Nos. 1 and 2, that certain Edwin I.
Hatch Nuclear Plant Purchase and Ownership Participation
Agreement dated as of January 6, 1975 and that certain Edwin
I. Hatch Nuclear Plant Operating Agreement dated as of January
6, 1975;
(iii) in the case of the Nuclear Resource associated with Plant
Alvin W. Vogtle Unit Nos. 1 and 2, that Plant Alvin W. Vogtle
Unit Numbers 1 and 2 Purchase and Ownership Participation
Agreement dated as of August 27, 1976 and that certain Plant
Alvin W. Vogtle Unit Numbers 1 and 2 Operating Agreement dated
as of August 27, 1976;
(iv) in the case of Plant Robert W. Scherer Unit Nos.1 and 2, that
certain Plant Robert W. Scherer Units Number 1 and 2 Purchase and
Ownership Participation Agreement dated as of May 15, 1980 and
that certain Plant Robert W. Scherer Units Number 1 and 2
Operating Agreement dated as of May 15, 1980;
(v) in the case of Plant Hal Wansley Unit Nos. 1 and 2, that certain
Plant Hal Wansley Purchase and Ownership Participation Agreement
dated as of March 26, 1976 and that certain Plant Hal Wansley
Operating Agreement dated as of March 26, 1976; and
(vi) in the case of Plant Hal Wansley Unit No. 5A (and the associated
Pseudo CT Resource), that certain Plant Hal Wansley Combustion
Turbine Agreement dated as of August 2, 1982, as amended by that
certain letter from A.W.
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Dahlberg of Georgia Power to David M. Holmes of Oglethorpe Power
dated October 20, 1982.
(25) "Level A - means the generator voltage side of each step-up or
station service transformer of each generation facility of Georgia
Power or other entity that supplies power directly into the ITS.
(26) "Level A to B-1 Loss Factors" - means factors intended to reflect
energy loss from Level A to Level B-1 for generation, as adopted by
the Joint Committee.
(27) "Level A to B-2 Loss Factors" - means factors intended to reflect
energy loss from Level A to Level B-2 for station service, as adopted
by the Joint Committee.
(28) "Level B-1" - means the transmission voltage side of each step-up
transformer of each generation facility of Georgia Power or other
entity that supplies power directly into the ITS, or any points of
interconnection where power flows into the ITS.
(29) "Level B-1 to B-2 Loss Factors" - means factors intended to reflect
energy loss from Level B-1 to Level B-2, as adopted by the Joint
Committee.
(30) "Level B-2" - means the transmission facilities included in the ITS
which operate at 115 kV or above or any points of interconnection
where power flows out of the ITS, including, but not limited to,
station service.
(31) "Level D" - means the distribution voltage side of the meter points
where power flows out of the ITS.
(32) "Level D to B-1 Loss Factors" - means factors intended to reflect
energy loss from Level D to Level B-1, as adopted by the Joint
Committee.
(33) "Marginal Replacement Fuel Cost" - means the fuel cost, in dollars per
millions of British Thermal Units (MMBTU), including the value of SO2
allowances, for the
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Pseudo CT Resource, as determined in accordance with the IIC marginal
fuel cost procedures filed with FERC (as such procedures may be
amended from time to time), which is used for Southern Dispatch.
Georgia Power shall use reasonable best efforts to make available to
Oglethorpe Power the Marginal Replacement Fuel Cost on or before three
(3) Days prior to the Day on which such cost will take effect.
(34) "Maximum Utilization Level" - means the maximum level of allowed
resource Utilization of the Pseudo CT Resource by Oglethorpe Power
during an Hour, as reasonably determined by Georgia Power in
accordance with Prudent Utility Practice, which shall represent as
closely as possible the actual maximum operating limitation on the
generation facility associated with such Pseudo CT Resource at that
time.
(35) "Month" - means a calendar month, commencing at one (1) minute prior
to 12:01 a.m. (Birmingham, Alabama prevailing time) on one of
January 1, February 1, March 1, April 1, May 1, June 1, July 1, August
1, September 1, October 1, November 1 or December 1 and ending at one
(1) minute after 11:59 p.m. (Birmingham, Alabama prevailing time) of
the succeeding January 31, February 28 or 29, March 31, April 30, May
31, June 30, July 31, August 31, September 30, October 31, November 30
or December 31. "Monthly" - has a meaning correlative to that of
Month.
(36) "Monthly CSA Administration Fee" - for a given Month of the Term,
means the fee, in dollars per Month ($/Mo), equal to the summation of
all costs incurred by Georgia Power or its agent during the previous
Month which are reimbursable by Oglethorpe Power under Section 16.2.
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(37) "Monthly CSA Implementation Fee" - for a given Month of the Term,
means the fee, in dollars per Month ($/Mo), equal to the summation of
all costs incurred by Georgia Power or its agent during the previous
Month which are reimbursable by Oglethorpe Power under Section 16.1.
(38) "NERC" - means the North American Electric Reliability Council,
including the regional organization(s) to which the Parties belong,
and any successor organization.
(39) "Non-Territorial Control Area Services" - means Control Area Services
associated with OPC Non-Territorial Load, as determined pursuant to
Article XIV.
(40) "Nuclear Resource" - means the generation capability associated with
Oglethorpe Power's ownership in any one (1) of the following
Joint-Owned Facilities: Edwin I. Hatch Nuclear Plant Unit No. 1,
Edwin I. Hatch Nuclear Plant Unit No. 2, Plant Alvin W. Vogtle Unit
No. 1 and Plant Alvin W. Vogtle Unit No. 2. "Nuclear Resources" -
means, collectively, more than one (1) Nuclear Resource.
(41) "OPC-Controllable-ITS Resource" - from time to time during the Term,
means the generation capability associated with Oglethorpe Power's or
the EMCs' entitlement to any generation facility or other resource
that has all of the following characteristics at such time:
(i) Oglethorpe Power's or the EMCs' entitlement to the generation
facility or other resource is not being operated in Southern
Dispatch;
(ii) the generation facility or other resource (a) is directly
connected to the ITS or is Dynamically Scheduled, or (b) is
connected to a distribution system which is directly connected
to the ITS; provided, however, that such facility(ies) has a
capability of one (1) megawatt or greater through a single
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meter; and provided further that the Delivery Point meter
readings for such distribution system are adjusted to add back
any energy produced by such facility(ies), if appropriate, and
that all such Actual Hourly Resource Utilization and Available
Capability values are adjusted by appropriate distribution
loss factors prior to adjustment by the loss factors defined
in this Agreement;
(iii) the generation facility or other resource is within the
Southern Control Area; and
(iv) the generation facility or other resource is not associated
with one of the following types of OPC Resources: a Block
Resource, a SEPA Resource, a Nuclear Resource, an OPC
Off-System Resource or the Pseudo CT Resource.
"OPC-Controllable-ITS Resources" - means, collectively, more
than one (1) OPC-Controllable-ITS Resource.
(42) "OPC Non-Territorial Load" - means the hourly sum of Oglethorpe
Power's and the EMCs' sales to another person or entity, excluding OPC
Territorial Load, adjusted for losses using Level B-1 to B-2 Loss
Factors or Level D to B-1 Loss Factors, as appropriate.
(43) "OPC Off-System Resource" - means any OPC Off-System Transaction
associated with the purchase of energy by Oglethorpe Power or the
EMCs. "OPC Off-System Resources" - means, collectively, more than one
(1) OPC Off-System Resource.
(44) "OPC Off-System Transaction" - means (a) any sales transaction, which
serves OPC Non-Territorial Load, between Oglethorpe Power or its
Affiliate and another person or entity, where such other person or
entity (i) is engaged in the selling of
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wholesale power, (ii) is not directly connected to the ITS, or (iii)
is outside the Southern Control Area; provided, however, that any sale
that is Dynamically Scheduled from a single OPC Resource or any sale
that is Dynamically Scheduled to serve the load of an entity which is
not engaged in selling wholesale power shall not be an OPC Off-System
Transaction; (b) any purchase transaction between Oglethorpe Power or
its Affiliate and another person or entity, where such other person or
entity (i) is engaged in the selling of wholesale power to person(s)
or entity(ies) other than Oglethorpe Power, (ii) is not directly
connected to the ITS, or (iii) is outside the Southern Control Area;
provided, however, that any purchase that is Dynamically Scheduled
from a single generation facility shall not be an OPC Off-System
Transaction; or (c) any transaction by which GTC provides or causes or
allows to be provided transmission service into, out of or across the
ITS. "OPC Off-System Transactions" means, collectively, more than one
(1) OPC Off-System Transaction. All OPC Off-System Transactions
shall be adjusted for losses using Level A to B-1 Loss Factors and/or
Level B-1 to B-2 Loss factors, as appropriate.
(45) "OPC Operational Deficiency" - from time to time during the Term,
means the negative amount, if any, computed by Georgia Power pursuant
to and in accordance with Section 13.3.
(46) "OPC Resource" - means any one (1) of the following resources: the
OPC-Controllable-ITS Resources, the Block Resources, the SEPA
Resources, the Nuclear Resources, the OPC Off-System Resources and the
Pseudo CT Resource. "OPC Resources" - means, collectively, more than
one (1) OPC Resource.
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(47) "OPC Territorial Load" - means the hourly sum of the Delivery Point
loads associated with the retail loads of each EMC of Oglethorpe Power
(for so long as and to the extent that such EMC or its successor
remains a member of Oglethorpe Power), adjusted for losses using Level
D to B-1 Loss Factors, as appropriate; any requirements associated
with any (company-use) facilities directly served by Oglethorpe Power,
adjusted for losses using Level D to B-1 Loss Factors, as appropriate;
any net station service requirement associated with an OPC Resource,
adjusted for losses using Level A to B-2 Loss Factors and Level B-1 to
B-2 Loss Factors, as appropriate; and any pumping or motoring energy
associated with Oglethorpe Power's ownership interest in Rocky
Mountain, adjusted for losses using Level A to B-2 Loss Factors and
Level B-1 to B-2 Loss Factors, as appropriate.
(48) "OPC Total Load Requirements" - means the sum of OPC Territorial Load
and OPC Non-Territorial Load.
(49) "Open Access Transmission Tariff of Southern Companies" - means the
Open Access Transmission Tariff filed with the FERC by Southern
Companies in Docket No. OA96-27-000, as accepted by the FERC and as
revised or amended from time to time at the direction of or under the
authority of the FERC. To the extent Oglethorpe Power is subject to
rates under the Open Access Transmission Tariff of Southern Companies
pursuant to the terms of this Agreement, such rates shall be subject
to adjustment (refund with interest, or surcharge with interest)
consistent with any changes to such rates required by final FERC order
in Docket No. OA96-27-000 or any subsequent rate proceeding under the
Federal Power Act.
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(50) "Party" - means Georgia Power, Oglethorpe Power or GSOC. "Parties"
means any two or more of Georgia Power, Oglethorpe Power and GSOC.
(51) "Peaking Block Resource" - means the generation capability associated
with any one (1) of the "Component Peaking Blocks" (as such term is
defined in the Block Power Sale Agreement). "Peaking Block Resources"
- means, collectively, more than one (1) Peaking Block Resource. Each
Peaking Block Resource is a Block Resource.
(52) "Prudent Utility Practice" - means, at a particular time, any of the
practices, methods and acts engaged in or approved by a significant
portion of the electric utility industry prior to such time, or any of
the practices, methods and acts which, in the exercise of reasonable
judgment in light of the facts known at the time the decision was
made, could have been expected to accomplish the desired results at
the lowest reasonable cost consistent with good business practices,
reliability, safety and expedition. Prudent Utility Practice is not
intended to be limited to the optimum practice, method or act to the
exclusion of all others, but rather to be a spectrum of possible
practices, methods or acts expected to accomplish the desired results,
having due regard for, among other things, manufacturers' warranties
and the requirements of governmental authorities of competent
jurisdiction and the requirements of this Agreement.
(53) "Pseudo CT Resource" - means the generation capability associated with
Oglethorpe Power's ownership in the following Joint-Owned Facility:
Plant Hal Wansley Unit No. 5A (combustion turbine).
(54) "Pseudo CT Resource Heat Rate" - means the value shown for station
economy (expressed in MMBTU/MWH) for Wansley Unit No. 5A, as shown on
the then-
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current IIC Informational Schedule No. 2 or successor thereto,
adjusted for losses using the appropriate Level A to B-1 Loss Factor.
(55) "Pseudo Energy" - means the integrated hourly difference between (i)
the Actual Hourly Resource Utilization of the Pseudo CT Resource in
megawatt hours (MWH), less (ii) the Actual Hourly Facility Generation
allocated to Oglethorpe Power from the Pseudo CT Resource in megawatt
hours (MWH), as determined under the Joint Ownership Agreement
governing the Pseudo CT Resource.
(56) "Pseudo Energy Purchase" - means, if the Pseudo Energy is negative in
an Hour, Georgia Power shall be deemed to have made an energy purchase
from Oglethorpe Power equal to the absolute value of the amount of
such Pseudo Energy, which purchase shall be subject to the provisions
of Section 10.6.
(57) "Pseudo Energy Sale" - means, if the Pseudo Energy is positive in an
Hour, Georgia Power shall be deemed to have made an energy sale to
Oglethorpe Power equal to the amount of such Pseudo Energy, which sale
shall be subject to the provisions of Section 10.6.
(58) "Pseudo Schedule[ing] and Dispatch" - means the hourly scheduling and
dispatch of the Pseudo CT Resource by Oglethorpe Power by and through
Georgia Power in accordance with Article X.
(59) "Quarter Hour" - means any one of the 15 minute increments starting on
each Hour, at 15 minutes past each Hour, at 30 minutes past each Hour,
and at 45 minutes past each Hour.
(60) "Real-Time" - when used as an adjective or adverb, means on as near an
instantaneous basis as possible.
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(61) "Revised ITSA" - means that certain Revised and Restated Integrated
Transmission System Agreement between Georgia Power and Oglethorpe
Power dated as of November 12, 1990, and each of the similar
agreements between Georgia Power and the Municipal Electric Authority
of Georgia and between Georgia Power and the City of Dalton, Georgia,
as amended.
(62) "SEPA" - means the Southeastern Power Administration.
(63) "SEPA Resource" - from time to time during the Term, means the
generation capability associated with Oglethorpe Power's and the EMCs'
entitlement to the output of the hydroelectric generation facilities
that make up any one (1) SEPA project. "SEPA Resources" - means,
collectively, more than one (1) SEPA Resource (or if Oglethorpe Power
is scheduling with SEPA as a single resource, pursuant to Section 6.1,
at a given time during the Term, then at such time it means that one
(1) OPC Resource).
(64) "SERC" - means the Southeastern Electric Reliability Council, a
regional organization within NERC.
(65) "Southern Companies" - means, collectively, the operating company
affiliates of Southern Company, including Alabama Power Company,
Georgia Power Company, Gulf Power Company, Mississippi Power Company,
and Savannah Electric and Power Company.
(66) "Southern Control Area" - means the electric service area encompassed
by the tie lines, including, but not limited to, the pseudo tie lines
(as defined by NERC's "Terms Used in the Policies"), between the
Southern Companies and other utilities.
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(67) "Southern Dispatch" - means the ability of Southern Company Services,
Inc. (or other Affiliate of Georgia Power) to schedule and control,
directly or indirectly, manually or automatically, the output of a
generation facility in the Southern Control Area in order to increase
or decrease the electricity delivered from such generation facility
into the electric system with which it is interconnected.
(68) "Southern Sub-Region" - means the sub-region of the Southeastern
Electric Reliability Council, including the Southern Control Area, the
control area of the Alabama Electric Cooperative, Inc., the control
area of South Mississippi Electric Power Association, and the control
areas of SEPA.
(69) "Steam Block Resource" - means the generation capability associated
with any one (1) of the "Component Steam Blocks" (as such term is
defined in the Block Power Sale Agreement). "Steam Block Resources"
-means, collectively, more than one (1) Steam Block Resource. Each
Steam Block Resource is a Block Resource.
(70) "System Marginal Cost" - means the incremental energy cost of Southern
Dispatch after serving all sales obligations, which costs shall
include fuel expense, variable operating and maintenance expense, fuel
handling expense, emissions allowance value, and other appropriate
energy-related costs, including, but not limited to, energy purchases,
as permitted by the IIC and as determined in the Hour immediately
prior to the applicable Hour.
(71) "Term" - means the initial term of this Agreement specified in Section
18.1, as such initial or any additional term may be extended for
additional term(s) from time to time pursuant to Section 18.2.
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(72) "Territorial Control Area Services" - means Control Area Services
associated with OPC Territorial Load, as determined pursuant to
Article XI.
(73) "Territorial Marginal Cost" - means the incremental energy cost of
Southern Dispatch after serving all Southern Control Area obligations
but prior to serving any sales outside the Southern Control Area,
which costs shall include fuel expense, variable operating and
maintenance expense, fuel handling expense, emissions allowance value,
and other appropriate energy-related costs, including, but not limited
to, energy purchases, as permitted by the IIC and as determined in the
Hour immediately prior to the applicable Hour.
(74) "Umbrella Agreement" - means that certain ITSA, Power Sale and
Coordination Umbrella Agreement entered into between Georgia Power and
Oglethorpe Power as of November 12, 1990. Upon its effectiveness,
this Agreement shall be considered a "Packaged Document," as defined
in the Umbrella Agreement.
(75) "Utilization" - means the energy scheduled by Oglethorpe Power from
the Pseudo CT Resource in an Hour, including the effect of changes
submitted from time to time by Oglethorpe Power or deemed to be
scheduled by Oglethorpe Power, all as determined under Article X, as
delivered at Level B-1.
(76) "Week" - means each period of seven (7) Days, commencing at one (1)
minute prior to 12:01 a.m. (Birmingham, Alabama prevailing time) of
each Monday and ending at one (1) minute after 11:59 p.m. (Birmingham,
Alabama prevailing time) of each succeeding Sunday.
(77) "Year" - means a calendar year, commencing at one (1) minute prior to
12:01 a.m. (Birmingham, Alabama prevailing time) of each January 1 and
ending at one (1)
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minute after 11:59 p.m. (Birmingham, Alabama prevailing time) of each
succeeding December 31. "Yearly" - has a meaning correlative to that
of Year.
ARTICLE III
OPERATING OBLIGATIONS OF THE PARTIES
3.1 Basic Operation and Maintenance Obligations. Oglethorpe Power and
Georgia Power will each maintain sufficient generating capacity resources,
including reserves to supply its own and its customers' requirements at all
times in the future. Further, Oglethorpe Power and Georgia Power agree to
operate and maintain their systems in accordance with the North American
Electric Reliability Council Operating Manual (including the NERC-OC Reliability
Criteria for Interconnected Systems Operation and the NERC-OC Operating Guides)
and SERC Guidelines (collectively, "NERC Guidelines"), as the same may be
revised from time to time.
3.2 Obligations Under Future Standards. (a) If NERC or FERC issues
rules, standards or guidelines affecting or otherwise relevant to the Control
Area Services offered under this Agreement, Georgia Power and Oglethorpe
Power agree to revise or amend the sections of this Agreement pertaining to
Control Area Services if and as appropriate in order to comport therewith.
To that end, the Parties agree to use their reasonable best efforts to
develop mutually acceptable, specific performance criteria by which to
determine, on an objective basis, when such rules, standards or guidelines
are violated, such criteria to be incorporated into this Agreement; provided,
however, that if Georgia Power reasonably believes that the Parties will fail
to reach an agreement on such criteria prior to the end of ninety (90) Days,
Georgia Power may, at any time during such negotiations, unilaterally develop
and file any changes or revisions to this Agreement that it believes are
appropriate and warranted by such rules, standards or guidelines (which
filing shall include specific performance criteria by which to determine, on
an objective basis, when such rules,
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standards or guidelines are violated), to be effective ninety (90) Days
after Georgia Power provides written notice to Oglethorpe Power of the
issuance of the rules, standards or guidelines which it believes are
applicable to the Agreement. Oglethorpe Power shall have the right to
challenge Georgia Power's proposed changes in accordance with FERC
regulations and shall have the right to request that the FERC approve
alternative revisions pursuant to FERC regulations. Upon such filing by
Georgia Power or Oglethorpe Power, any Party shall have the right to
terminate this Agreement upon ninety (90) Days prior written notice to the
other Parties, provided, however, that such notice must be given within 15
Days after a final FERC order on such filing.
(b) Upon notice of termination under Section 3.2(a), the Parties agree to
use their reasonable best efforts to negotiate a mutually acceptable successor
arrangement to this Agreement (to the extent necessary to recognize and
accommodate the interrelated nature of the Parties' transmission systems and
control area functions within the state of Georgia); provided, however, that, at
any time during such negotiations, Georgia Power may file at the FERC a notice
of termination, effective no earlier than 90 Days following the above notice,
and a proposed successor arrangement with Oglethorpe Power if Georgia Power
reasonably believes that the Parties will fail to reach an agreement on a
successor arrangement prior to the end of ninety (90) Days. Oglethorpe Power
shall have the right to challenge Georgia Power's proposed successor arrangement
in accordance with FERC regulations, shall have the right to request, pursuant
to FERC regulations, that the FERC accept an alternative arrangement between
Georgia Power and Oglethorpe Power, and shall have the right to enter into a
separate arrangement with any other party. However, any election by Oglethorpe
Power to enter into an arrangement with a third party shall not affect Georgia
Power's right to file a proposed successor agreement with Oglethorpe Power which
Georgia Power believes is necessary or appropriate in recognition of and to
accommodate the interrelated nature of the
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Parties' transmission systems and control area functions within the state of
Georgia. At the end of ninety (90) Days following any Party's notice of
termination to the other Parties, if the FERC has not issued a final order (a)
establishing the terms and conditions of a successor arrangement between Georgia
Power and Oglethorpe Power or (b) determining that a successor arrangement
between Georgia Power and Oglethorpe Power is not necessary or appropriate,
Oglethorpe Power shall, until such final order is issued, (i) purchase Control
Area Services, with the exception of Reactive Supply and Voltage Control From
Generation Sources Service, from Georgia Power or its agent at the standard
rates then in effect under the Open Access Transmission Tariff of Southern
Companies; (ii) continue to purchase Energy Imbalance Service (including Back-Up
Capacity) in accordance with Article XII of this Agreement; and (iii) continue
to self-supply or purchase Reactive Supply and Voltage Control From Generation
Sources Service under this Agreement in accordance with Section 11.3. In
addition, Oglethorpe Power shall continue to Pseudo Schedule and Dispatch the
Pseudo CT Resource in accordance with Article X of this Agreement until such
final order is issued. Any amounts collected from Oglethorpe Power under this
Section 3.2(b) shall be subject to adjustment in accordance with the terms of a
final FERC order accepting Georgia Power's notice of termination and either (i)
establishing the terms and conditions of a successor arrangement between Georgia
Power and Oglethorpe Power or (ii) determining that a successor arrangement
between Georgia Power and Oglethorpe Power is not necessary or appropriate. For
purposes of this Article, a "final order" shall mean a FERC order which is no
longer subject to rehearing under the FERC's Rules of Practice and Procedure.
(c) If the FERC accepts the changes or revisions to this Agreement
pursuant to Section 3.2(a), and thereafter Georgia Power reasonably determines,
in accordance with Prudent Utility Practice, that Oglethorpe Power has failed to
comply with the same, Georgia Power may terminate
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this Agreement upon ninety (90) Days prior written notice to Oglethorpe Power;
provided, however, that the Parties shall, during such 90-day period prior to
termination, review both the data relied on to support such notice of
termination as well as Oglethorpe Power's performance, and Georgia Power shall
rescind such notice if it reasonably determines that the data is in error such
that Oglethorpe Power did not fail to adequately meet the specified criteria, or
if Georgia Power determines, in its sole discretion, that Oglethorpe Power has
adequately remedied its failure to comply with the specified criteria in
accordance with Prudent Utility Practice. Upon notice of termination, the
Parties agree to use their reasonable best efforts to negotiate a mutually
acceptable successor arrangement to this Agreement (to the extent necessary to
recognize and accommodate the interrelated nature of the Parties' transmission
systems and control area functions within the state of Georgia); provided,
however, that at any time during such negotiations, Georgia Power may file at
the FERC a notice of termination, effective no earlier than 90 Days following
the above notice, and a proposed successor arrangement with Oglethorpe Power if
Georgia Power reasonably believes that the Parties will fail to reach an
agreement on a successor arrangement prior to the end of ninety (90) Days.
Oglethorpe Power shall have no right to challenge Georgia Power's right to seek
termination under this Section 3.2(c). However, Oglethorpe Power (1) shall have
the right to challenge (i) the validity of the data relied on by Georgia Power
to support its notice of termination or (ii) the terms and conditions of Georgia
Power's proposed successor arrangement in accordance with FERC regulations, (2)
shall have the right to request, pursuant to FERC regulations, that the FERC
accept an alternative arrangement between Georgia Power and Oglethorpe Power,
and (3) shall have the right to enter into a separate arrangement with any other
party. However, any election by Oglethorpe Power to enter into an arrangement
with a third party shall not affect Georgia Power's right to file a proposed
successor agreement with Oglethorpe Power which Georgia Power believes
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is necessary or appropriate in recognition of and to accommodate the
interrelated nature of the Parties' transmission systems and control area
functions within the state of Georgia. At the end of ninety (90) Days following
Georgia Power's notice of termination to Oglethorpe Power under this Section
3.2(c), if the FERC has not issued a final order (a) establishing the terms and
conditions of a successor arrangement between Georgia Power and Oglethorpe Power
or (b) determining that a successor arrangement between Georgia Power and
Oglethorpe Power is not necessary or appropriate, Oglethorpe Power shall, until
such final order is issued, (i) purchase Control Area Services, subject to (iii)
below, from Georgia Power or its agent at the standard rates then in effect
under the Open Access Transmission Tariff of Southern Companies; (ii) continue
to purchase Energy Imbalance Service (including Back-Up Capacity) in accordance
with Article XII of this Agreement; and (iii) if the cause for Georgia Power's
notice of termination is not due to Oglethorpe Power's failure to comply with a
request for altered reactive dispatch under Section 11.3, continue to
self-supply or purchase Reactive Supply and Voltage Control From Generation
Sources Service under this Agreement in accordance with Section 11.3. In
addition, Oglethorpe Power shall continue to Pseudo Schedule and Dispatch the
Pseudo CT Resource in accordance with Article X of this Agreement until such
final order is issued. Any amounts collected from Oglethorpe Power under this
Section 3.2(c) shall be subject to adjustment in accordance with the terms of a
final FERC order accepting Georgia Power's notice of termination and either (i)
establishing the terms and conditions of a successor arrangement between Georgia
Power and Oglethorpe Power or (ii) determining that a successor arrangement
between Georgia Power and Oglethorpe Power is not necessary or appropriate.
3.3 System Security and Integrity. The Parties recognize that Georgia
Power or its agent must have the ability and means to maintain the safe and
reliable operation of the ITS and the
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surrounding Southern Control Area. To that end, the Parties agree that (a)
Georgia Power shall not unduly discriminate against Oglethorpe Power, Southern
Companies or any other transmission owners with regard to the redispatch of
resources and/or the curtailment of transactions across any constrained
interface, including the allocation of redispatch-related costs, if any; and (b)
Oglethorpe Power shall participate in the implementation of an appropriate
redispatch cost allocation methodology for the Southern Sub-Region of SERC, such
agreement to survive this Agreement.
3.4 Supply Deficiencies. This Section 3.4 shall apply only if Oglethorpe
Power has elected, for the current Year, to declare interruptible loads as
supplemental operating reserves pursuant to Section 11.6(c) herein. (a) If, at
any time during the Term of this Agreement, Georgia Power or its agent
determines that it is necessary or appropriate to take action to eliminate a
power supply deficiency in the Southern Control Area, and directs Oglethorpe
Power to participate in the elimination of such deficiency, Oglethorpe Power
agrees to take reasonable corrective measures as appropriate, including, without
limitation, load shedding and operations at valves wide open and overpressure,
unless Oglethorpe Power reasonably determines that such operation will be
detrimental to the reliability of the unit or Oglethorpe Power's system.
Oglethorpe Power may sell any energy surpluses resulting from operation at
valves wide open and overpressure to Southern Companies at market rates. Load
shedding shall be coordinated with Georgia Power and shall be implemented on a
pro rata basis, as nearly as practicable, among Oglethorpe Power, Georgia Power
and other ITS participants based on each ITS participant's non-coincident peak
load ratio, as defined in the Revised ITSA, of the quantities assigned to the
ITS (consistent with the IIC allocation procedures for the Southern Control Area
on file at the FERC), and shall be subject to the following curtailment
priorities: (1) non-firm third-party deliveries and interruptible native load
deliveries; and (2) firm load deliveries.
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(b) To the extent action under this Section causes energy surpluses or
Regulation Energy Variance, as described in Article XII and Section 11.4,
respectively, Georgia Power agrees to waive any Regulation Energy Variance
charges, and such Hours shall be excluded from the determination of Commitment
Cost under Section 12.4 of this Agreement. In addition, during the period of
such curtailment, Georgia Power shall credit Oglethorpe Power for any surplus
energy associated with such curtailment at Territorial Marginal Cost in lieu of
the credit determined in accordance with Section 12.5. To the extent Oglethorpe
Power curtails non-firm third-party sales under this Section, Georgia Power
shall credit Oglethorpe Power for such surpluses at the higher of the rates
stated in Section 12.5 or the highest price disclosed by Oglethorpe Power, if
any, of curtailed non-firm transactions of Oglethorpe Power. Similarly, to the
extent Southern curtails non-firm third-party sales under this Section,
Oglethorpe Power shall purchase from Georgia Power deficit energy at the higher
of the rates stated in Section 12.6 or the highest price disclosed by Georgia
Power, if any, of such curtailed non-firm transactions of Southern Companies.
3.5 Power Flows. Since the systems of Oglethorpe Power, GTC and Georgia
Power are now, or may in the future be, directly interconnected with other
electric systems, it is recognized that because of the physical and electrical
characteristics of the facilities involved, there may be flows of power from
Oglethorpe Power to Georgia Power, or vice versa, through other electric
systems, or from other electric systems through the electric system of
Oglethorpe Power, GTC or Georgia Power. It is likewise recognized that part of
any scheduled delivery of power from Oglethorpe Power to Georgia Power, or vice
versa, may flow through or be displaced through other electric systems.
Oglethorpe Power, GSOC and Georgia Power agree to advise other materially
affected electric systems of such flows and scheduled power transfers, to
attempt to minimize any resulting burden on such other electric systems, as
appropriate, to compensate such other systems for any such
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resulting burden, and to maintain communication and good relationships with
affected interconnected third parties.
3.6 Survival. The provisions of Sections 3.1 and 3.5 shall survive
termination of this Agreement.
ARTICLE IV
OPC-CONTROLLABLE-ITS RESOURCES
4.1 Energy Utilization. For purposes of calculating the Actual Hourly
Resource Utilization of each OPC-Controllable-ITS Resource during each Hour of
the Term, Oglethorpe Power shall be deemed to have utilized all energy delivered
into the ITS by or on behalf of Oglethorpe Power from the generation facility or
other resource associated with each such OPC-Controllable-ITS Resource during
such Hour, as determined by Oglethorpe Power and verified by Georgia Power or
its agent. The amount of such energy utilization shall be measured by
Oglethorpe Power and verified by Georgia Power or its agent in megawatt hours
(MWH), at the point of delivery to the ITS.
4.2 Transmission Responsibility. Oglethorpe Power shall be responsible
for making all transmission arrangements for the delivery of energy from
OPC-Controllable-ITS Resources and shall bear all costs associated with any and
all such transmission.
ARTICLE V
BLOCK RESOURCES
5.1 Dispatch. Except as provided in this Article V, Oglethorpe Power
hereby agrees to commit and schedule energy utilization of the Block Resources
in accordance with, and otherwise to abide by and comply with, the provisions of
the BPSA.
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5.2 Changes in Schedules. Oglethorpe Power shall provide notice to
Georgia Power or its agent at least fifteen (15) minutes prior to the start of
each Quarter Hour of the quantity of energy that Oglethorpe Power wishes to
schedule from a committed Steam Block Resource or any Peaking Block Resource for
such Quarter Hour. Oglethorpe Power may increase or decrease the level of
energy at which a Steam Block Resource is to be utilized during such Quarter
Hour until fifteen (15) minutes prior to the start of such Quarter Hour.
Oglethorpe Power may increase or decrease the level of energy at which a Peaking
Block Resource is to be utilized only once in any thirty (30) minute period, and
only upon fifteen (15) minutes prior notice to Georgia Power, to be effective at
the start of a Quarter Hour.
5.3 Energy Utilization. For purposes of calculating the Actual Hourly
Resource Utilization of each Block Resource during each Hour of the Term,
Oglethorpe Power shall be deemed to have utilized during such Hour that amount
of energy determined by averaging the four Quarter Hour schedules submitted for
that Hour under Section 5.2 above.
5.4 Emergency Decommitment. If all OPC Off-System Resources have been
interrupted pursuant to Section 8.1 and Oglethorpe Power continues to have
surplus energy as defined in Article XII, Oglethorpe Power may decommit a Steam
Block Resource on 15 minutes prior notice to Georgia Power, effective at the
start of any Quarter Hour.
5.5 Operability of Article. This Article V shall be operable from the
Effective Date through the earlier of the date this Agreement terminates or the
date, if any, upon which the BPSA expires; provided, however, that the Parties
may agree to any other mutually satisfactory date through which this Article
shall be operable.
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ARTICLE VI
SEPA RESOURCES
6.1 Dispatch. Oglethorpe Power hereby agrees to commit and schedule
energy utilization of the SEPA Resources in accordance with, and otherwise to
abide by and comply with, the Oglethorpe Power Corporation Scheduling Contract
between Oglethorpe Power and SEPA (Contract No. 89-00-1501-1059), or any
successor contract, and any related procedures adopted by Oglethorpe Power and
SEPA.
6.2 Energy Utilization. For purposes of calculating the Actual Hourly
Resource Utilization of the SEPA Resources during each Hour of the Term,
Oglethorpe Power shall be deemed to have utilized during such Hour that amount
of energy scheduled by Oglethorpe Power and delivered by SEPA pursuant to the
Oglethorpe Power Corporation Scheduling Contract between Oglethorpe Power and
SEPA (Contract No. 89-00-1501-1059), or any successor contract.
6.3 Operability of Article. This Article VI shall be operable from the
Effective Date until the earlier of the termination of this Agreement or the
expiration of the Oglethorpe Power Corporation Scheduling Contract between
Oglethorpe Power and SEPA (Contract No. 89-00-1501-1059), or any successor
contract; provided, however, that the Parties may agree to any other mutually
satisfactory date through which this Article shall be operable.
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ARTICLE VII
NUCLEAR RESOURCES
7.1 Delivery of and Payment for Energy. Georgia Power's and Oglethorpe
Power's respective rights and obligations concerning the delivery of and payment
for energy from the generation facilities associated with each of the Nuclear
Resources during any given Hour of the Term shall be as set forth in the
respective Joint Ownership Agreements associated with each such Nuclear
Resource.
7.2 Energy Utilization. For purposes of calculating the Actual Hourly
Resource Utilization of each Nuclear Resource during each Hour of the Term,
Oglethorpe Power shall be deemed to have utilized all energy delivered to
Oglethorpe Power from the generation facility associated with each such Nuclear
Resource during such Hour, as determined by Georgia Power or its agent and
verified by Oglethorpe Power under the Joint Ownership Agreements associated
with each such Nuclear Resource. The amount of such energy utilization shall be
measured by Georgia Power or its agent in megawatt hours (MWH) at the point of
delivery to the ITS.
7.3 Informational Available Capability and Energy Schedules. (a) Georgia
Power or its agent will provide Oglethorpe Power on or before 11:00 a.m.
(Birmingham, Alabama prevailing time) of the Friday prior to the commencement of
each Week during the Term, for informational purposes under this Agreement only,
a schedule of the expected levels of Available Capability and energy of each of
the Nuclear Resources during each Hour of each Day of the immediately following
Week.
(b) Georgia Power or its agent shall use good faith efforts to notify
Oglethorpe Power, for informational purposes under this Agreement only, of any
changes to the Available Capability and energy schedule of the Nuclear Resources
for a given Week from time to time during such Week
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as soon as practicable after Georgia Power learns of any actual or expected
unavailability (or reduction of Available Capability or energy) of any Nuclear
Resource. Notwithstanding the previous sentence, Georgia Power or its agent, as
determined by Georgia Power, shall provide Oglethorpe Power, on or before 11:00
a.m. (Birmingham, Alabama prevailing time) of each Day during the Term, for
informational purposes under this Agreement only, notice of any changes to
Georgia Power's then-current Available Capability and energy schedule of the
Nuclear Resources for the immediately following two (2) Days.
ARTICLE VIII
OPC OFF-SYSTEM TRANSACTIONS
8.1 Coordinate with Georgia Power. Oglethorpe Power hereby agrees to
coordinate all OPC Off-System Transactions with Georgia Power or its agent.
Oglethorpe Power further agrees that Georgia Power or its agent shall have to
take instructions for or concerning any OPC Off-System Transaction only from
Oglethorpe Power and that Georgia Power or its agent will ignore instructions
for or concerning any such transaction given by or received from any person or
entity other than Oglethorpe Power. Oglethorpe Power shall notify the Southern
Control Area operator of its desire to interrupt an OPC Off-System Transaction,
and the Southern Control Area operator shall interrupt such transaction as soon
as practicable, provided that all affected parties and control areas have
consented to such interruption.
8.2 Minimum Scheduling Notice. (a) Any OPC Off-System Transactions shall
be coordinated and scheduled with Georgia Power or its agent in a manner
consistent with the relevant scheduling provisions of Sections 13.8 and 14.6, as
applicable, of the Open Access Transmission Tariff of Southern Companies as they
apply to the initiation of or change in transaction schedules.
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(b) Except as set forth in this Article, this Agreement does not impose
any restrictions upon the right of Oglethorpe Power to schedule OPC Off-System
Transactions.
8.3 Energy Utilization. For purposes of calculating the Actual Hourly
Resource Utilization associated with each OPC Off-System Resource during each
Hour of the Term, Oglethorpe Power shall be deemed to have utilized all energy
scheduled by Oglethorpe Power during such Hour, in megawatt hours (MWH), as
thereafter verified by Georgia Power or its agent.
8.4 Load Responsibility. For purposes of calculating the OPC
Non-Territorial Load for each Hour of the Term, Oglethorpe Power shall have a
load responsibility associated with each OPC Off-System Transaction associated
with an energy delivery during such Hour. The amount of such load
responsibility shall be the amount of energy associated with such OPC Off-System
Transaction delivered by or on behalf of Oglethorpe Power, in megawatt hours
(MWH), as finally scheduled by Oglethorpe Power and thereafter verified by
Georgia Power or its agent.
8.5 Oglethorpe Power's Information Obligations. Oglethorpe Power shall
provide Georgia Power or its agent information concerning all OPC Off-System
Transactions in such detail and upon such frequency as Georgia Power or its
agent reasonably requests in order to schedule each such transaction, support
system security, support load regulation activities and/or support Georgia
Power's or its agent's timely completion of Georgia Power's billing functions
under Article XVII. Such information shall include for each such OPC Off-System
Transaction, without limiting Georgia Power's or its agent's aforesaid right to
reasonably request additional information, all information necessary to
implement NERC Policy 3 or its successor, including, but not limited to, NERC
tagging procedures therein, unless the FERC rules that NERC Policy 3 or the
tagging procedures therein shall not be obligatory. Oglethorpe Power shall not
be required to provide Georgia Power or its
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agent transaction price information unless it is required for billing
calculations pursuant to Sections 3.4(b), 11.5(f) or 11.6(f) of this Agreement.
8.6 Transmission Responsibility. Oglethorpe Power shall be responsible
for making all transmission arrangements for any and all OPC Off-System
Transactions and shall bear all costs associated with any and all such
transmission.
8.7 Indemnification. Oglethorpe Power shall indemnify and hold Georgia
Power and its agent harmless from and against any and all losses, costs,
liabilities, damages and expenses (including without limitation attorneys' fees
and expenses) of any kind incurred or suffered by Georgia Power or its agent
pursuant to, as a result of or in connection with Georgia Power's performance
under this Article VIII or the performance or nonperformance of Oglethorpe Power
under this Article VIII, except for losses, costs, liabilities, damages and
expenses (including without limitation attorneys' fees and expenses) incurred or
suffered by Georgia Power or its agent as a direct result of any action of
Georgia Power that violates this Article VIII and that is not in accordance with
Prudent Utility Practice or as a direct result of Georgia Power's or its agent's
willful misconduct.
ARTICLE IX
MUTUAL BUY/SELL TRANSACTIONS
To the extent the Parties wish to engage in buy/sell transactions, other
than pursuant to the BPSA, or otherwise sell or purchase capacity or energy from
each other, such transactions shall be implemented and governed by separate
market-based service agreements to be executed between Oglethorpe Power and
Georgia Power or its agent. These buy/sell transactions shall be declared and
treated as OPC Off-System Transactions.
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ARTICLE X
PSEUDO CT RESOURCE
10.1 Available Capability Schedule. (a) The provisions of this Article
shall be applicable for the Term of this Agreement; provided, however, that the
Parties may agree to any other mutually satisfactory date through which this
Article shall be operable.
(b) Georgia Power or its agent shall provide Oglethorpe Power, on or
before 11:00 a.m. (Birmingham, Alabama prevailing time) on the Friday prior to
the commencement of each Week during the Term, a schedule of the expected
Available Capability of the Pseudo CT Resource during each Hour of each Day of
the immediately following Week and the expected Maximum Utilization Level
thereof ("Available Capability Schedule").
10.2 Changes to Available Capability Schedule. (a) Georgia Power or its
agent shall use good faith efforts to notify Oglethorpe Power as soon as
practicable after Georgia Power learns of any actual or expected change in
Available Capability of the Pseudo CT Resource; provided, however, that Georgia
Power or its agent shall provide Oglethorpe Power, on or before 11:00 a.m.
(Birmingham, Alabama prevailing time) of each Day during the Term, notice of any
such changes to Georgia Power's then-current Available Capability Schedule for
the immediately following two (2) Days.
(b) Georgia Power may make changes to the Available Capability Schedule
and to the associated Maximum Utilization Level at any time Georgia Power
reasonably expects the Available Capability of the Pseudo CT Resource to change,
or at such time that such Available Capability has changed, for whatever reason,
including, without limitation, outages or deratings (as defined by NERC), or
transmission constraints (as defined by NERC) affecting the operation of the
Pseudo CT Resource.
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10.3 Hourly Utilization Schedule. (a) Oglethorpe Power shall provide
Georgia Power or its agent on or before 1:30 p.m. (Birmingham, Alabama
prevailing time) on each Day during the Term, a schedule of its anticipated
hourly Utilization of the Pseudo CT Resource for each Hour of the immediately
following Day ("Utilization Schedule").
(b) Oglethorpe Power's Utilization Schedule shall at all times be
consistent on an Hour by Hour basis with the most recent Available Capability
Schedule provided by Georgia Power to Oglethorpe Power. Any Utilization Schedule
provided by Oglethorpe Power which is not in compliance with such Available
Capability Schedule shall be deemed ineffective. Georgia Power shall use
reasonable best efforts to notify Oglethorpe power that such Utilization
Schedule has been deemed ineffective as soon as practicable following such
event.
(c) Oglethorpe Power's Utilization of the Pseudo CT Resource must at all
times be either zero or the Maximum Utilization Level. To the extent Oglethorpe
Power schedules any energy from the Pseudo CT Resource at any level other than
zero or such Maximum Utilization Level of the Pseudo CT Resource, it shall be
deemed to have scheduled energy at such Maximum Utilization Level.
10.4 Changes to Utilization Schedule. (a) Oglethorpe Power may, in its
discretion, make changes to its Utilization Schedule for a given Day from time
to time during such Day, subject to the provisions of this Article. Oglethorpe
Power shall use good faith efforts to notify Georgia Power or its agent of such
changes as soon as practicable after Oglethorpe Power decides to make such
changes.
(b) Oglethorpe Power shall provide notice to Georgia Power or its agent at
least twenty (20) minutes prior to the start of an Hour of the quantity of
energy that Oglethorpe Power wishes to schedule from the Pseudo CT Resource
during such Hour. Oglethorpe Power may increase or
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decrease the level of energy at which the Pseudo CT Resource is to be utilized
during such Hour only until twenty (20) minutes prior to such Hour. The
Utilization Schedule for the Pseudo CT Resource during a given Hour shall become
final after twenty (20) minutes prior to the start of the Hour and shall not
thereafter be subject to increase or decrease by Oglethorpe Power for that Hour.
(c) Oglethorpe Power shall be required to make such changes to the
Utilization Schedule from time to time during a Day to reflect any changes made
by Georgia Power to the Available Capability Schedule of the Pseudo CT Resource
for such Day. Oglethorpe Power shall make such changes as soon as practicable
after being notified of the actual or expected change in Available Capability;
provided, however, that Oglethorpe Power shall make such changes immediately in
the case of actual or imminent changes in Available Capability.
(d) For purposes of calculating the Actual Hourly Resource Utilization of
the Pseudo CT Resource during each Hour, Oglethorpe Power shall be deemed to
have utilized during such Hour all energy either (i) shown on the final and
effective Utilization Schedule during such Hour for the Pseudo CT Resource, or
(ii) deemed to have been scheduled by Oglethorpe Power during such Hour from the
Pseudo CT Resource, all in accordance with Sections 10.3, 10.4, or 10.5.
10.5 Pseudo CT Resource Test Energy. If Plant Hal Wansley Unit No. 5A is
required to operate for test purposes at any time, and Oglethorpe Power is
notified in advance of the scheduling deadline in Section 10.4(b), then
Oglethorpe Power shall be deemed to have scheduled Utilization from the Pseudo
CT Resource at a level equal to Oglethorpe Power's undivided ownership interest
in the Actual Hourly Facility Generation associated with the Pseudo CT Resource.
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10.6 Pricing of Pseudo Energy Sales and Purchases. (a) Each Hour of the
Term, Georgia Power shall compute the amount of the Pseudo Energy associated
with the Pseudo CT Resource for that Hour, in megawatt hours (MWH).
(b) If the amount of the Pseudo Energy associated with the Pseudo CT
Resource for an Hour is positive, then Georgia Power shall be deemed to have
made a Pseudo Energy Sale to Oglethorpe Power equal to the amount of such Pseudo
Energy. Georgia Power shall deliver such energy to Oglethorpe Power from any
resources available to it at Level B-1. Oglethorpe Power shall pay to Georgia
Power, for such Pseudo Energy Sale, a "Pseudo Resource Energy Charge", in
dollars per Month, equal to the product of:
(1) the sum of the hourly Pseudo Energy Sale(s) associated with the
Pseudo CT Resource for such Month, in megawatt hours (MWH); times
(2) the sum of (i) the product equal to (a) the Pseudo CT Resource
Heat Rate, times (b) the Marginal Replacement Fuel Cost in effect
for the Pseudo CT Resource at such time, plus (ii) the quotient
equal to (a) the most recent 12 Months total actual variable
operations and maintenance ("O&M") and fuel handling expenses for
the generation facility associated with the Pseudo CT Resource,
divided by (b) the net positive generation from such facility
over such 12 Month period, as determined pursuant to the Joint
Ownership Agreement accounting procedures employed by Georgia
Power or its agent at such time and calculated consistent with
the FERC account definitions utilized in the then-current IIC for
variable O&M and fuel handling expenses (both (i) and (ii) as
measured in dollars per megawatt hour ($/MWH)).
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(c) If the amount of the Pseudo Energy associated with the Pseudo CT
Resource for an Hour is negative, then Georgia Power shall be deemed to have
made a Pseudo Energy Purchase from Oglethorpe Power equal to the absolute value
of the amount of such Pseudo Energy. Georgia Power shall provide to Oglethorpe
Power, for such Pseudo Energy Purchase, a "Pseudo Resource Energy Credit", in
dollars per Month, equal to the product of:
(1) the sum of the hourly Pseudo Energy Purchase(s) associated with
the Pseudo CT Resource for such Month, in megawatt hours (MWH);
times
(2) the sum of (i) the product equal to (a) the Pseudo CT Resource
Heat Rate, times (b) the Marginal Replacement Fuel Cost in effect
for the Pseudo CT Resource at such time, plus (ii) the quotient
equal to (a) the most recent 12 Months total actual variable O&M
and fuel handling expenses for the generation facility associated
with the Pseudo CT Resource, divided by (b) the net positive
generation from such facility over such 12 Month period, as
determined pursuant to the Joint Ownership Agreement accounting
procedures employed by Georgia Power or its agent at such time
and calculated consistent with the FERC account definitions
utilized in the then-current IIC for variable O&M and fuel
handling expenses (both (i) and (ii) as measured in dollars per
megawatt hour ($/MWH)).
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ARTICLE XI
TERRITORIAL CONTROL AREA SERVICES
11.1 Availability. (a) Territorial Control Area Services are those
services which are necessary (i) to effectuate energy deliveries under this
Agreement and (ii) to maintain the integrity of the ITS and the Southern
Control Area pursuant to this Agreement. On a Yearly basis, Oglethorpe Power
shall elect either (i) to purchase all of the Territorial Control Area
Services described in Sections 11.4, 11.5 and 11.6, or (ii) to self-supply
all of the Territorial Control Area Services described in Sections 11.4, 11.5
and 11.6 in the manner set forth below. If Oglethorpe Power does not notify
Georgia Power of its election to purchase Territorial Control Area Services
at least 45 Days prior to the start of a given Year, Oglethorpe Power shall
be deemed to have elected to self-supply the Territorial Control Area
Services described in Sections 11.4, 11.5, and 11.6.
(b) The Territorial Control Area Services provided under this Article
shall be available only under the terms of this Agreement and shall not
survive the termination of this Agreement. In addition, the Territorial
Control Area Services shall be used solely for the purpose of serving OPC
Territorial Load, and shall not be remarketed or resold by Oglethorpe Power
or its Affiliates in any form to any entity, provided, however, that
Oglethorpe Power may at all times recover the costs of such service from OPC
Territorial Load customers.
11.2 Scheduling, System Control and Dispatch Service. Oglethorpe Power
shall purchase from Georgia Power Scheduling, System Control and Dispatch
Service to serve OPC Territorial Load. Oglethorpe Power shall pay Georgia
Power for Scheduling, System Control and Dispatch Service a charge equal to
$0.044960 per kilowatt per month (kW-month) times the OPC Territorial Load
coincident with the most recent twelve (12) monthly peak loads within the
Southern Control Area. Oglethorpe Power and its Affiliates hereby agree that
no Party will oppose or object
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to the level of the Scheduling, System Control and Dispatch Service rate
proposed by Southern Companies in the proceeding in Docket No. OA96-27 or in
any subsequent proceeding(s) during the Term of this Agreement, provided that
no Party has given notice of termination of this Agreement or, if such notice
has been given, provided that no successor arrangement to this Agreement has
been effectuated.
11.3 Reactive Supply and Voltage Control From Generation Sources
Service. (a) Oglethorpe Power and GSOC agree that if the Southern Control
Area requires additional or altered reactive dispatch, then the Southern
Control Area operator shall have the right to call for an altered reactive
dispatch from OPC Resources within the Southern Control Area, to the extent
such resources are capable of such operation, including, but not limited to,
the operation of resources which may have been off-line at the time of such
request, without adverse distinction to Oglethorpe Power or GSOC; provided,
however, that all generation facilities that become OPC Resources following
the date of execution of this Agreement shall be capable of operating
continuously at a leading power factor of 0.85. To the extent such requested
operation results in additional costs, such costs shall be treated in
accordance with the redispatch cost allocation methodology, if any,
referenced in Section 3.3. Subject to the provisions of Section 11.3(b)
below, Reactive Supply and Voltage Control From Generation Sources Service
("Reactive Service") will be deemed adequately provided by OPC Resources
within the Southern Control Area as long as and to the extent that
Oglethorpe Power complies with the Southern Control Area operator's calls for
altered reactive dispatch. If Georgia Power reasonably determines, in
accordance with Prudent Utility Practice, that Oglethorpe Power has failed to
comply with the Southern Control Area operator's calls for altered reactive
dispatch, Georgia Power shall treat Oglethorpe Power's failure to comply as a
failure to meet specific performance criteria under Section 3.2(c) of this
Agreement, and may terminate this
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Agreement upon ninety (90) Days prior written notice to Oglethorpe Power, in
accordance with and subject to the procedures set forth in Section 3.2(c) of
this Agreement.
(b) At such time that the industry develops a methodology for
accounting for MVAR utilization, the Parties agree to incorporate such
methodology and any resulting fees or charges into this Agreement. Should
the Parties fail to agree on the application of such methodology, Georgia
Power may file at the FERC to incorporate such changes. Oglethorpe Power and
its Affiliates shall have the right to contest the amount of such charge, but
may not contest Georgia Power's right to seek recovery of MVAR-related
charges if implemented pursuant to Section 11.3(b). Likewise, Georgia Power
shall not contest the right of Oglethorpe Power or its Affiliates to seek
recovery of appropriate MVAR-related charges, provided, however, that Georgia
Power reserves the right to contest the amount of any such charges and/or the
appropriateness of recovery from Georgia Power or Southern Companies.
11.4 Regulation and Frequency Response Service. (a) During the
effectiveness of this Agreement, Oglethorpe Power may elect, pursuant to
Section 11.1 (i) to purchase from Georgia Power Regulation and Frequency
Response Service for OPC Territorial Load at rates then in effect under the
Open Access Transmission Tariff of Southern Companies, (ii) to maintain,
subject to the provisions below or any change implemented pursuant to Section
3.2, an adequate Regulation Energy Variance (see Subsection (b) below) and
adequate capacity to meet its Regulation and Frequency Response Requirement
for OPC Territorial Load ("Regulation Requirement"), or (iii) to purchase
short term Regulation Service pursuant to Section 11.7.
(b) Unless and until a revised test is adopted pursuant to Section
11.4(f), Oglethorpe Power's Regulation Energy Variance shall equal the
absolute value of the difference between the Actual Hourly OPC Resources
Utilization and the Real-Time OPC Total Load Requirements at
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Level B-1, on an integrated hourly basis; provided, however, that the
absolute value of the difference between Oglethorpe Power's total metered
load and its integrated Real-Time total load is equal to or less than one
percent of the total metered load for at least 95 percent of the Hours in the
Month, and, provided further, that the absolute value of the difference
between (i) the integrated total output of the Joint-Owned Facilities
operated by Georgia Power, excluding Plant Hal Wansley Unit No. 5A, as
transmitted by Georgia Power to Oglethorpe Power and (ii) the total metered
output of such facilities is equal to or less than one (1) percent of the
total metered output of such facilities for at least 95 percent of the Hours
in the Month. If the absolute value of the difference between Oglethorpe
Power's total metered load and Oglethorpe Power's integrated Real-Time total
load is greater than one (1) percent of the total metered load for more than
five (5) percent of the Hours in the Month, then, in the discretion of
Georgia Power, total metered loads may be used in lieu of integrated
Real-Time total load for the OPC Total Load Requirements for purposes of the
Regulation Energy Variance for that Month. The comparison of total metered
load to integrated Real Time total load shall exclude all scheduled loads
(i.e., those which do not rely on meters, such as OPC Off-System
Transactions). If the absolute value of the difference between (i) the
integrated total output of the Joint-Owned Facilities operated by Georgia
Power, excluding Plant Hal Wansley Unit No. 5A, as transmitted by Georgia
Power to Oglethorpe Power and (ii) the total metered output of such
facilities is greater than one (1) percent of the total metered output of
such facilities for more than five (5) percent of the Hours in the Month,
then such integrated output shall be used in lieu of the Actual Hourly
Resource Utilization of such facilities for purposes of the Regulation Energy
Variance, Spinning Capabilities (Section 11.5(d)) and Supplemental
Capabilities (Section 11.6(d)) for that Month. The comparison of integrated
total output to total metered output for Spinning and
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Supplemental Capabilities shall only include the Joint-Owned Facilities
operated by Georgia Power and deemed Qualifying Resources - Spinning.
(c) Unless and until a different regulating standard is applied to the
Southern Control Area in accordance with Prudent Utility Practice or a
revised test is adopted pursuant to Section 11.4(f), Oglethorpe Power's
Regulation Requirement shall equal 2.09% of the OPC Territorial Load
coincident with the most recent calendar year twelve (12) monthly peak loads
of the Southern Control Area.
(d) An integrated hourly test shall be performed to ensure that
Oglethorpe Power's Regulation Energy Variance is less than or equal to
Oglethorpe Power's L10, as determined annually in accordance with NERC's
prescribed methodology applied to the maximum OPC Territorial Load from the
preceding Year. If the integrated hourly test (Oglethorpe Power's Regulation
Energy Variance minus Oglethorpe Power's L10) results in a zero or negative
value, then Oglethorpe Power shall be deemed to have adequately maintained
its Regulation Energy Variance for the Hour. However, if such integrated
hourly test results in a positive value, then Oglethorpe Power shall be
deemed not to have adequately maintained such Regulation Energy Variance for
the Hour, and Oglethorpe Power shall be required to purchase its Regulation
Energy Variance from Georgia Power in an amount equal to the difference
between its Regulation Energy Variance in such Hour and Oglethorpe Power's
L10 at such time. Until such time as the Southern Control Area operator
releases Plant Wansley Unit Nos. 1 and 2 and Plant Scherer Unit Nos. 1 and 2
for Automatic Generation Control operation by Oglethorpe Power, Oglethorpe
Power's L10 shall be replaced with the Inadvertent Energy Bandwidth in effect
for that Hour, as defined in Section 12.2.
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(e) To the extent Oglethorpe Power is required to purchase its
Regulation Energy Variance from Georgia Power pursuant to the provisions of
Subsection (d) hereto, such requirement shall be purchased from Georgia Power
at a rate calculated in accordance with Exhibit C.
(f) At such time that the Parties determine that it is practical to do
so, Georgia Power and Oglethorpe Power shall use reasonable best efforts to
negotiate a Real Time regulation performance test, based on applicable
performance criteria adopted by NERC, to replace the test described in
Section 11.4(d) above. Unless mutually agreed otherwise, at such time,
Oglethorpe Power's Regulation Requirement for Real Time performance shall be
zero megawatts (such changes to be implemented concurrently for regulation
and operating reserves).
11.5 Operating Reserve - Spinning Reserve Service. (a) During the
effectiveness of this Agreement, Oglethorpe Power may elect, pursuant to
Section 11.1, (i) to purchase from Georgia Power Operating Reserve - Spinning
Reserve Service for OPC Territorial Load at rates then in effect under the
Open Access Transmission Tariff of Southern Companies, (ii) to maintain,
subject to the provisions below or any change implemented pursuant to Section
3.2, spinning operating reserves for OPC Territorial Load, ("Spinning Reserve
Requirement"), or (iii) to purchase short term Spinning Reserve Service
pursuant to Section 11.7.
(b) Oglethorpe Power's Spinning Reserve Requirement shall equal 2.09%
of the OPC Territorial Load coincident with the 1996 twelve (12) monthly peak
loads of the Southern Control Area. The 2.09% value utilized herein shall be
updated and revised, if necessary, to comport with changes in the Southern
Control Area spinning operating reserve requirements, effectuated in
accordance with Prudent Utility Practice, or changes in the resource base for
the Southern Control Area (either an increase or decrease in the contingency
size).
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(c) Oglethorpe Power shall maintain its Regulation Requirement and
Spinning Reserve Requirement in unscheduled but on-line OPC Resources which
are qualified to supply Operating Reserve - Spinning Reserve Service
("Spinning Reserve Service"). In order for an OPC Resource to qualify as a
"Qualifying Resource - Spinning," it must (i) be located within the Southern
Control Area; (ii) be telemetered to the Southern Control Area operator;
(iii) be capable of responding to AGC; (iv) respond to frequency deviations;
and (v) be immediately callable by the Southern Control Area operator, by
verbal notification to Oglethorpe Power's system operator, to produce energy
on a pro rata basis, as nearly as practicable, with the other regulation and
spinning operating reserves of the Southern Control Area. For purposes of
this Section, Qualifying Resources - Spinning shall initially be limited to
Steam Block Resources, Plant Scherer Unit No. 1, Plant Scherer Unit No. 2,
Plant Wansley Unit No. 1, Plant Wansley Unit No. 2 and Rocky Mountain (units
which are in the generation mode). From time to time during the term of this
Agreement, Oglethorpe Power may request that one or more additional OPC
Resources be designated and treated as Qualifying Resources - Spinning. The
Parties agree to discuss the issue of whether such additional OPC Resources
meet the above requirements to be Qualifying Resources - Spinning, as well as
the terms and conditions related thereto, at the time of such request.
Oglethorpe Power shall not be precluded from submitting Dynamically Scheduled
OPC Resources or OPC-Controllable-ITS Resources which are connected to a
distribution system for credit as Qualifying Resources - Spinning; provided,
however, that in addition to the above requirements, such resources must be
callable at the sole discretion of Oglethorpe Power.
(d) An integrated hourly test shall be performed to ensure that the sum
of (i) the on-line Available Capability of the Qualifying Resources -
Spinning less the Actual Hourly Resource Utilization for such resources
(subject to Section 11.4(b)) and (ii) any Back-Up Capacity purchased
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by Oglethorpe Power within the Hour pursuant to Section 12.3 (collectively
referred to in this Subsection as "Spinning Capabilities") are greater than
or equal to Oglethorpe Power's Regulation Requirement and Spinning Reserve
Requirement. If the integrated hourly test (Spinning Capabilities minus
Oglethorpe Power's Regulation and Spinning Reserve Requirements) results in a
zero or positive value, then Oglethorpe Power shall be deemed to have
adequately maintained its Regulation and Spinning Reserve Requirements for
the Hour. However, if such integrated hourly test results in a negative
value, then Oglethorpe Power shall be deemed not to have adequately
maintained such requirements for the Hour, and Oglethorpe Power shall be
required to purchase its Regulation and Spinning Reserve Requirements from
Georgia Power in an amount equal to the difference between Oglethorpe Power's
Regulation and Spinning Reserve Requirements and Oglethorpe Power's Spinning
Capabilities.
(e) To the extent Oglethorpe Power is required to purchase its
Regulation and Spinning Reserve Requirements from Georgia Power pursuant to
the provisions of Subsection (d) hereto, such requirements shall be purchased
from Georgia Power at a rate calculated in accordance with Exhibit D.
(f) If Oglethorpe Power has elected to maintain its Regulation and
Spinning Reserve Requirements in accordance with Section 11.1, in any Hour in
which the Southern Control Area Operator calls for energy production from
Oglethorpe Power's regulation or spinning operating reserves and Oglethorpe
Power produces surplus energy in connection with such requested operation of
OPC Resources other than Block Resources, Georgia Power shall waive any
charges associated with the Regulation Energy Variance in Section 11.4(d) and
shall credit Oglethorpe Power for such surplus energy at the higher of 1.1
times the highest off-system transaction price disclosed by Oglethorpe Power,
if any, in effect at the time of the call (either a purchase or a sale) or
the credit
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determined in accordance with Section 12.5. In addition, such Hour shall be
excluded from the determination of Commitment Cost in Section 12.4. For any
such Hour in which Oglethorpe Power incurs any charges associated with the
integrated hourly tests performed in accordance with Sections 11.5(d) and
11.6(d), the computation of such charges shall be reduced by an amount
commensurate with Oglethorpe Power's surplus energy production, such surplus
to be applied first to the test set forth in Section 11.6(d) and second to
the test set forth in Section 11.5(d). The foregoing shall in no way
restrict Oglethorpe Power's use of the Block Resources, and any surplus
energy produced in such Hour shall be first credited to the increased output
of OPC Resources other than Block Resources, with any remainder being
credited in accordance with Section 12.5.
For any Hour in which the Southern Control Area operator has called for
energy production from Oglethorpe Power's regulation or spinning operating
reserves prior to ten (10) minutes before the end of such Hour and Oglethorpe
Power does not produce surplus energy, the on-line Available Capability of
any OPC Resource not operated by Georgia Power shall be deemed equal to
Oglethorpe Power's entitlement to the greater of (i) the integrated hourly
output of such resource, or (ii) the minimum output level maintained by the
resource between ten (10) minutes following the call and the earlier of the
end of the call or the end of each such Hour. The on-line Available
Capability of any Georgia Power operated resources shall continue to be
determined in accordance with the operating procedures for such resources.
In addition, the rate for deficit energy in excess of the Actual Hourly
Resource Utilization of the committed Block Resources less the then current
load carrying capability of such Block Resources shall be the higher of 1.1
times the highest off-system transaction price disclosed by Georgia Power, if
any, in effect at the time of the call (either a purchase or a sale) or the
rate determined in accordance with Section 12.6.
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(g) At such time that the Parties determine that it is practical to do
so, Georgia Power and Oglethorpe Power shall use reasonable best efforts to
negotiate a Real Time spinning operating reserve performance test to replace
the test in Section 11.5(d) above, based on Oglethorpe Power's highest
instantaneous load within the Hour (such changes to be implemented
concurrently for regulation and operating reserves).
11.6 Operating Reserve - Supplemental Reserve Service. (a) During the
effectiveness of this Agreement, Oglethorpe Power may elect, pursuant to
Section 11.1, (i) to purchase from Georgia Power Operating Reserve -
Supplemental Reserve Service for OPC Territorial Load at rates then in effect
under the Open Access Transmission Tariff of Southern Companies, (ii) to
maintain, subject to the provisions below or any change implemented pursuant
to Section 3.2, supplemental operating reserves for OPC Territorial Load
("Supplemental Reserve Requirement"), or (iii) to purchase short term
Supplemental Reserve Service pursuant to Section 11.7.
(b) Oglethorpe Power's Supplemental Reserve Requirement shall equal
2.09% of the OPC Territorial Load coincident with the 1996 twelve (12)
monthly peak loads of the Southern Control Area. The 2.09% value utilized
herein shall be updated and revised, if necessary, to comport with changes in
the Southern Control Area supplemental operating reserve requirements,
effectuated in accordance with Prudent Utility Practice, or changes in the
resource base for the Southern Control Area (either an increase or decrease
in the contingency size).
(c) Oglethorpe Power shall maintain its Regulation, Spinning and
Supplemental Reserve Requirements from unscheduled OPC Resources which are
qualified to supply Spinning Reserve Service or Operating Reserve -
Supplemental Reserve Service ("Supplemental Reserve Service") and qualifying
interruptible load. In order for an OPC Resource to qualify as a "Qualifying
Resource -Supplemental," it must (i) be located in the Southern Control Area;
(ii) be telemetered to the
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Southern Control Area operator; (iii) be capable of synchronous operation at
the output level declared by Oglethorpe Power for Supplemental Reserve
Service within ten (10) minutes of initial call by the Southern Control Area
operator to the Oglethorpe Power system operator; and (iv) be immediately
callable by the Southern Control Area operator, by verbal notification to the
Oglethorpe Power system operator, to produce energy on a pro rata basis, as
nearly as practicable, with the other supplemental operating reserves of the
Southern Control Area. For purposes of this Section, Qualifying Resources -
Supplemental shall initially be limited to fifteen (15) percent of the
Peaking Block Resources and Rocky Mountain (pumping load, and/or synchronous
condensing in the generation direction or off-line units while operating in a
mode which permits the declared level of synchronous output within 10 minutes
of initial call). From time to time during the term of this Agreement,
Oglethorpe Power may request that one or more additional OPC Resources be
designated and treated as Qualifying Resources - Supplemental. The Parties
shall discuss the issue of whether such additional OPC Resources meet the
above requirements to be Qualifying Resources - Supplemental, as well as the
terms and conditions related thereto, at the time of such request.
Oglethorpe Power shall not be precluded from submitting Dynamically Scheduled
OPC Resources or OPC-Controllable-ITS Resources which are connected to a
distribution system for credit as Qualifying Resources - Supplemental;
provided, however, that, in addition to the above requirements, such
resources must be callable at the sole discretion of Oglethorpe Power.
Qualifying interruptible loads must (i) be interruptible within 10 minutes of
initial call by the Southern Control Area operator to the Oglethorpe Power
system operator, (ii) be callable at the sole discretion of Oglethorpe Power,
and (iii) meet NERC guidelines for the treatment of interruptible loads as
non-spinning operating reserves. Oglethorpe Power must declare which, if
any, interruptible loads shall
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be included as qualifying interruptible loads at least 45 Days prior to the
commencement of each Year, This declaration shall constitute an election for
purposes of Section 3.4.
(d) An integrated hourly test shall be performed to ensure that the sum
of (i) the on-line Available Capability of the Qualifying Resources -
Spinning less the Actual Hourly Resource Utilization of such resources
(subject to Section 11.4(b)), (ii) the Available Capability of Qualifying
Resources - Supplemental less the Actual Hourly Resource Utilization of such
resources; (iii) the current hourly loads of each qualifying interruptible
customer in excess of that customer's firm contract demand; (iv) any Back-Up
Capacity purchased by Oglethorpe Power within the Hour under Section 12.3;
and (v) any Regulation and Spinning Reserve Requirements purchased by
Oglethorpe Power within the Hour pursuant to Section 11.5 (collectively
referred to in this Subsection as "Supplemental Capabilities") is greater
than or equal to Oglethorpe Power's Regulation Requirement, Spinning Reserve
Requirement and Supplemental Reserve Requirement. If the integrated hourly
test (Supplemental Capabilities minus Oglethorpe Power's Regulation, Spinning
Reserve and Supplemental Reserve Requirements) results in a zero or positive
value, then Oglethorpe Power shall be deemed to have adequately maintained
its Supplemental Reserve Requirement for the Hour. However, if such
integrated hourly test results in a negative value, then Oglethorpe Power
shall be deemed not to have adequately maintained such requirement, and
Oglethorpe Power shall be required to purchase its Supplemental Reserve
Requirement from Georgia Power in an amount equal to the difference between
Oglethorpe Power's Regulation, Spinning Reserve and Supplemental Reserve
Requirements and Oglethorpe Power's Supplemental Capabilities.
(e) To the extent Oglethorpe Power is required to purchase its
Supplemental Reserve Requirement from Georgia Power pursuant to the
provisions of Subsection (d) hereto, such
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requirement shall be purchased from Georgia Power at a rate calculated in
accordance with Exhibit E.
(f) If Oglethorpe Power has elected to maintain its Supplemental
Reserve Requirement in accordance with Section 11.1, in any Hour in which the
Southern Control Area Operator calls for energy production from Oglethorpe
Power's supplemental operating reserves and Oglethorpe Power produces surplus
energy in connection with such requested operation of OPC Resources other
than Block Resources, Georgia Power shall waive any charges associated with
the Regulation Energy Variance in Section 11.4(d), and shall credit
Oglethorpe Power for such surplus energy at the higher of 1.1 times the
highest off-system transaction price disclosed by Oglethorpe Power, if any,
in effect at the time of the call (either a purchase or a sale) or the credit
determined in accordance with Section 12.5. In addition, such Hour shall be
excluded from the determination of Commitment Cost in Section 12.4. For any
such Hour in which Oglethorpe Power incurs any charge associated with the
integrated hourly test performed in accordance with Section 11.6(d), the
computation of such charge shall be reduced by an amount commensurate with
Oglethorpe Power's surplus energy production, such surplus to be applied to
the test set forth in Section 11.6(d). The foregoing shall in no way
restrict Oglethorpe Power's use of the Block Resources, and any surplus
energy produced in such Hour shall be first credited to the increased output
of OPC Resources other than Block Resources, with any remainder being
credited in accordance with Section 12.5.
For any Hour in which the Southern Control Area operator has called for
energy production from Oglethorpe Power's supplemental operating reserves
prior to ten (10) minutes before the end of such Hour and Oglethorpe Power
does not produce surplus energy, the Available Capability of any OPC Resource
not operated by Georgia Power shall be deemed equal to Oglethorpe Power's
entitlement to the greater of (i) the integrated hourly output of such
resource, or (ii) the minimum
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output level maintained by the resource between ten (10) minutes following
the call and the earlier of the end of the call or the end of each such Hour.
The Available Capability of any Georgia Power operated resources shall
continue to be determined in accordance with the operating procedures for
such resources. In addition, the rate for deficit energy in excess of the
Actual Hourly Resource Utilization of the committed Block Resources less the
then current load carrying capability of such Block Resources shall be the
higher of 1.1 times the highest off-system transaction price disclosed by
Georgia Power, if any, in effect at the time of the call (either a purchase
or a sale) or the rate determined in accordance with Section 12.6.
(g) At such time that the Parties determine that it is practical to do
so, Georgia Power and Oglethorpe Power shall use reasonable best efforts to
negotiate a Real Time supplemental operating reserve performance test to
replace the test in Section 11.6(d) above, based on Oglethorpe Power's
highest instantaneous load within the Hour (such changes to be implemented
concurrently for regulation and operating reserves).
11.7 Short-Term Purchase Of Territorial Control Area Services. (a)
Oglethorpe Power may purchase short-term Regulation Service in accordance
with the terms of Section 11.7(c) and (d) below if (i) Oglethorpe Power's
control center computer or communication equipment is inoperable such that
Oglethorpe Power cannot reasonably determine its instantaneous load and
generation or (ii) one or more of the following generation facilities is
unavailable due to an unplanned outage (as defined by NERC): Plant Scherer
Unit No. 1, Plant Scherer Unit No. 2, Plant Wansley Unit No. 1 or Plant
Wansley Unit No. 2.
(b) Oglethorpe Power may purchase short-term Spinning and Supplemental
Reserve Services in accordance with the terms of Section 11.7(c) and (d)
below if any two or more of the Qualifying Resources - Spinning and/or
Supplemental (i) are unavailable due to unplanned outages
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(as defined by NERC), or (ii) in the case of Block Resources, are derated to
zero MW load carrying capability, in accordance with the BPSA.
(c) A short-term purchase under this Section shall commence at midnight
following Oglethorpe Power's request; provided, however, that such request
shall be made no later than four (4) o'clock p.m. (Birmingham, Alabama time)
on the Monday through Friday following a 12-Hour period after such qualifying
event occurs. A short-term purchase of Regulation Service under this
Section shall end at midnight following (i) the repair of Oglethorpe Power's
control center equipment or (ii) a change in operating status of the
applicable generating units, such that the qualifying condition no longer
exists, subject to the minimum service duration set forth in Section 11.7(d)
below. A short-term purchase of Spinning and Supplemental Reserve Services
under this Section shall end at midnight following a change in operating
status of the applicable generating units, such that the qualifying condition
no longer exists, subject to the minimum service duration set forth in
Section 11.7(d) below.
(d) In its request for short-term Regulation Service and/or short-term
Spinning and Supplemental Reserve Services, Oglethorpe Power shall identify
the event(s) which qualify Oglethorpe Power for such service(s), the
service(s) Oglethorpe Power wishes to purchase, and the minimum duration of
such service(s), either 30 Days or 120 Days. Oglethorpe Power may purchase
Regulation Service separately from Spinning and Supplemental Reserve
Services, but must purchase Spinning Reserve Service and Supplemental Reserve
Service together. The rates for all short term services under this Section
are set forth in Exhibit F.
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ARTICLE XII
ENERGY IMBALANCE SERVICE
12.1 Energy Imbalance. (a) For each Hour of the Term, Georgia Power
shall calculate the Energy Imbalance as the difference between: (i) the
Actual Hourly OPC Resources Utilization in the Hour, as measured at or
adjusted to Level B-1, less (ii) OPC Total Load Requirements.
(b) If the Energy Imbalance is positive, then Oglethorpe Power has
surplus energy in such Hour and is deemed to have sold energy to Georgia
Power in an amount equal to this difference under the terms of Section 12.5
of this Agreement, and Oglethorpe Power may incur Commitment Costs associated
with such sale in accordance with Section 12.4 of this Agreement.
(c) If the Energy Imbalance is negative, then Oglethorpe Power has
deficit energy in such Hour and is deemed to have purchased from Georgia
Power energy in an amount equal to the absolute value of this difference
under the terms of Sections 12.3, 12.4, and 12.6 of this Agreement.
12.2 Inadvertent Energy Bandwidth. (a) For each Day of the Term,
Georgia Power shall calculate the average Energy Imbalance by computing the
quotient of: (i) the sum of the absolute values of the Energy Imbalance for
each Hour in the Day, divided by (ii) the total number of Hours in the Day.
(b) If such average Energy Imbalance for a Day is less than or equal to
60 megawatts, then (i) the Inadvertent Energy Bandwidth for surplus energy
(IEBS) for each Hour in the Day shall be 100 Megawatts and (ii) the
Inadvertent Energy Bandwidth for deficit energy (IEBD) for each Hour in the
Day shall be -100 megawatts.
(c) If the average Energy Imbalance for a Day is greater than 60
megawatts, then (i) the Inadvertent Energy Bandwidth for surplus energy
(IEBS) for each hour in the Day shall be 60
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megawatts and (ii) the Inadvertent Energy Bandwidth for deficit energy (IEBD)
for each Hour in the Day shall be -60 megawatts.
(d) Until such time as the Southern Control Area operator releases
Plant Wansley Unit Nos. 1 and 2 and Plant Scherer Unit Nos. 1 and 2 for
Automatic Generation Control operation by Oglethorpe Power, the 60 megawatt
value referenced in (b) and (c) above shall be replaced with 80 megawatts.
12.3 Back-Up Capacity Charge. If Oglethorpe Power has hourly deficit
energy and the absolute value of such deficit is greater than the absolute
value of the difference between (i) the sum of the Actual Hourly Resource
Utilization of all Block Resources and the Pseudo CT Resource, less (ii) the
sum of the then-current load carrying capability of all Block Resources and
the Maximum Utilization Level of the CT Resource ("Difference"), then
Oglethorpe Power shall pay Georgia Power a Back-Up Capacity Charge equal to
the product of: (i) the absolute value of the hourly deficit energy minus the
absolute value of the Difference for that Hour, and (ii) the greater of the
Critical Period rate for Regulation and Spinning Reserve Requirements (see
Exhibit D) and 400 dollars per megawatt hour ($/MWH).
12.4 Commitment Cost. (a) If Oglethorpe Power has surplus energy during
any Hour of the Day that is greater than the IEBS for that Hour, then, unless
such Hour is excluded pursuant to Section 3.4(b), 11.5(f) or 11.6(f),
Oglethorpe Power shall pay Georgia Power a Commitment Cost equal to the
product of: (i) the maximum amount of hourly surplus energy in that Day and
(ii) the Commitment Cost Rate for that Day. The Commitment Cost Rate, in
dollars per megawatt day, shall be calculated pursuant to Georgia Power's
current practice, as set forth in Exhibit B; provided, however, that any
changes to such practices as applied to this Agreement shall be agreed to in
advance by the Parties.
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(b) If Oglethorpe Power has deficit energy in any Hour of a Day that is
less than the IEBD for that Hour, then Oglethorpe Power shall pay a
Commitment Cost to Georgia Power for that Day equal to the product of (i) the
maximum of the absolute value of the hourly deficit energy in that Day and
(ii) the Commitment Cost Rate for that Day.
12.5 Credit for Hourly Surplus Energy. In each Hour when Oglethorpe
Power has surplus energy, Georgia Power shall credit Oglethorpe Power for
this surplus energy an amount equal to the sum of:
(a) the product of
(i) the amount of the hourly surplus energy, up to but not greater
than the IEBS for that Hour, times (ii) the Territorial Marginal
Cost for that Hour (unless modified by Sections 3.4(b), 11.5(f)
or 11.6(f)), and
(b) the product of
(i) the amount of the hourly surplus energy, if any, which is greater
than the IEBS for that Hour, times (ii)the lesser of System
Marginal Cost for that Hour minus ten dollars per megawatt hour
($/MWH) and Territorial Marginal Cost for that Hour (unless
modified by Sections 3.4(b), 11.5(f) or 11.6(f)).
12.6 Payment for Hourly Deficit Energy. In each Hour when Oglethorpe
Power has deficit energy, Oglethorpe Power shall pay Georgia Power for this
deficit energy an amount equal to the sum of:
(a) the product of
(i) the amount of the absolute value of the hourly deficit energy, up
to but not greater than the absolute value of the IEBD for that
Hour, times (ii) the
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System Marginal Cost for that Hour (unless modified by Sections
3.4(b), 11.5(f) or 11.6(f)), and
(b) the product of
(i) the amount of the absolute value of the hourly deficit energy, if
any, which is greater than the absolute value of the IEBD for
that Hour, times (ii) the System Marginal Cost for that Hour plus
ten dollars per megawatt hour ($/MWH) (unless modified by
Sections 3.4(b), 11.5(f) or 11.6(f)).
ARTICLE XIII
OPERATIONAL DEFICIENCY
13.1 Operational Responsibility. Oglethorpe Power and Georgia Power
shall each be responsible for committing sufficient resources, scheduling
energy utilization therefrom and maintaining sufficient actual or deemed
spinning reserve levels to meet reasonably foreseeable operating
contingencies, to accommodate load forecast errors, transmission and
generation equipment failures and similar matters and to ensure that its
resources as nearly as possible equal its resource requirements on an
instantaneous basis.
13.2 Oglethorpe Power's Real-Time Information Obligations. (a)
Oglethorpe Power shall provide Georgia Power or its agent information
concerning the output levels of the OPC-Controllable-ITS Resources and the
scheduled output of the SEPA Resources on a Real-Time basis, in such detail
as Georgia Power or its agent reasonably requests in order to support system
security or load regulation activities. Oglethorpe Power shall provide such
Real-Time information through a combination of telemetered and estimated
values consistent with Prudent Utility Practice. Oglethorpe Power shall not
be required to provide Hourly individual unit output levels to Georgia Power
or its agent unless it is necessary or appropriate for the above purposes.
In addition,
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Oglethorpe Power shall also provide Georgia Power or its agent revenue
metering records, in electronic form if available, of the actual output of
the OPC-Controllable-ITS Resources and the delivered output of the SEPA
Resources in such detail and upon such frequency as Georgia Power or its
agent reasonably requests in order to support, verify and timely complete
either or both Oglethorpe Power's calculation of the Actual Hourly Resource
Utilization of the OPC-Controllable-ITS Resources under Section 4.1 and
Georgia Power's billing functions under Article XVII.
(b) Oglethorpe Power shall provide Georgia Power or its agent Real-Time
information concerning energy usage by Oglethorpe Power as measured at each
of Oglethorpe Power's Delivery Points, in such detail as Georgia Power or its
agent reasonably requests to support system security or load regulation
activities. Oglethorpe Power shall provide such Real-Time information through
a combination of telemetered and estimated values in such form as is
reasonably suitable to Georgia Power or its agent. In addition, Oglethorpe
Power shall provide Georgia Power or its agent revenue metering records, in
electronic form, of the actual energy flows at each of the Delivery Points in
such detail and upon such frequency as Georgia Power or its agent reasonably
requests in order to support, verify and timely complete Georgia Power's
calculation of OPC Total Load Requirements and Georgia Power's billing
functions under Article XVII.
13.3 Determination of OPC Operational Deficiency. (a) Oglethorpe Power
shall provide Georgia Power or its agent, on a Real-Time basis, (1) the sum
of the instantaneous Actual Hourly Resource Utilization of each of the OPC
Resources at Level B-1, and (2) Oglethorpe Power's instantaneous values for
OPC Total Load Requirements at Level B-1.
(b) Georgia Power or its agent shall, using the information provided
by Oglethorpe Power pursuant to Section 13.3(a), as verified by Georgia Power
or its agent, determine if there is an OPC Operational Deficiency, from time
to time during the Term on as near an instantaneous basis as
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practicable given the timing of Oglethorpe Power's provision of such
information. An OPC Operational Deficiency is the amount equal to the
difference between (1) the sum provided by Oglethorpe Power pursuant to
Section 13.3(a)(1); minus (2) the amount provided by Oglethorpe Power
pursuant to Section 13.3(a)(2), if such difference is negative.
(c) Oglethorpe Power shall provide Georgia Power or its agent the
Real-Time information required pursuant to this Article through a combination
of telemetered and estimated values in such form consistent with Prudent
Utility Practice.
(d) The existence of an OPC Operational Deficiency is an indicator to
the Parties of a circumstance relevant to monitoring system conditions to
ensure system security and reliability.
13.4 Corrective Action to Eliminate an OPC Operational Deficiency. This
Section 13.4 shall apply only if Oglethorpe Power has not elected, for the
current Year, to declare interruptible loads as supplemental operating
reserves pursuant to Section 11.6(c) herein. (a) If at any time during the
Term an OPC Operational Deficiency exists and Georgia Power or its agent
determines that it is necessary or appropriate, in accordance with the
CSA-IOD Interruption Procedures developed by Georgia Power or its agent, for
Oglethorpe Power to take action to eliminate such OPC Operational Deficiency,
then Oglethorpe Power, at the direction of Georgia Power or its agent, shall
take such action or actions as Oglethorpe Power, in its sole discretion,
deems necessary or appropriate (including, without limitation, load shedding)
to eliminate such OPC Operational Deficiency.
(b) Should Georgia Power or its agent have given a direction to
Oglethorpe Power to eliminate an OPC Operational Deficiency pursuant to
Section 13.4(a), and if after a reasonable time, in accordance with the
CSA-IOD Interruption Procedures developed by Georgia Power or its agent,
Oglethorpe Power shall not have eliminated such OPC Operational Deficiency,
then Georgia Power or its agent may take such action or actions consistent
with Prudent Utility Practice as Georgia
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Power or its agent deems necessary or appropriate to eliminate the OPC
Operational Deficiency, including, without limitation, load shedding and
opening any of the interconnections between Georgia Power and Oglethorpe
Power.
(c) Neither Georgia Power nor Oglethorpe Power shall be required to
shed load in order to allow the other to maintain an operational deficiency.
13.5 No Liability; Indemnity. (a) Neither Georgia Power nor its agent
shall have any liability to Oglethorpe Power or any other person or entity
for any losses, costs, liabilities, damages or expenses (including without
limitation attorneys' fees and expenses) of any kind incurred or suffered
pursuant to, as a result of, or in connection with any action taken by or at
the direction of Georgia Power under this Article XIII, except for losses,
costs, liabilities, damages or expenses (including without limitation
attorneys' fees and expenses) resulting directly from actions taken by or
directions given by Georgia Power that are in violation of this Article XIII
and that are not Prudent Utility Practice or resulting directly from willful
misconduct of Georgia Power or its agent.
(b) Oglethorpe Power hereby indemnifies and holds Georgia Power and its
agent harmless from and against any and all losses, costs, liabilities,
damages and expenses (including without limitation attorneys' fees and
expenses) of any kind incurred or suffered by Georgia Power or its agent
pursuant to, as a result of or in connection with Oglethorpe Power's
performance or nonperformance under Section 13.4, including, but not limited
to, any action taken by or at the direction of Georgia Power under Section
13.4, except for losses, costs, liabilities, damages or expenses (including
without limitation attorneys' fees and expenses) resulting directly from
actions taken by or directions given by Georgia Power that are not Prudent
Utility Practice or from willful misconduct of Georgia Power or its agent.
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(c) With respect to data and information provided by Oglethorpe Power
pursuant to Section 13.3, Oglethorpe Power shall indemnify Georgia Power for
any and all damages awarded to a third party by a court of competent
jurisdiction in connection with action(s) taken by Georgia Power in reliance
on data or information provided by Oglethorpe Power which understates
Oglethorpe Power's Operational Deficiency.
ARTICLE XIV
NON-TERRITORIAL CONTROL AREA SERVICES
14.1 Load Within Southern Control Area. (a) Any OPC Non-Territorial
Load which is within the Southern Control Area will be provided with
Non-Territorial Control Area Services as follows: (i) Scheduling System
Control and Dispatch Service, and Reactive Supply and Voltage Control From
Generation Sources Service will be made available on terms consistent with
the provisions of this Agreement for OPC Territorial Load; and (ii)
Regulation and Frequency Response Service and Operating Reserve - Spinning
and Supplemental Reserve Services will be made available at the standard
rates then in effect under the Open Access Transmission Tariff of Southern
Companies.
(b) Notwithstanding the provisions of Section 14.1(a), to the extent an
OPC Non-Territorial Load purchaser inside the Southern Control Area is
receiving and paying for Control Area Services for Regulation and Frequency
Response Service, Operating Reserve - Spinning Reserve Service and Operating
Reserve -Supplemental Reserve Service under the Open Access Transmission
Tariff of Southern Companies, Georgia Power's invoice to Oglethorpe Power
shall show the charge for such Control Area Services as determined in Section
14.1(a), and shall also reflect a credit for the amounts paid by such
purchaser to Southern Companies. In addition, to the extent OPC
Non-Territorial Load consists of a sale to an entity and such entity is
self-supplying one or more Control
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Area Services with respect to such sale pursuant to a written agreement
between such entity and Georgia Power or its agent, Georgia Power's invoice
to Oglethorpe Power shall show the charge for such Control Area Services as
determined in Section 14.1(a), and shall also reflect a credit for the value
of such Control Area Services self-supplied by such entity, as determined by
the rates then in effect under the Open Access Transmission Tariff of
Southern Companies.
14.2 Other Loads. Any OPC Non-Territorial Load which is not within the
Southern Control Area will be provided with Non-Territorial Control Area
Services as follows: (i) Scheduling, System Control and Dispatch Service will
be charged a rate of $.092637 per megawatt hour (MWH); and (ii) Reactive
Supply and Voltage Control From Generation Sources Service will be provided
in accordance with the provisions of Section 11.3 of this Agreement.
Regulation and Frequency Response Service and Operating Reserve - Spinning
and Supplemental Reserve Services will not be provided under this Agreement.
ARTICLE XV
CONFIDENTIALITY OF DATA
15.1 Information Obligations; Confidentiality of Data. (a) The Parties
agree to make available to each other certain information, as set forth in
this Article XV, in fulfillment of their obligations under this Agreement.
Except as provided in Sections 15.1(b), 15.1(c) and 15.1(d) below, the
following information, when acquired from another Party which is not an
Affiliate, shall be treated as confidential, and shall not be disclosed to
any third party or Affiliate at any time without the prior written consent of
the other Party(ies); provided, however, that nothing in this Article shall
restrict any Party's use or disclosure of its own information.
(b) The Parties shall have no obligation to treat as confidential or
otherwise withhold from disclosure to any third party or Affiliate any
information that is available through sources in
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the public domain or becomes available without violating the terms of this
Agreement or without the disclosing Party violating any applicable legal
requirements through such disclosure. In addition, no Party shall be
prohibited from providing to a regulatory authority or court of competent
jurisdiction information received pursuant to this Agreement if ordered or
otherwise compelled to do so; provided, however, that such Party shall use
its reasonable best efforts to notify the other Party(ies) in advance of such
disclosure.
(c) Any aggregate information provided in regulatory reports in
accordance with this Article shall include only that information required by
the applicable regulatory authority, in only the form required by such
regulatory authority.
(d) Any information not specifically addressed in this Article XV
which relates to the services provided under this Agreement, as currently
defined or as modified by the terms of this Agreement or by FERC order, shall
be provided in the reasonable discretion of the Parties, as determined at the
time of request by one Party to the other(s).
15.2 Information Related To Supply Deficiencies. (a) All megawatt-hour
quantities and negotiated market rates associated with sales of surplus
energy associated with participation in control area supply deficiencies
shall be disclosed to other Parties solely for internal use by those Parties
or their agents, and the Party(ies) in receipt of such information shall at
no time disclose the same to any third party without the prior written
consent of the disclosing Party, such consent not to be unreasonably
withheld; provided, however, that no Party shall be required to obtain the
consent of any Party to use aggregate megawatt-hour quantities and dollar
amounts in financial and regulatory reports.
(b) Aggregate megawatt-hour quantities (i.e., not per customer,
Delivery Point or EMC) associated with load shedding (interruptible and firm
load) shall be disclosed after-the-fact to other
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Parties solely for internal use by those Parties or their agents, and the
Party(ies) in receipt of such information shall at no time disclose the same
to any third party without the prior written consent of the disclosing Party,
such consent not to be unreasonably withheld.
(c) Transaction-specific data related to load shedding of interruptible
third-party load shall be treated consistent with the treatment of OPC
Off-System Transaction information, as set forth in Section 15.4 below.
Transaction-specific information related to load shedding of interruptible
native load and estimated Delivery Point information related to load shedding
of firm load shall be disclosed solely to each Party's operations and
billing/audit personnel, and the Party(ies) in receipt of such information
shall at no time disclose the same to any marketing personnel (including
Affiliates) or any third party.
15.3 Information Related To Block and CT Resources. Block Resource and
Pseudo CT Resource information (schedules and prices) shall be disclosed to
other Parties solely for internal use by those Parties or their agents, and
the Party(ies) in receipt of such information shall at no time disclose the
same to any third party without the prior written consent of the disclosing
Party, such consent not to be unreasonably withheld; provided, however, that
no Party shall be required to obtain the consent of any Party to use
aggregate megawatt-hour quantities and dollar amounts in financial and
regulatory reports.
15.4 Information Related To Off-System Transactions. OPC Off-System
Transaction specific scheduling information shall be disclosed solely to
Georgia Power's or its agent's operations and billing/audit personnel, and
Georgia Power and its agent shall at no time disclose the same to any
marketing personnel (including Affiliates) or any third party. Transaction
specific pricing information related to off-system transactions shall be
disclosed solely to the other Party's billing/audit personnel; provided,
however, that such information shall be disclosed only to the
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extent required under Sections 3.4(b), 11.5(f) and 11.6(f) of this Agreement.
Megawatt-hour scheduling quantities shall be disclosed, upon request by any
one of the Parties, in accordance with the information disclosure
requirements set forth in FERC Order Nos. 889 and 889-A (and their
successors) and the regulations promulgated thereunder.
15.5 Information Related To Territorial Control Area Services/Energy
Imbalance Service. (a) All Scheduling, System Control and Dispatch Service
sales information (quantities and prices) shall be disclosed to other Parties
solely for internal use by those Parties or their agents, and the Party(ies)
in receipt of such information shall at no time disclose the same to any
third party without the prior written consent of the disclosing Party, such
consent not to be unreasonably withheld; provided, however, that no Party
shall be required to obtain the consent of any Party to use aggregate
megawatt-hour quantities and dollar amounts in financial and regulatory
reports.
(b) All sales information related to Reactive Service, Regulation
Energy Variance, Spinning Reserve Service and Supplemental Reserve Service
(quantities and prices), all information necessary to calculate (i)
Oglethorpe Power's L10, (ii) Regulation and Spinning Reserve Requirements,
(iii) Supplemental Reserve Requirements and (iv) the rate adjustment ratios
in Exhibits C, D, and E to this Agreement, and all megawatt-hour quantities
and resulting rates associated with sales of surplus energy from operating
reserves shall be disclosed to other Parties solely for internal use by those
Parties or their agents, and the Party(ies) in receipt of such information
shall at no time disclose the same to any third party without the prior
written consent of the disclosing Party, such consent not to be unreasonably
withheld; provided, however, that no Party shall be required to obtain the
consent of any Party to use aggregate MVAR quantities, megawatt-hour
quantities (i.e., no less than daily and excluding statistical analyses), and
dollar amounts in financial and regulatory reports. The information used to
determine the quantity of
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Reactive Service, Regulation Energy Variance, Spinning Reserve Service and
Supplemental Reserve Service, to the extent not otherwise provided for under
this Article XV, shall be disclosed solely to each Party's operations and
billing/audit personnel and to the senior management of each Party in such
detail as is reasonably required to clarify billing or performance disputes.
(c) All Energy Imbalance Service sales information, including Back-Up
Capacity, Commitment Cost, Credits for Hourly Surplus Energy and Payments for
Hourly Deficit Energy (quantities and prices) shall be disclosed to other
Parties solely for internal use by those Parties or their agents, and the
Party(ies) in receipt of such information shall at no time disclose the same
to any third party without the prior written consent of the disclosing Party,
such consent not to be unreasonably withheld; provided, however, that no
Party shall be required to obtain the consent of any Party to use aggregate
megawatt-hour quantities (i.e., no less than daily and excluding statistical
analyses) and dollar amounts in financial and regulatory reports. The
information used to determine the quantity of Energy Imbalance, to the extent
not otherwise provided for under this Article XV, shall be disclosed solely
to each Party's billing/audit personnel and to the senior management of each
Party in such detail as is reasonably required to clarify billing or
performance disputes.
15.6 Information Related To Real-Time and Revenue Meter Data. (a)
Oglethorpe Power shall disclose facility-specific information related to
OPC-Controllable-ITS Resources and SEPA Resources under Sections 4.1, 6.2,
and 13.2(a) of this Agreement (to the extent not disclosed pursuant to the
Joint Ownership Agreements) solely to Georgia Power's or its agent's
operations and billing/audit personnel (operations personnel to receive only
Real-Time information and billing/audit personnel to receive Real-Time and
revenue meter information), and Georgia Power or its agent shall at no time
disclose such information to any marketing personnel (including Affiliates)
or any third party; provided, however, Oglethorpe Power's NERC/GADS type
information, to the extent
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and in the form available, shall be disclosed to Georgia Power's or its
agent's marketing personnel (but not to third parties) to the extent such
information relates to facilities which constitute Qualifying Resources -
Spinning or Qualifying Resources - Supplemental under this Agreement.
Neither Georgia Power nor its agent shall be obligated to disclose any
information regarding any resources of Georgia Power or its Affiliates (to
the extent not disclosed pursuant to the Joint Ownership Agreements);
provided, however, that to the extent Oglethorpe Power receives such
information through access to computer interfaces with Georgia Power or its
agent, Oglethorpe Power shall provide such information solely to its
operations personnel and shall not disclose the same to any other personnel
(including Affiliates) or any third parties. No Party shall be required to
obtain the consent of any Party to use aggregate megawatt-hour quantities
(i.e., one hourly number each for OPC-Controllable-ITS Resources and for SEPA
Resources) in financial and regulatory reports.
(b) Oglethorpe Power shall disclose Delivery Point information under
Section 13.2(b) of this Agreement solely to Georgia Power's or its agent's
operations and billing/audit personnel (operations personnel to receive only
Real-Time information and billing/audit personnel to receive Real-Time and
revenue meter information), and Georgia Power or its agent shall at no time
disclose such information to any marketing personnel (including Affiliates)
or any third party. Aggregate megawatt-hour quantities (i.e., one hourly
total value each for OPC Territorial Load and OPC Non-Territorial Load within
the Southern Control Area which is not an OPC Off-System Transaction) shall
be disclosed after-the-fact to other Parties solely for internal use by those
Parties or their agents, and the Party(ies) in receipt of such information
shall at no time disclose the same to any third party without the prior
written consent of the disclosing Party, such consent not to be unreasonably
withheld; provided, however, that no Party shall be required to obtain the
consent of any Party to use
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aggregate megawatt-hour quantities (i.e., one hourly total value each for OPC
Territorial Load and OPC Non-Territorial Load within the Southern Control
Area which is not an OPC Off-System Transaction) in financial and regulatory
reports.
(c) The Real-Time generation and load information used to determine
Oglethorpe Power's Operational Deficiency under Section 13.3 of this
Agreement shall be disclosed solely to Georgia Power's or its agent's
operations and billing/audit personnel and to the senior management of
Georgia Power or its agent in such detail as is reasonably required to
clarify billing or performance disputes. Georgia Power or its agent shall at
no time disclose such information to any marketing personnel (including
Affiliates) or any third party. The Real-Time value of Oglethorpe Power's
Operational Deficiency, as determined in Article XIII of this Agreement,
shall be disclosed to other Parties solely for internal use by those Parties
or their agents, and the Party(ies) in receipt of such information shall at
no time disclose the same to any third party without the prior written
consent of the disclosing Party, such consent not to be unreasonably withheld.
15.7 Information Related To Non-Territorial Control Area Services. The
hourly total megawatt-hour quantities and dollar amounts associated with
sales of Non-Territorial Control Area Services within and outside the
Southern Control Area (to the extent such information is not disclosed under
other provisions of this Article XV) shall be disclosed to other Parties
solely for internal use by those Parties or their agents, and the Party(ies)
in receipt of such information shall at no time disclose the same to any
third party without the prior written consent of the disclosing Party, such
consent not to be unreasonably withheld; provided, however, that no Party
shall be required to obtain the consent of any Party to use aggregate
megawatt-hour quantities and dollar amounts in financial and regulatory
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ARTICLE XVI
IMPLEMENTATION AND ADMINISTRATION FEES
16.1 CSA Implementation Fee. Oglethorpe Power hereby agrees to
reimburse Georgia Power for all reasonable costs incurred by Georgia Power or
its agent in connection with implementing this Agreement. Such monthly CSA
Implementation Fee shall include costs associated with, without limitation,
manpower, manpower overheads, equipment, computer software, and computer
time, and other reasonable costs associated with the implementation of this
Agreement, with the exception of attorneys' fees. Georgia Power agrees to
provide Oglethorpe Power a prior estimate of the scope and cost of any
implementation projects, including, but not limited to, the initial
implementation of this Agreement, for which the estimated cost exceeds Twenty
Thousand Dollars ($20,000).
16.2 CSA Administration Fee. Oglethorpe Power hereby agrees to
reimburse Georgia Power for all reasonable costs incurred by Georgia Power or
its agent in connection with the administration of this Agreement. Such
monthly CSA Administration Fee shall include costs associated with, without
limitation, manpower, manpower overheads, equipment, computer software,
computer time and other reasonable costs associated with the administration
of this Agreement, with the exception of attorneys' fees. Georgia Power
agrees to provide Oglethorpe Power a prior estimate of the scope of any
administration projects, for which the estimated cost exceeds Five Thousand
Dollars ($5,000).
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ARTICLE XVII
BILLING AND COLLECTIONS
17.1 Billing and Payment. (a) As promptly as practicable after the
commencement of each Month during the Term, Georgia Power shall send
Oglethorpe Power an invoice stating the amounts due from Oglethorpe Power for
Territorial Control Area Services (Article XI), Non-Territorial Control Area
Services (Article XIV), Energy Imbalance Service (including Back-Up Capacity
Charges, Commitment Costs and credits and payments associated with hourly
surpluses and deficits, respectively) (Article XII), the Pseudo Resource
Energy Charges and Credits (Article X), the Monthly CSA Implementation Fee
(Section 16.1) and the Monthly CSA Administration Fee (Section 16.2),
together with any other amounts then due by Oglethorpe Power to Georgia Power
or (except for amounts covered by Section 17.2) by Georgia Power to
Oglethorpe Power pursuant to the provisions of this Agreement. Georgia Power
will provide Oglethorpe Power, along with such invoices, all supporting data
necessary to compute the above quantities, subject to the confidentiality
provisions of Article XV, in electronic form, as it is available to Georgia
Power from time to time.
(b) All such invoices showing a net amount due from Oglethorpe Power to
Georgia Power shall be due and payable on or before the tenth (10th) Day
after Oglethorpe Power's receipt of such notice. If such tenth (10th) Day
after Oglethorpe Power's receipt is not a banking Day, then payment shall be
due on the next succeeding banking Day. Oglethorpe Power shall make payment
to Georgia Power in accordance with such invoices on or before the date due
in immediately available funds through wire transfer of funds or other means
acceptable to Georgia Power. If Oglethorpe Power does not make any of the
payments referenced above on or before such tenth (10th) Day, then interest
shall be added to the overdue payment, from the date such overdue payment
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was due until such overdue payment together with interest is paid, which
interest shall accrue in simple interest terms per annum at the Interest Rate
defined herein.
(c) In the event the calculation set forth in Section 17.1(a) shows a
net amount due from Georgia Power to Oglethorpe Power, Oglethorpe Power shall
send an invoice to Georgia Power in that amount. Such invoice shall be due
and payable on or before the tenth (10th) Day after Georgia Power's receipt
of such notice. If such tenth (10th) Day after Georgia Power's receipt is
not a banking Day, then payment shall be due on the next succeeding banking
Day. Georgia Power shall make payment to Oglethorpe Power in accordance with
such invoices on or before the date due in immediately available funds
through wire transfer of funds or other means acceptable to Oglethorpe Power.
If Georgia Power does not make any of the payments reflected above on or
before such tenth (10th) Day, then interest shall be added to the overdue
payment, from the date such overdue payment was due until such overdue
payment together with interest is paid, which interest shall accrue in simple
interest terms per annum at the Interest Rate defined herein.
(d) Oglethorpe Power agrees that Georgia Power may render invoices
pursuant to Section 17.1(a) stating the aggregate net amount required
pursuant to said Section 17.1(a) based wholly or partially upon preliminary
data. If Georgia Power elects to render such a preliminary invoice, Georgia
Power shall provide for an adjustment in the subsequent Month's invoice
reflecting a true-up to actual data of all calculations based upon
preliminary data. Any payment required to be made by Oglethorpe Power to
Georgia Power or by Georgia Power to Oglethorpe Power to reflect such
adjustment shall be made concurrently with the next Month's payment pursuant
to Section 17.1(b) or 17.1(c), as appropriate. Neither Oglethorpe Power nor
Georgia Power shall owe interest to the other on the amount of any such
adjustment calculated under this Section 17.1(d).
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17.2 Billing Disputes and Final Accounting. (a) If Oglethorpe Power
questions or contests the amount of any payment claimed by Georgia Power to
be due pursuant to this Agreement, Oglethorpe Power may make such payment
under protest and thereafter shall be reimbursed by Georgia Power for any
amount in error after the settlement of such question or contest, in
accordance with this Section 17.2; provided, however, that no disagreement or
dispute of any kind between Oglethorpe Power and Georgia Power concerning any
matter, including without limitation the amount of any payment due from
Oglethorpe Power or the correctness of any charge made by Georgia Power to
Oglethorpe Power, shall permit Oglethorpe Power to delay or withhold any
payment pursuant to this Agreement.
(b) In the event that Oglethorpe Power, by timely notice to Georgia
Power, questions or contests the correctness of any such charge or credit,
Georgia Power shall promptly review the questioned charge or credit and shall
notify Oglethorpe Power, within sixty (60) Days following receipt by Georgia
Power of such notice from Oglethorpe Power, of the amount of any error and
the amount of any payment or reimbursement that Oglethorpe Power is required
to make or is entitled to receive in respect of such alleged error. Not
later than the tenth (10th) banking Day after receipt by Oglethorpe Power of
such notice from Georgia Power as to the amount of any payment that
Oglethorpe Power is required to make, Oglethorpe Power shall make payment to
Georgia Power in immediately available funds. If Georgia Power is required
to make any reimbursement to Oglethorpe Power, Georgia Power shall make such
reimbursement not later than the tenth (10th) banking Day after Georgia Power
receives an invoice from Oglethorpe Power in the amount of such required
reimbursement. Payments and reimbursements made by either Oglethorpe Power
or Georgia Power under this Section 17.2(b) shall include interest from the
date the original payment was due until the date such payment or
reimbursement together with interest is made, which interest
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shall accrue in simple interest terms per annum at the Interest Rate defined
herein. Oglethorpe Power shall have until the 180th Day after receipt of an
invoice to question or contest the correctness of any charge or credit made
to Oglethorpe Power during such Month pursuant to Section 17.1, after which
time the correctness of all such charges and credits shall be conclusively
presumed.
(c) If Oglethorpe Power disputes Georgia Power's resolution under
Section 17.2(b) of any question or contest by Oglethorpe Power of the
correctness of any charge or credit made to Oglethorpe Power pursuant to
Section 17.1, then at Oglethorpe Power's request Georgia Power and Oglethorpe
Power agree to use their reasonable best efforts to achieve a mutually
acceptable solution to such dispute. In the event that either Georgia Power
or Oglethorpe Power believes that any such efforts by Georgia Power and
Oglethorpe Power have been or will be unsuccessful, then it may submit such
dispute to, for resolution by, the Joint Committee. If the Joint Committee
fails to resolve such dispute by the third (3rd) regularly scheduled meeting
following the meeting at which Oglethorpe Power or Georgia Power first
submitted such dispute to the Joint Committee, then either Oglethorpe Power
or Georgia Power may submit such dispute to, for resolution by, the
respective Chief Executive Officers of Oglethorpe Power and Georgia Power.
If the Chief Executive Officers fail to resolve such dispute within a
reasonable period of time after it is submitted to them, then either
Oglethorpe Power or Georgia Power may resort to any remedy, at law or in
equity, that may be available therefor. If either Georgia Power or
Oglethorpe Power submits such dispute to the Joint Committee, then neither of
them shall thereafter have any further obligation to use its reasonable best
efforts to achieve a mutually acceptable solution as aforesaid.
(d) Notwithstanding the foregoing provisions of Section 17.2, if
Oglethorpe Power is then in default with respect to any payments required to
be made under this Agreement, Georgia
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Power may withhold any reimbursement due Oglethorpe Power under this Section
17.2 up to the amount of the payments in default.
(e) Georgia Power will provide Oglethorpe Power with such information
as is reasonably required by Oglethorpe Power in order to account for
payments made pursuant to this Section 17.2 on Oglethorpe Power's books.
17.3 Availability of Records. (a) Georgia Power will for each Month of
the Term, at all times prior to the end of such 180 Day period set forth in
Section 17.2(b), make available to Oglethorpe Power, subject to the
confidentiality provisions of Article XV, and Oglethorpe Power may audit,
such books and records of Georgia Power as are necessary for Oglethorpe Power
to calculate the payments to be made hereunder and thereby to verify the
accuracy of the amounts billed to or for Oglethorpe Power pursuant to Section
17.1. No payment made pursuant to the provisions of this Article shall
constitute a waiver of any right of Oglethorpe Power under Section 17.2 to
question or contest the correctness of any charge or credit by Georgia Power
or to dispute Georgia Power's resolution of any such question or contest.
(b) Oglethorpe Power shall for each Month of the Term, at all times
prior to the end of such 180 Day period set forth in Section 17.2(b), make
available to Georgia Power, subject to the confidentiality provisions of
Article XV, and Georgia Power may audit, such books and records of Oglethorpe
Power as are necessary for Georgia Power to obtain or verify information to
calculate or for the calculation of the payments to be made hereunder and
thereby to verify the accuracy of the amounts billed to or for Oglethorpe
Power during such Month pursuant to Section 17.1. No invoice sent pursuant
to the provisions of this Article shall constitute a waiver of any right of
Georgia Power under Section 17.2 to question or contest the correctness of
any Oglethorpe Power information.
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(c) In addition to Section 17.3(b), Oglethorpe Power's metering records
shall be available at all times during the Term to authorized agents and
employees of the Parties for purposes of this Agreement, subject to the
confidentiality provisions of Article XV.
17.4 Failure to Make Payments. (a) If Oglethorpe Power fails to pay
when due the full amounts of any payment(s) required by Section 17.1, then
subject to the requirements of Section 17.4(b), Georgia Power may withhold
provision of services hereunder to Oglethorpe Power until Oglethorpe Power
has paid the full amounts of such overdue payment(s) to Georgia Power
(including without limitation interest) as required by Section 17.1.
(b) Before Georgia Power may withhold provision of service to
Oglethorpe Power pursuant to Section 17.4(a), Georgia Power shall give
Oglethorpe Power written notice of Oglethorpe Power's delinquency and at
least twenty (20) Days advance written notice of Georgia Power's intent to
withhold service if Oglethorpe Power's delinquency is not remedied and
provided that Georgia Power has filed the written notice of the intended
suspension of service with the FERC.
(c) Georgia Power shall not withhold service from Oglethorpe Power or
shall cease withholding service under this Section 17.4 if and when
Oglethorpe Power cures the delinquency that gave rise to the notice.
(d) In addition to the rights granted in Sections 17.2 and 17.3,
Georgia Power may take any action, at law or in equity, to enforce this
Agreement and to recover any and all unrecovered damages and expenses and
other losses, costs and liabilities (including without limitation reasonable
attorneys' fees and expenses) incurred or suffered by Georgia Power as a
result of or in connection with any default in payment by Oglethorpe Power
under this Agreement.
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ARTICLE XVIII
TERM OF AGREEMENT
18.1 Term. (a) This Agreement shall take effect on the first Day of the
first Month after the date this Agreement is accepted for filing and permitted
to become effective by the FERC ("Effective Date"). On the Effective Date, this
Agreement shall supersede the CSA in its entirety and the CSA shall be
irrevocably terminated. If the FERC does not accept this Agreement for filing,
the CSA shall remain in effect; provided, however, that Georgia Power shall have
the right to file unilaterally any agreement which it reasonably believes is
appropriate, which agreement shall become effective, and shall supersede and
terminate the CSA in its entirety upon FERC acceptance of such agreement for
filing.
(b) This Agreement shall remain in effect through December 31, 1998,
unless otherwise terminated in accordance with the provisions of this Agreement.
18.2 Extension of the Term. (a) This Agreement shall continue in effect
after December 31, 1998 for successive one (1) year terms unless terminated by
Georgia Power, Oglethorpe Power or GSOC upon six (6) months prior written
notice to the other Parties. No such notice of termination shall be permitted
to be submitted to any Party until at least six (6) Months after the Effective
Date of this Agreement.
(b) Notwithstanding the provisions of Sections 3.2 and 18.3, any Party may
exercise its right to terminate pursuant to this Section 18.2. If any Party
exercises its right to terminate under this Section 18.2, the Parties agree to
use their reasonable best efforts to negotiate a mutually acceptable amendment
to this Agreement (to the extent necessary to recognize and accommodate the
interrelated nature of the Parties' transmission systems and control area
functions within the state of Georgia). If the Parties have failed to
successfully negotiate an amended Agreement prior to the
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end of two (2) months after notice of termination is provided under Section
18.2(a), Oglethorpe Power or GSOC may request that Georgia Power file a proposed
amendment to this Agreement to become effective as soon as possible, but in no
event earlier than six (6) months following such notice of termination;
provided, however, that Oglethorpe Power or GSOC must fully disclose to Georgia
Power at the time of such request all terms and conditions relevant to the
services provided under this Agreement of any separate coordination or operating
arrangement between Oglethorpe Power, GSOC and any third party, in order to
allow Georgia Power to prepare a proposed amendment which it believes is
necessary or appropriate, in recognition of and to accommodate the interrelated
nature of the Parties' transmission systems and control area functions in the
state of Georgia. Georgia Power shall not disclose to third parties the terms
and conditions of such separate coordination or operating arrangement; provided,
however, that Georgia Power may provide such information to the FERC to the
extent necessary to support its filing. Georgia Power shall, on or before the
later of 150 days following any Party's notice of termination under Section
18.2(a) or 90 days following Oglethorpe Power's or GSOC's request under this
Section 18.2(b), file a proposed amendment to this Agreement, to become
effective as soon as possible, but in no event earlier than six (6) months
following any notice of termination under Section 18.2(a), which it believes is
necessary or appropriate in recognition of and to accommodate the interrelated
nature of the Parties' transmission systems and control area functions within
the state of Georgia. Following Georgia Power's filing, Oglethorpe Power and
GSOC shall have the right to challenge Georgia Power's proposed amendment in
accordance with FERC regulations and shall have the right to request, pursuant
to FERC regulations, that the FERC either accept an alternative proposed
amendment or determine that this Agreement is no longer necessary or
appropriate.
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If Oglethorpe Power or GSOC has requested that Georgia Power file an
amendment to this Agreement to recognize a separate third-party coordination or
operating arrangement, and if, at the end of six months following a notice of
termination pursuant to Section 18.2(a), the FERC has not issued an order on
Georgia Power's filing or Oglethorpe Power has not received the necessary
regulatory approvals, if any, for the separate third-party coordination or
operating arrangement disclosed to Georgia Power in conjunction with the above
request, this Agreement shall remain in effect until (i) Georgia Power's
proposed amendment is accepted for filing and otherwise permitted to take
effect, or (ii) Oglethorpe Power receives any necessary regulatory approvals in
connection with and implements its third-party arrangement, whichever is later.
Upon the later of (i) or (ii), the Parties agree to adhere to the terms of any
notice of filing or interim FERC order until the FERC issues a final order
either establishing the terms and conditions of an amendment to this Agreement
or determining that a successor arrangement between Georgia Power and Oglethorpe
Power is not necessary or appropriate. Once such final order is issued, any
amounts collected from Oglethorpe Power pursuant to this Section 18.2 on and
after the effective date of Georgia Power's filing under this Section shall be
subject to adjustment in accordance with the terms of such final FERC order.
If Oglethorpe Power or GSOC has not requested that Georgia Power file an
amendment to this Agreement to recognize a separate third-party coordination or
operating arrangement, and if, at the end of six months following a notice of
termination under Section 18.2(a), the FERC has not issued an order on Georgia
Power's filing, this Agreement shall remain in effect until the FERC issues an
order accepting Georgia Power's filing and otherwise permitting it to take
effect. The Parties agree to adhere to the terms of any notice of filing or
interim FERC order until the FERC issues a final order either establishing the
terms and conditions of an amendment to this Agreement or determining that a
successor arrangement between Georgia Power and Oglethorpe Power is not
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necessary or appropriate. Once such final order is issued, any amounts
collected from Oglethorpe Power pursuant to this Section 18.2 on and after the
effective date of Georgia Power's filing under this Section shall be subject to
adjustment in accordance with the terms of such final FERC order. For purposes
of this Article, a "final FERC order" shall mean a FERC order which is no longer
subject to rehearing under the FERC's Rules of Practice and Procedure.
18.3 FERC Changes; Rights to Terminate. (a) Subject to the provisions of
this Section 18.3, either Georgia Power, Oglethorpe Power or GSOC may terminate
this Agreement, upon ninety (90) Days written notice to the other Party,
following the issuance of a final FERC order (i) rejecting this Agreement, (ii)
approving the same in a modified form where a material condition imposed by the
FERC is unacceptable to one or more Parties, or otherwise (iii) requiring
modification of this Agreement after it becomes effective, where a material
condition imposed by the FERC is unacceptable to one or more Parties; provided,
however, that no Party shall exercise such right to terminate after ninety (90)
Days following the expiration of all periods within which an appeal of such an
order could be filed by any person or entity.
(b) Notwithstanding the provisions of Section 3.2 and 18.2, any Party may
exercise its right to terminate this Agreement pursuant to Section 18.3(a). If
any Party exercises its right to terminate under Section 18.3(a), the Parties
agree to use their reasonable best efforts to negotiate a mutually acceptable
successor arrangement to this Agreement (to the extent necessary to recognize
and accommodate the interrelated nature of the Parties' transmission systems and
control area functions within the state of Georgia); provided, however, that
Georgia Power may, at any time during such negotiations, unilaterally file at
the FERC a notice of termination, effective no earlier than 90 Days following
the above notice, and a proposed successor arrangement with Oglethorpe Power to
the extent Georgia Power reasonably believes that the Parties will fail to reach
an
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agreement on a successor arrangement prior to the end of ninety (90) Days after
notification of termination under this Section 18.3. Oglethorpe Power shall
have the right to challenge Georgia Power's proposed successor arrangement in
accordance with FERC regulations, shall have the right to request, pursuant to
FERC regulations, that the FERC accept an alternative arrangement between
Georgia Power and Oglethorpe Power, and shall have the right to enter into a
separate arrangement with any other party. However, any election by Oglethorpe
Power to enter into an arrangement with a third party shall not affect Georgia
Power's right to file a proposed successor agreement with Oglethorpe Power which
Georgia Power believes is necessary or appropriate in recognition of and to
accommodate the interrelated nature of the Parties' transmission systems and
control area functions within the state of Georgia. If the FERC has issued an
order as described in Section 18.3(a)(ii) or Section 18.3(a)(iii), and has not
issued a final order either (i) establishing the terms and conditions of a
successor arrangement between Georgia Power and Oglethorpe Power or (ii)
determining that a successor arrangement between Georgia Power and Oglethorpe
Power is not necessary or appropriate before the end of ninety (90) Days after
any Party's notification of termination to the other Parties, this Agreement
shall remain in effect until such order is issued. If the FERC issues an order
as described in Section 18.3(a)(i) prior to allowing this Agreement to go into
effect, the Coordination Services Agreement dated November 12, 1990 shall remain
in effect until a successor arrangement is filed and put into effect in
accordance with Section 18.1. If the FERC issues an order as described in
Section 18.3(a)(i) after allowing this Agreement to go into effect, the Parties
shall operate pursuant to whatever arrangement or agreement the FERC determines
is appropriate until a successor arrangement is filed and put into effect in
accordance with this Section 18.3. Any amounts collected from Oglethorpe Power
pursuant to this Section 18.3 shall be subject to adjustment in accordance with
the terms of a final FERC order accepting Georgia Power's
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notice of termination and either (i) establishing the terms and conditions of a
successor arrangement between Georgia Power and Oglethorpe Power or (ii)
determining that a successor arrangement between Georgia Power and Oglethorpe
Power is not necessary or appropriate.
ARTICLE XIX
MISCELLANEOUS PROVISIONS
19.1 Approvals. (a) Oglethorpe Power, GSOC and Georgia Power commit to
use their best efforts to apply for promptly and to pursue diligently any
regulatory approvals necessary for the Parties to consummate transactions under
and otherwise comply fully with the terms of this Agreement. Oglethorpe Power
and GSOC represent that approval by the Rural Utilities Service (or its
successor) is not required in order for Oglethorpe Power and GSOC to execute and
implement this Agreement. This Section 19.1 is not intended to subject this
Agreement to the jurisdiction of any governmental authority that does not have
such jurisdiction over this Agreement at the time of execution of this
Agreement.
(b) It is further agreed that Georgia Power, Oglethorpe Power and GSOC
will actively support and defend this Agreement against any and all claims which
may prevent or delay the consummation of transactions under this Agreement, or
otherwise prevent the Parties from complying fully with the terms of this
Agreement, including any and all claims raised by any governmental authority.
19.2 Assignment. (a) Except to the extent provided in Section 19.2(b), (c)
and (d), neither Oglethorpe Power, GSOC nor Georgia Power may sell, assign or
otherwise transfer any or all of this Agreement or its respective rights, or
delegate any or all of its respective obligations, under this Agreement, at any
time, without the prior written consent of the other in each instance; provided,
however, that Georgia Power may assign this Agreement and its respective rights,
and delegate its
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respective obligations, under this Agreement to a generation Affiliate
succeeding to substantially all of Georgia Power's interests in substantially
all of Georgia Power's intermediate steam and combustion turbine generating
facilities, without the consent of Oglethorpe Power and GSOC.
(b) Notwithstanding the provisions of Section 19.2(a), Georgia Power
acknowledges that it is aware of that certain Indenture dated as of March 1,
1997, from Oglethorpe Power to SunTrust Bank, Atlanta, as trustee (together with
any successors or assigns in the trust created thereby, the "Trustee") as the
same may hereafter be supplemented (the "Indenture"), and hereby consents to the
conveyance by Oglethorpe Power to the Trustee, of a security interest in this
Agreement as security for obligations of Oglethorpe Power issued or to be issued
pursuant to the Indenture; provided, however, that in no event shall the Trustee
convey or assign any interest in this Agreement to any other person or entity
without the prior written consent of Georgia Power in each instance. As a
consequence of the restrictions on assignability and conveyance under this
Section, the Trustee, shall have no right to sell or otherwise dispose of any
interest in this Agreement upon any Event of Default by Oglethorpe Power, as
defined in the Indenture, without the prior written consent of Georgia Power.
Georgia Power hereby agrees to accept any funds paid to it under this Agreement
on behalf of Oglethorpe Power by any entity as though such funds were paid
directly by Oglethorpe Power.
(c) Notwithstanding the provisions of Section 19.2(a), actions identified
herein as being accomplished by Georgia Power may be accomplished either by
Georgia Power or by its agent(s), and actions identified herein as being
accomplished by Oglethorpe Power may be accomplished either by Oglethorpe Power
or its agent(s); provided, however, that the Parties shall assume full and
primary responsibility for all actions undertaken by their agents.
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(d) Notwithstanding the provisions of Section 19.2(a), the use of GSOC's
and GTC's employees to carry out Oglethorpe Power's obligations under this
Agreement, and the transfer to GTC and GSOC (as well as the ownership by GTC and
GSOC) of equipment necessary for Oglethorpe Power to carry out its obligations
under this Agreement, shall not constitute a violation by Oglethorpe Power of
the terms of this Agreement. Georgia Power hereby consents to Oglethorpe
Power's assignment of those rights, and delegation of those obligations, under
the CSA to GSOC as are necessary to perform the system operations services
contemplated by Oglethorpe Power's restructuring documents provided to Georgia
Power (as supplemented) commencing upon the effective date of such
restructuring; provided however, that such assignment and delegation shall not
expand or diminish the rights and obligations of Oglethorpe Power under this
Agreement.
19.3 Georgia Power's Agent. Wherever this Agreement requires Oglethorpe
Power or GSOC to provide information, schedules, notice or the like to, or to
take direction from, Georgia Power or its agent, Oglethorpe Power and GSOC shall
provide such information, schedules, notice or the like to, or take direction
from, whichever of Georgia Power, its agent or both that Georgia Power may
direct from time to time.
19.4 Cooperation. Georgia Power, Oglethorpe Power and GSOC agree to
cooperate with each other as reasonably necessary or appropriate to implement
the provisions and carry out the intent of this Agreement.
19.5 No Partnership. Oglethorpe Power, GSOC and Georgia Power do not
intend for this Agreement to, and this Agreement shall not, create any joint
venture, partnership, association taxable as a corporation, or other entity for
the conduct of any business for profit.
19.6 Successors and Assigns. This Agreement shall inure to the benefit of
and be binding upon any respective successors and assigns of Oglethorpe Power,
GSOC and Georgia Power.
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19.7 No Third Party Benefit. Subject to the provisions of Section 19.2,
nothing in this Agreement shall be construed to create any duty, obligation or
liability of Georgia Power to any person or entity not a Party to this
Agreement. Subject to the provisions of Section 19.2, nothing in this Agreement
shall be construed to create any direct rights to or in favor of any person or
entity not a Party to this Agreement.
19.8 No Consequential Damages. (a) Notwithstanding any other provision of
this Agreement, Georgia Power shall not be liable to Oglethorpe Power or GSOC
for any indirect, incidental or consequential damages arising out of, due to, or
in connection with Georgia Power's performance or nonperformance of this
Agreement or any of its obligations herein, whether based on contract, tort
(including, without limitation, negligence), strict liability, warranty or
otherwise.
(b) Notwithstanding any other provision of this Agreement, Oglethorpe
Power and GSOC shall not be liable to Georgia Power for any indirect, incidental
or consequential damages arising out of, due to, or in connection with
Oglethorpe Power's and GSOC's performance or nonperformance of this Agreement or
any of their obligations herein, whether based on contract, tort (including,
without limitation, negligence), strict liability, warranty or otherwise;
provided; however, that nothing in this Section 19.8 shall limit or otherwise
affect Georgia Power's rights under Sections 8.7, 13.5 and 17.4.
19.9 No Affiliate Liability. Notwithstanding any other provision of this
Agreement, no Affiliate of Georgia Power (including without limitation any
Affiliate of Georgia Power acting as Georgia Power's agent where Georgia Power's
agent is given certain authorities hereunder) shall have any liability
whatsoever for any Party's performance, nonperformance or delay in performance
under this Agreement. Georgia Power may be liable for its Affiliates' actions,
failures to act, representations or omissions, in accordance with Article I.
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19.10 Disclaimers of Warranty. (a) GEORGIA POWER, ON BEHALF OF ITSELF,
EACH OF ITS AFFILIATES AND EACH OF THEIR RESPECTIVE EMPLOYEES, OFFICERS,
DIRECTORS, AGENTS, SUCCESSORS AND ASSIGNS, HEREBY DISCLAIMS ANY AND ALL EXPRESS,
IMPLIED OR STATUTORY WARRANTIES CONCERNING ANY OR ALL OF THE SERVICES OR ENERGY
(OR CAPACITY) TO BE SOLD BY GEORGIA POWER HEREUNDER OR CONCERNING ANY
INFORMATION FURNISHED BY GEORGIA POWER HEREUNDER, INCLUDING WITHOUT LIMITATION
ANY AND ALL WARRANTIES AS TO MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE,
AVAILABILITY, QUALITY, QUANTITY OR OTHERWISE.
(b) OGLETHORPE POWER, ON BEHALF OF ITSELF, EACH OF ITS AFFILIATES AND EACH
OF THEIR RESPECTIVE EMPLOYEES, OFFICERS, DIRECTORS, AGENTS, SUCCESSORS AND
ASSIGNS, HEREBY DISCLAIMS ANY AND ALL EXPRESS, IMPLIED OR STATUTORY WARRANTIES
CONCERNING ANY OR ALL OF THE SERVICES OR ENERGY (OR CAPACITY) TO BE SOLD BY
OGLETHORPE POWER HEREUNDER OR CONCERNING ANY INFORMATION FURNISHED BY OGLETHORPE
POWER HEREUNDER, INCLUDING WITHOUT LIMITATION ANY AND ALL WARRANTIES AS TO
MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, AVAILABILITY, QUALITY,
QUANTITY OR OTHERWISE; PROVIDED, HOWEVER, THAT THIS SECTION 19.10(b) SHALL NOT
EXTINGUISH OR IN ANY WAY AFFECT OGLETHORPE POWER'S OBLIGATION TO INDEMNIFY
GEORGIA POWER UNDER SECTION 13.5(c).
19.11 Supply Constancy. Notwithstanding any other provision of this
Agreement, Georgia Power does not guarantee or warrant that it shall provide an
uninterrupted supply of capacity or energy to Oglethorpe Power under this
Agreement. Georgia Power shall not be in breach of this
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Agreement by reason of, and shall have no liability whatsoever to Oglethorpe
Power for any failure to supply capacity or energy under this Agreement, for any
interruption in supply under this Agreement, or for any deficiency in the
quality of supply provided under this Agreement; provided however, that the
foregoing exculpatory clause shall not apply to any failure that is the direct
result of (i) any action of Georgia Power which is not consistent with Prudent
Utility Practice or (ii) Georgia Power's willful misconduct.
19.12 Time of Essence; No Waiver. Time is of the essence in this
Agreement. Neither Georgia Power's, Oglethorpe Power's nor GSOC's failure to
enforce any provision or provisions of this Agreement shall in any way be
construed as a waiver of any such provision or provisions as to any future
violation thereof, nor prevent it from enforcing each and every other provision
of this Agreement at such time or at any time thereafter. The waiver by either
Georgia Power, Oglethorpe Power or GSOC of any right or remedy shall not
constitute a waiver of its right to assert said right or remedy, at any time
thereafter, or any other rights or remedies available to it at the time of or
any time after such waiver.
19.13 Amendments. Except as otherwise provided in this Agreement, the
Parties agree that this Agreement may be amended by and only by a written
instrument duly executed by each of Oglethorpe Power, GSOC and Georgia Power,
which has received all regulatory approvals necessary for the effectiveness
thereof.
19.14 Superseding Effect. This Agreement satisfies in full the
Memorandum of Understanding between the Parties dated March 6, 1997, and
supersedes in their entirety both the Memorandum of Understanding and the CSA.
19.15 Notice. Any notice, request, consent or other communication
permitted or required by this Agreement shall be in writing and shall be deemed
given on the Day hand-delivered to the
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officer identified below, or the third (3rd) Day after the same is deposited in
the United States Mail, first class postage prepaid, and if given to Georgia
Power shall be addressed to:
Georgia Power Company
c/o Southern Company Services
333 Piedmont Avenue, N.E.
Atlanta, Georgia 30308
Attention: Senior Vice President
Southern Wholesale Energy
If given to Oglethorpe Power shall be addressed to:
Oglethorpe Power Corporation
2100 East Exchange Place
P.O. Box 1349
Tucker, Georgia 30085-1349
Attention: Senior Vice President - Power Supply
If given to GSOC shall be addressed to:
Georgia System Operations Corporation
2100 East Exchange Place
P.O. Box 2087
Tucker, Georgia 30085-2087
Attention: Chief Operating Officer
unless Georgia Power, Oglethorpe Power or GSOC shall have designated a different
officer or address for itself by notice to the other Parties.
19.16 Counterparts. This Agreement may be executed in two or more
counterparts, each of which shall be deemed an original but all of which
together shall constitute one and the same instrument.
19.17 Article and Section Headings. The descriptive headings of the
various Articles, Sections and Parts of this Agreement and the Exhibits hereto
have been inserted for convenience of reference only and shall in no way modify
or restrict any of the terms or provisions hereof.
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19.18 Including. Wherever the term "including" is used in this
Agreement, such term shall not be construed as limiting the generality of any
statement, clause, phrase or term.
19.19 Governing Law. The validity, interpretation and performance of
this Agreement and each of its provisions shall be governed by the laws of the
State of Georgia.
19.20 Section 206 Rights. Unless otherwise provided in this Agreement,
Oglethorpe Power shall retain any and all rights it may have under Section 206
of the Federal Power Act.
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IN WITNESS WHEREOF, the undersigned parties hereto have duly executed this
Agreement under seal in Atlanta, Georgia, as of the date set forth in the
introductory paragraph hereof.
GEORGIA POWER COMPANY
ATTEST:
/s/ Cherry C. Hudgins By: /s/ Fred D. Williams
- ----------------------------- ----------------------
Name: Cherry C. Hudgins Fred D. Williams
Title: Assistant Corporate Secretary Senior Vice President
Georgia Power Company
(CORPORATE SEAL)
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IN WITNESS WHEREOF, the undersigned parties hereto have duly executed this
Agreement under seal in Atlanta, Georgia, as of the date set forth in the
introductory paragraph hereof.
OGLETHORPE POWER
CORPORATION (AN ELECTRIC
MEMBERSHIP CORPORATION)
ATTEST:
/s/ Patricia N. Nash By: /s/ Clarence D. Mitchell
- ---------------------------- --------------------------
Name: Patricia N. Nash Clarence D. Mitchell
Title: Secretary Senior Vice President
Power Supply
(CORPORATE SEAL)
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IN WITNESS WHEREOF, the undersigned parties hereto have duly executed this
Agreement under seal in Atlanta, Georgia, as of the date set forth in the
introductory paragraph hereof.
GEORGIA SYSTEM OPERATIONS
CORPORATION
ATTEST:
/s/ Patricia N. Nash By: /s/ Jerry J. Saacks
- ---------------------------- ----------------------------
Name: Patricia N. Nash Jerry J. Saacks
Title: Assistant Secretary Chief Operating Officer
(CORPORATE SEAL)
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Exhibit A
Member Systems:
Oglethorpe Power Corporation
Georgia Transmission Corporation
Georgia System Operations Corporation
Altamaha EMC
Amicalola EMC
Canoochee EMC
Carroll EMC
Central Georgia EMC
Coastal EMC
Cobb EMC
Colquitt EMC
Coweta-Fayette EMC
Excelsior EMC
Flint EMC
Grady EMC
Greystone Power Corp.
Habersham EMC
Hart EMC
Irwin EMC
Jackson EMC
Jefferson EMC
Lamar EMC
Little Ocmulgee EMC
Middle Georgia EMC
Mitchell EMC
Ocmulgee EMC
Oconee EMC
Okefenoke Rural EMC
Pataula EMC
Planters EMC
Rayle EMC
Satilla Rural EMC
Sawnee EMC
Slash Pine EMC
Snapping Shoals EMC
Sumter EMC
Three Notch EMC
Tri-County EMC
Troup EMC
Upson County EMC
Walton EMC
Washington EMC
<PAGE>
Exhibit B
Commitment Cost Rate
(a) On Friday of each week of the Term of this Agreement and at other
times Georgia Power or its agent deems appropriate, Georgia Power or its agent
shall perform unit commitment studies for units under Southern Dispatch for
three scenarios extending for a minimum of seven (7) Days. The base case will
include all projected Southern Company system load as well as all off-system
transactions proposed by the customers and by Southern Companies. The two
additional cases will include all items from the base case plus a 400 MW load
increase for all Hours in one case and a 400 MW load decrease in all Hours of
the other case. Georgia Power or its agent may use reasonable allocations and
approximations in performing these studies. For each change case, the
commitment cost will be determined as the difference in the total production
cost, including start-up costs, between the change case and the base case over
the seven (7) succeeding Days less the cost of the 400 MW load increase, or
decrease, based on the average of the marginal cost of the respective change
case and the base case. If the marginal cost of the 400 MW load exceeds the
difference in production cost for either case, the commitment cost for that
change case will be deemed to be zero (0). The resulting commitment cost, if
any, for the two change cases will be added and this total will be divided by
800 MW and divided by seven (7) days to determine the Commitment Cost Rate. If
the Commitment Cost Rate exceeds the Maximum Commitment Cost Rate determined
pursuant to paragraph (b) below, the Commitment Cost Rate shall be deemed to be
the Maximum Commitment Cost Rate. If the Commitment Cost Rate is less than the
Minimum Commitment Cost Rate determined pursuant to paragraph (b) below, the
Commitment Cost Rate shall be deemed to be the
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Minimum Commitment Cost Rate. If, within the seven (7) Day period used to
determine the Commitment Cost Rate, a revised projection of unit commitment
would result in a change in the Commitment Cost Rate of ten percent (10%) or
more, Georgia Power or its agent will issue a revised Commitment Cost Rate
effective for the remainder of the weekly period or until another adjustment
pursuant to this sentence is warranted.
(b) The Maximum Commitment Cost Rate shall be $90/megawatt-Day and the
Minimum Commitment Cost Rate shall be $10/megawatt-Day; provided, however, that
if either the Maximum Commitment Cost Rate or the Minimum Commitment Cost Rate
is utilized for more than ten percent (10%) of the weekly calculations described
in paragraph (a) within a single Year, upon written request by any Party to the
other Parties, the Parties will discuss adjustments to the Maximum Commitment
Cost Rate and the Minimum Commitment Cost Rate.
2
<PAGE>
Exhibit C
Regulation Energy Variance Rates
The following table of rates shall be applicable from the Effective Date
until the earlier of December 31, 1997 or the issuance of a "final order" on the
Open Access Transmission Tariff of Southern Companies (Docket No. OA96-27-000).
On each succeeding January 1 and on each date FERC permits a change to the
charge for Regulation and Frequency Response Service contained in the Open
Access Transmission Tariff of Southern Companies, the rates shall be adjusted,
in accordance with the procedure described herein.
<TABLE>
<CAPTION>
-----------------------------------------------
Equivalent Occurrences Rate ($/MWH)
-----------------------------------------------
<S> <C>
1 - 200 $ 15
-----------------------------------------------
201 - 600 $ 25
-----------------------------------------------
601 -1200 $ 45
-----------------------------------------------
1201 or more $ 70
-----------------------------------------------
</TABLE>
For each adjustment period, the rates above shall be adjusted by the ratio
(expressed to six (6) decimal places) of:
(a) the amount, rounded to the nearest whole dollar value, determined by
(i) the portion of the charge for Regulation and Frequency Response
Service in the then current Open Access Transmission Tariff of
Southern Companies associated with heat rate degradation, expressed in
dollars per kilowatt year to six (6) decimal places ($1.091468 as of
August 1, 1997), multiplied by (ii) the OPC Territorial Load
coincident with the most recent calendar year twelve (12) monthly peak
loads in the Southern Control Area, rounded to the nearest one
thousand kilowatts
Exhibit C page 1 of 2
<PAGE>
(3,832,000 kW based on 1996 loads at Level B-1), divided by (iii)
Oglethorpe Power's L10, based on the maximum OPC Territorial Load for
the most recent calendar year, rounded to the nearest whole megawatt
(51 MW based on a 1996 peak load of 5249 MW at Level B-1),
divided by
(b) $82,010 (the calculation resulting from the values noted in (a)
above), and then rounded to the nearest whole dollar per megawatt hour
($/MWH).
Equivalent Occurrences during any given Month shall equal the sum of the
number of Hours in which Oglethorpe Power incurred a charge for Regulation
Energy Variance in the preceding 365 Days that Oglethorpe Power did not
purchase short term Regulation Service.
The Parties may agree to alter the ratios of cost and the durations of
hourly occurrences associated with each rate level by mutual agreement for
any agreed adjustment period (as described above), provided however, that
such agreement does not bind the Parties to apply the revised ratios or the
hourly occurrence levels to any subsequent period.
Exhibit C page 2 of 2
<PAGE>
Exhibit D
Regulation and Spinning Reserve Requirements Rates
The following table of rates shall be applicable from the Effective Date
until the earlier of December 31, 1997, or the issuance of a "final order" on
the Open Access Transmission Tariff of Southern Companies (Docket No.
OA96-27-000). On each succeeding January 1 and on each date FERC permits a
change to the charge for Regulation and Frequency Response Service or
Operating Reserve - Spinning Reserve Service contained in the Open Access
Transmission Tariff of Southern Companies, the rates shall be adjusted, in
accordance with the procedure described herein.
<TABLE>
<CAPTION>
-----------------------------------------------
Rate ($/MWH)
-----------------------------------------------
<S> <C>
Off-Peak Hours $ 45
-----------------------------------------------
Critical Hours $ 446
-----------------------------------------------
On-Peak Hours
Equivalent Occurrences
-----------------------------------------------
1 - 40 $ 45
-----------------------------------------------
41 - 110 $ 135
-----------------------------------------------
111 - 200 $ 260
-----------------------------------------------
201 or more $ 446
-----------------------------------------------
</TABLE>
For each adjustment period, the rates above shall be adjusted by the ratio
(expressed to six (6) decimal places) of:
(a) the amount, rounded to the nearest whole dollar value, determined by
(i) the portion of the charge for Regulation and Frequency Response
Service in the then current Open Access Transmission Tariff of
Southern Companies not associated with heat
Exhibit D page 1 of 3
<PAGE>
rate degradation, expressed in dollars per kilowatt year to six (6)
decimal places ($1.506741 as of August 1, 1997) multiplied by the OPC
Territorial Load coincident with the most recent calendar year twelve
(12) monthly peak loads in the Southern Control Area, rounded to the
nearest one thousand kilowatts (3,832,000 kW based on 1996 loads at
Level B-1), plus (ii) the charge for Operating Reserve - Spinning
Reserve Service in the then current Open Access Transmission Tariff of
Southern Companies expressed in dollars per kilowatt year to six (6)
decimal places ($1.800079 as of August 1, 1997) multiplied by the OPC
Territorial Load coincident with the 1996 twelve (12) monthly peak
loads in the Southern Control Area, rounded to the nearest one
thousand kilowatts (3,832,000 kW based on 1996 loads at Level B-1),
all divided by (iii) Oglethorpe Power's Regulation Requirement,
rounded to the nearest whole megawatt (80 MW based on 1996 loads of
3,832 MW at Level B-1) plus Oglethorpe Power's Spinning Reserve
Requirement, rounded to the nearest whole megawatt (80 MW based on
1996 loads of 3,832 MW at Level B-1),
divided by
(b) $79,198 (the calculation resulting from the values noted in (a)
above), and then rounded to the nearest whole dollar per megawatt hour
($/MWH).
Equivalent Occurrences during any given Month shall equal the sum (with any
resulting fraction being truncated) of the number of Hours in which
Oglethorpe Power incurred a charge for Regulation and Spinning Reserve
Requirements in the preceding 365 Days that Oglethorpe Power did not
purchase short term Spinning Reserve Service, accumulated in the
Exhibit D page 2 of 3
<PAGE>
following manner: (i) Off-Peak Hours divided by 4.5, plus (ii) On-Peak
Hours, plus (iii) Critical Hours.
Critical Hours are the Hours in which the Southern Control Area operator
has declared, for other than economic reasons or transmission constraints,
that (a) an Alert Level 3 or 4 condition exists or (b) an Alert Level 2
condition exists and the Control Area operator has called for (i) operation
of any resource at valves wide open or over pressure, (ii) operation of
non-company owned standby generation, (iii) interruption of any contract
interruptible load, or (iv) curtailment of any off-system transaction for
other than economic reasons or transmission constraints. The Oglethorpe
Power system operator shall be notified at the time the Southern Control
Area operator implements an event which results in a Critical Hour.
On-Peak Hours are the Hours defined as on-peak in NERC's Inadvertent
Interchange Energy Accounting Practices, which are not Critical Hours.
Off-Peak Hours are the Hours defined as off-peak in NERC's Inadvertent
Interchange Energy Accounting Practices, which are not Critical Hours.
The Parties may agree to alter the ratios of cost and the durations of
hourly occurrences associated with each rate level by mutual agreement for
any agreed adjustment period (as described above), provided however, that
such agreement does not bind the Parties to apply the revised ratios or the
hourly occurrence levels to any subsequent period.
Exhibit D page 3 of 3
<PAGE>
Exhibit E
Supplemental Reserve Requirement Rates
The following table of rates shall be applicable from the Effective Date until
the issuance of a "final order" on the Open Access Transmission Tariff of
Southern Companies (Docket No. OA96-27-000). On each date FERC permits a change
to the charge for Operating Reserve - Supplemental Reserve Service contained in
the Open Access Transmission Tariff of Southern Companies, the rates shall be
adjusted, in accordance with the procedure described herein.
<TABLE>
<CAPTION>
-----------------------------------------------
Rate ($/MWH)
-----------------------------------------------
<S> <C>
Off-Peak Hours $ 35
-----------------------------------------------
Critical Hours $286
-----------------------------------------------
On-Peak Hours
Equivalent Occurrences
-----------------------------------------------
1- 40 $ 35
-----------------------------------------------
41-110 $ 85
-----------------------------------------------
111-200 $170
-----------------------------------------------
201 or more $286
-----------------------------------------------
</TABLE>
For each adjustment period, the rates above shall be adjusted by the ratio
(expressed to six (6) decimal places) of:
(a) the amount, rounded to the nearest whole dollar value, determined by
(i) the charge for Operating Reserve -Supplemental Reserve Service in
the then current Open Access Transmission Tariff of Southern Companies
expressed in dollars per kilowatt year to six (6) decimal places
($1.070156 as of August 1, 1997) multiplied by the OPC Territorial
Load coincident with the 1996 twelve (12) monthly peak loads in the
Exhibit E page 1 of 3
<PAGE>
Southern Control Area, rounded to the nearest one thousand kilowatts
(3,832,000 kW based on 1996 loads at Level B-1), divided by (ii)
Oglethorpe Power's Supplemental Reserve Requirement, rounded to the
nearest whole megawatt (80 MW based on 1996 loads of 3,832 MW at
Level B-1),
divided by
(b) $51,260 (the calculation resulting from the values noted in (a)
above), and then rounded to the nearest whole dollar per megawatt hour
($/MWH).
Equivalent Occurrences during any given Month shall equal the sum (with any
resulting fraction being truncated) of the number of Hours in which
Oglethorpe Power incurred a charge for Supplemental Reserve Requirements in
the preceding 365 Days that Oglethorpe Power did not purchase short term
Supplemental Reserve Service, accumulated in the following manner: (i)
Off-Peak Hours divided by 4.5, plus (ii) On-Peak Hours, plus (iii) Critical
Hours.
Critical Hours are the Hours in which the Southern Control Area operator
has declared, for other than economic reasons or transmission constraints,
that (a) an Alert Level 3 or 4 condition exists or (b) an Alert Level 2
condition exists and the Control Area operator has called for (i) operation
of any resource at valves wide open or over pressure, (ii) operation of
non-company owned standby generation, (iii) interruption of any contract
interruptible load, or (iv) curtailment of any off-system transaction for
other than economic reasons or
Exhibit E page 2 of 3
<PAGE>
transmission constraints. The Oglethorpe Power system operator shall be
notified at the time the Southern Control Area operator implements an event
which results in a Critical Hour.
On-Peak Hours are the Hours defined as on-peak in NERC's Inadvertent
Interchange Energy Accounting Practices, which are not Critical Hours.
Off-Peak Hours are the Hours defined as off-peak in NERC's Inadvertent
Interchange Energy Accounting Practices, which are not Critical Hours.
The Parties may agree to alter the ratios of cost and the durations of
hourly occurrences associated with each rate level by mutual agreement for
any agreed adjustment period (as described above), provided however, that
such agreement does not bind the Parties to apply the revised ratios or the
hourly occurrence levels to any subsequent period.
Exhibit E page 3 of 3
<PAGE>
Exhibit F
Short Term Control Area Services Rates
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------
<S> <C> <C>
Short Term 30 Days 120 Days
Control Area minimum duration minimum duration
Services
- -------------------------------------------------------------------------------------
Regulation Service $667 per MW per Day times $333 per MW per Day
current L10 times current L10
- -------------------------------------------------------------------------------------
Spinning Reserve $1000 per MW per Day $500 per MW per Day
Service times current Regulation and times current Regulation and
Spinning Reserve Requirement Spinning Reserve Requirement
- -------------------------------------------------------------------------------------
Supplemental $667 per MW per Day $333 per MW per Day
Reserve Service times current Supplemental times current Supplemental
Reserve Requirement Reserve Requirement
- -------------------------------------------------------------------------------------
</TABLE>
The above rate table is applicable through December 31, 1998. On or before
October 1 of each Year of the Term after 1997, Georgia Power will update the
above rate table, by written notice to Oglethorpe Power, to become effective the
following January 1 of each Year of the Term. If any Party provides notice of
termination, in accordance with the terms of this Agreement, prior to December 1
of any Year of the Term, the then effective rate schedule for Short Term Control
Area Services shall remain effective until the earlier of (i) initialization of
Territorial Control Area Services purchases at the rates in the Open Access
Transmission Tariff of Southern Companies in accordance with the terms of this
Agreement or (ii) a Georgia Power proposed amendment to this Agreement is
accepted for filing and otherwise permitted to take effect by the FERC.
Exhibit F page 1 of 1
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from
Oglethorpe Power Corporation's balance sheet as of December 31, 1997
and related statements of revenues and expenses and cash flows for
the period ended December 31, 1997 and is qualified in its entirety
by reference to such financial statements.
</LEGEND>
<MULTIPLIER> 1,000
<CURRENCY> U.S.DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<EXCHANGE-RATE> 1
<BOOK-VALUE> PER-BOOK<F1>
<TOTAL-NET-UTILITY-PLANT> 3,601,782
<OTHER-PROPERTY-AND-INVEST> 211,734
<TOTAL-CURRENT-ASSETS> 344,287
<TOTAL-DEFERRED-CHARGES> 352,054
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,509,857
<COMMON> 0
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 330,509
<TOTAL-COMMON-STOCKHOLDERS-EQ> 0
0
0
<LONG-TERM-DEBT-NET> 3,258,046
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 83,121
0
<CAPITAL-LEASE-OBLIGATIONS> 288,638
<LEASES-CURRENT> 6,435
<OTHER-ITEMS-CAPITAL-AND-LIAB> 543,108
<TOT-CAPITALIZATION-AND-LIAB> 4,509,857
<GROSS-OPERATING-REVENUE> 1,047,852
<INCOME-TAX-EXPENSE> 0
<OTHER-OPERATING-EXPENSES> 788,177
<TOTAL-OPERATING-EXPENSES> 788,177
<OPERATING-INCOME-LOSS> 259,675
<OTHER-INCOME-NET> 46,646
<INCOME-BEFORE-INTEREST-EXPEN> 306,321
<TOTAL-INTEREST-EXPENSE> 283,916
<NET-INCOME> 22,405
0
<EARNINGS-AVAILABLE-FOR-COMM> 0
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 41,688
<CASH-FLOW-OPERATIONS> 242,123
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1>$ 330,509 represents total retained patronage capital.
The registrant is a membership corporation and has no
authorized or outstanding equity securities.
</FN>
</TABLE>
