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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
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Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes _X_ No___
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ X ]
State the aggregate market value of the voting 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
ITEM PAGE
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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
i
SELECTED DEFINITIONS
When used herein the following terms will have the meanings indicated below:
TERM MEANING
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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
ii
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.
1
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.)
2
Immediately after the Corporate Restructuring, Oglethorpe's corporate name
was changed from "Oglethorpe Power Corporation (An Electric Membership
Generation & Transmission Corporation)" to "Oglethorpe Power Corporation (An
Electric Membership Corporation)" to reflect that it no longer provides
transmission services.
In connection with the Corporate Restructuring, Oglethorpe undertook to
remove the costs of its marketing services business from its general rates and
recover these costs on a fee-for-services basis beginning in 1998. To do so,
Oglethorpe created a subsidiary, EnerVision, to which it has transferred its
marketing services business, which includes 30 full-time and 13 part-time
employees. Further, all or part of this subsidiary may be sold to third parties.
Oglethorpe does not expect any of these potential actions to have a material
effect on its financial condition or results of operations.
POWER SUPPLY BUSINESS
Oglethorpe provides wholesale electric service to the 39 Members pursuant to
long-term, take-or-pay Wholesale Power Contracts described herein that obligate
the Members on a 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
5
December 31 of the applicable year and refunded to the Members during the period
April through December of the following year. The rate schedule formula is
intended to provide 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
6
regulatory environment and, accordingly, provide for GTC to serve on a
nondiscriminatory basis both member and non-member customers on terms intended
to meet FERC's reciprocity requirement. For information regarding a FERC filing
relating to GTC and Oglethorpe, see "LEGAL PROCEEDINGS" in Item 3.
GTC owns approximately 2,400 miles of transmission line and approximately
460 substations of various voltages. In connection with the Corporate
Restructuring, GTC succeeded to Oglethorpe's rights in the ITS, which consists
of transmission facilities owned by GTC, GPC, MEAG and Dalton. Through
agreements, common access to the combined facilities that compose the ITS
enables the owners to use their combined resources to make deliveries to or for
their respective consumers, to provide transmission service to third parties and
to make off-system purchases and sales.
GTC's rights and obligations with respect to the ITS are 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
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.
8
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.
Altamaha EMC Habersham EMC Planters EMC
Amicalola EMC Hart EMC Rayle EMC
Canoochee EMC Irwin EMC Satilla Rural EMC
Carroll EMC Jackson EMC Sawnee EMC
Central Georgia EMC Jefferson EMC Slash Pine EMC
Coastal EMC Lamar EMC Snapping Shoals EMC
Cobb EMC Little Ocmulgee EMC Sumter EMC
Colquitt EMC Middle Georgia EMC Three Notch EMC
Coweta-Fayette EMC Mitchell EMC Tri-County EMC
Excelsior EMC Ocmulgee EMC Troup EMC
Flint EMC Oconee EMC Upson County EMC
Grady EMC Okefenoke Rural EMC Walton EMC
GreyStone Power Pataula EMC Washington EMC
Corporation, an EMC
The Members serve approximately 1.2 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
9
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
10
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.
11
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
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.
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)
----------------- --------------- --------------- ------------- ------------- -----------
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
- ------------------------
(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
13
costs, which do not vary significantly from month to month; therefore, capacity
charges are billed and capacity revenues are recognized in equal monthly
amounts.
POWER MARKETER ARRANGEMENTS
In 1996, Oglethorpe began utilizing power marketer arrangements to reduce
the cost of power to the Members. During 1997, Oglethorpe entered into long-term
power marketer agreements with LEM for approximately 50% of the load
requirements of the Members and with Morgan Stanley with respect to 50% of the
Members' then forecasted load requirements. The LEM agreements are based on the
actual requirements of the Members during the contract term, whereas the Morgan
Stanley agreement represents a fixed supply obligation. Generally, these
arrangements reduce the cost of supplying power to the Members by limiting the
risk of unit availability, by providing a guaranteed benefit for the use of
excess resources and by providing future power needs at a fixed price. All of
Oglethorpe's existing generating facilities and power purchase arrangements are
available for use by LEM and Morgan Stanley for the term of the respective
agreements. Oglethorpe continues to be responsible for all of the costs of its
system resources but receives revenue, as described below, from LEM and Morgan
Stanley for the use of the resources.
LEM AGREEMENTS
Effective January 1, 1997, Oglethorpe entered into power marketer agreements
with LEM for 50% of the load requirements of the Members. Under the agreements,
LEM is obligated to deliver, and Oglethorpe is obligated to take, approximately
50% of the load requirements of the participating Members less the load
requirements for certain customers who have the right to choose electric
suppliers, plus 50% of the delivery obligations under Oglethorpe's existing firm
power off-system sale contracts. For certain smaller customer choice loads, LEM
is obligated to deliver, if Oglethorpe requests, 50% of the associated load
requirements. Oglethorpe has the option of purchasing the energy requirements
for any customer choice load from another supplier. Oglethorpe is obligated to
sell and LEM is obligated to buy 50% of the output of each participating
Member's PCR share of the "must run" units (primarily nuclear units). Oglethorpe
is also obligated to make available the same share of all other resources, which
LEM may schedule. LEM does not have the right to the output of 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
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
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
16
Morgan Stanley were designed to provide substantially all of the Members'
requirements during their contract terms, Oglethorpe will continue to offer
these planning services for requirements beyond the contract terms as well as
for evaluation of contract options and balancing of actual requirements against
fixed purchase obligations. Consequently, Oglethorpe has forecasted that peak
requirements for the Members will exceed contracted purchases over the next
several years and has issued a request for proposals for an aggregate of 100 MW
to 1,100 MW to supply these additional requirements. Oglethorpe has signed
contracts for an aggregate of 160 MW for delivery during the summer months of
1998, and may sign additional contracts up to 350 MW in the aggregate for supply
during that period. Oglethorpe is continuing to analyze proposals for deliveries
after 1998. All Members currently participate in joint planning.
17
CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY
GENERAL
The electric utility industry has been and in the future will continue to be
affected by a number of factors which could have an impact on the financial
condition of an electric utility such as Oglethorpe. These factors likely would
affect individual utilities in different ways. Such factors include, among
others: (i) the transition to increasing competition in the generation of
electricity and the corresponding increase in competition from other suppliers
of electricity, (ii) fluctuations in the market price for electricity, (iii)
effects of compliance with changing environmental, licensing and regulatory
requirements, (iv) regulatory and other changes in national and state energy
policy, including open access transmission, (v) uncertain access to low cost
capital for replacement of aging fixed assets, (vi) increases in operating
costs, including the cost of fuel for the generation of electric energy, (vii)
uncertain recovery of the cost of existing facilities, (viii) fluctuations in
demand, including rates of load growth and changes in competitive market share,
(ix) unbundling of services and corresponding corporate and functional
restructurings by electric utility companies, and (x) the effects of
conservation and energy management on the use of electric energy. These factors
present an increasing challenge to companies in the electric utility industry,
including Oglethorpe and the Members, to reduce costs, improve the management of
resources and respond to the changing environment. (See "Environmental and Other
Regulation" herein, "OGLETHORPE POWER CORPORATION--Corporate Restructuring,"
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Competition" in Item 7, "MEMBER REQUIREMENTS AND POWER SUPPLY
RESOURCES--General" and "--Power Purchase and Sale Arrangements--OTHER POWER
PURCHASES.")
COMPETITION
The electric utility industry in the United States is undergoing fundamental
change and is becoming increasingly competitive. (See "MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Competition" in
Item 7.)
ENVIRONMENTAL AND OTHER 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
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--
19
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
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.
21
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.")
OGLETHORPE'S
SHARE OF
NAMEPLATE COMMERCIAL LICENSE
TYPE OF PERCENTAGE CAPACITY OPERATION EXPIRATION
FACILITIES FUEL INTEREST(1) (MW) DATE DATE
- -------------------------------------------------- --------- ----------- ------------ ------------- -----------
Plant Hatch (near Baxley, Ga.)
Unit No. 1...................................... Nuclear 30 243.0 1975 2014
Unit No. 2...................................... Nuclear 30 246.0 1979 2018
Plant Vogtle (near Waynesboro, Ga.)
Unit No. 1...................................... Nuclear 30 348.0 1987 2027
Unit No. 2...................................... Nuclear 30 348.0 1989 2029
Plant Wansley (near Carrollton, Ga.)
Unit No. 1...................................... Coal 30 259.5 1976 N/A(2)
Unit No. 2...................................... Coal 30 259.5 1978 N/A(2)
Combustion Turbine.............................. Oil 30 14.8 1980 N/A(2)
Plant Scherer (near Forsyth, Ga.)
Unit No. 1...................................... Coal 60 490.8 1982 N/A(2)
Unit No. 2...................................... Coal 60 490.8 1984 N/A(2)
Tallassee (near Athens, Ga.)...................... Hydro 100 2.1 1986 2023
Rocky Mountain (near Rome, Ga.)................... Pumped
Storage
Hydro 74.61 632.5 1995 2027
------------
Total Ownership............................. 3,335.0
------------
------------
- ------------------------------
(1) The 60% interest in Scherer Unit No. 2 is leased under leases that expire in
2013, subject to options to renew for a total of 8.5 years. The 74.61%
interest in Rocky Mountain is leased under leases that expire in 2016.
Oglethorpe has an ownership interest in all of the other facilities. (See
"CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--The Plant
Agreements--ROCKY MOUNTAIN.")
(2) Coal-fired units and combustion turbines do not operate under operating
licenses similar to those granted to nuclear units by the Nuclear Regulatory
Commission and to hydroelectric plants by FERC.
22
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:
EQUIVALENT AVAILABILITY(1) CAPACITY
FACTOR(2)
------------------------------------- -----------
UNIT 1997 1996 1995 1997
- --------------------------------------------------------------------- ----- ----- ----- -----
Plant Hatch
Unit No. 1......................................................... 86% 83% 98% 86%
Unit No. 2......................................................... 85 97 75 84
Plant Vogtle
Unit No. 1......................................................... 81 80 98 81
Unit No. 2......................................................... 100 88 89 101
Plant Wansley
Unit No. 1......................................................... 91 88 90 62
Unit No. 2......................................................... 92 91 89 59
Plant Scherer
Unit No. 1......................................................... 76 92 95 57
Unit No. 2......................................................... 99 84 97 84
Rocky Mountain(3)
Unit No. 1......................................................... 96 94 83 20
Unit No. 2......................................................... 96 95 92 13
Unit No. 3......................................................... 97 95 92 19
UNIT 1996 1995
- --------------------------------------------------------------------- ----- -----
Plant Hatch
Unit No. 1......................................................... 83% 100%
Unit No. 2......................................................... 99 75
Plant Vogtle
Unit No. 1......................................................... 80 98
Unit No. 2......................................................... 89 90
Plant Wansley
Unit No. 1......................................................... 58 56
Unit No. 2......................................................... 62 56
Plant Scherer
Unit No. 1......................................................... 74 73
Unit No. 2......................................................... 72 85
Rocky Mountain(3)
Unit No. 1......................................................... 15 16
Unit No. 2......................................................... 13 15
Unit No. 3......................................................... 10 16
- ------------------------------
(1) Equivalent Availability is 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
23
dispatch of Plant Scherer in 1994 and at Plant Wansley in May 1997. Oglethorpe
continues to use GPC as its agent for fuel procurement.
To take advantage of these changes at Plants Scherer and Wansley, Oglethorpe
formed a wholly owned subsidiary, Black Diamond Energy, Inc., to acquire rail
cars. This subsidiary has purchased or leased approximately 300 rail cars.
Oglethorpe entered into an initial 15-year lease with this subsidiary which
obligates Oglethorpe to pay all of the 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.
24
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.)
NUCLEAR COAL-FIRED
-------------------- --------------------------------------------
PLANT PLANT PLANT SCHERER UNITS
HATCH VOGTLE WANSLEY NO. 1 & NO. 2
-------------------- -------------------- -------------------- --------------------
% MW(1) % MW(1) % MW(1) % MW(1)
-------- -------- -------- -------- -------- -------- -------- --------
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
-------- -------- -------- -------- -------- -------- -------- --------
-------- -------- -------- -------- -------- -------- -------- --------
PUMPED
STORAGE
------------------------
ROCKY
MOUNTAIN
------------------------ TOTAL
% MW(1) MW(1)
---------- ---------- --------
Oglethorpe..... 74.61 (2) 633 3,319
GPC............ 25.39 215 3,155
MEAG........... -- -- 1,570
Dalton......... -- -- 120
---------- ----- --------
Total.......... 100.00 848 8,164
---------- ----- --------
---------- ----- --------
- ------------------------------
(1) Based on nameplate ratings.
(2) Oglethorpe leases its interest in Scherer Unit No. 2 and Rocky Mountain
pursuant to long-term net leases.
GEORGIA POWER COMPANY
GPC is a wholly owned subsidiary of The Southern Company, a registered
holding company under the Public Utility Holding Company Act, and is engaged
primarily in the generation and purchase of electric energy and the
transmission, distribution and sale of such energy within the State of Georgia
at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus,
Macon, Rome and Valdosta), as well as in rural areas, and at wholesale to
Oglethorpe, MEAG and three municipalities. GPC is the largest supplier of
electric energy in the State of Georgia. (See "OGLETHORPE POWER CORPORATION--
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
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
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
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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.
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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.