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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
(Mark One)
[ X ] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2000
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
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
2100 East Exchange Place
Tucker, Georgia 30085-1349
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (770) 270-7600
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes _X__ No ___
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
State the aggregate market value of the voting and non-voting common equity
held by non-affiliates of the registrant. None
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. The Registrant is a
membership corporation and has no authorized or outstanding equity securities.
Documents Incorporated by Reference: None
OGLETHORPE POWER CORPORATION
2000 FORM 10-K ANNUAL REPORT
Table of Contents
ITEM Page
PART I
1 Business ................................................................1
Oglethorpe Power Corporation...........................................1
Oglethorpe's Power Supply Resources....................................7
The Members and Their Power Supply Resources..........................12
Factors Affecting the Electric Utility Industry.......................17
2 Properties..............................................................22
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..............40
8 Financial Statements and Supplementary Data.............................44
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................................64
PART III
10 Directors and Executive Officers of the Registrant......................64
11 Executive Compensation..................................................68
12 Security Ownership of Certain Beneficial Owners and Management..........70
13 Certain Relationships and Related Transactions..........................70
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K........71
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SELECTED DEFINITIONS
The following terms used in this report have the meanings indicated below:
Term Meaning
CFC National Rural Utilities Cooperative Finance Corporation
EMC Electric Membership Corporation
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)
LEM LG&E Energy Marketing Inc.
MEAG Municipal Electric Authority of Georgia
NRC Nuclear Regulatory Commission
RUS Rural Utilities Service
SEPA Southeastern Power Administration
SONOPCO Southern Nuclear Operating Company
TVA Tennessee Valley Authority
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PART I
ITEM 1. BUSINESS
OGLETHORPE POWER CORPORATION
General
Oglethorpe Power Corporation (An Electric Membership Corporation)
("Oglethorpe") is a Georgia electric membership corporation incorporated in 1974
and headquartered in metropolitan Atlanta. Oglethorpe is owned by 39 retail
electric distribution cooperative members (the "Members"). Oglethorpe's
principal business is providing wholesale electric power to the Members. As with
cooperatives generally, Oglethorpe operates on a not-for-profit basis.
Oglethorpe is the largest electric cooperative in the United States in terms of
operating revenues, assets, kilowatt-hour ("kWh") sales and, through the
Members, consumers served. Oglethorpe has approximately 160 employees.
Oglethorpe and the Members completed a corporate restructuring in 1997 in
which Oglethorpe was divided into three separate operating companies. Oglethorpe
sold its transmission business to Georgia Transmission Corporation (An Electric
Membership Corporation) ("GTC"), a Georgia electric membership corporation
formed for that purpose. Oglethorpe sold its system operations business to
Georgia System Operations Corporation ("GSOC") a Georgia nonprofit corporation
formed for that purpose. Oglethorpe retained all of its owned and leased
generation assets and purchased power resources. (See "Power Supply Business,"
"Relationship with GTC," and "Relationship with GSOC" herein and "OGLETHORPE'S
POWER SUPPLY RESOURCES.")
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 1.4 million
electric consumers (meters) representing approximately 3.4 million people. For
information on the Members, see "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES."
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 (that is, margins) to increase its patronage capital, which is the
equity component of its capitalization. Any such margins are considered capital
contributions (that is, equity) from the members and 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.
Power Supply Business
Oglethorpe provides wholesale electric service to the 39 Members for a
substantial portion of their requirements from a combination of owned and leased
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generating plants and power purchased from other suppliers and power marketers.
This service is provided pursuant to long-term, take-or-pay Wholesale Power
Contracts described below. The Wholesale Power Contracts 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. The Members may satisfy all or
a portion of their requirements above their existing Oglethorpe purchase
obligations with purchases from Oglethorpe or other suppliers. The Members are
now purchasing varying portions of their requirements from other suppliers. (See
"OGLETHORPE'S POWER SUPPLY RESOURCES--Future Power Resources" and "THE MEMBERS
AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources" and "--Future
Power Resources.")
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 1,501 MW of coal-fired capacity, 1,185 MW of
nuclear-fueled capacity, 632 MW of pumped storage hydroelectric capacity, 15 MW
of oil-fired combustion turbine capacity and 2 MW of conventional hydroelectric
capacity. In addition, Oglethorpe purchases a total of approximately 1,200 MW of
power pursuant to long-term power purchase agreements. Oglethorpe meets its
supplemental power supply needs through short-term power purchase contracts and
spot market purchases. GTC provides transmission services to the Members for
delivery of the Members' power purchases. (See "Relationship with GTC" herein,
"OGLETHORPE'S POWER SUPPLY RESOURCES" and "PROPERTIES--Generating Facilities" in
Item 2.)
Oglethorpe has entered into power supply arrangements with two power
marketers to reduce the cost of capacity and energy delivered to the Members.
(See "OGLETHORPE'S POWER SUPPLY RESOURCES--Power Marketer Arrangements.")
In 2000, Cobb EMC and Jackson EMC accounted for 11.9% 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 2000.
Wholesale Power Contracts
In 1997, Oglethorpe entered into a substantially similar Amended and
Restated Wholesale Power Contract with each Member extending through December
31, 2025. Under the Wholesale Power Contract, each 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.
Each Member's cost responsibility under its Wholesale Power Contract is
based on agreed-upon fixed percentage capacity responsibilities. Percentage
capacity responsibilities have been assigned for all of Oglethorpe's existing
generation and purchased power resources. Percentage capacity responsibilities
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.
Under the Wholesale Power Contracts, each Member must establish rates and
conduct its business in a manner that will enable the Member to pay (i) to
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Oglethorpe when due, all amounts payable by the Member under its Wholesale Power
Contract and (ii) any and all other amounts payable from, or which might
constitute a charge or a lien upon, the revenues and receipts derived from the
Member's 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.
Under the Wholesale Power Contracts, Oglethorpe is not obligated to provide
all of the Members' capacity or energy requirements. The Members also have
various options regarding services provided by Oglethorpe. These options
include:
o whether to have Oglethorpe provide joint planning and resource management
services,
o whether to participate in a capacity and energy pool or to separately
schedule their resources, and
o whether to satisfy all or a portion of their power requirements above
their existing Oglethorpe purchase obligations from Oglethorpe or from
other suppliers.
For more information about these options see "OGLETHORPE'S POWER SUPPLY
RESOURCES--Future Power Resources" and "--Capacity and Energy Pool" and "THE
MEMBERS AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources."
Electric Rates
Each Member is required to pay Oglethorpe for capacity and energy furnished
under its Wholesale Power Contract in accordance with rates established by
Oglethorpe. Oglethorpe reviews its rates at such intervals as it deems
appropriate but is required to do so at least once every year. Oglethorpe is
required to revise its rates as necessary so that the revenues derived from its
rates, together with its revenues from all other sources, will be sufficient to
pay all costs of its system, to provide for reasonable reserves and to meet all
financial requirements.
Oglethorpe's principal financial requirements are contained in the
Indenture, dated as of March 1, 1997, from Oglethorpe to SunTrust Bank
("SunTrust"), as trustee (as supplemented, the "Mortgage Indenture"). 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 a Margins for Interest Ratio for
each fiscal year equal to at least 1.10. "Margins for Interest Ratio" is the
ratio of "Margins for Interest" to total "Interest Charges" for a given period.
Margins for Interest is the sum of:
o 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
o 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
or premium on issuance, but excluding interest charges on indebtedness
assumed by GTC ("Interest Charges"), plus
o any amount included in net margins for accruals for federal or state
income taxes imposed on income after deduction of interest expense.
Margins for Interest 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.
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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 (that is, the Member's
percentage capacity responsibility). 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, including fuel costs,
variable operations and maintenance costs and purchased energy costs. (See
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--General--Rates and Regulation" in Item 7.)
The rate schedule formula also includes a prior period adjustment mechanism
designed to ensure that Oglethorpe achieves the minimum 1.10 Margins for
Interest Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum
1.10 Margins for Interest Ratio are accrued as of December 31 of the applicable
year and collected from 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 Margins for Interest Ratio.
Under the Mortgage Indenture and related loan contract with the Rural
Utilities Service ("RUS"), adjustments to Oglethorpe's rates to reflect changes
in Oglethorpe's budgets are generally not subject to RUS approval. Changes to
the rate schedule under the Wholesale Power Contracts are generally 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").
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 and other power suppliers. GTC also provides transmission services to
Oglethorpe and third parties. Oglethorpe has entered into an agreement with GTC
to provide transmission services for third party transactions and for service to
Oglethorpe's headquarters and the administration building at the Rocky Mountain
Pumped Storage Hydroelectric Facility ("Rocky Mountain").
GTC has rights in the Integrated Transmission System, which consists of
transmission facilities owned by GTC, Georgia Power Company ("GPC"), the
Municipal Electric Authority of Georgia ("MEAG") and the City of Dalton
("Dalton"). Through agreements, common access to the combined facilities that
compose the Integrated Transmission System 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. The Integrated Transmission System 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.
Relationship with GSOC
Oglethorpe, GTC and the 39 Members are members of GSOC. GSOC operates the
system control center and currently provides system operations services to
Oglethorpe and GTC. Oglethorpe has also contracted with GSOC to operate an
electric capacity and energy pool for scheduling and dispatching Oglethorpe and
Member resources. (See "OGLETHORPE'S POWER SUPPLY RESOURCES--Capacity and Energy
Pool"). Since January 1, 2000, GSOC has been providing support services to
Oglethorpe in the areas of accounting, auditing, communications, human
resources, facility management, telecommunications and information technology at
cost-based rates.
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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.
Relationship with Smarr EMC
In providing joint planning and resource management services under the
Wholesale Power Contracts, Oglethorpe identified Member needs that could best be
met by the construction and ownership of simple cycle combustion turbine
facilities. Oglethorpe and the Members determined that such facilities should be
owned, not by Oglethorpe, but by a separate Member-owned entity. Accordingly,
Smarr EMC was formed as a Georgia electric membership corporation in 1998 and is
now owned by 37 of Oglethorpe's 39 Members. Oglethorpe is providing operation
and financial management services for Smarr Energy Facility and Sewell Creek
Energy Facility, the gas-fired combustion turbine projects currently owned by
Smarr EMC.
Relationship with GPC
Oglethorpe's relationship with GPC is a significant factor in several
aspects of Oglethorpe's business. 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"). GPC is also one
of Oglethorpe's suppliers of purchased power. For further information regarding
the relationships and agreements with GPC, see "THE MEMBERS AND THEIR POWER
SUPPLY RESOURCES--Service Area and Competition" and "OGLETHORPE'S POWER SUPPLY
RESOURCES--Power Purchase and Sale Arrangements--Power Purchases from GPC." Also
see "PROPERTIES--Fuel Supply," "--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 the Federal Financing Bank ("FFB") have been a major source of
funding for Oglethorpe. (See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--Financial Condition--Capital Requirements"
and "--Liquidity and Sources of Capital" in Item 7.)
Oglethorpe entered into a loan contract with RUS in connection with the
Mortgage Indenture. Under the loan contract, RUS has approval rights over
certain significant actions and arrangements, including, without limitation,
o significant additions to or dispositions of system assets,
o significant power purchase and sale contracts,
o changes to the Wholesale Power Contracts, including the rate
schedule contained therein,
o changes to plant ownership and operating agreements, and
o in limited circumstances, issuance of additional secured debt.
The extent of RUS's approval rights under the 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 relative to RUS's standard mortgage. The Mortgage
Indenture constitutes a lien on substantially all of the owned tangible and
certain intangible property of Oglethorpe.
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Oglethorpe has submitted loan applications to RUS to provide permanent
financing for six new combustion turbines and a combined cycle facility being
constructed to meet future requirements of the Members. The facilities may
ultimately be owned by a subsidiary of Oglethorpe, by Smarr EMC or by a similar
separate entity. The loan applications were made on behalf of any entity that
may ultimately own these facilities. (See "OGLETHORPE'S POWER SUPPLY
RESOURCES--Future Power Resources" and "THE MEMBERS AND THEIR POWER SUPPLY
Resources--Future Power Resources.")
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. Energy revenues track energy costs as they are
incurred and also fluctuate month to month. Capacity revenues reflect the
recovery of Oglethorpe's fixed costs, which do not vary significantly from month
to month; therefore, capacity charges are billed and capacity revenues are
recognized in equal monthly amounts.
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OGLETHORPE'S 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 has also
entered into power supply arrangements with power marketers to reduce the cost
of capacity and energy delivered to the Members. Oglethorpe meets its
supplemental power supply needs through short-term power purchase contracts and
spot-market purchases.
Generating Plants
Oglethorpe's thirteen generating units consist of 30% undivided interests
in the Edwin I. Hatch Plant ("Plant Hatch"), the Alvin W. Vogtle Plant ("Plant
Vogtle") and the Hal B. Wansley Plant ("Plant Wansley"), 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 Rocky Mountain. Plant Hatch
consists of two nuclear-fueled units, with nameplate ratings of 810 MW and 820
MW, respectively. Plant Vogtle consists of two nuclear-fueled units, each with a
nameplate rating of 1,160 MW. 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 Scherer consists of four coal-fired units,
each with a nameplate rating of 818 MW. Oglethorpe has 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
three-unit pumped storage hydroelectric facility with a nameplate rating of
847.8 MW.
Participants in Plants Hatch, Vogtle and Wansley and Scherer Units No. 1
and No. 2 also include MEAG, Dalton and GPC. GPC serves as operating agent for
these units. GPC is also a participant in Rocky Mountain, which is operated by
Oglethorpe.
See "PROPERTIES" in Item 2 for a description of Oglethorpe's generating
facilities, fuel supply and the co-ownership arrangements.
Power Marketer Arrangements
Oglethorpe utilizes power marketer arrangements to reduce the cost of power
to the Members. Oglethorpe has power marketer agreements with LG&E Energy
Marketing Inc. ("LEM") for approximately 50% of the load requirements of the 37
participating Members and with Morgan Stanley Capital Group Inc. ("Morgan
Stanley") with respect to 50% of the 39 Members' load requirements forecasted at
the time Oglethorpe entered into the agreement. The LEM agreement is based on
the actual requirements of the participating 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. 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. Most of Oglethorpe's generating facilities and power
purchase arrangements are available for use by LEM and Morgan Stanley under the
terms 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.
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LEM Agreement
Effective January 1, 1997, Oglethorpe entered into a power marketer
agreement with LEM, an indirect, wholly owned subsidiary of LG&E Energy Corp.,
which is a diversified energy services company headquartered in Louisville,
Kentucky. In December 2000, LG&E Energy Corp. completed a merger with Powergen
plc, a British public limited company, under which LG&E Energy Corp. became an
indirect wholly owned subsidiary of Powergen plc.
Under the power marketer agreement, LEM is obligated to deliver, and
Oglethorpe is obligated to take, (i) 50% of the load requirements of the 37
participating Members, less (ii) the load requirements for certain customers who
have the right to choose electric suppliers, plus (iii) 50% of the 37 Members'
percentage capacity responsibility shares 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 of the 37 Members' percentage capacity responsibility shares of the "must
run" units (primarily nuclear units). Oglethorpe is also obligated to make
available the same share of most of Oglethorpe's 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 megawatt-hour ("MWh") purchased.
The LEM agreement has a term extending through 2011. With one year's
notice, Oglethorpe has the right to terminate the LEM agreement as of December
31, 2001 or any December 31 after that. With 18 months' notice, LEM has the
right to terminate the agreement as of December 31, 2004 or any December 31
after that. In February 2001, LEM initiated the contractually defined
arbitration process to resolve a number of issues relating to the administration
of the LEM agreement. (See "LEGAL PROCEEDINGS" in Item 3.)
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 percentage
capacity responsibility 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 most of Oglethorpe's other 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 manages the portion of
the system resources covered by the Morgan Stanley agreement on behalf of the
"pool" participants through scheduling and dispatching such resources.
Oglethorpe makes purchases and sales on behalf of the "pool" participants 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
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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.
Power Purchase and Sale Arrangements
Power Purchases from GPC
Oglethorpe has an agreement with GPC to purchase capacity and associated
energy on a take-or-pay basis. Under this agreement, Oglethorpe purchased
capacity and associated energy from GPC as follows: 750 MW through May 31, 2000,
500 MW from June 1, 2000 to August 31, 2000 and 375 MW from September 1, 2000 to
December 31, 2000. Oglethorpe will continue to purchase 375 MW of capacity and
associated energy under this agreement through August 31, 2001, and will
purchase 250 MW from September 1, 2001 to March 31, 2006.
Other Power Purchases
Oglethorpe purchases 100 MW of capacity from each of Entergy Power, Inc.
("Entergy Power") and Big Rivers Electric Corporation ("Big Rivers"), under
agreements extending through June and July 2002, respectively. The availability
of capacity under the Entergy Power contract is dependent on the availability of
two specific generating units available to Entergy Power. The Tennessee Valley
Authority ("TVA") provides the transmission service to deliver the power from
the Big Rivers electric system to the Integrated Transmission System. 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 Entergy Power to the Integrated Transmission System.
Oglethorpe has a contract through 2019 to purchase approximately 300 MW of
capacity from Hartwell Energy Limited Partnership, a joint venture between
Dynegy Inc. and American National Power, Inc., a subsidiary of National Power,
PLC. This capacity is provided by two 150 MW gas-fired combustion turbine
generating units on a site near Hartwell, Georgia. Oglethorpe has the right to
dispatch the units fully.
Oglethorpe has an agreement with Doyle I, LLC, a limited liability company
owned by an affiliate of Enron North America Corp. and one of Oglethorpe's
Members, to purchase the output of a 325 MW gas-fired combustion turbine
generating facility over a 15-year term. Delivery commenced May 15, 2000.
Oglethorpe has the right to dispatch the units fully.
See Note 9 of Notes to Financial Statements in Item 8 for a discussion of
Oglethorpe's commitments under these power purchase agreements.
In addition, Oglethorpe also purchases small amounts of capacity and energy
from "qualifying facilities" under the Public Utility Regulatory Policies Act of
1978 ("PURPA"). Under a waiver order from the Federal Energy Regulatory
Commission ("FERC"), 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 less than 0.1% of
Oglethorpe's energy requirements for the Members in 2000. Under their Wholesale
Power Contracts, the Members may make such purchases instead of Oglethorpe.
Long-Term Power Sales
Oglethorpe has an agreement to sell 100 MW of base capacity to Alabama
Electric Cooperative, Inc. 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 this power sale.
9
Other Power System Arrangements
Oglethorpe has interchange, transmission and/or short-term capacity and
energy purchase or sale agreements with over 80 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 Integrated Transmission System 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
Although the existing long-term power marketer arrangements with LEM and
Morgan Stanley were designed to provide substantially all of the Members'
requirements during their contract terms, in fact the Members' requirements have
exceeded the amounts provided by these arrangements. Oglethorpe expects that the
Members' requirements will continue to exceed contracted purchases over the next
several years. The Members also have significant additional requirements beyond
the term of the power marketer arrangements.
Under the Wholesale Power Contracts, Members can elect on an annual basis
whether to have Oglethorpe provide joint planning and resource management
services. These services consist of bulk power supply planning, future resource
procurement, and bulk power sales for the Members. Some Members are currently
not participating in joint planning and resource management services.
Oglethorpe is in the process of arranging the necessary power supply for
Members that currently participate in joint planning and resource management
services. In this regard, Oglethorpe has entered into agreements to acquire and
construct six gas-fired combustion turbines designed to provide 618 MW of
capacity and a gas-fired combined cycle facility designed to provide 468 MW of
capacity. Four of the combustion turbines are scheduled for completion in 2002,
with the other two to be completed in 2003. The combined cycle facility is
scheduled for completion in 2003. Oglethorpe also has an agreement to purchase
equipment for a possible 2005 gas-fired combined cycle project. Members have
subscribed for all of the capacity and energy from these facilities except for
the capacity and associated energy of a 2003 combustion turbine and the capacity
and energy of the possible 2005 combined cycle project. Oglethorpe is evaluating
options with respect to the unsubscribed portions, which include seeking
additional subscriptions from Members, contracting to sell some of the output of
the facilities to non-Members, or selling the equipment.
Although Oglethorpe plans for and procures power supply resources for
electing Members, Oglethorpe will not necessarily own these resources. For a
number of reasons, these facilities may be owned by a subsidiary of Oglethorpe,
by Smarr EMC or by a similar separate entity owned by those Members who
participate in the facilities. Oglethorpe has submitted loan applications to RUS
for FFB loans to permanently finance the 2002 and 2003 combustion turbine
facilities and the 2003 combined cycle facility. The loan applications were made
on behalf of any entity that may ultimately own these facilities. Oglethorpe
expects RUS to act on these loan applications later in 2001. See "THE MEMBERS
AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources" and "--Future
Power Resources" for a discussion of capacity purchased by the Members from
sources other than Oglethorpe. See also "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF Operations--Financial Condition--Capital
Requirements" in Item 7.
Oglethorpe is also investigating other power supply options to meet the
remainder of the projected requirements of those Members for which it is
currently providing joint planning and resource management services. Based on
the current load forecasts of these Members, the projected additional
requirements could be as much as 1300 MW in 2005, with increases thereafter.
Because Members can elect whether or not to receive these services from
10
Oglethorpe on an annual basis, the projections may change significantly if
Members change their elections in future years. Current load forecasts for the
Members may not accurately predict the Members' actual load in the future, due
to changes in growth in the Members' service territories and the competitive
environment in the electric utility industry, among other reasons.
Oglethorpe's current power procurement efforts for these projected
requirements include initial discussions with a number of entities regarding
contractual power supply arrangements. These arrangements could take a form
similar to Oglethorpe's existing power marketer arrangements or a form more like
traditional power purchase arrangements. Oglethorpe may also evaluate other
alternatives for meeting future power supply requirements. (See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Miscellaneous--Competition" in Item 7).
Capacity and Energy Pool
In connection with scheduling rights granted to the Members in the
Wholesale Power Contracts adopted in 1997, Oglethorpe established an electric
capacity and energy pool for scheduling and dispatching Oglethorpe and Member
resources. Pursuant to the Wholesale Power Contracts and the policies and
procedures governing the pool, the Members may elect either to participate in
the pool or separately to schedule and dispatch the capacity represented by the
Member's percentage capacity responsibility under the Wholesale Power Contract.
The Members may also elect to include all or part of their other resources in
the pool. Some Members have elected to be self-scheduling Members. See "THE
MEMBERS AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources."
Oglethorpe has contracted with GSOC to operate the pool. Oglethorpe and
GSOC maintain, and in conjunction with the Members are currently refining,
policies and procedures relating to the pool and self-scheduling Members.
11
THE MEMBERS AND THEIR POWER SUPPLY RESOURCES
Member Demand and Energy Requirements
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 Energy Cooperative, an 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 1.4 million electric consumers (meters)
representing approximately 3.4 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 2000 amounted to approximately 27 million MWh, with
approximately 66% to residential consumers, 31% to commercial and industrial
consumers and 3% 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 1998 through 2000 of 5% in number of
consumers, 7% in MWh sales and 5% in electric revenues.
The following table shows the aggregate peak demand and energy requirements
of the Members for the years 1998 through 2000, and also shows the amounts of
energy requirements supplied by Oglethorpe. From 1998 through 2000, demand and
energy requirements of the Members increased at an average annual compound
growth rate of 7.3% and 7.4%, respectively.
Member Member Energy
Demand (MW) Requirements (MWh)
----------------------------------------------------------------
Total(1) Total(2) Supplied by
------- ------- Oglethorpe(3)
------------
1998 5,816 24,494,807 23,315,950
1999 6,452 25,760,322 24,755,812
2000 6,703 28,210,327 27,232,641
(1) System peak demand of the Members measured at the Members' delivery points
(net of system losses), adjusted to include Members' resources behind the
delivery points.
(2) Retail requirements served by Members' resources, adjusted to include
resources behind the delivery points. (See "Member Power Supply Resources"
below.)
(3) Includes energy supplied to self-scheduling Members for resale at
wholesale. (See "OGLETHORPE'S POWER SUPPLY RESOURCES--Capacity and Energy
Pool.")
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Service Area and Competition
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 principal 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
premise and the electric utility is unwilling or unable to comply with an order
from GPSC regarding such service.
Since 1973, 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 load upon initial full
operation of 900 kilowatts or greater to receive electric service from the
retail supplier of its choice. The Members, with Oglethorpe's support, are
actively engaged in competition with other retail electric suppliers for these
new 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 "FACTORS
AFFECTING THE ELECTRIC UTILITY INDUSTRY--General" and "MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Miscellaneous--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 generally
must obtain approval from Oglethorpe before it may 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. The Member may enter such a transaction
without Oglethorpe`s approval if specified conditions are satisfied, including,
but not limited to, an agreement by the transferee, satisfactory to Oglethorpe,
to assume 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.
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
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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 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 that have the new form of RUS
loan documents). (See "Members' Relationship with RUS" below.)
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 Earned Ratio
and an average Debt Service Coverage Ratio of not less than 1.25 for the two
highest out of every three successive years. Members that have the new form of
RUS loan documents are also required to maintain an Operating Times Interest
Earned Ratio and an Operating Debt Service Coverage Ratio of not less than 1.10
for the two highest out of every three successive years.
The Georgia Electric Membership Corporation Act, under which each of the
Members was formed, requires the Members to operate on a not-for-profit basis
and to set rates at levels that are sufficient to recover their costs and to
provide for reasonable reserves. The setting of rates by the Members is not
subject to approval by any federal or state agency or authority other than RUS,
but 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.
Cobb EMC, Flint EMC, Mitchell EMC, Oconee EMC, Snapping Shoals EMC, Troup
EMC and Walton EMC have paid 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. 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.
Historically, federal loan programs providing direct loans from RUS to
electric cooperatives have been a major source of funding for the Members. Under
the current RUS loan program, interest rates are based on rates being paid on
14
municipal bonds with comparable maturities. Certain borrowers with either low
consumer density or higher-than-average rates and lower-than-average consumer
income are eligible for special loans at 5%. Distribution borrowers are also
eligible for loans made by FFB or other lenders and guaranteed by RUS.
Oglethorpe cannot predict the future cost, availability and amount of RUS direct
and guaranteed loans which may be available to the Members.
Members' Relationships with GTC and GSOC
GTC provides transmission services to the Members for delivery of the
Members' power purchases from Oglethorpe and other power suppliers. GTC and the
Members have entered into Member Transmission Service Agreements under which GTC
provides transmission service to the Members pursuant to a transmission tariff.
The Member Transmission Service Agreements have a minimum term for network
service for current load until December 31, 2025. After an initial term ending
in 2006, load growth above 1995 requirements may, with notice to GTC, be served
by others. The Member Transmission Service 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 Service Agreements,
Members have the right to design, construct and own new distribution
substations.
For information about the Members' relationships with GSOC, see "OGLETHORPE
POWER CORPORATION--Relationship with GSOC."
Member Power Supply Resources
Oglethorpe Power Corporation
Oglethorpe currently supplies a substantial portion of the Members'
requirements. Each Member has a take-or-pay, fixed percentage capacity
responsibility for all of Oglethorpe's existing resources. Members may satisfy
all or a portion of their requirements above their existing Oglethorpe purchase
obligations with purchases from Oglethorpe or other suppliers. (See "OGLETHORPE
POWER CORPORATION--Wholesale Power Contracts.")
Contracts with SEPA
The Members purchase hydroelectric power from the Southeastern Power
Administration ("SEPA") under contracts that extend until 2016. In 2000, the
aggregate SEPA allocation to the Members was 543 MW plus associated energy. Each
Member must schedule its energy allocation, and each Member has designated
Oglethorpe to perform this function. 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.
Smarr EMC
The Members participating in the facilities owned by Smarr EMC purchase the
output of those facilities pursuant to long-term, take-or-pay power purchase
agreements. Smarr EMC owns Smarr Energy Facility, a two-unit, 217 MW gas-fired
combustion turbine facility (with 36 participating Members), and Sewell Creek
Energy Facility, a four-unit, 492 MW gas-fired combustion turbine facility (with
31 participating Members). Smarr Energy Facility began commercial operation in
June 1999, and Sewell Creek Energy Facility began commercial operation in June
2000.
Other Member Resources
Two Members formed an entity that has constructed and continues to
construct combustion turbine capacity. Oglethorpe anticipates that these two
Members will use a portion of this capacity to serve some or all of their load
growth.
15
In addition, a number of Members have installed and may continue to install
small diesel generators and gas-fired microturbines on their distribution
systems.
Future Power Resources
Oglethorpe has entered into agreements on behalf of participating Members
to acquire and construct six gas-fired combustion turbines designed to provide
618 MW of capacity and a gas-fired combined cycle facility designed to provide
468 MW of capacity. Four of the combustion turbines are targeted for completion
in 2002, with the other two to be completed in 2003. The combined cycle facility
is targeted for completion in 2003. Oglethorpe has an agreement to purchase
equipment for a possible 2005 gas-fired combined cycle project. Although
Oglethorpe plans for and procures generating resources for electing Members,
these generating resources may not necessarily be owned by Oglethorpe. For a
number of reasons, the facilities may be owned by a subsidiary of Oglethorpe, by
Smarr EMC or by a similar separate entity owned by those Members who participate
in the facilities. For information on financing for these facilities, see
"OGLETHORPE'S POWER SUPPLY RESOURCES--Future Power Resources.")
Several Members have entered into long-term contracts with a third party
for all of their future incremental power requirements. Other Members may do so
in the future.
16
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 an electric
utility such as Oglethorpe. These factors likely would affect individual
utilities in different ways. Such factors include, among others:
o the transition to increasing competition in the generation of
electricity and the corresponding increase in competition from other
suppliers of electricity,
o fluctuations in the market price for electricity,
o effects of compliance with changing environmental, licensing and
regulatory requirements,
o regulatory and other changes in national and state energy policy,
including open access transmission,
o uncertain access to low cost capital for replacement of aging fixed
assets,
o increases in operating costs, including the cost of fuel for the
generation of electric energy,
o uncertain recovery of the cost of existing facilities,
o limitations on purchasing and selling energy from and to other
suppliers due to transmission constraints,
o limitations on supply of equipment and available sites for
construction of generation resources,
o fluctuations in demand, including rates of load growth and changes in
competitive market share,
o unbundling of services and corresponding corporate and functional
restructurings by electric utility companies, and
o 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.
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--Miscellaneous--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
dioxide 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.
17
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. Oglethorpe made
environmental-related capital expenditures of approximately $3 million in 2000,
and expects to spend $28 million in 2001 and $66 million in 2002 to achieve
compliance with current environmental requirements. (See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Financial Condition--Capital Requirements" in Item 7.) Based on the
current status of regulatory requirements, Oglethorpe does not anticipate that
these capital expenditures will have a material effect on its results of
operations or its financial condition. However, as discussed below, future
regulations could require Oglethorpe to make additional capital expenditures.
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. The most significant
environmental legislation applicable to Oglethorpe is the Clean Air Act. One of
the purposes of the Clean Air Act 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 at Plants Wansley and Scherer.
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 stringent reductions on all affected units. The aggregate
emissions of sulfur dioxide from all affected units are now capped at 8.9
million tons per year. Oglethorpe is now complying with this program by using
lower-sulfur fuel, coupled with the use of emission allowances (issued, banked
or purchased, if needed). Installation of flue gas desulfurization equipment
remains a possibility for compliance in the more distant future.
A number of recently finalized regulations, proposed regulations and other
actions 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 have imposed further limits on
such emissions. Recently, both Plants Wansley and Scherer were made subject to
stringent nitrogen oxides averaging plans, which will cause the co-owners of the
plants to install new control equipment at both plants no later than May 2003.
Oglethorpe expects to incur significant capital expenditures over the next three
years to install this equipment.
Second, EPA attempted to tighten 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 were
made. On appeal, the Supreme Court reversed a successful challenge of these
revised NAAQS, and remanded the case back to the Court of Appeals for further
disposition. This decision may result in tightening of the standards for both
18
ozone and particulate matter. Other challenges to both NAAQS are still pending
at the Court of Appeals level. In addition, with respect to the ozone NAAQS, EPA
must harmonize provisions in the Clean Air Act imposing the old ozone NAAQS with
its proposed standard before the new standard can be implemented.
Third, in 1998, EPA issued a regulation calling for regional reductions in
nitrogen oxides emissions from 22 states, including Georgia, which imposes a
fixed cap on nitrogen oxides emissions from such states beginning in the year
2004. States remain free to choose the sources on which to impose reductions
needed to stay below the cap. The Georgia Environmental Protection Division has
indicated that if Georgia must adhere to the regulation, it will require large
fossil fuel-fired units, including those at Plants Wansley and Scherer, to
participate in achieving the required reductions. On appeal, EPA's regulation
was upheld in part, with that portion of the rule that would have applied to
Georgia sent back to EPA for further consideration. EPA recently indicated its
intention to finalize shortly a rule reinstating the cap for Georgia. As a
result, Georgia's implementation plan for this regulation will depend on this
new rulemaking. Therefore, it is not yet known what additional controls, if any,
would be needed at Plants Wansley and/or Scherer to comply with this regional
nitrogen oxides reduction program.
Fourth, EPA has promulgated a new regional haze rule, which affects 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. Several industry groups have challenged the rule and some have
also petitioned EPA to reconsider the rule. Until such litigation is resolved,
Oglethorpe will not know what controls, if any, must be installed at Plants
Wansley and/or Scherer to comply with this rule.
Fifth, although EPA had decided not to impose a new NAAQS for sulfur
dioxide, that decision has been remanded to EPA for further rulemaking, so it is
still possible that a new short-term standard for sulfur dioxide could be
established.
Finally, several studies required by the Clean Air Act examined the health
effects of power plant emissions of certain hazardous air pollutants. In late
2000, EPA concluded that mercury emissions from coal and oil-fired electric
utility steam generating units should be regulated. Emissions of other hazardous
air pollutants, such as nickel and cadmium, may also become regulated. EPA
expects to follow a rulemaking schedule that would require compliance by
2007-2008. Depending on the outcome of such rulemaking, significant capital
expenditures might be incurred at Plants Wansley and/or Scherer.
On November 3, 1999, the United States Justice Department, on behalf of
EPA, filed lawsuits against GPC and some of its affiliates, as well as other
utilities. The lawsuits allege violations of the new source review provisions
and the new source performance standards of the Clean Air Act at, among other
facilities, Plant Scherer Unit Nos. 3 and 4. Oglethorpe is not currently named
in the lawsuits and Oglethorpe does not have an ownership interest in the named
units of Plant Scherer. However, Oglethorpe can give no assurance that units in
which Oglethorpe has an ownership interest will not be named in this or a
related lawsuit in the future. The resolution of this matter is highly uncertain
at this time, as is any responsibility of Oglethorpe for a share of any
penalties and capital costs required to remedy any violations at facilities
co-owned by Oglethorpe.
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--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 Scherer.
19
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.
On February 29, 2000, Southern Nuclear Operating Company ("SONOPCO"), the
operator of Plant Hatch, filed an application with the NRC to extend the
operating licenses for each unit of Plant Hatch, until 2034 and 2038,
respectively. The NRC has published a timetable that indicates a decision will
be made by the end of March 2002.
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. This 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.
Contracts with DOE have been executed to provide for the permanent disposal
of spent nuclear fuel produced at Plants Hatch and Vogtle. DOE failed to begin
disposing of spent fuel in 1998 as required by the contracts, and GPC, as agent
for the co-owners of the plants, is pursuing legal remedies against DOE for
breach of contract.
Plants Hatch and Vogtle currently have on-site spent fuel storage capacity.
Effective June 2000, an on-site dry storage facility for Plant Hatch became
operational. Based on normal operations and retention of all spent fuel in the
reactor, sufficient capacity is believed to be available to continue dry storage
operations at Plant Hatch for the life of the plant, and Plant Vogtle spent fuel
storage is expected to be sufficient into 2014. In addition, SONOPCO, as agent
for the co-owners of the plant, is a member of Private Fuel Storage, LLC, a
joint utility effort to develop a private spent fuel storage facility for
temporary storage of spent nuclear fuel. This facility is planned to begin
operation as early as the year 2003. (See Note 1 of Notes to Financial
Statements 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.
20
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
had until the Spring of 1999 to classify co-managed utility wastes as either
hazardous or non-hazardous. Recently, EPA decided that although these wastes
should be considered non-hazardous, national regulations were warranted.
Depending on the outcome of such rulemaking, substantial additional costs for
the management of these wastes might be required of Oglethorpe, although the
full impact would depend on the subsequent development of such rules.
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.
21
ITEM 2. PROPERTIES
Generating Facilities
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.
Oglethorpe's
Share of
NamePlate Commercial License
Type of Percentage Capacity Operation Expiration
Facilities Fuel Interest (MW) Date Date
- ----------------------------------------------------------------------------------------------------------------
Plant Hatch (near Baxley, Ga.)
Unit No. 1........................ Nuclear 30 243.0 1975 2014(1)
Unit No. 2........................ Nuclear 30 246.0 1979 2018(1)
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) Southern Nuclear Operating Company, the operator of Plant Hatch, has filed
an application with the NRC to extend the licenses with respect to Plant
Hatch by 20 years. (See "FACTORS AFFECTING THE ELECTRIC UTILITY
INDUSTRY--Environmental and Other Regulation--Nuclear Regulation" in Item
1.)
(2) Coal-fired units and combustion turbines do not operate under operating
licenses similar to those granted to nuclear units by the NRC 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 2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ---- ----
Plant Hatch
Unit No. 1........... 84% 81% 100% 85% 83% 99%
Unit No. 2........... 89 92 81 90 94 81
Plant Vogtle
Unit No. 1........... 86 92 100 91 94 102
Unit No. 2........... 100 88 82 102 89 82
Plant Wansley
Unit No. 1........... 83 91 86 77 73 56
Unit No. 2........... 78 86 92 72 66 50
Plant Scherer
Unit No. 1........... 100 86 93 79 67 70
Unit No. 2........... 90 95 89 73 79 75
Rocky Mountain(3)
Unit No. 1........... 94 97 90 26 23 24
Unit No. 2........... 91 96 95 20 16 13
Unit No. 3........... 94 91 94 17 19 22
- -----------------------
(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) As a pumped storage plant, Rocky Mountain primarily operates as a peaking
plant, which results in a low capacity factor.
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, 2001, there was a
26-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,
2001, the coal stockpile at Plant Scherer contained a 50-day supply based on
nameplate rating. Plant Scherer burns both sub-bituminous and bituminous coals,
and a separate stockpile of sub-bituminous coal is maintained in addition to the
stockpile of bituminous coal. Oglethorpe leases over 700 rail cars to transport
coal to Plants Scherer and Wansley.
The Plant Scherer and Wansley ownership and operating agreements allow each
co-owner (i) to dispatch separately its respective ownership interest in
conjunction with contracting separately for long-term coal purchases procured by
GPC and (ii) to procure separately long-term coal purchases. Oglethorpe
separately dispatches Plant Scherer and Plant Wansley, but continues to use GPC
as its agent for fuel procurement.
23
For information relating to the impact that the Clean Air Act will have on
Oglethorpe, see "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. 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.
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 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.
Nuclear Coal-Fired Pumped Storage
Plant Plant Plant Scherer Units Rocky
Hatch Vogtle Wansley No. 1 & No. 2 Mountain Total
----------- ------------- -------------- ---------------- --------------- -----
% MW(1) % MW(1) % MW(1) % MW(1) % MW(1) MW(1)
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Oglethorpe... 30.0 489 30.0 696 30.0 519 60.0 982 74.61 633 3,319
GPC.......... 50.1 817 45.7 1,060 53.5 926 8.4 137 25.39 215 3,155
MEAG......... 17.7 288 22.7 527 15.1 261 30.2 494 -- -- 1,570
Dalton 2.2 36 1.6 37 1.4 24 1.4 23 -- -- 120
--- ---- ---- ---- ----- ---- ------ ----- ------ ---- ----
Total..... 100.0 1,630 100.0 2,320 100.0 1,730 100.0 1,636 100.00 848 8,164
===== ===== ===== ===== ===== ===== ===== ===== ====== === =====
(1) Based on nameplate ratings.
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. GPC distributes and sells
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 two 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 47 cities and one county in the State of
Georgia. Such political subdivisions, located in 39 of the State's 159 counties,
collectively serve approximately 283,000 electric consumers (meters).
24
City of Dalton, Georgia
The City of Dalton, located in northwest Georgia, supplies electric
capacity and energy to consumers in Dalton, and presently serves more than
10,000 residential, commercial and industrial customers.
The Plant Agreements
Hatch, Wansley, Vogtle and Scherer
Oglethorpe's rights and obligations with respect to Plants Hatch, Wansley,
Vogtle and Scherer are contained in a number of contracts between Oglethorpe and
GPC and, in some instances, MEAG and Dalton. Oglethorpe is a party to four
Purchase and Ownership Participation Agreements ("Ownership Agreements") under
which it acquired from GPC a 30% undivided interest in each of Plants Hatch,
Wansley and Vogtle, a 60% undivided interest in Scherer Units No. 1 and No. 2
and a 30% undivided interest in those facilities at Plant Scherer intended to be
used in common by Scherer Units No. 1, No. 2, No. 3 and No. 4 (the "Scherer
Common Facilities"). Oglethorpe has also entered into four Operating Agreements
("Operating Agreements") relating to the operation and maintenance of Plants
Hatch, Wansley, Vogtle and Scherer, respectively. The 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.
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. Oglethorpe's leases expire in 2013, with options to renew
for a total of 8.5 years. (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. Each Operating Agreement gives GPC, as agent, sole authority and
responsibility for the management, control, maintenance and operation of the
plant to which it relates. Each Operating Agreement also provides for the use of
power and energy from the plant and the sharing of the costs of the plant by the
participants in accordance with their respective interests in the plant. 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 for Scherer Units No. 1 and 2 subject to certain
limited rights of the participants to disapprove capital budgets proposed by GPC
and to substitute alternative capital budgets. GPC has responsibility for
budgeting capital expenditures for Plants Hatch and Vogtle, subject to the right
of any co-owner to disapprove large discretionary capital improvements.
In 1993, the co-owners of Plants Hatch and Vogtle entered into the Amended
and Restated Nuclear Managing Board Agreement, which provides for a 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
25
third party for the operation of the nuclear units. In March 1997, GPC
designated SONOPCO as the operator of Plants Hatch and Vogtle, pursuant to the
Nuclear Operating Agreement between GPC and SONOPCO, which the co-owners had
previously approved. 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
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. Oglethorpe
separately dispatches its ownership share of Scherer Units No. 1 and No. 2 and
of Plant Wansley. (See "Fuel Supply" herein.)
For Plants Hatch and Vogtle, each participant 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 is responsible for its fuel costs and for
variable Operating Costs in proportion to the net energy output for its
ownership interest, and is responsible for a percentage of fixed Operating Costs
equal to the percentage of its undivided interest which is owned or leased in
such plant or unit. GPC is required to furnish budgets for Operating Costs, fuel
plans and scheduled maintenance plans. In the case of Scherer Units No. 1 and
No. 2, the participants have limited rights 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. Oglethorpe
anticipates that the Operating Agreement will be extended if the operating
license for Plant Hatch is extended. (See "FACTORS AFFECTING THE ELECTRIC
UTILITY Industry--Environmental and Other Regulation--Nuclear Regulation.") 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 owns a 74.61% undivided interest in Rocky Mountain and GPC owns
the remaining 25.39% undivided interest.
The Rocky Mountain Pumped Storage Hydroelectric Ownership Participation
Agreement, by and between Oglethorpe and GPC (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 Pumped
Storage Hydroelectric Project Operating Agreement (the "Rocky Mountain Operating
Agreement") gives Oglethorpe, as agent, sole authority and responsibility for
the management, control, maintenance and operation of Rocky Mountain.
26
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, with interest, 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. The lease
transactions are characterized as a sale and leaseback for income tax purposes,
but not for financial reporting purposes. 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. Oglethorpe intends to 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.
27
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-Integrated Transmission
System ("TVA-ITS") interface to the Florida-Integrated Transmission System
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. Since this action involves transmission access
to the ITS and is exclusively a transmission matter, Oglethorpe has requested
that FERC dismiss the action as to Oglethorpe. 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.
As previously reported, Oglethorpe and LEM have been addressing a number of
issues relating to administration of the power marketer agreement entered into
in 1997. In February 2001, LEM initiated the contractually defined arbitration
process to resolve these issues. Oglethorpe continues to receive power under the
LEM agreement. Oglethorpe's management does not expect the ultimate resolution
of these issues will have a material adverse effect on its financial condition
or results of operations. For a discussion of the LEM agreement, see
"OGLETHORPE'S POWER SUPPLY RESOURCES--Power Marketer Arrangements--LEM
Agreement" in Item 1.
Oglethorpe is a party to various other actions and proceedings incidental
to its normal business. Liability in the event of final adverse determinations
in any of these matters is either covered by insurance or, in the opinion of
Oglethorpe's management, after consultation with counsel, should not in the
aggregate have a material adverse effect on the financial position or results of
operations of Oglethorpe.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
28
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, 2000, have been derived from the audited
financial statements of Oglethorpe. Due to a 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 and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS" in Item 7.
(dollars in thousands)
2000 1999 1998 1997 1996
-----------------------------------------------------------------------------------
Operating revenues:
Sales to Members $ 1,146,064 $ 1,122,336 $ 1,095,904 $ 1,000,319 $ 1,023,094
Sales to non-Members 53,333 53,896 48,263 47,533 78,343
- -----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,199,397 1,176,232 1,144,167 1,047,852 1,101,437
- -----------------------------------------------------------------------------------------------------------------------------
Operating expenses:
Fuel 216,952 196,182 191,399 206,315 206,524
Production 215,834 215,517 198,378 181,923 173,497
Purchased power 403,574 401,719 387,662 266,875 229,089
Depreciation and amortization 142,082 130,883 124,074 126,730 163,130
Other operating expenses - - - 6,334 46,448
- -----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 978,442 944,301 901,513 788,177 818,688
- -----------------------------------------------------------------------------------------------------------------------------
Operating margin 220,955 231,931 242,654 259,675 282,749
Other income, net 60,839 50,545 42,293 46,646 65,334
Net interest charges (261,816) (262,538) (263,867) (283,916) (326,331)
- -----------------------------------------------------------------------------------------------------------------------------
Net margin $ 19,978 $ 19,938 $ 21,080 $ 22,405 $ 21,752
- -----------------------------------------------------------------------------------------------------------------------------
Electric plant, net:
In service $ 3,214,974 $ 3,312,669 $ 3,429,704 $ 3,588,204 $ 4,345,200
Construction work in progress 62,357 18,299 20,948 13,578 31,181
- -----------------------------------------------------------------------------------------------------------------------------
Total electric plant $ 3,277,331 $ 3,330,968 $ 3,450,652 $ 3,601,782 $ 4,376,381
- -----------------------------------------------------------------------------------------------------------------------------
Total assets $ 4,568,170 $ 4,564,622 $ 4,506,265 $ 4,509,857 $ 5,362,175
- -----------------------------------------------------------------------------------------------------------------------------
Capitalization:
Long-term debt $ 3,019,019 $ 3,103,590 $ 3,177,883 $ 3,258,046 $ 4,052,470
Obligation under capital leases 267,449 275,224 282,299 288,638 293,682
Other obligations 63,665 59,579 55,755 52,176 41,685
Patronage capital and membership fees 392,682 370,025 352,701 330,509 356,229
- -----------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 3,742,815 $ 3,808,418 $ 3,868,638 $ 3,929,369 $ 4,744,066
- -----------------------------------------------------------------------------------------------------------------------------
Property additions $ 108,254 $ 41,829 $ 43,904 $ 63,527 $ 93,704
- -----------------------------------------------------------------------------------------------------------------------------
Energy supply (megawatt-hours):
Generated 19,565,925 18,295,514 17,781,896 17,722,059 17,866,143
Purchased 11,401,071 7,971,583 8,544,714 6,377,643 6,606,931
- -----------------------------------------------------------------------------------------------------------------------------
Available for sale 30,966,996 26,267,097 26,326,610 24,099,702 24,473,074
- -----------------------------------------------------------------------------------------------------------------------------
Member revenue per kWh sold 4.21 cents 4.53 cents 4.70 cents 4.83 cents 5.11 cents
- -----------------------------------------------------------------------------------------------------------------------------
29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
General
Margins and Patronage Capital
Oglethorpe Power Corporation (An Electric Membership Corporation)
("Oglethorpe") provides wholesale electric service to its 39 retail electric
distribution cooperative members ("Members"). Oglethorpe operates on a
not-for-profit basis and, accordingly, seeks only to generate revenues
sufficient to recover its cost of service and to generate margins sufficient to
establish reasonable reserves and meet certain financial coverage requirements.
Revenues in excess of current period costs in any year are designated as net
margin in Oglethorpe's statements of revenues and expenses and patronage
capital. Retained net margins are designated on Oglethorpe's balance sheets as
patronage capital, which is allocated to each of the Members on the basis of its
electricity purchases from Oglethorpe. Since its formation in 1974, Oglethorpe
has generated a positive net margin in each year and had a balance of $393
million in patronage capital as of December 31, 2000. Oglethorpe's equity ratio
(patronage capital and membership fees divided by total capitalization)
increased from 9.7% at December 31, 1999 to 10.5% at December 31, 2000.
Patronage capital constitutes the principal equity of Oglethorpe. Any
distributions of patronage capital are subject to the discretion of the Board of
Directors. However, under the Indenture, dated as of March 1, 1997, from
Oglethorpe to SunTrust Bank, as trustee ("Mortgage Indenture"), Oglethorpe is
prohibited from making any distribution of patronage capital to the Members if,
at the time of or after giving effect to the distribution, (i) an event of
default exists under the Mortgage Indenture, (ii) Oglethorpe's equity as of the
end of the immediately preceding fiscal quarter is less than 20% of Oglethorpe's
total capitalization, or (iii) the aggregate amount expended for distributions
on or after the date on which Oglethorpe's equity first reaches 20% of
Oglethorpe's total capitalization exceeds 35% of Oglethorpe's aggregate net
margins earned after such date. This last restriction, however, will not apply
if, after giving effect to such distribution, Oglethorpe's equity as of the end
of the immediately preceding fiscal quarter is not less than 30% of Oglethorpe's
total capitalization.
Rates and Regulation
Pursuant to the Amended and Restated Wholesale Power Contracts, dated
August 1, 1996 ("Wholesale Power Contracts") entered into between Oglethorpe and
each of the Members, Oglethorpe is required to design capacity and energy rates
that generate sufficient revenues to recover all costs, to establish and
maintain reasonable margins and to meet its financial coverage requirements.
Oglethorpe reviews its capacity rates at least annually to ensure that it meets
its net margin goals.
The rate schedule under the Wholesale Power Contracts implements on a
long-term basis the assignment to each Member of responsibility for fixed costs.
The monthly charges for capacity and other non-energy charges are based on a
rate formula using the Oglethorpe budget. The Board of Directors may adjust
these charges during the year through an adjustment to the annual budget. Energy
charges are based on actual energy costs, including fuel costs, variable
operations and maintenance costs, and purchased energy costs.
Under the Mortgage Indenture, Oglethorpe is required, subject to any
necessary regulatory approval, to establish and collect rates that are
reasonably expected, together with other revenues of Oglethorpe, to yield a
Margins for Interest Ratio for each fiscal year equal to at least 1.10. The
Margins for Interest Ratio is determined by dividing Margins for Interest by
Interest Charges. Margins for Interest equal the sum of (i) Oglethorpe's net
margins (after certain defined adjustments), (ii) Interest Charges and (iii) any
amount included in net margins for accruals for federal or state income taxes.
The definition of Margins for Interest 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.
30
The rate schedule also includes a prior period adjustment mechanism
designed to ensure that Oglethorpe achieves the minimum 1.10 Margins for
Interest Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum
1.10 Margins for Interest 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. 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 Margins for Interest
Ratio.
For 2000, 1999 and 1998, Oglethorpe achieved a Margins for Interest Ratio
of 1.10.
Under the Mortgage Indenture and related loan contract with the Rural
Utilities Service ("RUS"), adjustments to Oglethorpe's rates to reflect changes
in Oglethorpe's budgets are generally not subject to RUS approval. Changes to
the rate schedule under the Wholesale Power Contracts are generally 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").
Results of Operations
Power Marketer Arrangements
Oglethorpe is utilizing power marketer arrangements to reduce the cost of
power to the Members. Oglethorpe has a power marketer agreement with LG&E Energy
Marketing Inc. ("LEM"), for approximately 50% of the load requirements of 37 of
the Members and an additional power marketer agreement with Morgan Stanley
Capital Group Inc. ("Morgan Stanley"), effective May 1, 1997, with respect to
50% of the 39 Members' then forecasted load requirements. The LEM agreement is
based on the actual requirements of the participating 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. Most of Oglethorpe's generating facilities and power purchase
arrangements are available for use by LEM and Morgan Stanley. Oglethorpe
continues t be responsible for all of the costs of its system resources but
receives revenue from LEM and Morgan Stanley for the use of the resources.
In February 2001, LEM initiated the contractually defined arbitration
process to resolve a number of issues relating to administration of the
agreement.
Operating Revenues
Sales to Members. Revenues from Members are collected pursuant to the
Wholesale Power Contracts and are a function of the demand for power by the
Members' consumers and Oglethorpe's cost of service. Revenues from sales to
Members increased by 2.1% for 2000 compared to 1999 and increased by 2.4% for
1999 compared to 1998. Kilowatt-hours (kWh) sales to Members were 10.0% higher
in 2000 compared to 1999 and 6.2% higher in 1999 compared to 1998. The average
revenue per kWh from sales to Members decreased 7.1% for 2000 compared to 1999
and decreased 3.6% for 1999 compared to 1998. The components of Member revenues
were as follows:
- -----------------------------------------------------------------
(dollars in thousands)
2000 1999 1998
- -----------------------------------------------------------------
Capacity revenues $ 624,537 $ 613,974 $ 623,464
Energy revenues 521,527 508,362 472,440
- -----------------------------------------------------------------
Total $1,146,064 $1,122,336 $1,095,904
- -----------------------------------------------------------------
Capacity revenues from Members increased from 1999 to 2000 primarily due to
capacity charges incurred for new power purchase agreements and higher
depreciation and amortization offset in part by higher investment income. For
1999 compared to 1998, Member capacity revenues decreased due to lower interest
costs and higher investment income offset in part by higher production expenses.
Energy revenues from Members increased by 2.6% from 1999 to 2000 and by
7.6% from 1998 to 1999. The increases in Member energy revenues over the past
two years were primarily due to greater volumes of energy sold to Members.
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The following table summarizes the amounts of kWh sold to Members and total
revenues per kWh during each of the past three years:
- ------------------------------------------------------------------------------
(in thousands)
Kilowatt-hours Cents per
Kilowatt-hour
- ------------------------------------------------------------------------------
2000 27,232,641 4.21
1999 24,755,812 4.53
1998 23,315,950 4.70
- ------------------------------------------------------------------------------
In 2000, a cold November and December combined with growth in the Members'
service territories resulted in a 10.0% increase in kWh sales to Members. The
6.2% increase in kWh sales to Members in 1999 compared to 1998 was due to
continued sales growth in the Members' service territories. In addition,
Oglethorpe provided the Members with additional energy in 1999 to offset lower
delivery of hydroelectric power from Southeastern Power Administration due to
lower than normal rainfall.
The energy portion of Member revenues per kWh decreased 6.8% in 2000
compared to 1999 and increased 1.4% in 1999 compared to 1998. Oglethorpe passes
through actual energy costs to the Members such that energy revenues equal
energy costs. The decrease in 2000 of energy revenues per kWh was primarily due
to the pass-through of lower purchased power costs. The increase in 1999 for the
cost of energy supplied to the Members resulted primarily from higher purchased
power costs. See "Operating Expenses" below.
Sales to non-Members. The following table summarizes non-Member revenues
for the past three years:
- -----------------------------------------------------------------
(dollars in thousands)
2000 1999 1998
- -----------------------------------------------------------------
Sales to other utilities $46,952 $46,186 $28,890
Sales to power marketers 6,381 7,710 19,373
- -----------------------------------------------------------------
Total $53,333 $53,896 $48,263
- -----------------------------------------------------------------
Sales to other utilities represent sales made directly by Oglethorpe.
Oglethorpe sells for its own account any energy available from the portion of
its resources dedicated to Morgan Stanley that is not scheduled by Morgan
Stanley pursuant to its power marketer arrangements. Sales to other utilities
were higher in 1999 compared to 1998 partly due to receiving a full year of
capacity revenues in 1999 under an agreement entered into with Alabama Electric
Cooperative to sell 100 megawatts ("MW") of capacity for the period June 1998
through December 2005 and partly due to higher energy prices experienced in the
wholesale electricity markets during 1999.
Sales to power marketers represent the net energy transmitted on behalf of
LEM and Morgan Stanley off-system on a daily basis from Oglethorpe's total
resources. Oglethorpe sold this energy to LEM at Oglethorpe's cost, subject to
certain limitations, and to Morgan Stanley at a contractually fixed price. The
volume of sales to power marketers depends primarily on the power marketers'
decisions for servicing their load requirements.
Operating Expenses
Oglethorpe's operating expenses increased 3.6% in 2000 compared to 1999 and
increased 4.7% in 1999 compared to 1998. Operating expenses increased in 2000
primarily as a result of higher fuel and depreciation and amortization costs.
The higher operating expenses in 1999 as compared to 1998 were primarily
attributable to increases in production expenses and purchased power costs.
For 2000 compared to 1999 total fuel costs increased 10.6% primarily as a
result of a 7.4% increase in MWhs of generation. For 2000 compared to 1999
output of nuclear generation was 4.3% higher and output of fossil generation was
9.9% higher. The larger portion of fossil generation, with its higher average
fuel cost compared to nuclear generation, yielded a 3.0% increase in average
fuel cost. Total fuel costs increased 2.5% in 1999 compared to 1998 primarily as
a result of a 2.4% increase in generation.
The increase in production expenses in 1999 as compared to 1998 was
primarily due to three factors: (1) write-off of $3.6 million of obsolete
inventory at Plants Vogtle, Hatch , Wansley and Scherer; (2) approximately $2
million in expenses resulting from a Georgia Power Company ("GPC") workforce
reduction at Plants Vogtle and Hatch; and (3) expenses incurred for the LEM
arbitration and other special projects totaling $4.9 million.
32
Purchased power costs increased 0.5% in 2000 compared to 1999 and increased
3.6% in 1999 compared to 1998 as follows:
- -------------------------------------------------------------------
(dollars in thousands)
2000 1999 1998
- -------------------------------------------------------------------
Capacity costs $105,763 $ 97,616 $115,599
Energy costs 297,811 304,103 272,063
- -------------------------------------------------------------------
Total $403,574 $401,719 $387,662
- -------------------------------------------------------------------
The increase in purchased power capacity costs for 2000 as compared to 1999
were primarily a result of capacity charges incurred for new power purchase
agreements, including an agreement with Doyle I, LLC. Purchased power capacity
costs were 15.6% lower in 1999 compared to 1998 primarily due to the elimination
on September 1 of 1998 of a 250 MW component block (coal-fired units) of power
under a power purchase agreement between Oglethorpe and GPC.
Purchased power energy costs decreased 2.1% in 2000 compared to 1999 and
increased by 11.8% in 1999 compared to 1998. The average cost of purchased power
energy per MWh decreased 31.5% in 2000 compared to 1999 and increased 19.8% in
1999 compared to 1998. The decrease in average cost in 2000 resulted from a
combination of lower prices in the wholesale electricity markets and from
purchases made under new power purchase agreements during 2000. The increase in
average cost in 1999 compared to 1998 resulted from slightly higher energy
prices.
The volumes of purchased power increased 43.0% in 2000 compared to 1999 and
decreased by 6.7% in 1999 compared to 1998. The higher volumes of purchased
power in 2000 were utilized to serve Member load that was not contractually
provided by the power marketers.
Purchased power expenses for the years 1998 through 2000 include the cost
of capacity and energy purchases under various long-term power purchase
agreements. These long-term agreements have, in some cases, take-or-pay minimum
energy requirements. For 1998 through 2000, Oglethorpe utilized its energy from
these power purchase agreements in excess of the take-or-pay requirements.
Oglethorpe's capacity and energy expenses under these agreements amounted to
approximately $176 million in 2000, $133 million in 1999 and $173 million in
1998. For a discussion of the power purchase agreements, see Note 9 of Notes to
Financial Statements.
The increase in depreciation and amortization in 2000 was primarily due to
$10.3 million of Board approved accelerated amortization of project costs for
the Vogtle radioactive waste facility. The increase in depreciation and
amortization for 1999 compared to 1998 resulted from the amortization of the
Vogtle radioactive waste facility. The amortization of these project costs
commenced January 1, 1999. For further discussion of the Vogtle radioactive
waste facility see Note 1 of Notes to Financial Statements.
Other Income (Expense)
The higher investment income for 2000 compared to 1999 was partly due to
higher cash and temporary cash investment balances and higher interest earnings
on those investments, partly due to higher earnings from the decommissioning
fund and partly due to interest earnings on the note receivable from Smarr EMC
relating to the Sewell Creek Energy Facility. Investment income was higher in
1999 compared to 1998 partly due to higher earnings from the decommissioning
fund and partly due to interest earnings on the notes and interim financing
receivable from Smarr EMC relating to the Smarr Energy Facility and the Sewell
Creek Energy Facility. For 1999, the increase in income under the caption
"Other" is due in part to a gain of $849,000 from the sale of rail cars and a
$1,005,000 increase in patronage allocation from GTC.
Interest Charges
Interest on long-term debt and capital leases decreased 5.2% in 1999
compared to 1998 primarily as a result of interest costs savings from
refinancing transactions. Other interest expense increased 18.5% in 2000
compared to 1999 and increased 53.3% in 1999 compared to 1998. The increase in
2000 was primarily as a result of interest charges incurred on commercial paper
33
issued as interim financing for the construction of combustion turbine
facilities owned by Smarr EMC. The increase for 1999 compared to 1998 was partly
due to interest charges incurred on commercial paper issued as interim financing
for Smarr EMC and partly due to an increase in interest expense for
decommissioning (which is recorded as an offset to interest earnings on the
decommissioning fund). The increase in amortization of debt discount and expense
for 1999 compared to 1998 was primarily due to the accelerated amortization of
$7 million in premiums paid to the Federal Financing Bank (FFB) for refinancing
$89 million in 1999. These cost are being amortized over a period of
approximately 3 years beginning in 1999.
Net Margin and Comprehensive Margin
Oglethorpe's net margin for 2000, 1999 and 1998 was $20.0 million, $19.9
million and $21.1 million, respectively. Oglethorpe's margin requirement is
based on a ratio applied to interest charges. For 1999 compared to 1998, the
reduction in interest charges reduced Oglethorpe's margin requirement.
Comprehensive margin for Oglethorpe is net margin adjusted for the net change in
unrealized gains and losses on investments in available-for-sale securities.
Financial Condition
General
The principal changes in Oglethorpe's financial condition in 2000 were due
to property additions, an increase in cash and temporary cash investments and an
increase in patronage capital.
Property additions, including nuclear fuel purchases, totaled $108 million,
and were financed with funds from operations and short-term borrowings.
Oglethorpe's cash and temporary cash investments increased by $108 million
from December 31, 1999 to December 31, 2000.
Oglethorpe achieved a net margin of $20 million in 2000; however,
Oglethorpe's equity (patronage capital) increased by $23 million due to a net
change in unrealized gain on available-for-sale securities.
Capital Requirements
As part of its ongoing capital planning, Oglethorpe forecasts expenditures
required for generation facilities and other capital projects. The table below
details these expenditure forecasts for 2001 through 2003. Actual construction
costs may vary from the estimates listed below because of factors such as
changes in business conditions, fluctuating rates of load growth, environmental
requirements, design changes and rework required by regulatory bodies, delays in
obtaining necessary federal and other regulatory approvals, construction delays,
cost of capital, equipment, material and labor, and decisions whether to
purchase or construct additional generation capacity.
- ----------------------------------------------------------------------
(dollars in thousands)
Capital Expenditures(1)
- ----------------------------------------------------------------------
Year Existing Future Nuclear General
Generation(2) Generation(3) Fuel Plant Total
2001 $ 43,114 $ 280,000 $ 47,247 $ 7,612 $377,973
2002 83,979 141,500 45,768 4,000 275,247
2003 44,413 23,200 48,660 4,120 120,393
- ----------------------------------------------------------------------
Total $ 171,506 $ 444,700 $141,675 $15,732 $773,613
- ----------------------------------------------------------------------
(1) Excludes allowance for funds used during construction.
(2) Consists of capital expenditures required for environmental compliance and
for replacements and additions to facilities in-service.
(3) Expenditures relate to new generation facilities that may ultimately be
owned by a subsidiary of Oglethorpe, by Smarr EMC or by a similar separate
entity.
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $3.3 billion as of December 31, 2000. Expenditures for property
additions during 2000 amounted to $108 million and were funded with a
combination of funds from operations and short-term borrowings. These
expenditures were primarily for additions and replacements to existing
generation facilities, construction of new generation facilities (as discussed
below) and for purchases of nuclear fuel.
Over the past several years, Oglethorpe has been providing interim funding
through its commercial paper program for two combustion turbine generation
facilities that were built to meet the growth of a majority of the Members.
These two facilities are now owned by Smarr EMC, a separate entity created
specifically for this purpose that is owned by 37 of Oglethorpe's 39 Members.
Smarr EMC secured permanent financing for these facilities, the proceeds of
which were used to reimburse Oglethorpe for the interim commercial paper
financings.
34
Oglethorpe continues to fund, on an interim basis, the construction of new
generation facilities on behalf of the participating Members. As of December 31,
2000, $78 million of commercial paper was outstanding for this purpose. The
projects currently being funded include six combustion turbines (totaling 618
MW) and a 468 MW combined cycle facility. Four of the six combustion turbines
are expected to be in-service in the summer of 2002, and the two remaining
combustion turbines and the combined cycle facility are expected to be
in-service in the summer of 2003. The costs associated with the combustion
turbines are reflected in construction work in progress and the costs associated
with the combined cycle facility are reflected in prepayments and other current
assets on Oglethorpe's balance sheet at December 31, 2000. It is anticipated
that these new facilities will ultimately be owned by a subsidiary of
Oglethorpe, Smarr EMC, or a similar separate entity.
Oglethorpe expects to issue the maximum amount of its commercial paper
($260 million) by the fall of 2001 in conjunction with the interim financing of
these new generation facilities. Oglethorpe has submitted loan applications to
RUS to provide financing for these projects and expects a response from RUS
later in 2001. If RUS funding is delayed or denied, Oglethorpe will continue to
finance these projects with funds from operations and will seek additional
construction financing until permanent financing is obtained.
Oglethorpe is also making payments under an agreement to purchase equipment
for a possible combined cycle facility for 2005. At December 31, 2000, $9
million of commercial paper was outstanding that was issued for this purpose,
and the payments are reflected in prepayments and other current assets on
Oglethorpe's balance sheet. If Oglethorpe and the Members elect to build this
project, Oglethorpe anticipates that it will continue to provide interim
construction funding until permanent financing is obtained. The estimated
capital expenditures related to this project, which are not included in the
capital expenditure table above, are approximately $215 million over the next
three years. If this project is not ultimately built, Oglethorpe will pursue a
sale of the equipment.
In addition to the funds needed for capital expenditures, approximately
$453 million will be required over the next three years (2001-2003) for current
sinking fund requirements and maturities of long-term debt. Of this amount, $294
million, or 65%, relates to the repayment of RUS and FFB debt. In addition,
Oglethorpe anticipates that it will refund $143 million of the $453 million due
over the next three years with proceeds from the issuance of new tax-exempt
pollution control bonds ("PCBs").
Liquidity and Sources of Capital
In the past, Oglethorpe has obtained the majority of its long-term
financing from RUS-guaranteed loans funded by FFB. Oglethorpe has also obtained
a substantial portion of its long-term financing requirements from the issuance
of PCBs.
In addition, Oglethorpe's operations have consistently provided a sizable
contribution to its funding of capital requirements, such that internally
generated funds have provided interim funding or long-term capital for nuclear
fuel reloads, general plant facilities, replacements and additions to existing
facilities, and retirement of long-term debt. Oglethorpe anticipates that it
will continue to meet these types of capital requirements through 2003 with
funds generated from operations. As discussed above, Oglethorpe is currently
providing interim financing for new generation facilities with a combination of
short-term borrowings and funds from operations until permanent financing is
obtained.
To meet short-term cash needs and liquidity requirements, Oglethorpe had,
as of December 31, 2000, (i) approximately $331 million in cash and temporary
cash investments, (ii) $82 million in other short-term investments and (iii) up
to $232 million available under the following credit facilities:
- ---------------------------------------------------------------------------
(dollars in thousands)
Authorized Available
Short-Term Credit Facilities Amount Amount
- ---------------------------------------------------------------------------
Committed line of credit:
Commercial paper $ 260,000 $ 182,000
Uncommitted line of credit:
National Rural Utilities
Cooperative Finance
Corporation 50,000 50,000
- ---------------------------------------------------------------------------
35
Under its commercial paper program, Oglethorpe may issue commercial paper
not to exceed $260 million outstanding at any one time. The commercial paper is
backed 100% by committed lines of credit provided by a group of banks that was
syndicated by Bank of America.
Oglethorpe has minimum liquidity requirements in conjunction with certain
financial agreements currently in place. These agreements include the commercial
paper line of credit, the interest rate swap arrangements relating to two PCB
transactions and the Rocky Mountain lease transactions. The maximum amount of
liquidity that could be required under these agreements is $80 million. As of
December 31, 2000, the required amount was $78 million.
Refinancing Transactions
Oglethorpe has a program under which it is refinancing, on a continued
tax-exempt basis, the annual principal maturities of serial bonds and the annual
sinking fund payments of term bonds originally issued on behalf of Oglethorpe by
the Development Authority of Burke County and the Development Authority of
Monroe County. The refinancing of these PCB principal maturities allows
Oglethorpe to preserve a low-cost source of financing. To date, Oglethorpe has
refinanced approximately $111 million under this program, including $22 million
of PCB principal which matured on January 1, 2001. Oglethorpe also has Board
approval to refinance Burke and Monroe principal of $23 million maturing on
January 1, 2002.
In connection with a corporate restructuring in 1997 in which Oglethorpe
sold its transmission assets to GTC, GTC assumed a portion of the indebtedness
associated with PCBs. Under an indemnity agreement executed in connection with
this assumption, GTC is entitled to participate in any refinancing of this PCB
debt by Oglethorpe by agreeing to assume a portion of the refinancing debt.
However, GTC agreed not to participate in Oglethorpe's refinancing of the Burke
and Monroe principal payments due January 1, 2000, 2001 and 2002. Pursuant to
this agreement, Oglethorpe provided a discount of approximately $1.1 million and
received cash of $2.6 million on the $3.7 million due from GTC in connection
with the Burke and Monroe principal payments due January 1, 2001.
The average interest rate on long-term debt was 6.21% at December 31, 2000.
Miscellaneous
Competition
The electric utility industry in the United States continues to undergo
fundamental changes and continues to become increasingly competitive. These
changes have been promoted by:
o the Energy Policy Act of 1992;
o Federal Energy Regulatory Commission ("FERC") policies regarding mergers,
transmission access and pricing and regional transmission organizations;
o federal and state deregulation initiatives;
o increased consolidation and mergers of electric utilities;
o the proliferation of power marketers and independent power producers;
o generation surpluses and deficits and transmission constraints in certain
regional markets;
o generation technology; and
o other factors.
Some states have implemented varying forms of retail competition among
power suppliers. Most other states are either in the process of implementing
retail competition or are studying options relating to retail competition.
Proposed federal legislation could mandate or encourage retail competition in
every state and otherwise deregulate the industry. No legislation related to
retail competition has yet been enacted in Georgia, and no bill is currently
pending in the Georgia legislature which would amend the Georgia Territorial
Electric Service Act (the "Territorial Act") or otherwise affect the exclusive
right of the Members to supply power to their current service territories. As a
36
result of the GPSC's order in the 1998 GPC rate case, the GPSC opened a docket
to address the mechanics of how stranded costs and stranded benefits should be
calculated, the estimated range of stranded costs and benefits, the proper level
of cost recovery, and the proper disposition of any stranded benefits. The GPSC
does not have the authority under Georgia law to order retail competition or
amend the Territorial Act. Oglethorpe and the Members have voluntarily provided
information and are participating in the GPSC proceedings. Oglethorpe and the
Members are also actively monitoring and studying legislative initiatives in
Congress and in other states to take advantage of the experiences of
cooperatives and other utilities in other states to protect their interests in
any future legislative activities in Georgia.
Under current Georgia law, the Members generally have the exclusive right
to provide retail electric service in their respective territories. Since 1973,
however, the Territorial Act has permitted limited competition among electric
utilities located in Georgia for sales of electricity to certain large
commercial or industrial customers. The owner of any new facility may receive
electric service from the power supplier of its choice if the facility is
located outside of municipal limits and has a connected load upon initial full
operation of 900 kilowatts or more. The Members, with Oglethorpe's support, are
actively engaged in competition with other retail electric suppliers for these
new commercial and industrial loads. While the competition for 900-kilowatt
loads represents only limited competition in Georgia, this competition has given
Oglethorpe and the Members the opportunity to develop resources and strategies
to prepare for an increasingly competitive market.
Oglethorpe cannot predict at this time the outcome of the various
developments that may lead to increased competition in the electric utility
industry or the effect of such developments on Oglethorpe or the Members.
Nonetheless, Oglethorpe has taken several steps to prepare for and adapt to the
fundamental changes that have occurred or appear likely to occur in the electric
utility industry and to reduce stranded costs. In 1997, Oglethorpe divided
itself into separate generation, transmission and system operations companies in
order to better serve its Members in a deregulated and competitive environment.
Oglethorpe also has pursued an interest cost reduction program, which has
included refinancings and prepayments of various debt issues, and that has
provided significant cost savings. Oglethorpe has also entered into arrangements
with power marketers to reduce power costs and to provide for future load
requirements without taking all the risk associated with traditional suppliers.
(See "Results of Operations--Power Marketer Arrangements.")
Oglethorpe and the Members continue to consider and evaluate a wide array
of other potential actions to meet future power supply needs, to reduce costs,
to reduce risks of the increasingly competitive generation business and to
respond more effectively to increasing competition. Among the alternatives
subject to such consideration are:
o additional power marketing arrangements or other alliance arrangements;
o whether potential load fluctuation risks in a competitive retail
environment can be shifted to other wholesale suppliers;
o whether power supply requirements will continue to be met by the current
mix of ownership and purchase arrangements;
o whether future power supply resources will be owned by Oglethorpe or by
other entities;
o whether disposition of existing assets or asset classes would be advisable;
o the effects of nuclear license extensions;
o ways to facilitate the prepayment of RUS-guaranteed indebtedness;
o the effects of proliferation of services offered by electric utilities; and
o other regulatory and business changes that may affect relative values of
generation classes or have impacts on the electric industry.
These activities are in various stages of study and consideration. Such
studies and consideration necessarily take account of and are subject to legal,
regulatory and contractual (including financing and plant co-ownership
arrangements) considerations.
Under the Wholesale Power Contracts, the Members may satisfy all or a
portion of their requirements above their existing Oglethorpe purchase
obligations with purchases from Oglethorpe or other suppliers. The Members are
now purchasing varying portions of their requirements from other suppliers.
37
Many Members are also providing or considering proposals to provide
non-traditional products and services such as telecommunications and other
services. Depending on the nature of future competition in Georgia, there could
be reasons for the Members to separate their physical distribution business from
their energy business, or otherwise restructure their current businesses to
operate more effectively under retail competition.
Oglethorpe's ongoing consideration of industry trends and developments in
general, and specifically its strategic alternatives with respect to existing
and future power supply arrangements and its efforts to explore debt prepayments
with RUS, may present opportunities for Oglethorpe to reduce costs, reduce risks
and otherwise to respond more effectively to increasing competition. However,
Oglethorpe cannot predict at this time the results of these matters or any
action Oglethorpe might take based thereon.
Oglethorpe has deferred recognition of certain costs of providing services
to the Members and certain income items pursuant to Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation." Note 1 of Notes to Financial Statements sets forth the
regulatory assets and liabilities reflected on Oglethorpe's balance sheet as of
December 31, 2000. Regulatory assets represent certain costs that are assured to
be recoverable by Oglethorpe from the Members in the future through the
ratemaking process. Regulatory liabilities represent certain items of income
that are being retained by Oglethorpe and that will be applied in the future to
reduce Member revenue requirements. (See "General--Rates and Regulation.") In
the event that competitive or other factors result in cost recovery practices
under which Oglethorpe can no longer apply the provisions of SFAS No. 71,
Oglethorpe would be required to eliminate all regulatory assets and liabilities
that could not otherwise be recognized as assets and liabilities by businesses
in general. In addition, Oglethorpe would be required to determine any
impairment to other assets, including plant, and write-down those assets, if
impaired, to their fair value.
Decommissioning Costs
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry regarding
the recognition, measurement and classification of decommissioning costs for
nuclear generating facilities in financial statements of electric utilities. In
response to these questions, the Financial Accounting Standards Board has issued
an Exposure Draft of a proposed Statement on "Accounting for Certain Liabilities
Related to Closure or Removal of Long-Lived Assets." The proposed Statement
would require the recognition of the entire obligation for decommissioning at
its present value as a liability in the financial statements. Rate-regulated
utilities would also recognize an offsetting asset for differences in the timing
of recognition of the costs of decommissioning for financial reporting and
ratemaking purposes. Oglethorpe's management does not believe that this proposed
Statement would have an adverse effect on results of operations due to its
current and future ability to recover decommissioning costs through rates.
Assuming extensions of the respective licenses are not obtained, it is
expected that Plant Hatch and Plant Vogtle will begin the decommissioning
process in 2014 and 2027, respectively. The expected timing of payments for
decommissioning costs will extend for a period of 9 to 14 years. Oglethorpe's
management does not expect such payments to have an adverse impact on liquidity
or capital resources due to available amounts that have been placed in reserves
for this purpose.
New Accounting Pronouncement
As of January 1, 2001, Oglethorpe adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The standard establishes
accounting and reporting requirements for derivative instruments, including
certain derivative instruments embedded in other contracts, and hedging
activities. It requires the recognition of all derivative instruments as assets
or liabilities in Oglethorpe's balance sheet and measurement of those
instruments at fair value. The accounting treatment of changes in fair value is
38
dependent upon whether or not a derivative instrument is designated as a hedge
and if so, the type of hedge. Oglethorpe's interest rate swap arrangements in
place at December 31, 2000 are designated as cash flow hedges. Adoption of SFAS
No. 133 on January 1, 2001, resulted in recording $33,515,000 of decline in fair
value to accumulated other comprehensive income and a comparable increase in
other liabilities.
Inflation
As with utilities generally, inflation has the effect of increasing the
cost of Oglethorpe's operations and construction program. Operating and
construction costs have been less affected by inflation over the last few years
because rates of inflation have been relatively low.
Forward-Looking Statements and Associated Risks
This Annual Report on Form 10-K contains forward-looking statements,
including statements regarding, among other items, (i) anticipated trends in
Oglethorpe's business, (ii) Oglethorpe's future power supply requirements,
resources and arrangements and (iii) disclosures regarding market risk included
in Item 7A. Some forward-looking statements can be identified by use of terms
such as "may," "will," "expects," "anticipates," "believes," "intends,"
"projects" or similar terms. These forward-looking statements are based largely
on Oglethorpe's current expectations and are subject to a number of risks and
uncertainties, certain of which are beyond Oglethorpe's control. For certain
factors that could cause actual results to differ materially from those
anticipated by these forward-looking statements, see "Competition" herein and
"OGLETHORPE'S POWER SUPPLY RESOURCES--Future Power Resources", "THE MEMBERS AND
THEIR POWER SUPPLY RESOURCES--Future Power Resources" and "FACTORS AFFECTING THE
ELECTRIC UTILITY INDUSTR in Item 1. In light of these risks and uncertainties,
Oglethorpe can give no assurance that events anticipated by the forward-looking
statements contained in this Annual Report will in fact transpire.
39
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oglethorpe is exposed to market risk, including changes in interest rates,
in the value of equity securities, and in the market price of electricity.
Oglethorpe's use of derivative financial or commodity instruments is for the
purpose of mitigating business risks and is not for trading purposes.
Oglethorpe has established a Risk Management Committee to provide general
management oversight over all risk management activities, including commodity
trading, fuels management, debt management and investment portfolio management.
The committee consists of senior executive officers, including the Chief
Executive Officer and the Chief Operating Officer. The committee has implemented
a comprehensive risk management policy, which includes authority limits and
credit policies. The committee regularly meets, reviews risk management reports
and reports activities to the Audit Committee of the Board of Directors.
Interest Rate Risk
Oglethorpe is exposed to the risk of changes in interest rates due to the
significant amount of financing obligations it has entered into, including fixed
and variable rate debt and interest rate swap transactions. Oglethorpe's
objective in managing interest rate risk is to maintain a balance of fixed and
variable rate debt that will lower its overall borrowing costs within reasonable
risk parameters. As part of this debt management strategy, Oglethorpe has a
guideline of having between 15% and 30% variable rate debt to total debt. At
December 31, 2000, Oglethorpe had 14% of its debt in a variable rate mode.
The table below details Oglethorpe's debt instruments and provides the fair
value at December 31, 2000, the outstanding balance at the beginning and end of
each year and the annual principal maturities and associated average interest
rates.
(dollars in thousands)
Fair Value Cost
----------- ------------------------------------------------------------------------------
2000 2001 2002 2003 2004 2005 Thereafter
---- ---- ---- ---- ---- ---- ----------
Fixed Rate Debt
- ---------------
Beginning of year $2,438,663 $2,321,527 $2,219,056 $2,059,686 $1,939,763 $1,810,010
Maturities (117,136) (102,471) (159,370) (119,923) (129,753)
--------- --------- --------- --------- ---------
End of year $2,644,443 $2,321,527 $2,219,056 $2,059,686 $1,939,763 $1,810,010
========= ========= ========= ========= =========
Average interest rate 6.09% 6.07% 6.18% 6.08% 6.09% 6.48%
Variable Rate Debt
- ------------------
Beginning of year $ 447,031 $ 441,492 $ 436,911 $ 386,218 $ 381,545 $376,810
Maturities (5,539) (4,581) (50,693) (4,673) (4,735)
--------- --------- --------- --------- ---------
End of year $443,924 $ 441,492 $ 436,911 $ 386,218 $ 381,545 $ 376,810
========= ========= ========= ========= =========
Average interest rate(1) 5.37% 5.35% 5.46% 5.51% 5.46% 4.71%
Interest Rate Swaps(2)
- -------------------
Beginning of year $ 260,149 $ 256,001 $ 251,420 $ 246,536 $ 241,315 $238,343
Maturities (4,148) (4,581) (4,884) (5,221) (2,972)
--------- --------- --------- --------- ---------
End of year $260,149 $ 256,001 $ 251,420 $ 246,536 $ 241,315 $ 238,343
========= ========= ========= ========= =========
Average interest rate 5.82% 5.83% 5.83% 5.83% 5.67% 5.80%
Unrealized loss on swaps ($33,515)
(1) Future variable debt interest rates are adjusted based on a forward U.S.
Treasury yield curve.
(2) The interest rate swaps converted variable rate underlying debt to a fixed
rate.
40
Interest Rate Swap Transactions
To refinance high-interest rate PCBs, Oglethorpe entered into two interest
rate swap transactions with a swap counterparty, AIG Financial Products Corp.
("AIG-FP"), which were designed to create a contractual fixed rate of interest
on $322 million of variable rate PCBs. These transactions were entered into in
early 1993 on a forward basis, pursuant to which approximately $200 million of
variable rate PCBs were issued on November 30, 1993 and approximately $122
million of variable rate PCBs were issued on December 1, 1994. Oglethorpe is
obligated to pay the variable interest rate that accrues on these PCBs; however,
the swap arrangements provide a mechanism for Oglethorpe to achieve a
contractual fixed rate which is lower than Oglethorpe would have obtained had it
issued fixed rate bonds. Oglethorpe's use of interest rate derivatives is
currently limited to these two swap transactions.
In connection with GTC's assumption of liability on a portion of the PCBs
pursuant to the corporate restructuring by which GTC became a separate company,
commencing April 1, 1997, GTC assumed and agreed to pay 16.86% of any amounts
due from Oglethorpe under these swap arrangements, including the net swap
payments and termination payments described below. Should GTC fail to make such
payments under the assumption, Oglethorpe remains obligated for the full amount
of such payments.
Under the swap arrangements, Oglethorpe is obligated to make periodic
payments to AIG-FP based on a notional principal amount equal to the aggregate
principal amount of the bonds outstanding during the period and a contractual
fixed rate ("Fixed Rate"), and AIG-FP is obligated to make periodic payments to
Oglethorpe based on a notional principal amount equal to the aggregate principal
amount of the bonds outstanding during the period and a variable rate equal to
the variable rate of interest accruing on the bonds during the period ("Variable
Rate"). These payment obligations are netted, such that if the Variable Rate is
less than the Fixed Rate, Oglethorpe makes a net payment to AIG-FP. Likewise, if
the Variable Rate is higher than the Fixed Rate, Oglethorpe receives a net
payment from AIG-FP. Thus, although changes in the Variable Rate affect whether
Oglethorpe is obligated to make payments to AIG-FP or is entitled to receive
payments from AIG-FP, the effective interest rate Oglethorpe pays with respect
to the PCBs is not affected by changes in interest rates. The Fixed Rate for the
$200 million of variable rate bonds issued in 1993 is 5.67% and the Fixed Rate
for the $122 million of variable rate bonds issued in 1994 is 6.01%. At December
31, 2000, the bonds issued in 1993 carried a variable rate of interest of 4.90%
and the bonds issued in 1994 carried a variable rate of interest of 4.95%. For
the three years ended December 31, 1998, 1999 and 2000, Oglethorpe has made in
connection with both interest rate swap arrangements combined net swap payments
to AIG-FP (net of amounts assumed by GTC) of $6.3 million, and $6.7 million, and
$4.3 million, respectively.
The swap arrangements extend for the life of these PCBs. If the swap
arrangements were to be terminated while the PCBs are still outstanding,
Oglethorpe or AIG-FP may owe the other party a termination payment depending on
a number of factors, including whether the fixed rate then being offered under
comparable swap arrangements is higher or lower than the Fixed Rate. Under the
terms of the swap agreements, AIG-FP has limited rights to terminate the swaps
only upon the occurrence of specified events of default or a reduction in
ratings on Oglethorpe's PCBs, without credit enhancement, to a level that is
below investment grade. Oglethorpe estimates that its maximum aggregate
liability (net of GTC's assumed percentage) for termination payments under both
swap arrangements had such payments been due on December 31, 2000 would have
been approximately $33.5 million.
Scherer Unit No. 2 Capital Lease
In December 1985, Oglethorpe sold and subsequently leased back from four
purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The
capital leases provide that Oglethorpe's rental payments vary to the extent of
interest rate changes associated with the debt used by the lessors to finance
their purchase of undivided ownership shares in the unit. The debt currently
consists of $224,702,000 in serial facility bonds due June 30, 2011 with a 6.97%
fixed rate of interest.
41
Equity Price Risk
Oglethorpe maintains trust funds, as required by the NRC, to fund certain
costs of nuclear decommissioning. (See Note 1 of Notes to Financial Statements
in Item 8.) As of December 31, 2000, these funds were invested primarily in
domestic equity securities, U.S. Government and corporate debt securities and
asset-backed securities. By maintaining a portfolio that includes long-term
equity investments, Oglethorpe intends to maximize the returns to be utilized to
fund nuclear decommissioning, which in the long-term will better correlate to
inflationary increases in decommissioning costs. However, the equity securities
included in Oglethorpe's portfolio are exposed to price fluctuation in equity
markets. A 10% decline in the value of the fund's equity securities as of
December 31, 2000 would result in a loss of value to the fund of approximately
$9 million. Oglethorpe actively monitors its portfolio by benchmarking the
performance of its investments against certain indexes and by maintaining, and
periodically reviewing, established target allocation percentages of the assets
in its trusts to various investment options. Because realized and unrealized
gains and losses from investment securities held in the decommissioning fund are
directly added to or deducted from the decommissioning reserve, fluctuations in
equity prices or interest rates do not affect Oglethorpe's net margin in the
short-term.
Commodity Price Risk
The market price of electricity is subject to price volatility associated
with changes in supply and demand in electricity markets. Oglethorpe's exposure
to electricity price risk relates to managing the supply of energy to the
Members. To secure a firm supply of electricity and to limit price volatility
associated with electricity purchases, Oglethorpe has taken several actions.
Oglethorpe supplies substantially all of the Members' requirements from a
combination of owned and leased generating plants and power purchased under
long-term contracts with other power suppliers and power marketers. Therefore,
only a small percentage of Oglethorpe's requirements is purchased in the
short-term market, and further only a small portion of these requirements is
covered by derivative commodity instruments. Oglethorpe's market price risk
exposure on these instruments is not material.
Oglethorpe has entered into a service agreement with ACES Power Marketing
("APM") under which APM acts as Oglethorpe's agent in the purchase and sale of
short-term wholesale power. APM also provides related risk management services.
APM is subject to Oglethorpe's risk management policies, including trading
authority limits. APM is an organization owned by several generation and
transmission cooperatives that provides energy trading services to rural
electric cooperatives.
Oglethorpe is also exposed to risks of changing prices for fuels, including
coal and natural gas. Oglethorpe has interests in 1,501 MW of coal-fired
capacity. Oglethorpe purchases coal under long-term contracts and in spot-market
transactions. Oglethorpe's long-term coal contracts provide volume flexibility
and fixed prices.
Oglethorpe has several power purchase contracts under which approximately
805 MW of capacity and associated energy is supplied by gas-fired facilities,
including the power purchase contracts with Doyle and Hartwell. Under these
contracts, Oglethorpe is exposed to variable energy charges, which incorporate
each facility's actual operation and maintenance and fuel costs. Oglethorpe has
the right to purchase natural gas for the Doyle and Hartwell facilities and
exercises this right from time to time to actively manage the cost of energy
supplied from these contracts and the underlying natural gas price and
operational risks.
In providing operation management services for Smarr EMC, Oglethorpe
negotiates natural gas supply and transportation contracts on behalf of Smarr
EMC, ensures that the Smarr facilities have fuel available for operations, and
42
assists Smarr EMC in managing its exposure to natural gas price and operational
risks. Oglethorpe expects to provide similar services for the gas-fired
combustion turbine and combined cycle projects currently under construction.
(See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES--Member Power Supply
Resources" in Item 1 and "PROPERTIES--Generating Facilities" and "--Fuel Supply"
in Item 2.)
Oglethorpe purchases natural gas for the above purposes under short-term
contracts that cannot be settled in cash. Oglethorpe currently has no derivative
commodity instruments with respect to coal or natural gas.
Changes in Risk Exposure
Oglethorpe's exposure to changes in interest rates, the price of equity
securities it holds, and electricity prices have not changed materially from the
previous reporting period. Oglethorpe is not aware of any facts or circumstances
that would significantly impact such exposure in the near future.
43
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index To Financial Statements
Page
Statements of Revenues and Expenses,
For the Years Ended December 31, 2000, 1999 and 1998................... 45
Statements of Patronage Capital,
For the Years Ended December 31, 2000, 1999 and 1998................... 45
Balance Sheets, As of December 31, 2000 and 1999.......................... 46
Statements of Capitalization, As of December 31, 2000 and 1999............ 48
Statements of Cash Flows,
For the Years Ended December 31, 2000, 1999 and 1998 .................. 49
Notes to Financial Statements............................................. 50
Report of Management...................................................... 63
Report of Independent Accountants......................................... 63
44
STATEMENTS OF REVENUES AND EXPENSES
For the years ended December 31, 2000, 1999 and 1998
(dollars in thousands)
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
Operating revenues (Note 1):
Sales to Members $ 1,146,064 $ 1,122,336 $ 1,095,904
Sales to non-Members 53,333 53,896 48,263
- -----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,199,397 1,176,232 1,144,167
- -----------------------------------------------------------------------------------------------------------------------------
Operating expenses:
Fuel 216,952 196,182 191,399
Production 215,834 215,517 198,378
Purchased power (Note 9) 403,574 401,719 387,662
Depreciation and amortization 142,082 130,883 124,074
Income taxes (Note 3) - - -
- -----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 978,442 944,301 901,513
- -----------------------------------------------------------------------------------------------------------------------------
Operating margin 220,955 231,931 242,654
- -----------------------------------------------------------------------------------------------------------------------------
Other income (expense):
Investment income 42,897 33,262 27,767
Amortization of deferred gains (Notes 1 and 4) 2,475 2,475 2,486
Amortization of net benefit of sale of income
tax benefits (Note 1) 11,195 11,195 11,195
Allowance for equity funds used during
construction (Note 1) 204 180 158
Other 4,068 3,433 687
- -----------------------------------------------------------------------------------------------------------------------------
Total other income 60,839 50,545 42,293
- -----------------------------------------------------------------------------------------------------------------------------
Interest charges:
Interest on long-term debt and capital leases 221,893 224,489 236,692
Other interest 21,954 18,531 12,086
Allowance for debt funds used during construction (Note 1) (3,522) (1,570) (1,679)
Amortization of debt discount and expense 21,491 21,088 16,768
- -----------------------------------------------------------------------------------------------------------------------------
Net interest charges 261,816 262,538 263,867
- -----------------------------------------------------------------------------------------------------------------------------
Net margin 19,978 19,938 21,080
Net change in unrealized gain (loss) on
available-for-sale securities 2,679 (2,614) 1,112
- -----------------------------------------------------------------------------------------------------------------------------
Comprehensive margin $ 22,657 $ 17,324 $ 22,192
- -----------------------------------------------------------------------------------------------------------------------------
STATEMENTS OF PATRONAGE CAPITAL
For the years ended December 31, 2000, 1999 and 1998
(dollars in thousands)
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
Patronage capital and membership fees -
beginning of year (Note 1) $ 370,025 $ 352,701 $ 330,509
Comprehensive margin 22,657 17,324 22,192
- -----------------------------------------------------------------------------------------------------------------------------
Patronage capital and membership fees - end of year $ 392,682 $ 370,025 $ 352,701
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
45
BALANCE SHEETS
December 31, 2000 and 1999
(dollars in thousands)
2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Assets
Electric plant (Notes 1, 4 and 6):
In service $ 4,883,680 $ 4,854,037
Less: Accumulated provision for depreciation (1,752,176) (1,625,933)
- -----------------------------------------------------------------------------------------------------------------------------
3,131,504 3,228,104
Nuclear fuel, at amortized cost 83,470 84,565
Construction work in progress 62,357 18,299
- -----------------------------------------------------------------------------------------------------------------------------
Total electric plant 3,277,331 3,330,968
- -----------------------------------------------------------------------------------------------------------------------------
Investments and funds (Notes 1 and 2):
Decommissioning fund, at market 148,300 135,703
Deposit on Rocky Mountain transactions, at cost 63,665 59,579
Bond, reserve and construction funds, at market 29,167 31,158
Investment in associated companies, at cost 19,997 17,919
Other, at cost 1,513 2,535
- -----------------------------------------------------------------------------------------------------------------------------
Total investments and funds 262,642 246,894
- -----------------------------------------------------------------------------------------------------------------------------
Current assets:
Cash and temporary cash investments, at cost (Note 1) 330,622 222,814
Other short-term investments, at market 81,715 75,482
Receivables 143,353 109,705
Inventories, at average cost (Note 1) 75,389 89,766
Notes receivable (Note 5) 1,032 94,070
Prepayments and other current assets 59,824 19,293
- -----------------------------------------------------------------------------------------------------------------------------
Total current assets 691,935 611,130
- -----------------------------------------------------------------------------------------------------------------------------
Deferred charges:
Premium and loss on reacquired debt, being amortized (Note 5) 175,944 196,289
Deferred amortization of Scherer leasehold (Note 4) 102,753 101,404
Discontinued projects, being amortized (Note 1) 9,490 28,020
Deferred debt expense, being amortized 16,968 17,070
Other (Note 1) 31,107 32,847
- -----------------------------------------------------------------------------------------------------------------------------
Total deferred charges 336,262 375,630
- -----------------------------------------------------------------------------------------------------------------------------
Total assets $ 4,568,170 $ 4,564,622
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
46
(dollars in thousands)
2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Equity and Liabilities
Capitalization (see accompanying statements):
Patronage capital and membership fees (Note 1) $ 392,682 $ 370,025
Long-term debt 3,019,019 3,103,590
Obligation under capital leases (Note 4) 267,449 275,224
Obligation under Rocky Mountain transactions (Note 1) 63,665 59,579
- -----------------------------------------------------------------------------------------------------------------------------
Total capitalization 3,742,815 3,808,418
- -----------------------------------------------------------------------------------------------------------------------------
Current liabilities:
Long-term debt and capital leases due within one year (Note 5) 136,053 129,419
Accounts payable 114,964 69,555
Notes payable (Note 5) 78,482 88,479
Accrued interest 67,394 50,201
Other current liabilities 23,691 9,344
- -----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 420,584 346,998
- -----------------------------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities:
Gain on sale of plant, being amortized (Note 4) 53,332 55,807
Net benefit of sale of income tax benefits, being amortized (Note 1) 10,012 18,021
Net benefit of Rocky Mountain transactions, being amortized (Note 1) 82,819 86,004
Accumulated deferred income taxes (Note 3) 63,485 63,203
Decommissioning reserve (Note 1) 174,553 164,510
Other 20,570 21,661
- -----------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 404,771 409,206
- -----------------------------------------------------------------------------------------------------------------------------
Total equity and liabilities $ 4,568,170 $ 4,564,622
- -----------------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 4 and 9)
- -----------------------------------------------------------------------------------------------------------------------------
47
STATEMENTS OF CAPITALIZATION
December 31, 2000 and 1999
(dollars in thousands)
2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Long-term debt (Note 5):
Mortgage notes payable to the Federal Financing Bank (FFB) at interest rates
varying from 4.66% to 8.43% (average rate of 6.40% at December 31, 2000)
due in quarterly installments through 2023 $2,248,502 $2,326,730
Mortgage notes payable to the Rural Utilities Service (RUS) at an interest
rate of 5% due in monthly installments through 2021 13,344 13,749
Mortgage notes issued in conjunction with the sale by public authorities of
pollution control revenue bonds (PCBs):
o Series 1992A
Serial bonds, 5.95% to 6.80%, due serially from 2001 through 2012 107,820* 113,745*
o Series 1993
Serial bonds, 4.35% to 5.25%, due serially from 2001 through 2013 33,410* 34,544*
o Series 1993A
Adjustable tender bonds, 4.90%, due 2001 through 2016 192,420* 195,015*
o Series 1993B
Serial bonds, 4.35% to 5.05%, due serially from 2001 through 2008 105,980* 113,750*
o Series 1994
Serial bonds, 6.0% to 7.125%, due serially from 2001 through 2015 8,930* 9,315*
Term bonds, 7.15%, due 2016 to 2021 11,550* 11,550*
o Series 1994A
Adjustable tender bonds, 4.95%, due 2001 to 2019 120,500* 122,740*
o Series 1994B
Serial bonds, 6.00% to 6.45%, due serially from 2001 through 2005 7,585* 9,125*
o Series 1998A
Adjustable tender bonds, 4.10% to 4.40%, due 2019 116,925* 116,925*
o Series 1998B
Adjustable tender bonds, 4.10% to 4.45%, due 2019 100,000* 100,000*
o Series 1999A
Adjustable tender bonds, 5.10%, due 2020 20,070 20,070
o Series 1999B
Adjustable tender bonds, 5.10%, due 2020 68,705 68,705
Unsecured notes issued in conjunction with the sale by public authorities of
pollution control revenue bonds:
o Series 2000
Adjustable tender bonds, 5.10%, due 2021 21,950 -
CoBank, ACB notes payable:
o Headquarters mortgage note payable: fixed at 7.52% through July 31, 2001,
due in quarterly installments through January 1, 2009 3,212 3,602
o Transmission mortgage note payable: fixed at 8.13% through February 28, 2001;
due in bi-monthly installments through November 1, 2018 1,770 1,797
o Transmission mortgage note payable: fixed at 8.13% through February 28, 2001;
due in bi-monthly installments through September 1, 2019 6,815 6,906
o Medium-term loan, variable at 7.23% to 7.36%, due at various maturities
through October 2001, due March 31, 2003 46,065 46,065
National Rural Utilities Cooperative Finance Corporation mortgage note payable:
o Medium-term loan fixed at 6.575%, due March 31, 2003 46,065 46,065
- -----------------------------------------------------------------------------------------------------------------------------
3,281,618 3,360,398
*Less: Portion (16.86%) of PCBs assumed by Georgia Transmission Corporation (135,775) (135,775)
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term debt, net 3,145,843 3,224,623
Less:Long-term debt due within one year (126,824) (121,033)
- -----------------------------------------------------------------------------------------------------------------------------
Long-term debt, excluding amount due within one year 3,019,019 3,103,590
Obligation under capital leases, long-term (Note 4) 267,449 275,224
Obligation under Rocky Mountain transactions, long-term (Note 1) 63,665 59,579
Patronage capital and membership fees (Note 1) 392,682 370,025
- -----------------------------------------------------------------------------------------------------------------------------
Total capitalization $3,742,815 $3,808,418
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
48
STATEMENTS OF CASH FLOWS
For the years ended December 31, 2000, 1999 and 1998
(dollars in thousands)
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
Net margin $ 19,978 $ 19,938 $ 21,080
- -----------------------------------------------------------------------------------------------------------------------------
Adjustments to reconcile net margin to net cash provided by
operating activities:
Depreciation and amortization 188,870 177,065 170,466
Interest on decommissioning reserve 11,007 12,266 9,716
Amortization of deferred gains (2,475) (2,474) (2,486)
Amortization of net benefit of sale of income tax benefits (11,195) (11,195) (11,195)
Allowance for equity funds used during construction (204) (180) (158)
Deferred income taxes 283 - 86
Other 453 1,465 491
Change in net current assets, excluding long-term debt due
within one year:
Receivables (33,649) 1,214 (5,025)
Inventories 14,377 (12,983) (11,255)
Prepayments and other current assets 2,398 2,102 (8,865)
Accounts payable 45,409 22,879 (4,427)
Accrued interest 17,192 40,128 (2,887)
Accrued and withheld taxes 648 (188) (302)
Other current liabilities 13,698 (8,584) 9,472
- -----------------------------------------------------------------------------------------------------------------------------
Total adjustments 246,812 221,515 143,631
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 266,790 241,453 164,711
- -----------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Property additions (108,254) (41,829) (43,904)
Activity in decommissioning fund - Purchases (735,352) (608,471) (504,720)
- Proceeds 722,620 591,851 490,450
Activity in bond, reserve and construction funds - Purchases (12,699) (23,325) -
- Proceeds 15,319 24,053 893
Decrease (increase) in other short-term investments (4,181) (3,718) 24,137
Increase in investment in associated organizations (2,078) (1,688) (291)
Decrease (increase) in notes receivable (143) 97 60
Other - generation equipment deposits (42,929) - -
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (167,697) (63,030) (33,375)
- -----------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Debt proceeds, net 26,260 18,196 15,958
Debt payments (100,729) (68,517) (86,889)
Premium paid on refinancing of debt - - (24,041)
(Decrease) increase in notes payable (Note 5) (9,997) 37,493 50,986
Decrease (increase) in note receivable under interim financing
agreement (Note 5) 93,181 (49,016) (44,330)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities 8,715 (61,844) (88,316)
- -----------------------------------------------------------------------------------------------------------------------------
Net increase in cash and temporary cash investments 107,808 116,579 43,020
Cash and temporary cash investments at beginning of year 222,814 106,235 63,215
- -----------------------------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year $330,622 $ 222,814 $ 106,235
- -----------------------------------------------------------------------------------------------------------------------------
Cash paid for:
Interest (net of amounts capitalized) $212,126 $ 189,056 $ 240,270
Income taxes - - -
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
49
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2000, 1999 and 1998
1. Summary of significant accounting policies:
a. Business description
Oglethorpe Power Corporation (Oglethorpe) is an electric membership
corporation incorporated in 1974 and headquartered in suburban Atlanta.
Oglethorpe provides wholesale electric service, on a not-for-profit basis, to 39
of Georgia's 42 Electric Membership Corporations (EMCs). These 39 electric
distribution cooperatives (Members) in turn distribute energy on a retail basis
to approximately 3.4 million people across two-thirds of the State. Oglethorpe
is the nation's largest electric cooperative in terms of operating revenues,
assets, kilowatt-hour sales and, through its Members, consumers served.
Oglethorpe owns or leases undivided interests in thirteen generating units
totaling 3,335 megawatts (MW) of capacity. Oglethorpe also purchases a total of
1200 MW of capacity pursuant to power purchase agreements.
b. Basis of accounting
Oglethorpe follows generally accepted accounting principles and the
practices prescribed in the Uniform System of Accounts of the Federal Energy
Regulatory Commission (FERC) as modified and adopted by the Rural Utilities
Service (RUS).
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities as of December 31, 2000 and 1999
and the reported amounts of revenues and expenses for each of the three years
ending December 31, 2000. Actual results could differ from those estimates.
c. Patronage capital and membership fees
Oglethorpe is organized and operates as a cooperative. The Members paid a
total of $195 in membership fees. Patronage capital includes retained net margin
of Oglethorpe and the unrealized gain or loss on available-for-sale securities,
excluding securities held in the decommissioning fund. For 2000, 1999 and 1998
the unrealized gain or loss on available-for-sale securities were $1,070,000,
($1,609,000) and $1,005,000, respectively. As provided in the bylaws, any excess
of revenue over expenditures from operations is treated as advances of capital
by the Members and is allocated to each of them on the basis of their
electricity purchases from Oglethorpe.
Any distributions of patronage capital are subject to the discretion of the
Board of Directors, subject to Mortgage Indenture requirements. Under the
Mortgage Indenture, Oglethorpe is prohibited from making any distribution of
patronage capital to the Members if, at the time thereof or giving effect
thereto, (i) an event of default exists under the Mortgage Indenture, (ii)
Oglethorpe's equity as of the end of the immediately preceding fiscal quarter is
less than 20% of Oglethorpe's total capitalization, or (iii) the aggregate
amount expended for distributions on or after the date on which Oglethorpe's
equity first reaches 20% of Oglethorpe's total capitalization exceeds 35% of
Oglethorpe's aggregate net margins earned after such date. This last
restriction, however will not apply if, after giving effect to such
distribution, Oglethorpe's equity as of the end of the immediately preceding
fiscal quarter is not less than 30% of Oglethorpe's total capitalization.
d. Margin policy
For the years 1998 through 2000 under the Mortgage Indenture, Oglethorpe
was required to produce a Margins for Interest (MFI) Ratio of at least 1.10.
e. Operating revenues
Operating revenues consist primarily of electricity sales pursuant to
long-term wholesale power contracts which Oglethorpe maintains with each of its
Members. These wholesale power contracts obligate each Member to pay Oglethorpe
for capacity and energy furnished in accordance with rates established by
Oglethorpe. Energy furnished is determined based on meter readings which are
50
conducted at the end of each month. Actual energy costs are compared, on a
monthly basis, to the billed energy costs, and an adjustment to revenues is made
such that energy revenues are equal to actual energy costs.
Revenues from Jackson EMC and Cobb EMC, two of Oglethorpe's Members,
accounted for 11.8% and 11.9% in 2000, 11.8% and 11.7% in 1999, and 11.4% and
12.8% in 1998, respectively, of Oglethorpe's total operating revenues.
f. Nuclear fuel cost
The cost of nuclear fuel, including a provision for the disposal of spent
fuel, is being amortized to fuel expense based on usage. The total nuclear fuel
expense for 2000, 1999 and 1998 amounted to $47,105,000, $46,226,000 and
$46,751,000, respectively.
Contracts with the U.S. Department of Energy (DOE) have been executed to
provide for the permanent disposal of spent nuclear fuel. DOE failed to begin
disposing of spent fuel in January 1998 as required by the contracts, and
Georgia Power Company (GPC), as agent for the co-owners of the plants, is
pursuing legal remedies against DOE for breach of contract. Effective June 2000,
an on-site dry storage facility for Plant Hatch became operational. Sufficient
capacity is believed to be available to continue dry storage operations at Plant
Hatch through the life of the plant. The Plant Vogtle spent fuel storage is
expected to be sufficient into 2014. In addition, GPC, as agent for the
co-owners of the plant, is a member of Private Fuel Storage, LLC, a joint
utility effort to develop a private spent fuel storage facility for temporary
storage of spent nuclear fuel. This facility is planned to begin operation as
early as the year 2003; however, the timing of availability is uncertain.
The Energy Policy Act of 1992 required that utilities with nuclear plants
be assessed over a 15-year period an amount which will be used by DOE for the
decontamination and decommissioning of its nuclear fuel enrichment facilities.
The amount of each utility's assessment was based on its past purchases of
nuclear fuel enrichment services from DOE. Based on its ownership in Plants
Hatch and Vogtle, Oglethorpe has a remaining nuclear fuel asset of approximately
$9,463,000, which is being amortized to nuclear fuel expense over the next 10
years. Oglethorpe has also recorded an obligation to DOE which approximated
$7,085,000 at December 31, 2000.
g. Nuclear decommissioning
Oglethorpe's portion of the costs of decommissioning co-owned nuclear
facilities is estimated as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
Hatch Hatch Vogtle Vogtle
Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2
- --------------------------------------------------------------------------------
Year of site study 2000 2000 2000 2000
Expected start date
of decommissioning 2014 2018 2027 2029
Decommissioning cost:
Discounted $139,000 $175,000 $137,000 $171,000
Undiscounted 265,000 400,000 475,000 650,000
- --------------------------------------------------------------------------------
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in regulatory requirements, changes in technology, and
changes in costs of labor, materials and equipment.
Based on the most recent Nuclear Regulatory Commission (NRC) funding
requirement, Oglethorpe has determined that its existing decommmissioning
reserve together with expected earnings on the external funds, should be
sufficient to meet the current projected required funding levels for Plant
Vogtle and Plant Hatch. Therefore, Oglethorpe did not record an annual provision
for decommissioning in 2000 and 1999. Based on current assumptions, Oglethorpe's
management does not expect to record an annual provision for decommissioning in
future years. The annual provision for decommissioning for 1998 was $2,597,000
and was accounted for as depreciation expense with an offsetting credit to a
decommissioning reserve. In developing the amount of the annual provision for
1999 and 2000, the escalation rate was assumed to be 3.6% and return on trust
assets was assumed to be 8%, respectively. Oglethorpe's management is of the
opinion that any changes in cost estimates of decommissioning can be recovered
in future rates.
51
In compliance with a NRC regulation, Oglethorpe maintains an external trust
fund to provide for a portion of the cost of decommissioning its nuclear
facilities. The NRC regulation requires funding levels based on average expected
cost to decommission only the radioactive portions of a typical nuclear
facility.
h. Depreciation
Depreciation is computed on additions when they are placed in service using
the composite straight-line method. Annual depreciation rates in effect in 2000,
1999 and 1998 were as follows:
2000 1999 1998
- ------------------------------------------------------------
Steam production 1.98% 2.15% 2.14%
Nuclear production 2.48% 2.69% 2.77%
Hydro production 2.00% 2.00% 2.00%
Other production 3.75% 3.75% 3.75%
Transmission 2.75% 2.75% 2.75%
General 2.00-33.33% 2.00-33.33% 2.00-20.00%
- ------------------------------------------------------------
i. Electric plant
Electric plant is stated at original cost, which is the cost of the plant
when first dedicated to public service, plus the cost of any subsequent
additions. Cost includes an allowance for the cost of equity and debt funds used
during construction. The cost of equity and debt funds is calculated at the
embedded cost of all such funds.
Maintenance and repairs of property and replacements and renewals of items
determined to be less than units of property are charged to expense.
Replacements and renewals of items considered to be units of property are
charged to the plant accounts. At the time properties are disposed of, the
original cost, plus cost of removal, less salvage of such property, is charged
to the accumulated provision for depreciation.
j. Bond, reserve and construction funds
Bond, reserve and construction funds for pollution control revenue bonds
(PCBs) are maintained as required by Oglethorpe's bond agreements. Bond funds
serve as payment clearing accounts, reserve funds maintain amounts equal to the
maximum annual debt service of each bond issue and construction funds hold bond
proceeds for which construction expenditures have not yet been made. As of
December 31, 2000 and 1999, substantially all of the funds were invested in U.S.
Government securities.
k. Cash and temporary cash investments
Oglethorpe considers all temporary cash investments purchased with a
maturity of three months or less to be cash equivalents. Temporary cash
investments with maturities of more than three months are classified as other
short-term investments.
At December 31, 2000 and 1999, $22,241,000 and $20,155,000 were restricted
by PCBs trust indentures and were utilized in January 2001 and 2000 for payment
of principal on certain PCBs, respectively.
l. Inventories
Oglethorpe maintains inventories of fossil fuels and spare parts for its
generation plants. These inventories are stated at weighted average cost on the
accompanying balance sheets.
At December 31, 2000 and 1999, fossil fuels inventories were $15,565,000
and $31,787,000, respectively. Inventories for spare parts at December 31, 2000
and 1999 were $59,824,000 and $57,979,000, respectively.
m. Deferred charges
Oglethorpe accounts for nuclear refueling outage costs on a normalized
basis. Under this method of accounting, refueling outage costs are deferred and
subsequently amortized to expense over the 18-month operating cycle of each
unit. Deferred nuclear outage costs at December 31, 2000 and 1999 were
$19,897,000 and $18,483,000, respectively.
As a result of the determination that the Plant Vogtle radioactive waste
facility has no usefulness as a radioactive waste storage facility, the
remaining project costs of $5,076,000 are reflected as deferred charges on the
accompanying balance sheets. In 1998, Oglethorpe's Board of Directors authorized
that these project costs be amortized and fully recovered through rates over a
period of four years beginning in 1999.
52
n. Deferred credits
In April 1982, Oglethorpe sold to three purchasers certain of the income
tax benefits associated with Scherer Unit No.1 and related common facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act of
1981. Oglethorpe received a total of approximately $110,000,000 from the safe
harbor lease transactions. Oglethorpe accounts for the net benefits as a
deferred credit and is amortizing the amount over the 20-year term of the
leases.
In December 1996 and January 1997, Oglethorpe entered into long-term lease
transactions for its 74.6% undivided ownership interest in Rocky Mountain,
through a wholly owned subsidiary of Oglethorpe, Rocky Mountain Leasing
Corporation (RMLC). The lease transactions are characterized as a sale and
lease-back for income tax purposes, but not for financial reporting purposes. As
a result of these leases, Oglethorpe recorded a net benefit of $95,560,000 which
was deferred and is being amortized to income over the 30-year lease-back
period.
o. Regulatory assets and liabilities
Oglethorpe is subject to the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation." Regulatory assets represent certain costs that are assured to be
recoverable by Oglethorpe from the Members in the future through the ratemaking
process. Regulatory liabilities represent certain items of income that are being
retained by Oglethorpe and that will be applied in the future to reduce Member
revenue requirements. The following regulatory assets and liabilities were
reflected on the accompanying balance sheets as of December 31, 2000 and 1999:
- --------------------------------------------------------------------------------
(dollars in thousands)
2000 1999
- --------------------------------------------------------------------------------
Premium and loss on reacquired debt $ 175,944 $ 196,289
Deferred amortization of Scherer leasehold 102,753 101,404
Discontinued projects 9,490 28,020
Other regulatory assets 28,141 29,017
Net benefit of sale of income tax benefits (10,012) (18,021)
Net benefit of Rocky Mountain transactions (82,819) (86,004)
- --------------------------------------------------------------------------------
$ 223,497 $ 250,705
- --------------------------------------------------------------------------------
In the event that competitive or other factors result in cost recovery
practices under which Oglethorpe can no longer apply the provisions of SFAS No.
71, Oglethorpe would be required to eliminate all regulatory assets and
liabilities that could not otherwise be recognized as assets and liabilities by
businesses in general. In addition, Oglethorpe would be required to determine
any impairment to other assets, including plant, and write-down those assets, if
impaired, to their fair value.
p. Presentation
Certain prior year amounts have been reclassified to conform with current
year presentation.
q. New accounting pronouncement
As of January 1, 2001, Oglethorpe adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The standard establishes
accounting and reporting requirements for derivative instruments, including
certain derivative instruments embedded in other contracts, and hedging
activities. It requires the recognition of all derivative instruments as assets
or liabilities in Oglethorpe's balance sheet and measurement of those
instruments at fair value. The accounting treatment of changes in fair value is
dependent upon whether or not a derivative instrument is designated as a hedge
and if so, the type of hedge. Oglethorpe's interest rate swap arrangements in
place at December 31, 2000 are designated as cash flow hedges. Adoption of SFAS
No. 133 on January 1, 2001, resulted in recording $33,515,000 of decline in fair
value to accumulated other comprehensive income and a comparable increase in
other liabilities. For information regarding the interest rate swap
arrangements, see Note 2.
53
2. Fair value of financial instruments:
A detail of the estimated fair values of Oglethorpe's financial instruments
as of December 31, 2000 and 1999 is as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
2000 1999
Fair Fair
Cost Value Cost Value
- --------------------------------------------------------------------------------
Cash and temporary
cash investments:
Commercial paper $ 330,052 $ 330,052 $ 220,941 $ 220,941
Cash and money
market securities 570 570 1,873 1,873
- --------------------------------------------------------------------------------
Total $ 330,622 $ 330,622 $ 222,814 $ 222,814
- --------------------------------------------------------------------------------
Other short term
investments $ 80,854 $ 81,715 $ 76,673 $ 75,482
- --------------------------------------------------------------------------------
Bond, reserve and
construction funds:
U. S. Government
securities $ 25,397 $ 25,608 $ 25,443 $ 25,025
Repurchase
agreements 3,559 3,559 6,133 6,133
- --------------------------------------------------------------------------------
Total $ 28,956 $ 29,167 $ 31,576 $ 31,158
- --------------------------------------------------------------------------------
Decommissioning
fund:
U. S. Government
securities $ 29,674 $ 31,049 $ 23,858 $ 23,574
Foreign government
securities 1,173 1,161 732 656
Commercial paper 6,183 6,180 2,387 2,388
Corporate bonds 6,784 6,929 11,215 10,891
Equity securities 80,795 85,225 69,944 77,148
Asset-backed
securities 12,156 12,406 9,954 9,751
Other bonds - - - -
Cash and money
market securities 5,350 5,350 11,293 11,295
- --------------------------------------------------------------------------------
Total $142,115 $148,300 $129,383 $135,703
- --------------------------------------------------------------------------------
Long-term debt $3,019,019 $ 3,221,692 $3,103,590 $3,007,048
- --------------------------------------------------------------------------------
Interest rate swap
(unrealized loss) $ - $ (33,515) $ - $ (18,935)
- --------------------------------------------------------------------------------
The contractual maturities of debt securities available for sale at
December 31, 2000 and 1999, regardless of their balance sheet classification,
are as follows:
- -----------------------------------------------------------------------------
(dollars in thousands)
2000 1999
Fair Fair
Cost Value Cost Value
- -----------------------------------------------------------------------------
Due within one year $ 3,559 $ 3,559 $ 6,818 $ 6,866
Due after one year
through five years 39,583 40,022 36,017 35,509
Due after five years
through ten years 12,499 12,904 11,597 11,262
Due after ten years 23,102 24,227 22,902 22,393
- -----------------------------------------------------------------------------
$ 78,743 $ 80,712 $ 77,334 $76,030
- -----------------------------------------------------------------------------
Oglethorpe uses the methods and assumptions described below to estimate the
fair value of each class of financial instruments. For cash and temporary cash
investments, the carrying amount approximates fair value because of the
short-term maturity of those instruments. The fair value of Oglethorpe's
long-term debt and the swap arrangements is estimated based on the quoted market
prices for the same or similar issues or on the current rates offered to
Oglethorpe for debt of similar maturities.
A portion (16.86%) of the interest rate swap arrangements was assumed by
Georgia Transmission Corporation (GTC) in connection with a corporate
restructuring. Under the interest rate swap arrangements, Oglethorpe makes
payments to the counterparty based on the notional principal at a contractually
fixed rate and the counterparty makes payments to Oglethorpe based on the
notional principal at the existing variable rate of the refunding bonds. The
differential to be paid or received is accrued as interest rates change and is
recognized as an adjustment to interest expense. Oglethorpe entered into the
swap arrangements for the purpose of securing a fixed rate lower than otherwise
would have been available to Oglethorpe had it issued fixed rate bonds. For the
Series 1993A notes, the notional principal at December 31, 2000 was $192,420,000
(includes the portion assumed by GTC) and the fixed swap rate is 5.67% (the
variable rate at December 31, 2000 and 1999 was 4.90% and 5.40%, respectively).
With respect to the Series 1994A notes, the notional principal at December 31,
2000 was $120,500,000 (includes the portion assumed by GTC) and the fixed swap
rate is 6.01% (the variable rate at December 31, 2000 and 1999 was 4.95% and
54
5.65%, respectively). The notional principal amount is used to measure the
amount of the swap payments and does not represent additional principal due to
the counterparty. The swap arrangements extend for the life of the refunding
bonds, with reductions in the outstanding principal amounts of the refunding
bonds causing corresponding reductions in the notional amounts of the swap
payments. Oglethorpe's portion of the estimated fair value of the swap
arrangements at December 31, 2000 and 1999 was an unrealized loss of $33,515,000
and $18,935,000, respectively, representing the estimated payment Oglethorpe
would pay if the swap arrangements were terminated. Oglethorpe may be exposed to
losses in the event of nonperformance of the counterparty, but does not
anticipate such nonperformance.
Under SFAS No. 115, "Accounting for Certain Investments in Debt and Equity
Securities," investment securities held by Oglethorpe are classified as either
available-for-sale or held-to-maturity. Available-for-sale securities are
carried at market value with unrealized gains and losses, net of any tax effect,
added to or deducted from patronage capital. Unrealized gains and losses from
investment securities held in the decommissioning fund, which are also
classified as available-for-sale, are directly added to or deducted from the
decommissioning reserve. Held-to-maturity securities are carried at cost. All
realized and unrealized gains and losses are determined using the specific
identification method. Gross unrealized gains and losses at December 31, 2000
were $15,937,000 and $8,681,000, respectively. Gross unrealized gains and losses
at December 31, 1999 were $11,451,000 and $6,740,000, respectively. Gross
unrealized gains and losses at December 31, 1998 were $12,182,000 and
$1,845,000, respectively. For 2000, 1999 and 1998 proceeds from sales of
available-for-sale securities totaled $725,240,000, $592,579,000 and
$491,343,000, respectively. Gross realized gains and losses from the 2000 sales
were $19,556,000 and $16,086,000, respectively. Gross realized gains and losses
from the 1999 sales were $29,429,000 and $22,167,000, respectively. Gross
realized gains and losses from 1998 sales were $12,892,000 and $6,602,000,
respectively.
Investments in associated companies were as follows at December 31, 2000
and 1999:
- --------------------------------------------------------------------------------
(dollars in thousands)
2000 1999
- --------------------------------------------------------------------------------
National Rural Utilities
Cooperative Finance Corp. (CFC) $ 13,476 $ 13,603
CoBank, ACB 2,407 1,577
Georgia Transmission
Corporation (GTC) 3,815 2,615
Other 299 124
- --------------------------------------------------------------------------------
Total $ 19,997 $ 17,919
- --------------------------------------------------------------------------------
The CFC investments are in the form of capital term certificates and are
required in conjunction with Oglethorpe's membership in CFC. Accordingly, there
is no market for these investments. The investments in CoBank and GTC represent
capital credits. Any distributions of capital credits are subject to the
discretion of the Board of Directors of CoBank and GTC.
The deposit, which is carried at cost, on the Rocky Mountain transactions
(see Note 1 where discussed) is invested in a guaranteed investment contract
which will be held to maturity (the end of the 30-year lease-back period). At
maturity, Oglethorpe intends to repurchase tax ownership and to retain all other
rights of ownership with respect to the plant if it is advantageous to do so.
The assets of RMLC are not available to pay creditors of Oglethorpe or its
affiliates.
In addition, from the proceeds of the Rocky Mountain transactions,
Oglethorpe paid $640,611,000 to a financial institution. In return, this
financial institution undertook to pay a portion of Oglethorpe's lease
obligations. Both Oglethorpe's interest in this payment undertaking agreement
and the corresponding lease obligations have been extinguished for financial
reporting purposes.
55
3. Income taxes:
Oglethorpe is a not-for-profit membership corporation subject to federal
and state income taxes. As a taxable electric cooperative, Oglethorpe has
annually allocated its income and deductions between Member and non-Member
activities. Any Member taxable income has been offset with a patronage exclusion
and member loss carryforwards.
Oglethorpe accounts for its income taxes pursuant to SFAS No. 109. SFAS No.
109 requires the recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been included in the
financial statements or tax returns.
A detail of the provision for income taxes in 2000, 1999 and 1998 is shown
as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
2000 1999 1998
- --------------------------------------------------------------------------------
Current
Federal $ (283) $ - $ (86)
State - - -
- --------------------------------------------------------------------------------
(283) - (86)
- --------------------------------------------------------------------------------
Deferred
Federal 283 - 86
State - - -
- --------------------------------------------------------------------------------
283 - 86
- --------------------------------------------------------------------------------
Income taxes charged
to operations $ - $ - $ -
- --------------------------------------------------------------------------------
The difference between the statutory federal income tax rate on income
before income taxes and Oglethorpe's effective income tax rate is summarized as
follows:
- --------------------------------------------------------------------------------
2000 1999 1998
- --------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Patronage exclusion (35.8%) (35.6%) (35.7%)
Other 0.8% 0.6% 0.7%
- --------------------------------------------------------------------------------
Effective income tax rate 0.0% 0.0% 0.0%
- --------------------------------------------------------------------------------
The components of the net deferred tax liabilities as of December 31, 2000
and 1999 were as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
2000 1999
- --------------------------------------------------------------------------------
Deferred tax assets
Net operating losses $ 478,497 $ 477,817
Member loss carryforwards 44,341 78,231
Tax credits (alternative minimum tax
and other) 196,452 199,650
Accounting for Rocky Mountain
transactions 312,441 309,474
Accounting for sale of income tax benefits 16,702 27,909
Accrued nuclear decommissioning expense 64,545 60,264
Accounting for asset dispositions 20,010 28,185
Other 3,000 3,540
- --------------------------------------------------------------------------------
1,135,988 1,185,070
Less: Valuation allowance (194,145) (197,343)
- --------------------------------------------------------------------------------
941,843 987,727
- --------------------------------------------------------------------------------
Deferred tax liabilities
Depreciation (738,313) (771,577)
Accounting for Rocky Mountain
transactions (195,376) (199,675)
Accounting for debt extinguishment (57,042) (64,362)
Other (14,597) (15,316)
- --------------------------------------------------------------------------------
(1,005,328) (1,050,930)
- --------------------------------------------------------------------------------
Net deferred tax liabilities $ (63,485) $ (63,203)
- --------------------------------------------------------------------------------
56
As of December 31, 2000, Oglethorpe has federal tax net operating loss
carryforwards (NOLs), alternative minimum tax credits (AMT) and unused general
business credits (consisting primarily of investment tax credits) as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
- --------------------------------------------------------------------------------
Alternative
Minimum
Expiration Date Tax Credits Tax Credits NOLs
2001 $ - $ 7,264 $ -
2002 - 130,377 7,102
2003 - 652 253,665
2004 - 55,663 114,285
2005 - 189 213,080
2006 - - 209,009
2007 - - 86,779
2008 - - 94,927
2009 - - 96,394
2010 - - 77,970
2018 - - 61,533
2019 - - 10,516
2020 - - 4,809
None 2,307 - -
- --------------------------------------------------------------------------------
$ 2,307 $ 194,145 $1,230,069
- --------------------------------------------------------------------------------
Oglethorpe has not recorded a valuation allowance with respect to its
deferred tax asset related to NOLs. Oglethorpe intends to implement available
tax planning strategies if necessary to utilize NOLs prior to their expiration
date. If any NOLs are not utilized prior to their expiration date, Oglethorpe
believes it has available options to offset the effect, if any, of NOLs
expiring. The NOL expiration dates start in the year 2002 and end in the year
2020. However, as reflected in the above valuation allowance, it is more likely
than not that the tax credits will not be utilized before expiration. The change
in the valuation allowance from 1999 to 2000 was the result of the expiration of
$3,198,000 of tax credits in 2000. It is more likely than not that the AMT
credit will be utilized.
4. Capital leases:
In December 1985, Oglethorpe sold and subsequently leased back from four
purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The gain
from the sale is being amortized over the 36-year term of the leases. The
minimum lease payments under the capital leases together with the present value
of net minimum lease payments as of December 31, 2000 are as follows:
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
2001 $ 37,629
2002 37,491
2003 37,333
2004 37,156
2005 36,961
2006-2021 420,239
- --------------------------------------------------------------------------------
Total minimum lease payments 606,809
Less: Amount representing interest
at an assumed rate of 11.05% (330,131)
- --------------------------------------------------------------------------------
Present value of net minimum lease payments 276,678
Less: Current portion (9,229)
- --------------------------------------------------------------------------------
Long-term balance $ 267,449
- --------------------------------------------------------------------------------
The capital leases provide that Oglethorpe's rental payments vary to the
extent of interest rate changes associated with the debt used by the lessors to
finance their purchase of undivided ownership shares in Scherer Unit No. 2. In
December 1997, Oglethorpe refinanced the debt supporting the Scherer Unit No. 2
lease. The refunded debt consisted of $143,200,000 in serial facility bonds with
a 9.70% fixed interest rate (pertaining to three of the lessors) and $81,500,000
in bank debt with variable interest rates ranging from 6.40% to 6.90%
(pertaining to the remaining lessor). The debt was refinanced through a
$224,700,000 issue of serial facility bonds due June 30, 2011 with a 6.97% fixed
interest rate. The transaction costs related to this transaction are reported as
deferred charges on the balance sheet and are being amortized over the remaining
life of the leases. Oglethorpe's future rental payments under its leases will
vary from amounts shown in the table above to the extent that the actual
interest rates associated with the debt of the lessors varies from the 11.05%
debt rate assumed in the table.
The Scherer Unit No. 2 lease meets the definitional criteria to be reported
on Oglethorpe's balance sheets as a capital lease. For rate-making purposes,
however, Oglethorpe treats this lease as an operating lease; that is, Oglethorpe
considers the actual rental payment on the leased asset in its cost of service.
Oglethorpe's accounting treatment for this capital lease has been modified,
therefore, to reflect its rate-making treatment. Interest expense is applied to
57
the obligation under the capital lease; then, amortization of the leasehold is
recognized, such that interest and amortization equal the actual rental payment.
Through 1994, the level of actual rental payments was such that amortization of
the Scherer Unit No. 2 leasehold calculated in this manner was less than zero.
Thereafter, the scheduled cash rental payments increase such that positive
amortization of the leasehold occurs and the entire cost of the leased asset is
recovered through the rate-making process. The difference in the amortization
recognized in this manner on the statements of revenues and expenses and the
straight-line amortization of the leasehold is reflected on Oglethorpe's balance
sheets as a regulatory asset.
In 1991 and 1992, all four of the lessors received Notices of Proposed
Adjustments from the IRS proposing adjustments to the tax benefits claimed by
these lessors in connection with their purchase and ownership of an undivided
interest in Scherer Unit No. 2. In 1994, the IRS issued a revised Notice of
Proposed Adjustments to one of the lessors which reduced the proposed
adjustments. During 1995, this lessor advised Oglethorpe that it had settled
this issue on the basis of the revised Notice of Proposed Adjustments.
Oglethorpe subsequently made a lump sum indemnity payment of $362,000 to the
lessor in order to compensate for the reduction in the lessor's tax benefits
resulting from the sale and leaseback transaction. The IRS has indicated that it
will take consistent positions with the other three lessors. If the IRS's
current positions regarding the sale and leaseback transactions were ultimately
upheld, Oglethorpe would be required to indemnify the other three lessors.
Oglethorpe's indemnification liability to the three lessors is estimated to be
approximately $1,454,000 as of December 31, 2000. This liability has been
reflected on the accompanying balance sheet.
5. Long-term debt:
Long-term debt consists of mortgage notes payable to the United States of
America acting through the Federal Financing Bank (FFB) and the RUS, mortgage
notes and unsecured notes issued in conjunction with the sale by public
authorities of PCBs, mortgage notes and unsecured notes payable to CoBank, and
mortgage notes payable to National Rural Utilities Cooperative Finance
Corporation (CFC). Oglethorpe's headquarters facility is pledged as collateral
for the CoBank headquarters note; substantially all of the owned tangible and
certain of the intangible assets of Oglethorpe are pledged as collateral for the
FFB and RUS notes, the CoBank mortgage notes, the CFC notes, and the mortgage
notes issued in conjunction with the sale of PCBs. The detail of the two
medium-term notes is included in the statements of capitalization.
In connection with a corporate restructuring effective April 1, 1997,
16.86% of the then outstanding secured PCBs was assumed by GTC. Because
Oglethorpe was not legally released from its obligation to pay this debt, the
entire debt is shown in the Statement of Capitalization as a liability of
Oglethorpe with an offsetting amount reflecting the portion assumed by GTC.
In connection with a corporate restructuring, Oglethorpe defeased
approximately $92,000,000 in principal amount of Series 1992 PCBs. Initially
these bonds were defeased with the proceeds from the issuance of approximately
$92,000,000 in commercial paper. In March and April 1998, Oglethorpe refinanced
the commercial paper issuance with two medium-term loans; one from CoBank and
one from CFC, of approximately $46,100,000 each. Oglethorpe ultimately expects
to refinance the two medium-term loans with an issuance of PCBs in the fall of
2002.
In October 2000, Oglethorpe completed a current refunding transaction
whereby $21,950,000 of PCBs were issued. The proceeds were used to make
principal payments due January 1, 2001.
GTC agreed with Oglethorpe not to participate in this $21,950,000
refinancing to the extent of their assumed obligation in the PCBs. Pursuant to
this agreement, Oglethorpe will provide a discount to GTC of approximately
$1,110,000 on the $3,701,000 of principal payments due from GTC in connection
with such refinancings. This $1,110,000 loss will be reported, together with the
unamortized transaction costs, as a deferred charge on the balance sheet and
will be amortized over four years.
The annual interest requirement for 2001 is estimated to be $219,000,000.
58
Maturities for the long-term debt and amortization of the capital lease
obligations through 2005 are as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
2001 2002 2003 2004 2005
- --------------------------------------------------------------------------------
FFB and RUS $106,623 $ 90,830 $ 96,424 $101,383 $108,711
CoBank 523 540 46,623 580 603
PCBs* 19,678 20,264 25,835 27,855 28,146
CFC - - 46,065 - -
Capital Leases 9,229 8,544 9,455 10,387 11,474
- --------------------------------------------------------------------------------
Total $136,053 $120,178 $224,402 $140,205 $148,934
- --------------------------------------------------------------------------------
*Does not contain portion assumed by GTC
The weighted average interest rate for 2000 for long-term debt and capital
leases due within one year and notes payable is 6.21%.
Oglethorpe has a commercial paper program under which it may issue
commercial paper not to exceed a $260,000,000 balance outstanding at any time.
The commercial paper may be used for working capital requirements and for
general corporate purposes. Oglethorpe's commercial paper is backed 100% by
committed lines of credit.
As of December 31, 2000 and 1999, approximately $78,000,000 and
$88,000,000, respectively, of commercial paper was outstanding. The majority of
the amount outstanding at year-end 1999 relates to commercial paper issued to
fund, on an interim basis, the construction of a combustion turbine (CT) project
completed in Summer 2000. This project is owned by a cooperative, Smarr EMC,
which is owned by 37 of Oglethorpe's 39 Members. The commercial paper was
retired in October 2000 with proceeds from permanent financing secured by Smarr
EMC on a non-recourse basis to Oglethorpe. A majority of the commercial paper
outstanding at year-end 2000 was issued to fund, on an interim basis,
construction of additional generation facilities expected to be completed in
Summer 2002 and 2003. It is expected that by the time these projects are
completed, permanent financing will have been secured and the proceeds used to
retire the commercial paper. It is anticipated these new generating facilities
will be owned either by a subsidiary of Oglethorpe, Smarr EMC, or by a similar
separate entity.
Oglethorpe has a $50,000,000 uncommitted short-term line of credit with
CFC. No balance was outstanding on this line of credit at either December 31,
2000 or 1999.
6. Electric plant and related agreements:
Oglethorpe and GPC have entered into agreements providing for the purchase
and subsequent joint operation of certain of GPC's electric generating plants. A
summary of Oglethorpe's plant investments and related accumulated depreciation
as of December 31, 2000 is as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
Accumulated
Plant Investment Depreciation
- --------------------------------------------------------------------------------
In-service
Owned property
Vogtle Units No. 1 & No. 2
(Nuclear - 30% ownership) $2,734,776 $ 931,580
Hatch Units No. 1 & No. 2
(Nuclear - 30% ownership) 531,655 249,097
Wansley Units No. 1 & No. 2
(Fossil - 30% ownership) 173,119 95,067
Scherer Unit No. 1
(Fossil - 60% ownership) 426,891 225,371
Rocky Mountain Units No. 1,
No. 2 & No. 3
(Hydro - 74.6% ownership) 556,875 61,860
Tallassee (Harrison Dam)
(Hydro - 100% ownership) 9,270 2,508
Wansley (Combustion Turbine -
30% ownership) 3,629 1,600
Generation step-up substations 60,470 26,387
Other 85,667 33,617
Property under capital lease
Scherer Unit No. 2
(Fossil - 60% leasehold) 301,328 125,089
- --------------------------------------------------------------------------------
Total in-service $4,883,680 $1,752,176
- --------------------------------------------------------------------------------
Construction work in progress
Generation improvements $ 24,033
New generation facilities 37,868
Other 456
- --------------------------------------------------------------------------------
Total construction work in progress $ 62,357
- --------------------------------------------------------------------------------
Oglethorpe, as of December 31, 2000, estimates property additions
(excluding capitalized interest and nuclear fuel) to be approximately
$331,000,000 in 2001, $229,000,000 in 2002 and $72,000,000 in 2003, primarily
for replacements and additions to generation facilities.
59
Oglethorpe's proportionate share of direct expenses of joint operation of
the above plants is included in the corresponding operating expense captions
(e.g., fuel, production or depreciation) on the accompanying statements of
revenues and expenses.
7. Employee benefit plans:
Effective December 31, 1998, Oglethorpe's Board of Directors approved
termination of the noncontributory defined benefit pension plan that covered
substantially all employees, resulting in a net gain of $1,645,000. For 1998,
the plan's pension cost recognized was a credit of $163,000.
The defined benefit pension plan was replaced with a new money purchase
pension plan which became effective January 1, 1999. Under this new plan
Oglethorpe contributes 5%, subject to IRS limitations, of each employee's annual
compensation. Oglethorpe's contributions to the plan were approximately $444,000
in 2000 and $365,000 in 1999.
Oglethorpe has a contributory employee retirement savings plan covering
substantially all employees. The employee may contribute, subject to
IRSlimitations, up to 16% of his annual compensation. Oglethorpe will match the
employee's contribution as long as there is sufficient net margin to do so. The
match, which is calculated each pay period, can be as much as one-half of the
first 6% of the employee's annual compensation depending upon the amount and
timing of the employee's contribution. Effective January 1, 2001, Oglethorpe
will match three-quarters of the first 6% of the employees contribution
depending on the amount and timing of the employee's contribution. Oglethorpe's
contributions to the plan were approximately $261,000 in 2000, $226,000 in 1999
and $214,000 in 1998.
8. Nuclear insurance:
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member
of Nuclear Electric Insurance, Ltd. (NEIL), a mutual insurer established to
provide property damage insurance coverage in an amount up to $500,000,000 for
members' nuclear generating facilities. In the event that losses exceed
accumulated reserve funds, the members are subject to retroactive assessments
(in proportion to their premiums). The portion of the current maximum annual
assessment for GPC that would be payable by Oglethorpe, based on ownership
share, is limited to approximately $3,421,000 for each nuclear incident.
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, has
coverage under NEIL II, which provides insurance to cover decontamination,
debris removal and premature decommissioning as well as excess property damage
to nuclear generating facilities for an additional $2,250,000,000 for losses in
excess of the $500,000,000 primary coverage described above. Under the NEIL
policies, members are subject to retroactive assessments in proportion to their
premiums if losses exceed the accumulated funds available to the insurer under
the policy. The portion of the current maximum annual assessment for GPC that
would be payable by Oglethorpe, based on ownership share, is limited to
approximately $4,000,000.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
annually renewed on or after April 2, 1991 shall be dedicated first for the sole
purpose of placing the reactor in a safe and stable condition after an accident.
Any remaining proceeds are next to be applied toward the costs of
decontamination and debris removal operations ordered by the NRC, and any
further remaining proceeds are to be paid either to the company or to its bond
trustees as may be appropriate under the policies and applicable trust
indentures.
The Price-Anderson Act, as amended in 1988, limits public liability claims
that could arise from a single nuclear incident to $9,500,000,000, which amount
is to be covered by private insurance and a mandatory program of deferred
premiums that could be assessed against all owners of nuclear power reactors.
Such private insurance (in the amount of $200,000,000 for each plant, the
maximum amount currently available) is carried by GPC for the benefit of all the
co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered
60
into by and between each of the co-owners and the NRC. In the event of a nuclear
incident involving any commercial nuclear facility in the country involving
total public liability in excess of $200,000,000, a licensee of a nuclear power
plant could be assessed a deferred premium of up to $88,095,000 per incident for
each licensed reactor operated by it, but not more than $10,000,000 per reactor
per incident to be paid in a calendar year. On the basis of its sell-back
adjusted ownership interest in four nuclear reactors, Oglethorpe could be
assessed a maximum of $105,714,000 per incident, but not more than $12,000,000
in any one year.
All retrospective assessments, whether generated for liability or property,
may be subject to applicable state premium taxes.
9. Commitments:
a. Power purchase and sale agreements
Oglethorpe is utilizing power marketer arrangements to reduce the cost of
power to the Members. Oglethorpe has a power marketer agreement with LG&E Energy
Marketing Inc. ("LEM"), for approximately 50% of the load requirements of 37 of
the Members and an additional power marketer agreement with Morgan Stanley
Capital Group Inc. ("Morgan Stanley"), effective May 1, 1997, with respect to
50% of the 39 Members' then forecasted load requirements. The LEM agreement is
based on the actual requirements of the participating 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. Most of Oglethorpe's generating facilities and power purchase
arrangements are available for use by LEM and Morgan Stanley. Oglethorpe
continues to be responsible for all of the costs of its system resources but
receives revenue from LEM and Morgan Stanley for the use of the resources.
In February 2001, LEM initiated the contractually defined arbitration
process to resolve a number of issues relating to administration of the
agreement.
In addition, Oglethorpe has entered into various long-term power purchase
agreements. As of December 31, 2000, Oglethorpe's minimum purchase commitments
under these agreements, without regard to capacity reductions or adjustments for
changes in costs, for the next five years are as follows:
- --------------------------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
2001 $95,400
2002 76,446
2003 63,423
2004 64,866
2005 66,329
- --------------------------------------------------------------------------------
Oglethorpe's power purchases from these agreements amounted to
approximately $175,623,000 in 2000, $132,721,000 in 1999 and $172,897,000 in
1998.
Oglethorpe has entered into an agreement with Alabama Electric Cooperative
to sell 100 MW of capacity for the period June 1998 through December 2005.
b. Operating leases
In December 1999, Oglethorpe sold existing coal rail cars and subsequently
entered into rental agreements with various terms and expiration dates for the
existing and for additional new coal rail cars. As of December 31, 2000,
Oglethorpe's estimated minimum rental commitments for these operating leases
over the next five years are as follows:
- --------------------------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
2001 $ 2,877
2002 2,877
2003 2,877
2004 2,877
2005 2,877
2006 and beyond 40,489
- --------------------------------------------------------------------------------
61
10. Quarterly financial data (unaudited):
Summarized quarterly financial information for 2000 and 1999 is as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
First Second Third Fourth
Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
2000
Operating revenues $ 274,882 $ 285,026 $ 314,433 $ 325,056
Operating margin 61,527 60,986 49,396 49,046
Net margin 9,188 9,624 (323) 1,489
1999
Operating revenues $ 250,764 $ 273,917 $ 393,636 $ 257,915
Operating margin 62,293 58,342 59,961 51,335
Net margin 8,099 4,483 6,241 1,115
- --------------------------------------------------------------------------------
Third quarter 2000 net margin was lower than the same period of 1999
primarily as a result of a $10,500,000 reduction in revenue requirement approved
by Oglethorpe's Board of Directors. Such reduction in revenues was recorded as a
reduction in sales to Members for the third quarter of 2000.
62
REPORT OF MANAGEMENT
The management of Oglethorpe Power Corporation has prepared this report and
is responsible for the financial statements and related information. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
Oglethorpe maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions. Limitations exist in any system of
internal control based upon the recognition that the cost of the system should
not exceed its benefits. Oglethorpe believes that its system of internal
accounting control, together with the internal auditing function, maintains
appropriate cost/benefit relations.
Oglethorpe's system of internal controls is evaluated on an ongoing basis
by a qualified internal audit staff. The Corporation's independent public
accountants (PricewaterhouseCoopers LLP) also consider certain elements of the
internal control system in order to determine their auditing procedures for the
purpose of expressing an opinion on the financial statements.
PricewaterhouseCoopers LLP also provides an objective assessment of how
well management meets its responsibility for fair financial reporting.
Management believes that its policies and procedures provide reasonable
assurance that Oglethorpe's operations are conducted with a high standard of
business ethics. In management's opinion, the financial statements present
fairly, in all material respects, the financial position, results of operations,
and cash flows of Oglethorpe.
Thomas A. Smith
President and Chief Executive Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of Oglethorpe
Power Corporation:
In our opinion, the accompanying balance sheets and statements of
capitalization and the related statements of revenues and expenses, patronage
capital and of cash flows present fairly, in all material respects, the
financial position of Oglethorpe Power Corporation at December 31, 2000 and
1999, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2000 in conformity with generally
accepted accounting principles in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards in the United States of America which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Atlanta, Georgia,
February 23, 2001
63
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Oglethorpe has a ten-member board of directors consisting of six directors
elected from the Members (the "Member Directors") and four independent outside
directors (the "Outside Directors"). Each Member Director must be a director or
general manager of an Oglethorpe Member. Five of the six Member Directors must
be located in each of five geographical regions of the State of Georgia. The
sixth Member Director is elected statewide. None of the four Outside Directors
may be a director, officer or employee of GTC, GSOC or any Member. All ten
directors are nominated by representatives from each Member whose weighted
nomination is based on the number of retail customers served by each Member.
After nomination, the directors are elected by a majority vote of each Member,
voting on a one-Member, one-vote basis.
The Bylaws provide for staggered three-year terms of the directors by
dividing the number of directors into three groups. The terms of approximately
one-third of the directors expire each year
Oglethorpe is managed and operated under the direction of a President and
Chief Executive Officer, who is appointed by the Board of Directors. The Senior
Officers and Directors of Oglethorpe are as follows:
Name Age Position
J. Calvin Earwood............ 59 Chairman of the Board of Directors,
Member Director, Statewide
Thomas A. Smith.............. 46 President and Chief Executive Officer
Michael W. Price............. 40 Chief Operating Officer
W. Clayton Robbins........... 54 Senior Vice President, Finance and
Administration
Elizabeth B. Higgins......... 32 Vice President, Corporate Strategy and
Member Services
Larry N. Chadwick............ 60 Member Director, Northwest Region
Benny W. Denham.............. 70 Member Director, Southwest Region
Sammy M. Jenkins............. 74 Member Director, Southeast Region
Mac F. Oglesby............... 68 Member Director, Northeast Region and
Treasurer
J. Sam L. Rabun.............. 69 Member Director, Central Region and
Vice Chairman
Ashley C. Brown.............. 55 Outside Director
Wm. Ronald Duffey............ 59 Outside Director
John S. Ranson............... 71 Outside Director
Jeffrey D. Tranen............ 54 Outside Director
J. Calvin Earwood is the Chairman of the Board and is the Member Director
elected statewide. Mr. Earwood has served as an executive officer of Oglethorpe
since March 1984 (from March 1984 to July 1986, as Vice President; from July
1986 to March 1989, as Vice Chairman of the Board; and since March 1989, as
Chairman of the Board). Mr. Earwood has served on the Board of Directors of
Oglethorpe since March 1981. His present term will expire in March 2003. He is
64
the Chairman of the Compensation Committee. From 1965 through 1982, Mr. Earwood
was a salesman and part owner of Builders Equipment Company. Since January 1983,
he has been the owner and President of Sunbelt Fasteners, Inc., which sells
specialty tools and fasteners to the commercial construction trade. He is also
Vice Chairman of the Board of Directors of both Community Trust Financial
Services and Community Trust Bank in Hiram, Georgia and a Director of GreyStone
Power Corporation.
Thomas A. Smith is the President and Chief Executive Officer of Oglethorpe
and has served in that capacity since September 1999. He previously served as
Senior Vice President and Chief Financial Officer of Oglethorpe from September
1998 to August 1999, Senior Financial Officer from 1997 to August 1998, Vice
President, Finance from 1986 to 1990, Manager of Finance from 1983 to 1986 and
Manager, Financial Services from 1979 to 1983. From 1990 to 1997, Mr. Smith was
Senior Vice President of the Rural Utility Banking Group of CoBank, where he
managed the bank's eastern division, rural utilities. Mr. Smith is a Certified
Public Accountant, has a Master of Science degree in Industrial
Management-Finance from the Georgia Institute of Technology, a Master of Science
degree in Analytical Chemistry from Purdue University and a Bachelor of Arts
degree in Mathematics and Chemistry from Catawba College. Mr. Smith is a
Director of GSOC and a Director of the Georgia Chamber of Commerce. Mr. Smith is
also a member of the Advisory Board of Mid-South Telecommunications, Inc. in
Houston, Texas.
Michael W. Price is the Chief Operating Officer of Oglethorpe and has
served in that office since February 1, 2000. Mr. Price served GSOC from January
1999 to January 2000, first as Senior Vice President and then as Chief Operating
Officer. He served as Vice President of System Planning and Construction of GTC
from May 1997 to December 1998. He served as a manager of system control of GSOC
from January to May 1997. From 1986 to 1997, Mr. Price served Oglethorpe in the
areas of control room operations, system planning, construction and engineering,
and energy management systems. Prior to joining Oglethorpe, he was a field test
engineer with the TVA from 1983 to 1986. Mr. Price has a Bachelor of Science
degree in Electrical Engineering from Auburn University.
W. Clayton Robbins is the Senior Vice President, Finance and Administration
of Oglethorpe and has served in that office since November 1999. Mr. Robbins
served as Senior Vice President and General Manager of Intellisource, Inc. from
February 1997 to November 1999. Prior to that, Mr. Robbins held several
positions at Oglethorpe since 1986, including Senior Vice President, Support
Services from December 1991 to January 1997 and Vice President, Market Research
and Analysis from December 1989 to December 1991. Before coming to Oglethorpe,
Mr. Robbins spent 18 years with Stearns-Catalytic World Corporation, a major
engineering and construction firm, including 13 years in management positions
responsible for human resources, information systems, contracts, insurance,
accounting and project controls. Mr. Robbins has a Bachelor of Arts degree in
Business Administration from the University of North Carolina in Charlotte.
Elizabeth B. Higgins is the Vice President, Corporate Strategy and Member
Services of Oglethorpe and has served in this office since July 2000. Ms.
Higgins served as the Vice President and Assistant to the Chief Executive
Officer from October 1999 to July 2000 and served in other capacities for
Oglethorpe from April 1997 to September 1999. Prior to that, Ms. Higgins served
as Project Manager at Southern Engineering from October 1995 to April 1997, as
Senior Consultant at Deloitte & Touche, LLP from April 1995 to October 1995, and
as Senior Consultant at Energy Management Associates from June 1991 to April
1995. In these positions, Ms. Higgins was responsible for competitive bidding
analyses, rate designs, integrated resource planning studies,
operational/dispatch studies, bulk power market analysis, merger analyses and
litigation support. Ms. Higgins has a Bachelor of Industrial Engineering from
the Georgia Institute of Technology.
Larry N. Chadwick is the Member Director from the Northwest Region. He has
been the owner of Chadwick's Hardware in Woodstock, Georgia since 1983. He has
65
served on the Board of Directors of Oglethorpe since July 1989. His present term
will expire in March 2002. Mr. Chadwick is an engineer, with experience in the
design of hydrogen gas plants. He is Chairman of the Board of Cobb EMC.
Benny W. Denham is the Member Director from the Southwest Region. He has
served on the Board of Directors of Oglethorpe since December 1988. His present
term will expire in March 2001. Mr. Denham has been co-owner of Denham Farms in
Turner County, Georgia since 1980. He serves as the Chairman of the Turner
County Chamber of Commerce. Mr. Denham is a Director of Community National Bank
Holding Co., Cumberland National Bank, Georgia Electric Membership Corporation
and Irwin EMC.
Sammy M. Jenkins is the Member Director from the Southeast Region. He has
retired from farming after 25 years. In addition, from 1973 to 1995, he was
President of Jenkins Ford Tractor Co., Inc., a seller of farm machinery. He has
served on the Board of Directors of Oglethorpe since March 1988. His present
term will expire in March 2002.
Mac F. Oglesby is the Member Director from the Northeast Region and the
Treasurer of Oglethorpe. He is a member of the Audit Committee. He has served as
a member of the Board of Directors of Hart EMC since 1980 and now serves as its
Chairman of the Board. He has served on the Board of Directors of Oglethorpe
since February 1987. His present term will expire in March 2003. Mr. Oglesby was
a U.S. Postal Service Rural Carrier for 30 years until he retired in 1991.
J. Sam L. Rabun is the Vice-Chairman of the Board and is the Member
Director from the Central Region. He is also a member of the Compensation
Committee. He has been the owner and operator of a farm in Jefferson County,
Georgia since 1979. He is also a 50% owner of R&R Livestock Farms, Inc. He has
served on the Board of Directors of Oglethorpe since March 1993. His present
term will expire in March 2001. Mr. Rabun served as the President of the Board
of Jefferson EMC from 1993 to 1996, was employed as General Manager from 1974 to
1979 and as Office Manager and Accountant from 1970 to 1974. Mr. Rabun is the
President of the Georgia EMC Directors' Association.
Ashley C. Brown is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. He is the Chairman of the Audit
Committee. His present term will expire in March 2002. He has been Executive
Director of the Harvard Electricity Policy Group at Harvard University's John F.
Kennedy School of Government since 1993. In addition, he is Of Counsel to the
law firm of LeBoeuf, Lamb, Greene and MacRae. From April 1983 through April
1993, Mr. Brown served as Commissioner of the Public Utilities Commission of
Ohio. Prior to his appointment to the Ohio Commission, he was Coordinator and
Counsel of the Montgomery County, Ohio, Fair Housing Center. From 1979 to 1981,
he was Managing Attorney for the Legal Aid Society of Dayton (Ohio), Inc. From
1977 to 1979, he was Legal Advisor of the Miami Valley Regional Planning
Commission in Dayton, Ohio. In addition, Mr. Brown has extensive teaching
experience in public schools and universities and has published widely in the
field of utility regulation. Mr. Brown has a law degree from the University of
Dayton School of Law, a Master of Arts degree from the University of Cincinnati,
and a Bachelor of Science degree from Bowling Green State University.
Wm. Ronald Duffey is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. He is a member of the Audit Committee.
His term will expire in March 2001. Mr. Duffey is the President and Chief
Executive Officer and a director of Peachtree National Bank in Peachtree City,
Georgia, a wholly owned subsidiary of Synovus Financial Corp. Prior to his
employment in 1985 with Peachtree National Bank, Mr. Duffey served as Executive
Vice President and Member of the Board of Directors for First National Bank in
Newnan, Georgia. He holds a Bachelor of Business Administration from Georgia
State College with a concentration in finance and has completed banking courses
at the Banking School of the South, the American Bankers Association School of
66
Bank Investments, and The Stonier Graduate School of Banking, Rutgers
University. Mr. Duffey is a Director of Fayette Community Hospital.
John S. Ranson is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. His term will expire in March 2002. He
is also a member of the Compensation Committee. He has been the President of
Ranson Municipal Consultants, L.L.C., a financial advisor in Wichita, Kansas,
since 1994. From 1990 to 1994, Mr. Ranson was Chairman of Ranson Capital Corp.
an investment banking firm. Mr. Ranson has approximately 48 years experience in
the investment banking business. His public finance clients have included the
Kansas Turnpike Authority, the Kansas Municipal Energy Agency, the Kansas
Municipal Gas Agency, and the Kansas City (Kansas) Board of Public Utilities.
Mr. Ranson received his Bachelor of Science in Business Administration from the
University of Kansas (Lawrence, Kansas) and attended the Navy Supply Corps
School in Bayonne, New Jersey.
Jeffrey D. Tranen is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 2000. His present term will expire in March
2003. Since May 2000, he has served as Senior Vice President of Lexecon, an
economic, regulatory and business strategy consulting firm. Prior to that, he
served as President and Chief Operating Officer of Sithe Northeast, a merchant
generation company. Mr. Tranen served as the President and Chief Executive
Officer of the California Independent System Operator from 1997 to 1999. From
1970 to 1997, Mr. Tranen worked in several positions for the New England
Electric System, most recently as Senior Vice President of the New England
Electric System. He is currently a member of the Board of Directors of Doble
Engineering. Mr. Tranen has a Bachelor of Science in Electrical Engineering and
a Master of Science in Electrical Engineering from the Massachusetts Institute
of Technology.
67
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The following table sets forth, for Oglethorpe's President and Chief
Executive Officer and for the three other executive officers, all compensation
paid or accrued for services rendered in all capacities during the years ended
December 31, 2000, 1999 and 1998.
Annual Compensation
Name and ------------------- All Other
Principal Position Year Salary Bonus Compensation
- ------------------ ---- ------ ----- ------------
Thomas A. Smith(1)................................... 2000 $ 275,000 $ 82,800 $ 14,005(2)
President and Chief Executive Officer 1999 202,008 65,283 14,237
1998 183,935 12,180 1,247
W. Clayton Robbins(3)................................ 2000 163,000 42,476 11,335(2)
Senior Vice President and Finance Administration 1999 23,341 35,945 1,259
1998 0 0 0
Michael W. Price(4).................................. 2000 157,667 50,912 23,583(2)(5)
Chief Operating Officer 1999 0 0 0
1998 0 0 0
Elizabeth B. Higgins................................. 2000 126,125 24,975 11,846(2)
Vice President, Corporate Strategy and 1999 88,431 22,233 9,457
Member Services 1998 55,355 13,365 1,845
- -----------------
(1) Prior to September 1, 1998, Mr. Smith provided services to Oglethorpe under
a contractual arrangement and the amounts reflected for 1998 include those
contract payments.
(2) Includes contributions made in 2000 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Mr. Smith, Mr. Robbins, Mr. Price and
Ms. Higgins of $5,100, $2,073, $4,768 and $4,239, respectively;
contributions under the Money Purchase Pension Plan on behalf of Mr. Smith,
Mr. Robbins, Mr. Price and Ms. Higgins of $8,500, $8,500, $8,500 and
$7,418, respectively; and insurance premiums paid on term life insurance on
behalf of Mr. Smith, Mr. Robbins, Mr. Price and Ms. Higgins of $405, $762,
$315 and $189, respectively.
(3) Mr. Robbins became an Oglethorpe employee on November 16, 1999.
(4) Mr. Price became an Oglethorpe employee on February 1, 2000.
(5) Includes a signing bonus of $10,000 paid in 2000.
Compensation of Directors
Oglethorpe pays its Outside Directors a fee of $5,500 per Board meeting for
four meetings in a year; a fee of $1,000 per Board meeting will be paid for the
remaining other Board meetings in a year. Outside Directors are also paid $1,000
per day for attending committee meetings, annual meetings of the Members or
other official meetings of Oglethorpe. Member Directors are paid a fee of $1,000
per Board meeting and $600 per day for attending committee meetings, annual
meetings of the Members or other official business of Oglethorpe. In addition,
Oglethorpe reimburses all Directors for out-of-pocket expenses incurred in
attending a meeting. All Directors are paid $50 per day when participating in
meetings by conference call. The Chairman of the Board is paid an additional 20%
of his Director's fee per Board meeting for time involved in preparing for the
meetings.
Employment Contracts
Oglethorpe entered into an Employment Agreement with Thomas A. Smith,
Oglethorpe's President and Chief Executive Officer, effective September 15,
1999. The agreement extends until December 31, 2002, and automatically renews
for successive one-year periods unless either party gives notice of termination
prior to December 31, 2000 or 25 months prior to the expiration of any extension
68
of the agreement. Mr. Smith's minimum base salary is $250,000 per year, and is
annually adjusted by the Board of Directors of Oglethorpe. In addition, Mr.
Smith has opportunities for variable pay for accomplishing goals set by
Oglethorpe's Board of Directors each year.
Upon the occurrence of any of the following events, Mr. Smith will be
entitled to a lump-sum severance payment: (1) Oglethorpe terminates Mr. Smith's
employment without cause; (2) Mr. Smith resigns within 180 days of a material
reduction or alteration of his title or responsibilities or a change in the
location of Mr. Smith's principal office by more than 50 miles; (3) Oglethorpe
is sold or Oglethorpe sells essentially all of its assets or control of its
assets, and the sale results in a termination of Mr. Smith's employment as
President and Chief Executive Officer of Oglethorpe or a material reduction of
his title or responsibilities; or (4) an event of default under Oglethorpe's RUS
loan contract occurs and is continuing and RUS requests that Oglethorpe
terminate Mr. Smith. The severance payment will equal Mr. Smith's base salary
through the rest of the term of the agreement (with a minimum of one year's pay
and a maximum of two years' pay) plus the cost of providing all health and
dental insurance for the longer of one year or the remaining term of the
agreement. In the case of (3) above, Oglethorpe also agrees to hire Mr. Smith as
a consultant for one year at a rate equal to his then-applicable base salary.
Oglethorpe has also entered into Employment Agreements with Michael W.
Price, W. Clayton Robbins and Elizabeth B. Higgins, Oglethorpe's Chief Operating
Officer, Senior Vice President of Finance and Administration and Vice President,
Corporate Strategy and Member Services, respectively. Mr. Price's agreement was
effective February 1, 2000, and Mr. Robbins' and Ms. Higgins' agreements were
effective August 1, 2000. Each agreement extends until December 31, 2001, and
automatically renews for a successive one-year period unless either party gives
notice of termination prior to November 30, 2000 or 13 months prior to the
expiration of any extension of the Agreement. Minimum annual base salaries are
$172,000 for Mr. Price, $164,000 for Mr. Robbins and $135,000 for Ms. Higgins.
Salaries are annually adjusted by the Board of Directors of Oglethorpe. Each
executive has opportunities for variable pay for accomplishing goals set by
Oglethorpe's Board of Directors each year.
Under each Employment Agreement, the executive will be entitled to a
lump-sum severance payment if Oglethorpe terminates the executive without cause
or if the executive resigns after (1) a demotion or a material reduction or
alteration of the executive's title or responsibilities, (2) a reduction of the
executive's base salary or (3) a change in the location of the executive's
principal office by more than 50 miles. The severance payment will equal the
executive's base salary for one year, plus the equivalent of six months' medical
allowance.
Compensation Committee Interlocks and Insider Participation
J. Calvin Earwood, John S. Ranson and J. Sam L. Rabun served as members of
the Oglethorpe Power Corporation Compensation Committee in 2000. Mr. Earwood has
served as an executive officer of Oglethorpe since 1984 and has served as the
Chairman of the Board since 1989.
69
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
70
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Page
(a) List of Documents Filed as a Part of This Report.
(1) Financial Statements (Included under "Item 8. Financial Statements
and Supplementary Data")
Statements of Revenues and Expenses, For the Years Ended
December 31, 2000, 1999 and 1998...............................45
Statements of Patronage Capital, For the Years Ended
December 31, 2000, 1999 and 1998...............................45
Balance Sheets, As of December 31, 2000 and 1999.................46
Statements of Capitalization, As of December 31, 2000 and 1999...48
Statements of Cash Flows, For the Years Ended
December 31, 2000, 1999 and 1998...............................49
Notes to Financial Statements....................................50
Report of Management.............................................63
Report of Independent Accountants................................63
(2) Financial Statement Schedules
None applicable.
(3) Exhibits
Exhibits marked with an asterisk (*) are hereby incorporated by
reference to exhibits previously filed by the Registrant as indicated in
parentheses following the description of the exhibit.
Number Description
*2.1 -- Second Amended and Restated Restructuring Agreement, dated
February 24, 1997, by and among Oglethorpe, Georgia Transmission
Corporation (An Electric Membership Corporation) and Georgia
System Operations Corporation. (Filed as Exhibit 2.1 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*2.2 -- Member Agreement, dated August 1, 1996, by and among Oglethorpe,
Georgia Transmission Corporation (An Electric Membership
Corporation), Georgia System Operations Corporation and the
Members of Oglethorpe. (Filed as Exhibit 2.2 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*3.1(a) -- Restated Articles of Incorporation of Oglethorpe, dated as of
July 26, 1988. (Filed as Exhibit 3.1 to the Registrant's Form
10-K for the fiscal year ended December 31, 1988, File No.
33-7591.)
*3.1(b) -- Amendment to Articles of Incorporation of Oglethorpe, dated as
of March 11, 1997. (Filed as Exhibit 3(i)(b) to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*3.2 -- Bylaws of Oglethorpe, as amended on January 10, 2000. (Filed as
Exhibit 3.2 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1999, File No. 33-7591.)
71
*4.1 -- Form of Serial Facility Bond Due June 30, 2011 (included in
Collateral Trust Indenture filed as Exhibit 4.2.)
*4.2 -- Collateral Trust Indenture, dated as of December 1, 1997, between
OPC Scherer 1997 Funding Corporation A, Oglethorpe and SunTrust
Bank, Atlanta, as Trustee. (Filed as Exhibit 4.2 to the
Registrant's Form S-4 Registration Statement, File No.
333-42759.)
*4.3 -- Nonrecourse Promissory Lessor Note No. 2, with a Schedule
identifying three other substantially identical Nonrecourse
Promissory Lessor Notes and any material differences. (Filed as
Exhibit 4.3 to the Registrant's Form S-4 Registration Statement,
File No. 333-42759.)
*4.4 -- Amended and Restated Indenture of Trust, Deed to Secure Debt and
Security Agreement No. 2, dated December 1, 1997, between
Wilmington Trust Company and NationsBank, N.A. collectively as
Owner Trustee, under Trust Agreement No. 2, dated December 30,
1985, with DFO Partnership, as assignee of Ford Motor Credit
Company, and The Bank of New York Trust Company of Florida, N.A.
as Indenture Trustee, with a Schedule identifying three other
substantially identical Amended and Restated Indentures of Trust,
Deeds to Secure Debt and Security Agreements and any material
differences. (Filed as Exhibit 4.4 to the Registrant's Form S-4
Registration Statement, File No. 333-42759.)
*4.5(a) -- Lease Agreement No. 2 dated December 30, 1985, between Wilmington
Trust Company and William J. Wade, as Owner Trustees under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, Lessor, and Oglethorpe, Lessee, with a Schedule
identifying three other substantially identical Lease Agreements.
(Filed as Exhibit 4.5(b) to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*4.5(b) -- First Supplement to Lease Agreement No. 2 (included as Exhibit B
to the Supplemental Participation Agreement No. 2 listed as
10.1.1(b)).
*4.5(c) -- First Supplement to Lease Agreement No. 1, dated as of June 30,
1987, between The Citizens and Southern National Bank as Owner
Trustee under Trust Agreement No. 1 with IBM Credit Financing
Corporation, as Lessor, and Oglethorpe, as Lessee. (Filed as
Exhibit 4.5(c) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1987, File No. 33-7591.)
*4.5(d) -- Second Supplement to Lease Agreement No. 2, dated as of December
17, 1997, between NationsBank, N.A., acting through its agent,
The Bank of New York, as an Owner Trustee under the Trust
Agreement No. 2, dated December 30, 1985, among DFO Partnership,
as assignee of Ford Motor Credit Company, as the Owner
Participant, and the Original Trustee, as Lessor, and Oglethorpe,
as Lessee, with a Schedule identifying three other substantially
identical Second Supplements to Lease Agreements and any material
differences. (Filed as Exhibit 4.5(d) to the Registrant's Form
S-4 Registration Statement, File No. 333-42759.)
*4.6 -- Amended and Consolidated Loan Contract, dated as of March 1,
1997, between Oglethorpe and the United States of America,
together with four notes executed and delivered pursuant thereto.
(Filed as Exhibit 4.7 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*4.7.1(a) -- Indenture, dated as of March 1, 1997, made by Oglethorpe to
SunTrust Bank, Atlanta, as trustee. (Filed as Exhibit 4.8.1 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
72
*4.7.1(b) -- First Supplemental Indenture, dated as of October 1, 1997, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1997B (Burke) Note. (Filed as Exhibit 4.8.1(b) to the
Registrant's Form 10-Q for the quarterly period ended September
30, 1997, File No. 33-7591.)
*4.7.1(c) -- Second Supplemental Indenture, dated as of January 1, 1998, made
by Oglethorpe to SunTrust Bank, as trustee, relating to the
Series 1997C (Burke) Note. (Filed as Exhibit 4.7.1(c) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1997, File No. 33-7591.)
*4.7.1(d) -- Third Supplemental Indenture, dated as of January 1, 1998, made
by Oglethorpe to SunTrust Bank, as trustee, relating to the
Series 1997A (Monroe) Note. (Filed as Exhibit 4.7.1(d) to the
Registrant's Form 10-K for the fiscal year December 31, 1997,
File No. 33-7591.)
*4.7.1(e) -- Fourth Supplemental Indenture, dated as of March 1, 1998, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1998A (Burke) and 1998B (Burke) Notes. (Filed as Exhibit
4.7.1(e) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1998, File No. 33-7591.)
*4.7.1(f) -- Fifth Supplemental Indenture, dated as of April 1, 1998, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1998 CFC Note. (Filed as Exhibit 4.7.1(f) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1998, File No. 33-7591.)
*4.7.1(g) -- Sixth Supplemental Indenture, dated as of January 1, 1999, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1998C (Burke) Note. (Filed as Exhibit 4.7.1(g) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1998, File No. 33-7591.)
*4.7.1(h) -- Seventh Supplemental Indenture, dated as of January 1, 1999, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1998A (Monroe) Note. (Filed as Exhibit 4.7.1(h) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1998, File No. 33-7591.)
*4.7.1(i) -- Eighth Supplemental Indenture, dated as of November 1, 1999, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1999B (Burke) Note. (Filed as Exhibit 4.7.1(i) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
*4.7.1(j) -- Ninth Supplemental Indenture, dated as of November 1, 1999, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1999B (Monroe) Note. (Filed as Exhibit 4.7.1(j) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
*4.7.1(k) -- Tenth Supplemental Indenture, dated as of December 1, 1999, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1999 Lease Notes. (Filed as Exhibit 4.7.1(k) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
*4.7.1(l) -- Eleventh Supplemental Indenture, dated as of January 1, 2000,
made by Oglethorpe to SunTrust Bank as trustee, relating to the
Series 1999A (Burke) Note. (Filed as Exhibit 4.7.1(l) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
*4.7.1(m) -- Twelfth Supplemental Indenture, dated as of January 1, 2000, made
by Oglethorpe to SunTrust Bank as trustee, relating to the Series
1999A (Monroe) Note. (Filed as Exhibit 4.7.1(m) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
73
4.7.1(n) -- Thirteenth Supplemental Indenture, dated as of January 1, 2001,
made by Oglethorpe to SunTrust Bank, as trustee, relating to the
Series 2000 (Burke) Note.
4.7.1(o) -- Fourteenth Supplemental Indenture, dated as of January 1, 2001,
made by Oglethorpe to SunTrust Bank, as trustee, relating to the
Series 2000 (Monroe) Note.
*4.7.2 -- Security Agreement, dated as of March 1, 1997, made by Oglethorpe
to SunTrust Bank, Atlanta, as trustee. (Filed as Exhibit 4.8.2 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
4.8.1(1) -- Loan Agreement, dated as of October 1, 1992, between Development
Authority of Monroe County and Oglethorpe relating to Development
Authority of Monroe County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Scherer Project), Series 1992A, and
five other substantially identical loan agreements.
4.8.2(1) -- Note, dated October 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated as
of October 1, 1992, between Development Authority of Monroe
County and Trust Company Bank, and five other substantially
identical notes.
4.8.3(1) -- Trust Indenture, dated as of October 1, 1992, between Development
Authority of Monroe County and Trust Company Bank, Trustee,
relating to Development Authority of Monroe County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Scherer
Project), Series 1992A, and five other substantially identical
trust indentures.
4.9.1(1) -- Loan Agreement, dated as of December 1, 1992, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Adjustable Tender Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A, and one other substantially identical loan
agreement.
4.9.2(1) -- Note, dated December 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated as
of December 1, 1992, between Development Authority of Burke
County and Trust Company Bank, and one other substantially
identical note.
4.9.3(1) -- Trust Indenture, dated as of December 1, 1992, from Development
Authority of Burke County to Trust Company Bank, as trustee,
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1993A, and one other
substantially identical trust indenture.
4.9.4(1) -- Interest Rate Swap Agreement, dated as of December 1, 1992, by
and between Oglethorpe and AIG Financial Products Corp. relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A, and one other substantially
identical agreement.
4.9.5(1) -- Liquidity Guaranty Agreement, dated as of December 1, 1992, by
and between Oglethorpe and AIG Financial Products Corp. relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A, and one other substantially
identical agreement.
74
4.9.6(1) -- Standby Bond Purchase Agreement, dated as of December 1, 1998,
between Oglethorpe and Bayerische Landesbank Girozentrale,
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1993A.
4.9.7(1) -- Standby Bond Purchase Agreement, dated as of November 30, 1994,
between Oglethorpe and Credit Local de France, Acting through its
New York Agency, relating to Development Authority of Burke
County Adjustable Tender Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1994A.
4.10.1(1) -- Loan Agreement, dated as of October 1, 1996, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1996, and
one other substantially identical loan agreements.
4.10.2(1) -- Note, dated October 1, 1996, from Oglethorpe to SunTrust Bank,
Atlanta, as trustee pursuant to an Indenture of Trust, dated as
of October 1, 1996, between Development Authority of Burke County
and SunTrust Bank, Atlanta, and one other substantially identical
note.
4.10.3(1) -- Indenture of Trust, dated as of October 1, 1996, between
Development Authority of Burke County and SunTrust Bank, Atlanta,
as trustee, relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1996, and one other substantially
identical indenture.
4.11.1(1) -- Loan Agreement, dated as of December 1, 1997, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project) Series 1997C, and
three other substantially identical loan agreements.
4.11.2(1) -- Note, dated January 14, 1998, from Oglethorpe to SunTrust Bank,
Atlanta, as trustee pursuant to an Indenture of Trust, dated as
of December 1, 1997, between Development Authority of Burke
County and SunTrust Bank, Atlanta, and three other substantially
identical notes.
4.11.3(1) -- Indenture of Trust, dated as of December 1, 1997, between
Development Authority of Burke County and SunTrust Bank, Atlanta,
as trustee, relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1997C, and three other substantially
identical indentures.
4.12.1(1) -- Loan Agreement, dated as of March 1, 1998, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1998A, and
one other substantially identical loan agreement.
4.12.2(1) -- Note, dated March 17, 1998, from Oglethorpe to SunTrust Bank,
Atlanta, as trustee pursuant to a Trust Indenture, dated as of
March 1, 1998, between Development Authority of Burke County and
SunTrust Bank, Atlanta, and one other substantially identical
note.
4.12.3(1) -- Trust Indenture, dated as of March 1, 1998, between Development
Authority of Burke County and SunTrust Bank, Atlanta, as trustee,
relating to Development Authority of Burke County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1998A, and one other substantially identical
indenture.
75
4.12.4(1) -- Standby Bond Purchase Agreement, dated March 17, 1998, between
Oglethorpe and Cooperatieve Centrale Raiffeisen-Boerenleenbank
B.A., "Rabobank Nederland", acting through its New York Branch,
relating to Development Authority of Burke County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1998A, and one other substantially identical
agreement.
*4.13.1 -- Indemnity Agreement, dated as of March 1, 1997, by and between
Oglethorpe and Georgia Transmission Corporation (An Electric
Membership Corporation). (Filed as Exhibit 4.13.1 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*4.13.2 -- Indemnification Agreement, dated as of March 11, 1997, by
Oglethorpe and Georgia Transmission Corporation (An Electric
Membership Corporation) for the benefit of the United States of
America. (Filed as Exhibit 4.13.2 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
4.14.1(1) -- Master Loan Agreement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, MLA No. 0459.
4.14.2(1) -- Consolidating Supplement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T1.
4.14.3(1) -- Promissory Note, dated March 1, 1997, in the original principal
amount of $7,102,740.26, from Oglethorpe to CoBank, ACB, relating
to Loan No. ML0459T1.
4.14.4(1) -- Consolidating Supplement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T2.
4.14.5(1) -- Promissory Note, dated March 1, 1997, in the original principal
amount of $1,856,475.12, made by Oglethorpe to CoBank, ACB,
relating to Loan No. ML0459T2.
4.14.6(1) -- Single Advance Term Loan Supplement, dated as of March 31, 1998,
between Oglethorpe and CoBank, ACB, relating to Loan No.
ML0459T3.
4.14.7(1) -- Promissory Note, dated March 31, 1998, in the original principal
amount of $46,065,000.00, made by Oglethorpe to CoBank, ACB,
relating to Loan No. ML0459T3.
*4.15.1 -- Loan Agreement, Loan No. T-830404, between Oglethorpe and
Columbia Bank for Cooperatives, dated as of April 29, 1983.
(Filed as Exhibit 4.18.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*4.15.2 -- Promissory Note, Loan No. T-830404-1, in the original principal
amount of $9,935,000, from Oglethorpe to Columbia Bank for
Cooperatives, dated as of April 29, 1983. (Filed as Exhibit
4.18.2 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*4.15.3 -- Security Deed and Security Agreement, dated April 29, 1983,
between Oglethorpe and Columbia Bank for Cooperatives. (Filed as
Exhibit 4.18.3 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*4.16 -- Exchange and Registration Rights Agreement, dated December 17,
1997, by and among Oglethorpe, OPC Scherer 1997 Funding
Corporation A, and Goldman, Sachs & Co. as representative of the
purchasers identified therein. (Filed as Exhibit 4.15 to the
Registrant's Form S-4 Registration Statement, File No.
333-42759.)
76
4.17.1 (1) -- Loan Agreement, dated as of April 1, 1998, between Oglethorpe and
the National Rural Utilities Cooperative Finance Corporation,
relating to Loan No. GA 109-1-9001.
4.17.2 (1) -- Series 1998 CFC Note, dated April 9, 1998, in the original
principal amount of $46,065,000.00, from Oglethorpe to the
National Rural Utilities Cooperative Finance Corporation,
relating to Loan No. GA 109-1-9001.
*10.1.1(a) -- Participation Agreement No. 2 among Oglethorpe as Lessee,
Wilmington Trust Company as Owner Trustee, The First National
Bank of Atlanta as Indenture Trustee, Columbia Bank for
Cooperatives as Loan Participant and Ford Motor Credit Company as
Owner Participant, dated December 30, 1985, together with a
Schedule identifying three other substantially identical
Participation Agreements. (Filed as Exhibit 10.1.1(b) to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.1(b) -- Supplemental Participation Agreement No. 2. (Filed as Exhibit
10.1.1(a) to the Registrant's Form S-1 Registration Statement,
File No. 33-7591.)
*10.1.1(c) -- Supplemental Participation Agreement No. 1, dated as of June 30,
1987, among Oglethorpe as Lessee, IBM Credit Financing
Corporation as Owner Participant, Wilmington Trust Company and
The Citizens and Southern National Bank as Owner Trustee, The
First National Bank of Atlanta, as Indenture Trustee, and
Columbia Bank for Cooperatives, as Loan Participant. (Filed as
Exhibit 10.1.1(c) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1987, File No. 33-7591.)
*10.1.1(d) -- Second Supplemental Participation Agreement No. 2, dated as of
December 17, 1997, among Oglethorpe as Lessee, DFO Partnership,
as assignee of Ford Motor Credit Company, as Owner Participant,
Wilmington Trust Company and NationsBank, N.A. as Owner Trustee,
The Bank of New York Trust Company of Florida, N.A. as Indenture
Trustee, CoBank, ACB as Loan Participant, OPC Scherer Funding
Corporation, as Original Funding Corporation, OPC Scherer 1997
Funding Corporation A, as Funding Corporation, and SunTrust Bank,
Atlanta, as Original Collateral Trust Trustee and Collateral
Trust Trustee, with a Schedule identifying three substantially
identical Second Supplemental Participation Agreements and any
material differences. (Filed as Exhibit 10.1.1(d) to Registrant's
Form S-4 Registration Statement, File No. 333-4275.)
*10.1.2 -- General Warranty Deed and Bill of Sale No. 2 between Oglethorpe,
Grantor, and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Grantee, together with a
Schedule identifying three substantially identical General
Warranty Deeds and Bills of Sale. (Filed as Exhibit 10.1.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.3(a) -- Supporting Assets Lease No. 2, dated December 30, 1985, between
Oglethorpe, Lessor, and Wilmington Trust Company and William J.
Wade, as Owner Trustees, under Trust Agreement No. 2, dated
December 30, 1985, with Ford Motor Credit Company, Lessee,
together with a Schedule identifying three substantially
identical Supporting Assets Leases. (Filed as Exhibit 10.1.3 to
the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
77
*10.1.3(b) -- First Amendment to Supporting Assets Lease No. 2, dated as of
November 19, 1987, together with a Schedule identifying three
substantially identical First Amendments to Supporting Assets
Leases. (Filed as Exhibit 10.1.3(a) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1987, File No. 33-7591.)
*10.1.3(c) -- Second Amendment to Supporting Assets Lease No. 2, dated as of
October 3, 1989, together with a Schedule identifying three
substantially identical Second Amendments to Supporting Assets
Leases. (Filed as Exhibit 10.1.3(c) to the Registrant's Form 10-Q
for the quarterly period ended March 31, 1998, File No. 33-7591.)
*10.1.4(a) -- Supporting Assets Sublease No. 2, dated December 30, 1985,
between Wilmington Trust Company and William J. Wade, as Owner
Trustees under Trust Agreement No. 2 dated December 30, 1985,
with Ford Motor Credit Company, Sublessor, and Oglethorpe,
Sublessee, together with a Schedule identifying three
substantially identical Supporting Assets Subleases. (Filed as
Exhibit 10.1.4 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.1.4(b) -- First Amendment to Supporting Assets Sublease No. 2, dated as of
November 19, 1987, together with a Schedule identifying three
substantially identical First Amendments to Supporting Assets
Subleases. (Filed as Exhibit 10.1.4(a) to the Registrant's Form
10-K for the fiscal year ended December 31, 1987, File No.
33-7591.)
*10.1.4(c) -- Second Amendment to Supporting Assets Sublease No. 2, dated as of
October 3, 1989, together with a Schedule identifying three
substantially identical Second Amendments to Supporting Assets
Subleases. (Filed as Exhibit 10.1.4(c) to the Registrant's Form
10-Q for the quarterly period ended March 31, 1998, File No.
33-7591.)
*10.1.5(a) -- Tax Indemnification Agreement No. 2, dated December 30, 1985,
between Ford Motor Credit Company, Owner Participant, and
Oglethorpe, Lessee, together with a Schedule identifying three
substantially identical Tax Indemnification Agreements. (Filed as
Exhibit 10.1.5 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.1.5(b) -- Amendment No. 1 to the Tax Indemnification Agreement No. 2, dated
December 17, 1997, between DFO Partnership, as assignee of Ford
Motor Credit Company, as Owner Participant, and Oglethorpe, as
Lessee, with a Schedule identifying three substantially identical
Amendments No. 1 to the Tax Indemnification Agreements and any
material differences. (Filed as Exhibit 10.1.5(b) to the
Registrant's Form S-4 Registration Statement, File No.
333-42759.)
*10.1.6 -- Assignment of Interest in Ownership Agreement and Operating
Agreement No. 2, dated December 30, 1985, between Oglethorpe,
Assignor, and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Assignee, together with
Schedule identifying three substantially identical Assignments of
Interest in Ownership Agreement and Operating Agreement. (Filed
as Exhibit 10.1.6 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
78
*10.1.7 -- Consent, Amendment and Assumption No. 2 dated December 30, 1985,
among Georgia Power Company and Oglethorpe and Municipal Electric
Authority of Georgia and City of Dalton, Georgia and Gulf Power
Company and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, together with a Schedule
identifying three substantially identical Consents, Amendments
and Assumptions. (Filed as Exhibit 10.1.9 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.1.7(a) -- Amendment to Consent, Amendment and Assumption No. 2, dated as of
August 16, 1993, among Oglethorpe, Georgia Power Company,
Municipal Electric Authority of Georgia, City of Dalton, Georgia,
Gulf Power Company, Jacksonville Electric Authority, Florida
Power & Light Company and Wilmington Trust Company and
NationsBank of Georgia, N.A., as Owner Trustees under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, together with a Schedule identifying three substantially
identical Amendments to Consents, Amendments and Assumptions.
(Filed as Exhibit 10.1.9(a) to the Registrant's Form 10-Q for the
quarterly period ended September 30, 1993, File No. 33-7591.)
*10.2.1 -- Section 168 Agreement and Election dated as of April 7, 1982,
between Continental Telephone Corporation and Oglethorpe. (Filed
as Exhibit 10.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.2.2 -- Section 168 Agreement and Election dated as of April 9, 1982,
between Rollins, Inc. and Oglethorpe. (Filed as Exhibit 10.4 to
the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.3.1(a) -- Plant Robert W. Scherer Units Numbers One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit
10.6.1 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.3.1(b) -- Amendment to Plant Robert W. Scherer Units Numbers One and Two
Purchase and Ownership Participation Agreement among Georgia
Power Company, Oglethorpe, Municipal Electric Authority of
Georgia and City of Dalton, Georgia, dated as of December 30,
1985. (Filed as Exhibit 10.1.8 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.3.1(c) -- Amendment Number Two to the Plant Robert W. Scherer Units Numbers
One and Two Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia, dated as of July 1, 1986.
(Filed as Exhibit 10.6.1(a) to the Registrant's Form 10-K for the
fiscal year ended December 31, 1987, File No. 33-7591.)
*10.3.1(d) -- Amendment Number Three to the Plant Robert W. Scherer Units
Numbers One and Two Purchase and Ownership Participation
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 1, 1988. (Filed as Exhibit 10.6.1(b) to the
Registrant's Form 10-Q for the quarterly period ended September
30, 1993, File No. 33-7591.)
79
*10.3.1(e) -- Amendment Number Four to the Plant Robert W. Scherer Units Number
One and Two Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia, dated as of December 31,
1990. (Filed as Exhibit 10.6.1(c) to the Registrant's Form 10-Q
for the quarterly period ended September 30, 1993, File No.
33-7591.)
*10.3.2(a) -- Plant Robert W. Scherer Units Numbers One and Two Operating
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of May 15, 1980. (Filed as Exhibit 10.6.2 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.3.2(b) -- Amendment to Plant Robert W. Scherer Units Numbers One and Two
Operating Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.7
to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.3.2(c) -- Amendment Number Two to the Plant Robert W. Scherer Units Numbers
One and Two Operating Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of December 31, 1990. (Filed as Exhibit
10.6.2(a) to the Registrant's Form 10-Q for the quarterly period
ended September 30, 1993, File No. 33-7591.)
*10.3.3 -- Plant Scherer Managing Board Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia,
City of Dalton, Georgia, Gulf Power Company, Florida Power &
Light Company and Jacksonville Electric Authority, dated as of
December 31, 1990. (Filed as Exhibit 10.6.3 to the Registrant's
Form 10-Q for the quarterly period ended September 30, 1993, File
No. 33-7591.)
*10.4.1(a) -- Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit
10.7.1 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.4.1(b) -- Amendment Number One, dated January 18, 1977, to the Alvin W.
Vogtle Nuclear Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia. (Filed as Exhibit 10.7.3 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.1(c) -- Amendment Number Two, dated February 24, 1977, to the Alvin W.
Vogtle Nuclear Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia. (Filed as Exhibit 10.7.4 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.2 -- Alvin W. Vogtle Nuclear Units Numbers One and Two Operating
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 27, 1976. (Filed as Exhibit 10.7.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
80
*10.5.1 -- Plant Hal Wansley Purchase and Ownership Participation Agreement
between Georgia Power Company and Oglethorpe, dated as of March
26, 1976. (Filed as Exhibit 10.8.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.5.2(a) -- Plant Hal Wansley Operating Agreement between Georgia Power
Company and Oglethorpe, dated as of March 26, 1976. (Filed as
Exhibit 10.8.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.5.2(b) -- Amendment, dated as of January 15, 1995, to the Plant Hal Wansley
Operating Agreements by and among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia. (Filed as Exhibit 10.5.2(a) to the Registrant's
Form 10-Q for the quarterly period ended September 30, 1996, File
No. 33-7591.)
*10.5.3 -- Plant Hal Wansley Combustion Turbine Agreement between Georgia
Power Company and Oglethorpe, dated as of August 2, 1982 and
Amendment No. 1, dated October 20, 1982. (Filed as Exhibit 10.18
to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.6.1 -- Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation
Agreement between Georgia Power Company and Oglethorpe, dated as
of January 6, 1975. (Filed as Exhibit 10.9.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.6.2 -- Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia
Power Company and Oglethorpe, dated as of January 6, 1975. (Filed
as Exhibit 10.9.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.7.1 -- Rocky Mountain Pumped Storage Hydroelectric Project Ownership
Participation Agreement, dated as of November 18, 1988, by and
between Oglethorpe and Georgia Power Company. (Filed as Exhibit
10.22.1 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1988, File No. 33-7591.)
*10.7.2 -- Rocky Mountain Pumped Storage Hydroelectric Project Operating
Agreement, dated as of November 18, 1988, by and between
Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.2
to the Registrant's Form 10-K for the fiscal year ended December
31, 1988, File No. 33-7591.)
*10.8.1 -- Amended and Restated Wholesale Power Contract, dated as of August
1, 1996, between Oglethorpe and Altamaha Electric Membership
Corporation and all schedules thereto, together with a Schedule
identifying 37 other substantially identical Amended and Restated
Wholesale Power Contracts, and an additional Amended and Restated
Wholesale Power Contract that is not substantially identical.
(Filed as Exhibit 10.8.1 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.2 -- Amended and Restated Supplemental Agreement, dated as of August
1, 1996, by and between Oglethorpe, Altamaha Electric Membership
Corporation and the United States of America, together with a
Schedule identifying 38 other substantially identical Amended and
Restated Supplemental Agreements. (Filed as Exhibit 10.8.2 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
81
*10.8.3 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of January 1, 1997, by and among Georgia
Power Company, Oglethorpe and Altamaha Electric Membership
Corporation, together with a Schedule identifying 38 other
substantially identical Supplemental Agreements. (Filed as
Exhibit 10.8.3 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
*10.8.4 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of March 1, 1997, by and between
Oglethorpe and Altamaha Electric Membership Corporation, together
with a Schedule identifying 36 other substantially identical
Supplemental Agreements, and an additional Supplemental Agreement
that is not substantially identical. (Filed as Exhibit 10.8.4 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.8.5 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of March 1, 1997, by and between
Oglethorpe and Coweta-Fayette Electric Membership Corporation,
together with a Schedule identifying 1 other substantially
identical Supplemental Agreement. (Filed as Exhibit 10.8.5 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.8.6 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of May 1, 1997 by and between Oglethorpe
and Altamaha Electric Membership Corporation, together with a
Schedule identifying 38 other substantially identical
Supplemental Agreements. (Filed as Exhibit 10.8.6 to the
Registrant's Form 10-Q for the quarterly period ended June 30,
1997, File No. 33-7591.)
*10.9(a) -- Joint Committee Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and the City
of Dalton, Georgia, dated as of August 27, 1976. (Filed as
Exhibit 10.14(b) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.9(b) -- First Amendment to Joint Committee Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia and
the City of Dalton, Georgia, dated as of June 19, 1978. (Filed as
Exhibit 10.14(a) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.10 -- Letter of Commitment (Firm Power Sale) Under Service Schedule
J--Negotiated Interchange Service between Alabama Electric
Cooperative, Inc. and Oglethorpe, dated March 31, 1994. (Filed as
Exhibit 10.11(b) to the Registrant's Form 10-Q for the quarter
ended June 30, 1994, File No. 33-7591.)
*10.11.1 -- Assignment of Power System Agreement and Settlement Agreement,
dated January 8, 1975, by Georgia Electric Membership Corporation
to Oglethorpe. (Filed as Exhibit 10.20.1 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591.)
*10.11.2 -- Power System Agreement, dated April 24, 1974, by and between
Georgia Electric Membership Corporation and Georgia Power
Company. (Filed as Exhibit 10.20.2 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
82
*10.11.3 -- Settlement Agreement, dated April 24, 1974, by and between
Georgia Power Company, Georgia Municipal Association, Inc., City
of Dalton, Georgia Electric Membership Corporation and Crisp
County Power Commission. (Filed as Exhibit 10.20.3 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.12 -- Long-Term Firm Power Purchase Agreement between Big Rivers
Electric Corporation and Oglethorpe, dated as of December 17,
1990. (Filed as Exhibit 10.24.3 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1990, File No. 33-7591.)
*10.13 -- Revised and Restated Coordination Services Agreement between and
among Georgia Power Company, Oglethorpe and Georgia System
Operations Corporation, dated as of September 10, 1997. (Filed as
Exhibit 10.14 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1997, File No. 33-7591.)
*10.14 -- ITSA, Power Sale and Coordination Umbrella Agreement between
Oglethorpe and Georgia Power Company, dated as of November 12,
1990. (Filed as Exhibit 10.28 to the Registrant's Form 8-K, filed
January 4, 1991, File No. 33-7591.)
*10.15 -- Amended and Restated Nuclear Managing Board Agreement among
Georgia Power Company, Oglethorpe Power Corporation, Municipal
Electric Authority of Georgia and City of Dalton, Georgia dated
as of July 1, 1993. (Filed as Exhibit 10.36 to the Registrant's
10-Q for the quarterly period ended September 30, 1993, File No.
33-7591.)
*10.16 -- Supplemental Agreement by and among Oglethorpe, Tri-County
Electric Membership Corporation and Georgia Power Company, dated
as of November 12, 1990, together with a Schedule identifying 38
other substantially identical Supplemental Agreements. (Filed as
Exhibit 10.30 to the Registrant's Form 8-K, filed January 4,
1991, File No. 33-7591.)
*10.17 -- Unit Capacity and Energy Purchase Agreement between Oglethorpe
and Entergy Power Incorporated, dated as of October 11, 1990.
(Filed as Exhibit 10.31 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1990, File No. 33-7591.)
*10.18 -- Power Purchase Agreement between Oglethorpe and Hartwell Energy
Limited Partnership, dated as of June 12, 1992. (Filed as Exhibit
10.35 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1992, File No. 33-7591).
*10.19(2) -- Power Purchase and Sale Agreement among LG&E Power Marketing
Inc., LG&E Energy Corp. and Oglethorpe, dated as of November 19,
1996. (Filed as Exhibit 10.30 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.20(2) -- Power Purchase and Sale Agreement among LG&E Power Marketing
Inc., LG&E Power Inc. and Oglethorpe, dated as of January 1,
1997. (Filed as Exhibit 10.31 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1996, File No. 33-7591.)
83
*10.21.1 -- Participation Agreement (P1), dated as of December 30, 1996,
among Oglethorpe, Rocky Mountain Leasing Corporation, Fleet
National Bank, as Owner Trustee, SunTrust Bank, Atlanta, as
Co-Trustee, the Owner Participant named therein and
Utrecht-America Finance Co., as Lender, together with a Schedule
identifying five other substantially identical Participation
Agreements. (Filed as Exhibit 10.32.1 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.2 -- Rocky Mountain Head Lease Agreement (P1), dated as of December
30, 1996, between Oglethorpe and SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other
substantially identical Rocky Mountain Head Lease Agreements.
(Filed as Exhibit 10.32.2 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.21.3 -- Ground Lease Agreement (P1), dated as of December 30, 1996,
between Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other substantially
identical Ground Lease Agreements. (Filed as Exhibit 10.32.3 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.21.4 -- Rocky Mountain Agreements Assignment and Assumption Agreement
(P1), dated as of December 30, 1996, between Oglethorpe and
SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Rocky Mountain
Agreements Assignment and Assumption Agreements. (Filed as
Exhibit 10.32.4 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
*10.21.5 -- Facility Lease Agreement (P1), dated as of December 30, 1996,
between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain
Leasing Corporation, together with a Schedule identifying five
other substantially identical Facility Lease Agreements. (Filed
as Exhibit 10.32.5 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.21.6 -- Ground Sublease Agreement (P1), dated as of December 30, 1996,
between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain
Leasing Corporation, together with a Schedule identifying five
other substantially identical Ground Sublease Agreements. (Filed
as Exhibit 10.32.6 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.21.7 -- Rocky Mountain Agreements Re-assignment and Assumption Agreement
(P1), dated as of December 30, 1996, between SunTrust Bank,
Atlanta, as Co-Trustee and Rocky Mountain Leasing Corporation,
together with a Schedule identifying five other substantially
identical Rocky Mountain Agreements Re-assignment and Assumption
Agreements. (Filed as Exhibit 10.32.7 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.8 -- Facility Sublease Agreement (P1), dated as of December 30, 1996,
between Oglethorpe and Rocky Mountain Leasing Corporation,
together with a Schedule identifying five other substantially
identical Facility Sublease Agreements. (Filed as Exhibit 10.32.8
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
84
*10.21.9 -- Ground Sub-sublease Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation and Oglethorpe,
together with a Schedule identifying five other substantially
identical Ground Sub-sublease Agreements. (Filed as Exhibit
10.32.9 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.21.10 -- Rocky Mountain Agreements Second Re-assignment and Assumption
Agreement (P1), dated as of December 30, 1996, between Rocky
Mountain Leasing Corporation and Oglethorpe, together with a
Schedule identifying five other substantially identical Rocky
Mountain Agreements Second Re-assignment and Assumption
Agreements. (Filed as Exhibit 10.32.10 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.11 -- Payment Undertaking Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation and Cooperatieve
Centrale Raiffeisen-Boerenleenbank B.A., New York Branch, as the
Bank, together with a Schedule identifying five other
substantially identical Payment Undertaking Agreements. (Filed as
Exhibit 10.32.11 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.21.12 -- Payment Undertaking Pledge Agreement (P1), dated as of December
30, 1996, between Rocky Mountain Leasing Corporation, Fleet
National Bank, as Owner Trustee, and SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other
substantially identical Payment Undertaking Pledge Agreements.
(Filed as Exhibit 10.32.12 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.21.13 -- Equity Funding Agreement (P1), dated as of December 30, 1996,
between Rocky Mountain Leasing Corporation, AIG Match Funding
Corp., the Owner Participant named therein, Fleet National Bank,
as Owner Trustee, and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other substantially
identical Equity Funding Agreements. (Filed as Exhibit 10.32.13
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*10.21.14 -- Equity Funding Pledge Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation and SunTrust
Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Equity Funding
Pledge Agreements. (Filed as Exhibit 10.32.14 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.15 -- Deed to Secure Debt, Assignment of Surety Bond and Security
Agreement (P1), dated as of December 30, 1996, between Rocky
Mountain Leasing Corporation, SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other
substantially identical Collateral Assignment, Assignment of
Surety Bond and Security Agreements. (Filed as Exhibit 10.32.15
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*10.21.16 -- Subordinated Deed to Secure Debt and Security Agreement (P1),
dated as of December 30, 1996, among Oglethorpe, AMBAC Indemnity
Corporation and SunTrust Bank, Atlanta, as Co-Trustee, together
with a Schedule identifying five other substantially identical
Subordinated Deed to Secure Debt and Security Agreements. (Filed
as Exhibit 10.32.16 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
85
*10.21.17 -- Tax Indemnification Agreement (P1), dated as of December 30,
1996, between Oglethorpe and the Owner Participant named therein,
together with a Schedule identifying five other substantially
identical Tax Indemnification Agreements. (Filed as Exhibit
10.32.17 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.21.18 -- Consent No. 1, dated as of December 30, 1996, among Georgia Power
Company, Oglethorpe, SunTrust Bank, Atlanta, as Co-Trustee, and
Fleet National Bank, as Owner Trustee, together with a Schedule
identifying five other substantially identical Consents. (Filed
as Exhibit 10.32.18 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.21.19(a)-- OPC Intercreditor and Security Agreement No. 1, dated as of
December 30, 1996, among the United States of America, acting
through the Administrator of the Rural Utilities Service,
SunTrust Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing
Corporation, SunTrust Bank, Atlanta, as Co-Trustee, Fleet
National Bank, as Owner Trustee, Utrecht-America Finance Co., as
Lender and AMBAC Indemnity Corporation, together with a Schedule
identifying five other substantially identical Intercreditor and
Security Agreements. (Filed as Exhibit 10.32.19 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.21.19(b)-- Supplement to OPC Intercreditor and Security Agreement No. 1,
dated as of March 1, 1997, among the United States of America,
acting through the Administrator of the Rural Utilities Service,
SunTrust Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing
Corporation, SunTrust Bank, Atlanta, as Co-Trustee, Fleet
National Bank, as Owner Trustee, Utrecht-America Finance Co., as
Lender and AMBAC Indemnity Corporation, together with a Schedule
identifying five other substantially identical Supplements to OPC
Intercreditor and Security Agreements. (Filed as Exhibit
10.32.19(b) to the Registrant's Form S-4 Registration Statement,
File No. 333-42759.)
*10.22.1 -- Member Transmission Service Agreement, dated as of March 1, 1997,
by and between Oglethorpe and Georgia Transmission Corporation
(An Electric Membership Corporation). (Filed as Exhibit 10.33.1
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*10.22.2 -- Generation Services Agreement, dated as of March 1, 1997, by and
between Oglethorpe and Georgia System Operations Corporation.
(Filed as Exhibit 10.33.2 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.22.3 -- Operation Services Agreement, dated as of March 1, 1997, by and
between Oglethorpe and Georgia System Operations Corporation.
(Filed as Exhibit 10.33.3 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23(2) -- Power Purchase and Sale Agreement between Morgan Stanley Capital
Group Inc. and Oglethorpe, dated as of April 7, 1997. (Filed as
Exhibit 10.34 to the Registrant's Form 10-Q for the quarterly
period ended March 31, 1997, File No. 33-7591.)
86
*10.24 -- Long Term Transaction Service Agreement Under Southern Companies'
Federal Energy Regulatory Commission Electric Tariff Volume No. 4
Market-Based Rate Tariff, between Georgia Power Company and
Oglethorpe, dated as of February 26, 1999. (Filed as Exhibit
10.27 to the Registrant's Form 10-Q for the quarterly period
ended March 31, 1999, File No. 33-7591.)
*10.25(3) -- Employment Agreement, dated as of September 15, 1999, between
Oglethorpe and Thomas A. Smith. (Filed as Exhibit 10.26 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
10.26(3) -- Employment Agreement, dated July 25, 2000, between Oglethorpe and
Michael W. Price.
*10.27(3) -- Employment Agreement, dated August 7, 2000, between Oglethorpe
and W. Clayton Robbins. (Filed as Exhibit 10.28 to the
Registrant's Form 10-Q for the quarterly period ended June 30,
2000, File No. 33-7591.)
*10.28(3) -- Employment Agreement, dated August 7, 2000, between Oglethorpe
and Elizabeth Higgins. (Filed as Exhibit 10.29 to the
Registrant's Form 10-Q for the quarterly period ended June 30,
2000, File No. 33-7591.)
21.1 -- Rocky Mountain Leasing Corporation, a Delaware corporation.
- ---------------------
(1) Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this document(s) is not filed
herewith; however the registrant hereby agrees that such document(s) will
be provided to the Commission upon request.
(2) Certain portions of this document have been omitted as confidential and
filed separately with the Commission.
(3) Indicates a management contract or compensatory arrangement required to be
filed as an exhibit to this Report.
(b) Reports on Form 8-K.
Oglethorpe filed no reports on Form 8-K during the fourth quarter of
2000.
87
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 16th day of
March, 2001.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
By: /s/ J. CALVIN EARWOOD
---------------------------------
J. CALVIN EARWOOD
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ J. CALVIN EARWOOD Chairman of the Board, Director March 16, 2001
- ----------------------- (Principal Executive Officer)
J. CALVIN EARWOOD
/s/ THOMAS A. SMITH President and Chief Executive Officer March 16, 2001
- ----------------------- (Principal Executive Officer)
THOMAS A. SMITH
/s/ MAC F. OGLESBY Treasurer, Director (Principal March 16, 2001
- ----------------------- Financial Officer)
MAC F. OGLESBY
/s/W. CLAYTON ROBBINS Senior Vice President, Finance and March 16, 2001
- ----------------------- Administration (Principal Financial
W. CLAYTON ROBBINS Officer)
/s/ WILLIE B. COLLINS Controller and Chief Risk Officer March 16, 2001
- -----------------------
WILLIE B. COLLINS
/s/ ASHLEY C. BROWN Director March 16, 2001
- -----------------------
ASHLEY C. BROWN
/s/ LARRY N. CHADWICK Director March 16, 2001
- -----------------------
LARRY N. CHADWICK
/s/ BENNY W. DENHAM Director March 16, 2001
- -----------------------
BENNY W. DENHAM
88
Signature Title Date
/s/ WM. RONALD DUFFEY Director March 16, 2001
- ---------------------------------------
WM. RONALD DUFFEY
/s/ SAMMY M. JENKINS Director March 16, 2001
- ---------------------------------------
SAMMY M. JENKINS
/s/ J. SAM L. RABUN Director March 16, 2001
- ---------------------------------------
J. SAM L. RABUN
/s/ JOHN S. RANSON Director March 16, 2001
- ---------------------------------------
JOHN S. RANSON
/s/ JEFFREY D. TRANEN Director March 16, 2001
- ---------------------------------------
JEFFREY D. TRANEN
89
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT.
The registrant is a membership corporation and has no authorized or outstanding
equity securities. Proxies are not solicited from the holders of Oglethorpe's
public bonds. No annual report or proxy material has been sent to such
bondholders.
90