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, 2001
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
2001 FORM 10-K ANNUAL REPORT
Table of Contents
ITEM Page
- ---- ----
PART I
1 Business ............................................................................... 1
Oglethorpe Power Corporation.......................................................... 1
Oglethorpe's Power Supply Resources................................................... 6
The Members and Their Power Supply Resources.......................................... 11
Factors Affecting the Electric Utility Industry....................................... 16
2 Properties.............................................................................. 21
3 Legal Proceedings....................................................................... 27
4 Submission of Matters to a Vote of Security Holders..................................... 28
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters................... 29
6 Selected Financial Data................................................................. 29
7 Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................................... 30
7A Quantitative and Qualitative Disclosures About Market Risk.............................. 41
8 Financial Statements and Supplementary Data............................................. 45
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................................................ 68
PART III
10 Directors and Executive Officers of the Registrant...................................... 68
11 Executive Compensation.................................................................. 72
12 Security Ownership of Certain Beneficial Owners and Management.......................... 74
13 Certain Relationships and Related Transactions.......................................... 74
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................ 75
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SELECTED DEFINITIONS
The following terms used in this report have the meanings indicated below:
Term Meaning
APM ACES Power Marketing
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 175 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 1.5 million
electric consumers (meters) representing approximately 3.7 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 generating
plants and power purchased from power marketers and other suppliers. Oglethorpe
provides this service pursuant to long-term, take-or-pay Wholesale Power
Contracts described below. The Wholesale Power Contracts obligate the Members on
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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
purchase 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 has undivided interests in eighteen generating units. These
units provide Oglethorpe with a total of 3,660 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, 325 MW
of gas-fired combustion turbine capacity, 15 MW of oil-fired combustion turbine
capacity and 2 MW of conventional hydroelectric capacity.
Oglethorpe purchases a total of approximately 750 MW of power pursuant to
long-term power purchase agreements. Oglethorpe also has arrangements with two
power marketers to supply power to Oglethorpe in amounts that are based on the
growth in the Members' requirements, representing about 30% of its power supply
capability in 2002. These power marketer arrangements also 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. (See "OGLETHORPE'S POWER SUPPLY RESOURCES" and
"PROPERTIES--Generating Facilities" in Item 2.)
GTC provides transmission services to the Members for delivery of the
Members' power purchases. (See "Relationship with GTC" herein.)
In 2001, Jackson EMC and Cobb EMC accounted for 12.1% and 11.6% of
Oglethorpe's total revenues, respectively. None of the other Members accounted
for as much as 10% of Oglethorpe's total revenues in 2001.
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
Oglethorpe when due, all amounts payable by the Member under its Wholesale Power
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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.
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
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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 and
administrative support services to Oglethorpe. Oglethorpe has contracted with
GSOC to operate Oglethorpe's electric capacity and energy pool and to schedule
and dispatch Oglethorpe's 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.
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.
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Relationships with Smarr EMC, Talbot EMC and Chattahoochee 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 and combined cycle facilities. Oglethorpe and the Members determined
that such facilities should be owned, not by Oglethorpe, but by separate
entities owned by participating Members.
Smarr EMC was formed as a Georgia electric membership corporation in 1998
and is owned by 37 of Oglethorpe's 39 Members. Smarr EMC owns two combustion
turbine facilities with aggregate capacity of 709 MW. Talbot EMC and
Chattahoochee EMC were formed in 2001 as Georgia electric membership
corporations. Talbot EMC is owned by 30 Members and is constructing a combustion
turbine facility designed to provide 618 MW of capacity. Chattahoochee EMC is
owned by 28 Members and is constructing a combined cycle facility designed to
provide 468 MW of capacity. See "THE MEMBERS AND THEIR POWER SUPPLY
RESOURCES--Member Power Supply Resources" and "--Future Power Supply Resources."
Oglethorpe also provides construction, operations, financial and management
services for Smarr EMC, Talbot EMC and Chattahoochee EMC.
Oglethorpe is providing interim loans to Talbot EMC and Chattahoochee EMC
to finance a portion of the cost of the construction of their generating
facilities. Oglethorpe is guaranteeing an interim financing arrangement between
Chattahoochee EMC and a financial institution providing up to 50 percent of the
cost of Chattahoochee EMC's generating facility. (See "MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Financial
Condition--Capital Requirements" in Item 7.)
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.
In 2000, loan applications were made to RUS to provide permanent financing
for the generating facilities now owned by Talbot EMC and Chattahoochee EMC.
(See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES--Future Power Resources.")
5
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 is also one of Oglethorpe's
suppliers of purchased power. GPC also supplies services to Oglethorpe and GSOC
to support the scheduling and dispatch of Oglethorpe's resources, including
off-system transactions. GPC and the Members are competitors in the State of
Georgia for electric service to any new customer that has a choice of supplier
under the Georgia Territorial Electric Service Act, which was enacted in 1973
(the "Territorial Act"). For further information regarding the agreements with
GPC and Oglethorpe's and the Members' relationships 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." Also see "PROPERTIES--Fuel Supply," "--Co-Owners
of the Plants--Georgia Power Company" and "--The Plant Agreements" in Item 2.
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 substantially equal monthly amounts.
OGLETHORPE'S POWER SUPPLY RESOURCES
General
Oglethorpe supplies capacity and energy to the Members from a combination
of generating plants and from power purchased under long-term contracts.
Oglethorpe also has arrangements with power marketers to supply power and 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 eighteen 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"), and 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"), a 74.61%
undivided interest in Rocky Mountain and a 100% interest in the Doyle I, LLC
Generating Plant ("Plant Doyle"), through a power purchase agreement that
Oglethorpe treats as a capital lease. 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. Plant Doyle consists of five
gas-fired combustion turbine units with an aggregate nominal contract capacity
of 325 MW.
MEAG, Dalton and GPC also have interests in Plants Hatch, Vogtle and
Wansley and Scherer Units No. 1 and No. 2. GPC serves as operating agent for
6
these units. GPC also has an interest 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. After
considering resources made available to LEM and Morgan Stanley, Oglethorpe
estimates that about 30% of its power supply capability will be provided by
these contracts in 2002.
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. LG&E Energy Corp. is now an indirect wholly owned subsidiary of
Powergen plc, a British public limited company.
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.
LEM and Oglethorpe are resolving issues relating to the administration of
the LEM agreement through the contractually defined arbitration process. (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
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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 participants in its electricity capacity
and energy pool 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.
(See "Capacity and Energy Pool" herein.)
Morgan Stanley is a subsidiary of Morgan Stanley Dean Witter & Co., a
diversified investment banking and financial services company. Morgan Stanley
Dean Witter & 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
Oglethorpe has an agreement with GPC to purchase capacity and associated
energy on a take-or-pay basis. Under this agreement, Oglethorpe purchased 375 MW
of capacity and associated energy from GPC through August 31, 2001, and
purchased and will continue to purchase 250 MW from September 1, 2001 to March
31, 2006.
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.
Oglethorpe also 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.
See Note 9 of Notes to Financial Statements 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
8
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 2001. 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 are responsible for supplying
Oglethorpe with sufficient power to fulfill this power sale.
Other Power System Arrangements
Oglethorpe has interchange, transmission and/or short-term capacity and
energy purchase or sale agreements with approximately 70 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, the Members' requirements have
exceeded the amounts provided by these arrangements. Oglethorpe expects that the
Members' requirements will continue to exceed contracted purchases through the
remaining term of these power marketing arrangements. 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.
Twenty-six Members have elected not to receive these services for 2002.
Oglethorpe and the remaining 13 Members are utilizing a pilot program pursuant
to which these Members have elected to receive certain basic planning services
under separate contracts and waive their right to receive planning and
procurement services under the Wholesale Power Contracts. Should these Members
find the pilot plan arrangement satisfactory, these services under the Wholesale
Power Contract may be eliminated after a transition period. For information
regarding the Members' plans to meet their future power needs, see "THE MEMBERS
AND THEIR POWER SUPPLY Resources--Future Power Resources."
Oglethorpe is not currently engaged in long-term resource procurement for
any Member, although it is involved in short-term procurement activities in
connection with the operation of the pool. Oglethorpe does not currently plan to
construct or acquire any additional power supply resources, although it is
currently providing construction management services for Talbot EMC and
Chattahoochee EMC. See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES--Member
Power Supply Resources."
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, which it may elect to discontinue at any time.
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
to schedule and pseudo-dispatch separately the capacity represented by the
9
Member's percentage capacity responsibility under the Wholesale Power Contracts.
The Members may also elect to include all or part of their other resources in
the pool. See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES--Member Power Supply
Resources."
Oglethorpe buys and sells energy on behalf of Members that participate in
the pool. Oglethorpe has a service agreement under which ACES Power Marketing
acts as Oglethorpe's agent to perform these services. (See "QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK--Commodity Price Risk--Risk
Management.") Oglethorpe has contracted with GSOC to operate the pool. Because a
large numbeR of Members have elected to schedule and pseudo-dispatch separately
their respective percentage capacity responsibilities, Oglethorpe, GSOC and the
Members are working to develop new arrangements to implement more effectively
the separate scheduling rights of the Members.
10
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 EMC
Grady EMC Okefenoke Rural EMC Walton EMC
GreyStone Power Corporation, an EMC Pataula EMC Washington EMC
The Members serve approximately 1.5 million electric consumers (meters)
representing approximately 3.7 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 2001 amounted to approximately 28 million MWh, with
approximately 66% to residential consumers, 32% to commercial and industrial
consumers and 2% to other consumers. The Members are the principal suppliers for
the power needs of rural Georgia. While the Members do not serve any major
cities, portions of their service territories are in close proximity to urban
areas and are experiencing substantial growth due to the expansion of urban
areas, including metropolitan Atlanta, into suburban areas and the growth of
suburban areas into neighboring rural areas. The Members have experienced
average annual compound growth rates from 1999 through 2001 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 1999 through 2001, and also shows the amounts of
energy requirements supplied by Oglethorpe. From 1999 through 2001, demand and
energy requirements of the Members increased at an average annual compound
growth rate of 0.6% and 4.8%, respectively.
Member Member Energy
Demand (MW) Requirements (MWh)
----------- -----------------------------------------------
Total(1) Total(2) Supplied by Oglethorpe(3)
-------- -------- -------------------------
1999 6,452 25,760,322 24,755,812
2000 6,703 28,221,306 27,232,641
2001 6,532 28,332,257 26,950,149
- ----------
<FN>
(1) System peak demand of the Members measured at the Members' delivery points
(net of system losses), adjusted to include requirements served by
Oglethorpe and Member resources behind the delivery points.
(2) Retail requirements served by Oglethorpe and Member resources, adjusted to
include requirements served by 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.")
</FN>
11
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
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
12
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, other 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
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
13
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.
GSOC provides operation services for the benefit of the Members through
agreements with Oglethorpe, including dispatch of Oglethorpe's resources and
other power supply resources owned by the Members.
For additional 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 2001, the
aggregate SEPA allocation to the Members was 564 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.
Incremental Requirements Purchases
A number of Members have entered into long-term contracts with third
parties for all of their future incremental power requirements. Other Members
may do so in the future.
Other Member Resources
Two Members formed an entity that has constructed 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.
14
In addition, a number of Members have installed and may continue to install
small diesel generators and gas-fired microturbines on their distribution
systems.
Oglethorpe has not undertaken to obtain a complete list of Member power
supply resources. Any of the Members may have committed or may commit to
additional power supply obligations not described above.
Future Power Resources
Talbot EMC and Chattahoochee EMC
Thirty of Oglethorpe's Members formed Talbot EMC, a Georgia electric
membership corporation, in 2001 to construct and own a six-unit gas fired
combustion turbine facility designed to provide 618 MW of capacity. Four of the
combustion turbines are targeted for completion by summer 2002, with the other
two to be completed in 2003. The Members of Talbot EMC have entered into
long-term, take-or-pay power purchase agreements with Talbot EMC pursuant to
which the Members will pay all costs of constructing, owning and operating the
facility and will be entitled to the output of the facility when it is
completed.
Twenty eight of Oglethorpe's Members formed Chattahoochee EMC, a Georgia
electric membership corporation, in 2001 to construct and own a gas-fired
combined cycle facility designed to provide 468 MW of capacity. The combined
cycle facility is targeted for completion in 2003. The Members of Chattahoochee
EMC have entered into long-term, take-or-pay power purchase agreements with
Chattahoochee EMC pursuant to which the Members will pay all costs of
constructing, owning and operating the facility and will be entitled to the
output of the facility when it is completed.
For information regarding services and financial support that Oglethorpe
provides to Talbot EMC and Chattahoochee EMC, see "OGLETHORPE POWER
CORPORATION--Relationships with Smarr EMC, Talbot EMC and Chattahoochee EMC" and
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Financial Condition--Capital Requirements" in Item 7.
GPC Block Purchase
Thirty Members have entered into long-term power supply contracts with GPC,
under which the Members will purchase an aggregate of 750 MW of capacity and
associated energy. Delivery under the agreement is scheduled to begin in 2005.
15
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 development of energy trading markets,
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 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.
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. Oglethorpe cannot provide assurance that it
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
16
environmental-related capital expenditures of approximately $17 million in 2001,
and expects to spend $76 million in 2002 and $31 million in 2003 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.
Reductions in nitrogen oxides emissions are also being imposed, as part of
Georgia's State Implementation Plan, in an effort to bring the metropolitan
Atlanta area, currently classified as a "serious nonattainment area" pursuant to
the one-hour National Ambient Air Quality Standards ("NAAQS") for ozone, into
attainment. As part of this Plan, both Plants Wansley and Scherer were recently
included in stringent nitrogen oxides emissions averaging plans, which will
cause the co-owners of the plants to install new control equipment at both
plants no later than May 2003. The expected costs to install this equipment are
included in Oglethorpe's expected environmental-related capital expenditures
described above.
A number of recently finalized regulations, proposed regulations and other
actions could result in more stringent controls on all emissions, including
utility emissions. The actions that appear to be the most significant are
described below.
First, 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
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.
Second, 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
2005. States remain free to choose the sources on which to impose reductions
17
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 has proposed a rule
reinstating the cap for Georgia, which would delay implementation until 2005.
Georgia's implementation plan for this regulation will depend on how this
proposed rulemaking is finalized. 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. However, the co-owners of
Plant Scherer are converting Units No. 1 and No. 2 from bituminous coal to
sub-bituminous coal, which will substantially reduce the nitrogen oxides
emissions from these units.
Third, 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 challenge is resolved,
Oglethorpe will not know what controls, if any, must be installed at Plants
Wansley and/or Scherer to comply with this rule.
Fourth, 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, 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 affected by 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.
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
18
purchased from GPC. (See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--Power
Purchase and Sale Arrangements--Power Purchases.")
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 2034 and 2038 and 2027 and 2029, respectively. The licenses for Plant
Hatch were extended to their current expiration dates in January 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 into 2010, and Plant Vogtle spent fuel storage is
expected to be sufficient into 2014. Oglethorpe expects that procurement of
on-site dry storage capacity at Plants Hatch and Vogtle will commence in
sufficient time to maintain pool full-core discharge capability. (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.
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.
19
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.
20
ITEM 2. PROPERTIES
Generating Facilities
The following table sets forth certain information with respect to
Oglethorpe's generating facilities, 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 2034
Unit No. 2........................ Nuclear 30 246.0 1979 2038
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(1)
Unit No. 2........................ Coal 30 259.5 1978 N/A(1)
Combustion Turbine................ Oil 30 14.8 1980 N/A(1)
Plant Scherer (near Forsyth, Ga.)
Unit No. 1........................ Coal 60 490.8 1982 N/A(1)
Unit No. 2........................ Coal 60 490.8 1984 N/A(1)
Tallassee (near Athens, Ga.)......... Hydro 100 2.1 1986 2023
Rocky Mountain (near Rome, Ga.)...... Pumped
Storage
Hydro 74.61 632.5 1995 2027
Plant Doyle (near Monroe, Ga.) ...... Gas 100 325.0(2) 2000 N/A(1)
--------
Total Ownership 3,660.0
=======
- ----------
<FN>
(1) Fossil-fired units do not operate under operating licenses similar to those
granted to nuclear units by the NRC and to hydroelectric plants by FERC.
(2) Nominal plant capacity identified in the Power Purchase and Sale Agreement
with Doyle I, LLC. See "The Plant Agreements--Doyle".
</FN>
21
Plant Performance
The following table sets forth certain operating performance information of
each of Oglethorpe's major generating facilities:
Equivalent Capacity
Availability(1) Factor(2)
--------------- ---------
Unit 2001 2000 1999 2001 2000 1999
- ---- ---- ---- ---- ---- ---- ----
Plant Hatch
Unit No. 1.. 99% 84% 81% 99% 85% 83%
Unit No. 2.. 86 89 92 86 90 94
Plant Vogtle
Unit No. 1.. 99 86 92 101 91 94
Unit No. 2.. 92 100 88 94 102 89
Plant Wansley
Unit No. 1.. 83 83 91 78 77 73
Unit No. 2.. 87 78 86 81 72 66
Plant Scherer
Unit No. 1.. 81 100 86 58 79 67
Unit No. 2.. 94 90 95 71 73 79
Rocky
Mountain(3)
Unit No. 1.. 94 94 97 24 26 23
Unit No. 2.. 99 91 96 21 20 16
Unit No. 3.. 95 94 91 17 17 19
Plant
Doyle(3,4)
Unit No. 1.. 100 100 -- 4 2 --
Unit No. 2.. 100 97 -- 5 8 --
Unit No. 3.. 100 92 -- 4 7 --
Unit No. 4.. 100 100 -- 6 9 --
Unit No. 5.. 100 100 6 8 --
- --------------
<FN>
(1) Equivalent Availability is a measure of the percentage of time that a unit
was available to generate if called upon, adjusted for periods when the unit
is partially derated from the "maximum dependable capacity" rating.
(2) Capacity Factor is a measure of the output of a unit as a percentage of the
maximum output, based on the "maximum dependable capacity" rating, over the
period of measure.
(3) Rocky Mountain and Plant Doyle primarily operate as peaking plants, which
results in low capacity factors.
(4) Plant Doyle began operation in May 2000. Equivalent Availability of each
Doyle unit is measured only during the period May 15 - September 15,
reflecting the contractual availability commitment of Doyle I, LLC. The
units may be dispatched by Oglethorpe during other periods if the units are
available.
</FN>
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, 2002, there was a
53-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,
2002, the coal stockpile at Plant Scherer contained a 36-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. The co-owners of Plant Scherer have undertaken a
project to convert Units No. 1 and No. 2 at Plant Scherer to burn sub-bituminous
coal, and will thus not then maintain separate stock piles. Oglethorpe leases
approximately 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.
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 to operate these plants, including nuclear fuel
22
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.
Natural Gas. Oglethorpe purchases the natural gas, including transportation
and other related services, needed to operate Doyle and the combustion turbines
owned by Hartwell Energy Limited Partnership. Oglethorpe purchases natural gas
in the spot market and under agreements at indexed prices. Oglethorpe has
entered into hedge agreements to manage its exposure to fluctuations in the
market price of natural gas. Oglethorpe expects to continue to manage exposure
to such risks only with respect to Members that participate in Oglethorpe's pool
and elect to receive such services. See "QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK--Commodity Price Risk."
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
===== ===== ===== ===== ===== ===== ===== ===== ====== === =====
<FN>
(1) Based on nameplate ratings.
</FN>
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 48 cities and one county in the State of
Georgia. Such political subdivisions, located in 39 of the State's 159 counties,
collectively serve approximately 290,000 electric consumers (meters).
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.
23
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
24
Plant Vogtle Ownership and Operating Agreements, provides for increased rights
for the co-owners regarding certain decisions and allows GPC to contract with a
third party for the operation of the nuclear units. 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 has
entered into an agreement with GPC, subject to RUS approval, to extend the
Operating Agreement for so long as an NRC operating license exists for each
unit. (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,
25
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.
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.
Doyle
Oglethorpe has an agreement with Doyle I, LLC, a limited liability company
owned by one of Oglethorpe's Members, Walton EMC, to purchase the output of a
gas-fired combustion turbine generating facility with a nominal contract rating
of 325 MW over a 15-year term. Delivery commenced May 15, 2000.
During the term of the agreement, Oglethorpe has the right and obligation
to purchase all of the capacity and energy from the facility. Oglethorpe is
obligated to pay to Doyle I each month a capacity charge based on a performance
rating and an energy charge equal to all costs of operating the facility.
Oglethorpe is responsible for supplying all natural gas necessary to operate the
facility. Oglethorpe has the right to dispatch the facility.
Doyle I operates the facility. Doyle I must make the units available from
May 15 to September 15 each year. Subject to air permit and other limitations,
Oglethorpe may dispatch the facility at other times to the extent that the
facility is available.
Oglethorpe has an option to purchase the facility at the end of the term of
the agreement at a fixed price. This agreement is treated as a capital lease of
the facility by Oglethorpe for financial reporting purposes.
26
ITEM 3. LEGAL PROCEEDINGS
PECO Proceeding
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 March 2002, FERC issued an
order denying Oglethorpe's request for dismissal. FERC also ordered GTC to file
an updated assessment of its "available transfer capacity" and ordered PECO to
inform FERC of its current transmission needs.
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.
2001 LEM Arbitration
In February 2001, LEM and its affiliates, LG&E Energy Corp. and LG&E Power,
Inc. (collectively, the "LG&E Parties") initiated a binding arbitration process
to resolve certain issues relating to the interpretation and administration of
the LEM Agreement and a similar agreement among LEM, LG&E Power, Inc. and
Oglethorpe that expired by its terms in 1999. The proceedings in the arbitration
were bifurcated into a liability phase and a damage determination phase. On
November 5, 2001, the arbitration panel issued an order on an issue-by-issue
basis in the liability phase, ruling in Oglethorpe's favor on some issues and in
the LG&E Parties' favor on some issues. Oglethorpe and the LG&E Parties have
submitted proposed remedies to the arbitration panel. The arbitration panel will
determine damages by selecting either Oglethorpe's proposed remedy or the LG&E
Parties' proposed remedy for each issue. Oglethorpe expects a decision on the
damage aspects of these issues in June 2002. Oglethorpe has recorded a $36
million reserve for estimated damages payable to LEM. If this arbitration panel
adopts all of LEM's proposed remedies, Oglethorpe believes the award could be
approximately $60 million.
1999 LEM Arbitration
In September 2001, the LG&E Parties filed motions in the United States
District Court for the Northern District of Georgia seeking to vacate the
court's confirmation of a 1999 arbitration award in Oglethorpe's favor affirming
the validity of the LEM Agreement, to vacate the underlying award, and to take
certain discovery, all based on alleged non-disclosure of information that LEM
claims would have been pertinent to the arbitration. Oglethorpe has filed
27
responses opposing LEM's motions and will continue to defend itself vigorously.
For a discussion of the LEM agreement, see "OGLETHORPE'S POWER SUPPLY
RESOURCES--Power Marketer Arrangements--LEM Agreement" in Item 1.
Other
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, 2001, 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)
2001 2000 1999 1998 1997
- ------------------------------------------------------------------------------------------------------------------------------------
Operating revenues:
Sales to Members $ 1,080,478 $ 1,146,064 $ 1,122,336 $ 1,095,904 $ 1,000,319
Sales to non-Members 58,811 53,333 53,896 48,263 47,533
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,139,289 1,199,397 1,176,232 1,144,167 1,047,852
- ------------------------------------------------------------------------------------------------------------------------------------
Operating expenses:
Fuel 221,449 230,729 196,182 191,399 206,315
Production 218,480 220,221 215,517 198,378 181,923
Purchased power 414,382 377,805 401,719 387,662 266,875
Depreciation and amortization 133,731 143,703 130,883 124,074 126,730
Income taxes (63,485) - - - -
Other operating expenses - - - - 6,334
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 924,557 972,458 944,301 901,513 788,177
- ------------------------------------------------------------------------------------------------------------------------------------
Operating margin 214,732 226,939 231,931 242,654 259,675
Other income, net 51,345 62,431 50,545 42,293 46,646
Net interest charges (247,660) (269,392) (262,538) (263,867) (283,916)
- ------------------------------------------------------------------------------------------------------------------------------------
Net margin $ 18,417 $ 19,978 $ 19,938 $ 21,080 $ 22,405
- ------------------------------------------------------------------------------------------------------------------------------------
Electric plant, net:
In service $ 3,224,634 $ 3,339,364 $ 3,312,669 $ 3,429,704 $ 3,588,204
Construction work in progress 38,564 24,841 18,299 20,948 13,578
- ------------------------------------------------------------------------------------------------------------------------------------
Total electric plant $ 3,263,198 $ 3,364,205 $ 3,330,968 $ 3,450,652 $ 3,601,782
- ------------------------------------------------------------------------------------------------------------------------------------
Total assets $ 4,724,667 $ 4,693,539 $ 4,564,622 $ 4,506,265 $ 4,509,857
- ------------------------------------------------------------------------------------------------------------------------------------
Capitalization:
Long-term debt $ 2,929,316 $ 3,019,019 $ 3,103,590 $ 3,177,883 $ 3,258,046
Obligation under capital leases 373,837 387,756 275,224 282,299 288,638
Other obligations 68,032 63,665 59,579 55,755 52,176
Patronage capital and membership fees 367,668 392,682 370,025 352,701 330,509
- ------------------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 3,738,853 $ 3,863,122 $ 3,808,418 $ 3,868,638 $ 3,929,369
- ------------------------------------------------------------------------------------------------------------------------------------
Property additions $ 69,824 $ 70,738 $ 41,829 $ 43,904 $ 63,527
- ------------------------------------------------------------------------------------------------------------------------------------
Energy supply (megawatt-hours):
Generated 19,157,910 19,802,501 18,295,514 17,781,896 17,722,059
Purchased 11,448,219 11,234,860 7,971,583 8,544,714 6,377,643
- ------------------------------------------------------------------------------------------------------------------------------------
Available for sale 30,606,129 31,037,361 26,267,097 26,326,610 24,099,702
- ------------------------------------------------------------------------------------------------------------------------------------
Member revenue per kWh sold 4.01(cent) 4.21(cent) 4.53(cent) 4.70(cent) 4.83(cent)
- ------------------------------------------------------------------------------------------------------------------------------------
29
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Summary of Critical Accounting Policies and Cooperative Operations
Basis of Accounting
Oglethorpe Power Corporation (An Electric Membership Corporation)
(Oglethorpe) follows generally accepted accounting principles and the practices
prescribed in the Uniform System of Accounts of the Federal Energy Regulatory
Commission (FERC) as modified and adopted by the Rural Utilities Service (RUS).
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, 2001 and 2000
and the reported amounts of revenues and expenses for each of the three years
ending December 31, 2001. Actual results could differ from those estimates.
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." SFAS No. 71 permits Oglethorpe to
record regulatory assets and regulatory liabilities to reflect future cost
recovery or refunds that Oglethorpe has a right to pass through to the Members.
At December 31, 2001, Oglethorpe's regulatory assets and liabilities totaled
$297 million and $82 million, respectively. See Note 1 of Notes to Financial
Statements in Item 8. 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.
Nuclear Decommissioning. Oglethorpe owns interests in two nuclear
facilities, Plant Vogtle and Plant Hatch. Oglethorpe will incur costs to
decommission these plants when their licenses expire. Oglethorpe currently
expects that Plant Vogtle and Plant Hatch will begin the decommissioning process
in 2027 and 2034, respectively. Based on a 2000 site study, Oglethorpe estimates
its portion of the costs of decommissioning to be $308 million for Plant Vogtle
and $314 million for Plant Hatch. The decommissioning cost estimates are based
on prompt dismantlement and removal of the plant from service. The actual
decommissioning costs may vary from these 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 decommissioning reserve
together with expected earnings on the external fund (described below), should
be sufficient to meet the current projected required funding levels for Plant
Vogtle and Plant Hatch. Based on current assumptions, Oglethorpe's management
does not expect to record an annual provision for decommissioning in future
years. These projections are based on an assumed cost escalation rate of 4.72%
and an assumed return on trust assets of 8%. Oglethorpe's management believes
that any increase in cost estimates of decommissioning can be recovered in
future rates.
In compliance with NRC regulations, Oglethorpe maintains an external trust
fund to provide for a portion of the cost of decommissioning its nuclear
facilities. The NRC regulations require funding levels based on average expected
cost to decommission only the radioactive portions of a typical nuclear
facility.
In June of 2001, the Financial Accounting Standards Board issued SFAS No.
143, "Accounting for Asset Retirement Obligations." The statement provides
accounting and reporting standards for recognizing obligations related to costs
associated with the retirement of long-lived assets. SFAS No. 143 requires
30
obligations associated with the retirement of long-lived assets to be recognized
at their fair value in the period in which they are incurred if a reasonable
estimate of fair value can be made. The fair value of the asset retirement costs
is capitalized as part of the carrying amount of the long-lived asset and
subsequently allocated to expense using a systematic and rational method over
the assets' useful life. Any subsequent changes to the fair value of the
liability due to passage of time or changes in the amount or timing of estimated
cash flows is recognized as an accretion expense.
Adoption of SFAS No. 143 would require Oglethorpe to recognize the fair
value of its decommissioning liability. Under SFAS No. 71, Oglethorpe may record
an offsetting regulatory asset or liability to reflect the difference in timing
of recognition of the costs of decommissioning for financial reporting purposes
and for ratemaking purposes. Oglethorpe will be required to adopt this statement
no later than January 1, 2003. Oglethorpe's management is currently assessing
the impact of this statement on its results of operations and financial
condition.
Accounting for Derivatives. 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, 2001 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 related to the interest rate
swaps. The fair value of the interest rate swap arrangements at December 31,
2001 was an unrealized loss of $36,859,000. See Note 2 of Notes to Financial
Statements.
The application of new rules for SFAS No. 133 is still evolving and further
guidance from the Financial Accounting Standards Board is expected which could
further impact Oglethorpe's financial statements. In addition, Oglethorpe will
continue to evaluate its use of derivatives, including their effectiveness for
hedging, and to apply appropriate procedures and methods for valuing them.
During 2001, Oglethorpe entered into natural gas financial contracts that are
classified as cash flow hedges. Oglethorpe utilizes natural gas financial
contracts in managing its exposure to fluctuations in the market price of
natural gas. At December 31, 2001, Oglethorpe recorded an unrealized loss in
other comprehensive margin of $7,537,000 and a corresponding increase in other
liabilities related to these natural gas financial contracts.
Margins and Patronage Capital
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, excluding
accumulated other comprehensive margin, of $410 million in patronage capital as
of December 31, 2001. Oglethorpe's equity ratio (patronage capital and
membership fees, excluding other comprehensive margin, divided by total
capitalization) increased from 9.6% at December 31, 2000 to 10.8% at December
31, 2001.
Patronage capital constitutes the principal equity of Oglethorpe. Any
distributions of patronage capital are subject to the discretion of the Board of
31
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.
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 2001, 2000 and 1999, 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 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. After
considering resources made available to LEM and Morgan Stanley, Oglethorpe
estimates that about 30% of its power supply capability will be provided by
these contracts in 2002.
32
In February 2001, LEM and its affiliates initiated a binding arbitration
process to resolve certain issues relating to the interpretation and
administration of the LEM agreement and a similar agreement with Oglethorpe that
expired by its terms in 1999. On November 5, 2001, the arbitration panel issued
an order on an issue-by-issue basis as to liability, ruling in Oglethorpe's
favor on some issues and in LEM's favor on some issues. Oglethorpe expects a
decision on the damage aspects of these issues in June 2002. Oglethorpe has
recorded a $36 million accrual to purchased power costs, and a corresponding
increase in current liabilities, for estimated damages payable to LEM. If the
arbitration panel adopts all of LEM's proposed remedies, Oglethorpe believes the
award could be approximately $60 million.
Operating Revenues
Sales to Members. Revenues from Members are collected pursuant to the
Wholesale Power Contracts and are a function of the demand for power by the
Members' consumers and Oglethorpe's cost of service. Revenues from sales to
Members decreased by 5.7% for 2001 compared to 2000 and increased by 2.1% for
2000 compared to 1999. Kilowatt-hours (kWh) sales to Members were 1.0% lower in
2001 compared to 2000 and 10.0% higher in 2000 compared to 1999. The average
revenue per kWh from sales to Members decreased 4.8% for 2001 compared to 2000
and decreased 7.1% for 2000 compared to 1999. The components of Member revenues
were as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
2001 2000 1999
- --------------------------------------------------------------------------------
Capacity revenues $ 537,392 $ 624,537 $ 613,974
Energy revenues 543,086 521,527 508,362
- --------------------------------------------------------------------------------
Total $1,080,478 $1,146,064 $1,122,336
- --------------------------------------------------------------------------------
Capacity revenues from Members decreased by 14.0% from 2000 to 2001
primarily as a result of lower depreciation and amortization and a credit to
income tax expense. For 2000 compared to 1999, Member capacity revenues
increased 1.7% primarily due to higher depreciation and amortization expense and
higher production costs offset in part by higher investment income.
Energy revenues from Members increased by 4.1% from 2000 to 2001 and by
2.6% from 1999 to 2000. The increase in Member energy revenues in 2001 compared
to 2000 primarily resulted from higher purchased power costs related to an
accrual for estimated damages payable to LEM resulting from the arbitration
ruling. The increase in 2000 compared to 1999 was primarily due to greater
volumes of energy sold to Members.
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
- --------------------------------------------------------------------------------
2001 26,950,149 4.01
2000 27,232,641 4.21
1999 24,755,812 4.53
- --------------------------------------------------------------------------------
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. In
2001 mild weather, combined with an increase in energy supplied by Member-owned
resources, mitigated by continued growth in the Members' service territories,
resulted in a 1.0% decrease in kWh sales to Members.
The energy portion of Member revenues per kWh increased 5.2% in 2001
compared to 2000 and decreased 6.8% in 2000 compared to 1999. Oglethorpe passes
through actual energy costs to the Members such that energy revenues equal
energy costs. The increase in 2001 for the cost of energy supplied to the
Members resulted primarily from higher purchased power costs. The decrease in
2000 of energy revenues per kWh was primarily due to the pass-through of lower
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)
2001 2000 1999
- --------------------------------------------------------------------------------
Sales to power companies $55,057 $46,952 $46,186
Sales to LEM and
Morgan Stanley 3,754 6,381 7,710
- --------------------------------------------------------------------------------
Total $58,811 $53,333 $53,896
- --------------------------------------------------------------------------------
Sales to power companies represent sales made directly by Oglethorpe.
Oglethorpe sells for its own account any energy available from the portion of
33
its resources dedicated to Morgan Stanley that is not scheduled by Morgan
Stanley pursuant to its power marketer arrangements. Sales to power companies
were higher in 2001 partly due to a cooler summer during 2001 and a
corresponding decrease in kWh sales to Members resulting in an increase in
energy available for sale to power companies. In addition, Oglethorpe increased
purchased kWhs for resale to power companies.
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 decreased 4.9% in 2001 compared to 2000
and increased 3.0% in 2000 compared to 1999. The decrease in operating expenses
in 2001 resulted primarily from lower depreciation and amortization and from a
credit for income taxes offset somewhat by higher purchased power costs.
Operating expenses increased in 2000 primarily as a result of higher fuel and
depreciation and amortization costs.
Total fuel costs decreased 4.0% in 2001 compared to 2000 primarily as a
result of a 3.1% decrease in generation. For 2000 compared to 1999 total fuel
costs increased 17.6% partly as a result of an 8.6% increase in kWhs of
generation and partly due to higher average fuel costs associated with increased
fossil generation and generation from a gas-fired combustion turbine facility
placed in service during May 2000. For 2000 compared to 1999 output of nuclear
generation was 4.3% higher and output of fossil generation was 9.9% higher. In
addition, output from gas-fired generation accounted for 1.2% of the total
increase in kWhs of generation. The larger portion of fossil and gas-fired
generation, with its higher average fuel cost compared to nuclear generation,
yielded an 8.4% increase in average fuel cost.
Purchased power costs increased 9.7% in 2001 compared to 2000 and decreased
6.0% in 2000 compared to 1999 as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
2001 2000 1999
- --------------------------------------------------------------------------------
Capacity costs $ 88,463 $ 93,771 $ 97,616
Energy costs 325,919 284,034 304,103
- --------------------------------------------------------------------------------
Total $414,382 $377,805 $401,719
- --------------------------------------------------------------------------------
Decreases in purchased power capacity costs in 2001 and 2000 were primarily
due to the elimination on September 1 of 2000 and 2001 of 125 megawatts of
capacity, on each date, under a power purchase agreement between Oglethorpe and
GPC.
Purchased power energy costs increased 14.7% in 2001 compared to 2000 and
decreased 6.6% in 2000 compared to 1999. The average cost of purchased power
energy per kWh increased 12.6% in 2001 compared to 2000 and decreased 33.7% in
2000 compared to 1999. The increase in average costs in 2001 was primarily due
to an accrual for estimated damages payable to LEM resulting from the
arbitration ruling. 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 volumes of purchased power increased 1.9% in 2001 compared to 2000 and
increased 42.5% in 2000 compared to 1999. 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 1999 through 2001 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 1999 through 2001, 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 $130 million in 2001, $150 million in 2000 and $133 million in
1999. For a discussion of the power purchase agreements, see Note 9 of Notes to
Financial Statements.
34
The higher 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 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.
The credit to income tax expense in 2001 resulted from a change in
Oglethorpe's Bylaws to determine its allocation of patronage on a tax basis
method rather than the historical book basis method. Due to this change,
Oglethorpe anticipates that all future patronage source income will be offset by
the patronage exclusion. Therefore, Oglethorpe has reversed $63,485,000 of net
deferred tax liabilities and has recognized an income tax credit in the same
amount. See Note 3 of Notes to Financial Statements.
Other Income (Expense)
Investment income decreased 27.8% in 2001 compared to 2000 primarily due to
lower earnings from the decommissioning fund. 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.
Interest Charges
Other interest expense decreased 50.6% in 2001 compared to 2000. The lower
other interest expense in 2001 was primarily as a result a decrease in interest
expense for decommissioning (which is recorded as an offset to interest earnings
on the decommissioning fund).
Net Margin
Oglethorpe's net margin for 2001, 2000 and 1999 was $18.4 million, $20.0
million and $19.9 million, respectively. Oglethorpe's margin requirement is
based on a ratio applied to interest charges. For 2001compared to 2000, the
reduction in interest charges reduced Oglethorpe's margin requirement.
Financial Condition
General
The principal changes in Oglethorpe's financial condition in 2001 were due
to property additions, an increase in patronage capital, an increase in the
amount of commercial paper outstanding and a decrease in cash and temporary cash
investments.
Property additions, including nuclear fuel purchases, totaled $70 million
and were financed with funds from operations.
Oglethorpe achieved a net margin of $18.4 million in 2001, which increased
equity (patronage capital) by a like amount for a total patronage capital,
excluding accumulated other comprehensive margin, of $410 million at December
31, 2001.
The amount of commercial paper outstanding increased by $275 million from
December 31, 2000 to December 31, 2001 due to borrowing to fund the interim
financing of new generation facilities owned by Talbot EMC and Chattahoochee
EMC.
Oglethorpe's cash and temporary cash investments totaled $276 million at
December 31, 2001, a decrease of $55 million from the prior year-end balance.
The decrease was due to the timing of long-term debt payments at year end 2000
and 2001. Included in the $276 million was $23 million in proceeds from the
issuance of pollution control bonds ("PCBs") in October 2001. The PCB proceeds
were used to repay a like amount of PCB principal that matured on January 1,
2002.
In addition to the $276 million in cash and temporary cash investments,
Oglethorpe had, at December 31, 2001, $89 million in other short-term
investments which represents a portion of its general funds invested with an
external fund manager. The funds are invested primarily in short-term bonds with
an average maturity of 1.7 years.
Capital Requirements
Capital Expenditures. As part of its ongoing capital planning, Oglethorpe
forecasts expenditures required for generating facilities and other capital
projects. The table below details these expenditure forecasts for 2002 through
2004. 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 regulatory approvals,
construction delays, cost of capital, equipment, material and labor, and
35
decisions whether to purchase or construct additional generation capacity.
- ----------------------------------------------------------------------------------------
(dollars in thousands)
Capital Expenditures(1)
- ----------------------------------------------------------------------------------------
Year Existing Environmental Nuclear General
Generation(2) Compliance Fuel Plant Total
- ----------------------------------------------------------------------------------------
2002 $ 28,000 $ 76,000 $ 37,000 $ 8,000 $149,000
2003 16,000 31,000 43,000 4,000 94,000
2004 19,000 2,000 33,000 5,000 59,000
- ----------------------------------------------------------------------------------------
Total $ 63,000 $109,000 $113,000 $ 17,000 $302,000
- ----------------------------------------------------------------------------------------
<FN>
(1) Excludes allowance for funds used during construction.
(2) Consists of replacements and additions to facilities in-service.
</FN>
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $3.2 billion as of December 31, 2001. Expenditures for property
additions during 2001 amounted to $70 million and were funded with funds from
operations. These expenditures were primarily for additions and replacements to
existing generation facilities, purchases of nuclear fuel and compliance with
environmental regulations.
Financing for Talbot EMC and Chattahoochee EMC. Thirty of Oglethorpe's
Members formed Talbot EMC, a Georgia electric membership corporation, in 2001 to
construct and own a six-unit gas-fired combustion turbine facility designed to
provide 618 MW of capacity. Four of the six combustion turbines are expected to
be in-service by the summer of 2002, with the other two expected to be
in-service by the summer of 2003.
Twenty-eight of Oglethorpe's Members formed Chattahoochee EMC, a Georgia
electric membership corporation, in 2001 to construct and own a gas-fired
combined cycle facility designed to provide 468 MW of capacity. The combined
cycle facility is expected to be in-service in the spring of 2003.
Oglethorpe is providing loans to Talbot EMC and Chattahoochee EMC to fund,
on an interim basis, a portion of the construction cost of the six combustion
turbines and the combined cycle facility. Oglethorpe is funding these loans
under its commercial paper program, and at December 31, 2001, $354 million of
commercial paper was outstanding for this purpose. At March 31, 2002, the amount
of commercial paper outstanding declined to $338 million. The loans are included
in Notes receivable on Oglethorpe's balance sheet.
The expected combined cost of constructing the six combustion turbines and
the combined cycle facility totals approximately $600 million. Oglethorpe
expects to have approximately $300 million of commercial paper outstanding into
early 2003 in conjunction with the interim financing for these facilities. Two
bridge loans have been secured to fund the remaining portion of the cost of
constructing these facilities. The National Rural Utilities Cooperative Finance
Corporation (CFC) is providing a $141 million bridge loan to Talbot EMC, and
Pitney Bowes Credit Corporation is providing a $160 million bridge loan to
Chattahoochee EMC. Oglethorpe's loans to Talbot EMC and Chattahoochee EMC are
subordinated to the CFC and Pitney Bowes loans, respectively. Oglethorpe is
providing a guarantee of the $160 million bridge loan to Chattahoochee EMC.
In 2000, Oglethorpe submitted loan applications to RUS to provide permanent
financing for these facilities. The loan applications were made on behalf of any
entity that may ultimately own these facilities, and Talbot EMC and
Chattahoochee EMC are now the applicants for RUS financing. Oglethorpe expects
RUS to act on these loan applications later in 2002. If approved by RUS, funding
is expected to occur for both projects by mid-2003. The proceeds of the RUS
permanent financing will be used first to repay the bridge loans and then the
loans from Oglethorpe. If RUS funding is delayed or denied, Oglethorpe will
assist Talbot EMC and Chattahoochee EMC to pursue alternative financing.
Contractual Obligations. In addition to the capital expenditures and
interim financing for Talbot EMC and Chattahoochee EMC discussed above, the
table below summarizes, as of December 31, 2001, Oglethorpe's contractual
obligations for the periods indicated.
- --------------------------------------------------------------------------------
(dollars in thousands)
Contractual
Obligations 2003- 2007
As of 12/31/01 2002 2006 and beyond Total
- --------------------------------------------------------------------------------
Long-Term Debt $ 111,971 $ 629,764 $2,299,552 $3,041,287
Capital Leases 44,314 177,206 463,715 685,235
Operating Leases 2,877 11,508 38,234 52,619
Unconditional
Power Purchases 58,451 184,933 336,895 580,279
- --------------------------------------------------------------------------------
Total $ 217,613 $1,003,411 $3,138,396 $4,359,420
- --------------------------------------------------------------------------------
36
Contingent Commitments. Oglethorpe is also liable, on a contingent basis,
for certain other contractual obligations. In each case, another party is liable
for these obligations, and Oglethorpe would be expected to pay only if the other
party fails to satisfy the obligations. These obligations are not shown on
Oglethorpe's balance sheet.
Several of these contingent liabilities are in connection with Oglethorpe's
transfer of the generation facilities under construction to Talbot EMC and
Chattahoochee EMC and the related assignment of contracts.
The contingent liabilities under construction contracts for Talbot EMC and
Chattahoochee EMC were $70 million and $45 million, respectively, as of March
31, 2002. Substantially all of these amounts will be paid by the commercial
operation dates of the respective facilities. As discussed above, bridge loans
have been secured by Talbot EMC and Chattahoochee EMC to fund the remaining cost
of construction.
Oglethorpe also remains liable, on a contingent basis, for obligations
under other operational agreements relating to the Chattahoochee EMC facility.
The combined obligation under these agreements totals $94 million through 2006,
and $20 million annually thereafter through approximately 2015.
In December 1996 and January 1997, Oglethorpe entered into long-term lease
transactions for its 74.6% ownership interest in the Rocky Mountain pumped
storage hydro facility (Rocky Mountain), through a wholly owned consolidated
subsidiary of Oglethorpe, Rocky Mountain Leasing Corporation (RMLC). From the
proceeds of the lease transactions, RMLC paid $641 million to a financial
institution and entered into a payment undertaking agreement whereby the
financial institution undertook to pay a portion of Oglethorpe's lease
obligations, including the semi-annual basic rent obligations under the lease.
Because of this, both Oglethorpe's interest in this payment undertaking
agreement and the corresponding lease obligations have been extinguished for
financial reporting purposes. On January 1, 2002, the semi-annual basic rent
payment was $46 million. If the financial insti tution fails to make the
required payments, Oglethorpe would be liable for the payments. The senior debt
obligations of the financial institution are rated "AAA" by Standard and Poor's
and "Aaa" by Moody's. Oglethorpe has the right, with the consent of the lessors,
to replace the financial institution if its ratings fall below "AA" and "Aa2" by
Standard & Poor's and Moody's, respectively. See Note 1 of Notes to Financial
Statements.
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. Oglethorpe was not legally released from its obligation to
pay this debt. See Note 5 of Notes to Financial Statements. Oglethorpe also has
contractual commitments on a corresponding portion of Oglethorpe's interest rate
swaps assumed by GTC.
Oglethorpe has entered into natural gas hedges with respect to Smarr EMC,
Talbot EMC and Chattahoochee EMC. See "QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK" in Item 7A.
Liquidity and Sources of Capital
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 2004 primarily
with funds generated from operations and, if necessary, with short-term
borrowings. However, in the future Oglethorpe may also pursue long-term
financing for these types of capital expenditures. In addition, Oglethorpe
intends to finance some of its prior and future environmental-related capital
expenditures by issuing long-term debt, some of which may be tax-exempt.
As discussed above, Oglethorpe is currently providing interim financing,
through its commercial paper program, for approximately fifty percent of the
cost of the new generation facilities owned by Talbot EMC and Chattahoochee EMC.
This interim funding will remain in place until permanent financing is obtained.
To meet short-term cash needs and liquidity requirements, Oglethorpe had,
37
as of December 31, 2001, (i) approximately $276 million in cash and temporary
cash investments, (ii) $89 million in other short-term investments and (iii) up
to $51 million available under the following credit facilities:
- --------------------------------------------------------------------------------
(dollars in thousands)
Authorized Available
Short-Term Credit Facilities Amount Amount
- --------------------------------------------------------------------------------
Committed line of credit:
Commercial paper $355,000 $ 1,000
Uncommitted line of credit:
Cooperative Finance
Corporation 50,000 50,000
- --------------------------------------------------------------------------------
Under its commercial paper program, Oglethorpe may issue commercial paper
not to exceed $355 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 liquidity requirements in conjunction with certain financial
agreements currently in place. These agreements include the interest rate swap
arrangements relating to two PCB transactions and the Rocky Mountain lease
transactions. The amount of liquidity required under these agreements was $77
million as of December 31, 2001, and Oglethorpe satisfied these requirements.
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 $134 million under this program, including $23 million
of PCB principal which matured on January 1, 2002.
Under an indemnity agreement executed in connection with GTC's assumption
of PCB indebtedness in the 1997 corporate restructuring, 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 $2.7 million on
the $3.8 million due from GTC in connection with the Burke and Monroe principal
payments due January 1, 2002.
Oglethorpe anticipates that it will continue to refinance the Burke and
Monroe principal maturities, averaging approximately $32 million annually over
the next five years. Oglethorpe also anticipates that GTC will agree not to
participate in the refinancing of this debt.
The average interest rate on long-term debt, capital lease obligations and
notes payable was 5.52% at December 31, 2001.
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. Other states are either in the process of implementing retail
competition or are studying options relating to retail competition. Proposed
federal legislation could encourage elements of 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
38
the Members to supply power to their current service territories. The GPSC does
not have the authority under Georgia law to order retail competition or amend
the Territorial Act. 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.
Many Members are also providing or considering proposals to provide
non-traditional products and services such as telecommunications and other
services. Each house of the Georgia legislature has passed legislation that
permits the Members to market natural gas. The legislation is now in conference.
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
39
more effectively under retail competition.
Oglethorpe will continue to consider indus try trends and developments, but
cannot predict at this time the results of these matters or any action
Oglethorpe might take based thereon.
Other New Accounting Pronouncements
In July 2001, the Financial Accounting Standards Board issued Statements of
Financial Accounting Standards No. 141, "Business Combinations", and No. 142,
"Goodwill and Other Intangible Assets". Under these new standards the FASB
eliminated accounting for certain mergers and acquisitions as poolings of
interests, eliminated amortization of goodwill and indefinite life assets, and
established new impairment measurement procedures for goodwill. For
calendar-year reporting companies, the standards become effective for all
acquisitions completed on or after June 30, 2001. Changes in financial statement
treatment for goodwill and intangible assets arising from mergers and
acquisitions completed prior to June 30, 2001 become effective January 1, 2002.
These pronouncements currently do not affect Oglethorpe's financial statements.
In October of 2001, the Financial Accounting Standards Board issued SFAS
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets", which
is effective for fiscal years beginning after December 15, 2001. This statement
supercedes FASB Statement No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of". However, it retains the
fundamental provisions of SFAS No. 121 for the recognition and measurement of
the impairment of long-lived assets to be held and used and the measurement of
long-lived assets to be disposed of by sale. Impairment of Goodwill is not
included in the scope of SFAS No. 144 and will be treated in accordance with the
accounting standards established in SFAS No. 142, "Goodwill and Other Intangible
Assets". According to SFAS No. 144, long-lived assets are to be measured at the
lower of carrying amount or fair value less cost to sell, whether reported in
continuing or discontinued operations. The statement applies to all long-lived
assets, including discontinued operrations, and replaces the provisions of APB
Opinion No. 30, "Reporting the Results of Operations - Reporting the Effects of
Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions", for the disposal of segments of a business.
Oglethorpe will be required to adopt this statement no later than January 1,
2002. This pronouncement currently does not affect Oglethorpe's financial
statements.
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 and the Members' 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," "plans" 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, some of which are beyond
Oglethorpe's control. For some of the factors that could cause actual results to
differ materially from those anticipated by these forward-looking statements,
see "Summary of Critical Accounting Policies and Cooperative Principles" and
"Miscellaneous-Competition" herein and "FACTORS AFFECTING THE ELECTRIC UTILITY
INDUSTRY" 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.
40
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 speculative purposes.
Oglethorpe's Risk Management Committee provides general management
oversight over all risk management activities, including commodity trading,
fuels management, insurance, 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, 2001, Oglethorpe had 21% of its debt in a variable rate mode.
The table below details Oglethorpe's debt instruments and provides the fair
value at December 31, 2001, 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
---------- ------------------------------------------------------------------------------------
2001 2002 2003 2004 2005 2006 Thereafter
---- ---- ---- ---- ---- ---- ----------
Fixed Rate Debt
- ---------------
Beginning of year $ 2,335,414 $ 2,232,139 $ 2,071,950 $ 1,951,191 $ 1,820,593 $ 1,684,340
Maturities (103,276) (160,189) (120,759) (130,598) (136,253)
-------- -------- -------- -------- --------
End of year $ 2,540,928 $ 2,232,139 $ 2,071,950 $ 1,951,191 $ 1,820,593 $ 1,684,340
=========== =========== =========== =========== ===========
Average interest rate(1) 6.03% 6.16% 6.04% 6.06% 6.09% 6.44%
Variable Rate Debt
- ------------------
Beginning of year $ 449,872 $ 445,758 $ 395,560 $ 391,406 $ 387,228 $ 383,023
Maturities (4,114) (50,918) (4,154) (4,178) (4,205)
------ ------- ------ ------ ------
End of year $ 434,016 $ 445,758 $ 395,560 $ 391,406 $ 387,228 $ 383,023
=========== =========== =========== =========== ===========
Average interest rate(1)(2) 4.13% 3.05% 4.47% 4.89% 5.28% 4.34%
Interest Rate Swaps
- -------------------
Beginning of year $ 256,001 $ 251,420 $ 246,536 $ 241,315 $ 238,343 $ 232,191
Maturities (4,581) (4,844) (5,221) (2,972) (6,152)
------ ------ ------ ------ ------
End of year $ 256,001 $ 251,420 $ 246,536 $ 241,315 $ 238,343 $ 232,191
=========== =========== =========== =========== ===========
Average interest rate(1) 5.83% 5.83% 5.83% 5.67% 5.83% 5.80%
Unrealized loss on swaps $ (36,859)
<FN>
(1) Average interest rates relate to the applicable principal maturities.
(2) Future variable debt interest rates are adjusted based on a forward U.S.
Treasury yield curve.
</FN>
41
Interest Rate Swap Transactions
Oglethorpe has 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, 2001, the bonds issued in 1993 carried a variable rate of interest of 1.6%
and the bonds issued in 1994 carried a variable rate of interest of 1.6%. For
the three years ended December 31, 1999, 2000 and 2001, 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 $6.7 million, and $4.3 million, and
$8.1 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, 2001 would have
been approximately $36.9 million.
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
capital leases provide that Oglethorpe's rental payments vary to the extent of
42
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 $183,252,000 in serial facility bonds due June 30, 2011 with a 6.97%
fixed rate of interest.
Oglethorpe entered into a power purchase and sale agreement with Doyle I,
LLC (Doyle Agreement) to purchase all of the output from a five-unit gas-fired
generation facility. The Doyle Agreement is reported on Oglethorpe's balance
sheet as a capital lease. The lease payments vary to the extent the interest
rate on the lessor's debt varies from 6.00%. At December 31, 2001, the weighted
average interest rate on the lease obligation was 6.48%.
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.)
As of December 31, 2001, 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, 2001 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 do not affect Oglethorpe's net margin in the short-term.
Commodity Price Risk
Electricity
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 obtains substantially all of the power it supplies to the Members
from a combination of generating plants and power purchased under long-term
contracts with power marketers and other power suppliers. 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 enters into seasonal options for
delivery of energy on behalf of Members that participate in Oglethorpe's pool.
Oglethorpe's market price risk exposure on these instruments is not material.
Coal
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.
Natural Gas
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 I (which Oglethorpe treats as
a capital lease) and Hartwell. Under these contracts, Oglethorpe is exposed to
variable energy charges, which incorporate each facility's actual operation and
43
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
purchases natural gas, including transportation and other related services, on
behalf of Smarr EMC and ensures that the Smarr facilities have fuel available
for operations. Oglethorpe expects to provide similar services for Talbot EMC
and Chattahoochee EMC. (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 has entered into natural gas swap arrangements (1) to manage its
exposure to fluctuations in the market price of natural gas related to
Oglethorpe resources and (2) to assist Members in managing such exposure related
to Smarr EMC, Talbot EMC and Chattahoochee EMC. Under these swap agreements,
Oglethorpe pays the counterparty contractually a fixed price for specified
natural gas quantities and receives a payment for such quantities based on a
market price index. These payment obligations are netted, such that if the
market price index is lower than the fixed price, Oglethorpe will make a net
payment, and if the market price index is higher than the fixed price,
Oglethorpe will receive a net payment. If the natural gas swaps had been
terminated at December 31, 2001, Oglethorpe would have been required to make a
net payment of $7,537,000 on the portion of the natural gas swaps related to
Oglethorpe resources. This amount does not include a net payment of $9,039,000
that Oglethorpe would have been required to make on the portion of the natural
gas swaps related to Smarr EMC, Talbot EMC and Chattahoochee EMC. Oglethorpe
remains fully obligated for any payments due under the swaps related to Smarr
EMC, Talbot EMC and Chattahoochee EMC, but is entitled to recover such amounts
from Smarr EMC, Talbot EMC and Chattahoochee EMC. Oglethorpe's market price risk
exposure on these agreements is not material. Oglethorpe expects to continue to
manage exposures to natural gas price risks only with respect to Members that
participate in Oglethorpe's pool and elect to receive such services.
ACES Power Marketing
Oglethorpe has 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 on behalf of Members that participate in the Oglethorpe capacity
and energy pool. (See "OGLETHORPE'S POWER SUPPLY RESOURCES--Capacity and Energy
Pool" in Item 1.) 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 (not including Oglethorpe) that provides energy trading and natural
gas management services to rural electric cooperatives and others.
APM, at Oglethorpe's request, also assists Oglethorpe in negotiating
purchases and sales of natural gas, and provides Oglethorpe with advice and risk
management services related to natural gas.
Changes in Risk Exposure
Oglethorpe's exposure to changes in interest rates, the price of equity
securities it holds, and commodity prices have not changed materially from the
previous reporting period. Oglethorpe is not aware of any facts or circumstances
that would significantly impact these exposures in the near future.
44
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index To Financial Statements
Page
----
Statements of Revenues and Expenses,
For the Years Ended December 31, 2001, 2000 and 1999................ 47
Balance Sheets, As of December 31, 2001 and 2000....................... 48
Statements of Capitalization, As of December 31, 2001 and 2000......... 50
Statements of Cash Flows,
For the Years Ended December 31, 2001, 2000 and 1999 ............... 51
Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive Margin
For the Years Ended December 31, 2001, 2000 and 1999 ............... 52
Notes to Financial Statements.......................................... 53
Report of Management................................................... 67
Report of Independent Accountants...................................... 67
45
[This Page Intentionally Left Blank]
46
Statements of Revenues and Expenses
For the years ended December 31, 2001, 2000 and 1999
(dollars in thousands)
2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------------
Operating revenues (Note 1):
Sales to Members $ 1,080,478 $ 1,146,064 $ 1,122,336
Sales to non-Members 58,811 53,333 53,896
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,139,289 1,199,397 1,176,232
- ------------------------------------------------------------------------------------------------------------------------------------
Operating expenses:
Fuel 221,449 230,729 196,182
Production 218,480 220,221 215,517
Purchased power (Note 9) 414,382 377,805 401,719
Depreciation and amortization 133,731 143,703 130,883
Income taxes (Note 3) (63,485) - -
- ------------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 924,557 972,458 944,301
- ------------------------------------------------------------------------------------------------------------------------------------
Operating margin 214,732 226,939 231,931
- ------------------------------------------------------------------------------------------------------------------------------------
Other income (expense):
Investment income 32,113 44,489 33,262
Amortization of deferred gains (Notes 1 and 4) 2,475 2,475 2,475
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) 290 204 180
Other 5,272 4,068 3,433
- ------------------------------------------------------------------------------------------------------------------------------------
Total other income 51,345 62,431 50,545
- ------------------------------------------------------------------------------------------------------------------------------------
Interest charges:
Interest on long-term debt and capital leases 220,525 227,877 224,489
Other interest 10,839 21,954 18,531
Allowance for debt funds used during construction (Note 1) (2,786) (1,930) (1,570)
Amortization of debt discount and expense 19,082 21,491 21,088
- ------------------------------------------------------------------------------------------------------------------------------------
Net interest charges 247,660 269,392 262,538
- ------------------------------------------------------------------------------------------------------------------------------------
Net margin $ 18,417 $ 19,978 $ 19,938
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
47
Balance Sheets
December 31, 2001 and 2000
(dollars in thousands)
2001 2000
- ------------------------------------------------------------------------------------------------------------------------------------
Assets
Electric plant (Notes 1, 4 and 6):
In service $ 5,029,192 $ 5,010,670
Less: Accumulated provision for depreciation (1,881,918) (1,754,776)
- ------------------------------------------------------------------------------------------------------------------------------------
3,147,274 3,255,894
Nuclear fuel, at amortized cost 77,360 83,470
Construction work in progress 38,564 24,841
- ------------------------------------------------------------------------------------------------------------------------------------
Total electric plant 3,263,198 3,364,205
- ------------------------------------------------------------------------------------------------------------------------------------
Investments and funds (Notes 1 and 2):
Decommissioning fund, at market 150,668 148,300
Deposit on Rocky Mountain transactions, at cost 68,032 63,665
Bond, reserve and construction funds, at market 28,691 29,167
Investment in associated companies, at cost 22,187 19,997
Other, at cost 731 1,513
- ------------------------------------------------------------------------------------------------------------------------------------
Total investments and funds 270,309 262,642
- ------------------------------------------------------------------------------------------------------------------------------------
Current assets:
Cash and temporary cash investments, at cost (Note 1) 275,786 330,622
Other short-term investments, at market 88,589 81,715
Receivables 73,039 143,353
Inventories, at average cost (Note 1) 81,768 75,389
Notes receivable (Note 5) 340,396 38,548
Prepayments and other current assets 16,182 59,824
- ------------------------------------------------------------------------------------------------------------------------------------
Total current assets 875,760 729,451
- ------------------------------------------------------------------------------------------------------------------------------------
Deferred charges:
Premium and loss on reacquired debt, being amortized (Note 5) 162,690 175,944
Deferred amortization of capital leases (Note 4) 107,254 103,732
Discontinued projects, being amortized (Note 1) 6,463 9,490
Deferred debt expense, being amortized 16,475 16,968
Other (Note 1) 22,518 31,107
- ------------------------------------------------------------------------------------------------------------------------------------
Total deferred charges 315,400 337,241
- ------------------------------------------------------------------------------------------------------------------------------------
Total assets $ 4,724,667 $ 4,693,539
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
48
(dollars in thousands)
2001 2000
- ------------------------------------------------------------------------------------------------------------------------------------
Equity and Liabilities
Capitalization (see accompanying statements):
Patronage capital and membership fees (Note 1) $ 367,668 $ 392,682
Long-term debt 2,929,316 3,019,019
Obligation under capital leases (Note 4) 373,837 387,756
Obligation under Rocky Mountain transactions 68,032 63,665
- ------------------------------------------------------------------------------------------------------------------------------------
Total capitalization 3,738,853 3,863,122
- ------------------------------------------------------------------------------------------------------------------------------------
Current liabilities:
Long-term debt and capital leases due within one year (Note 5) 127,621 141,115
Accounts payable 79,859 114,964
Notes payable (Note 5) 353,680 78,482
Power marketer reserve (Note 9) 36,000 -
Accrued interest 7,793 67,394
Other current liabilities 16,461 23,691
- ------------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 621,414 425,646
- ------------------------------------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities:
Gain on sale of plant, being amortized (Note 4) 50,858 53,332
Net benefit of sale of income tax benefits, being amortized (Note 1) 2,002 10,012
Net benefit of Rocky Mountain transactions, being amortized (Note 1) 79,633 82,819
Accumulated deferred income taxes (Note 3) - 63,485
Decommissioning reserve (Note 1) 174,506 174,553
Interest rate swap arrangements 36,859 -
Other 20,542 20,570
- ------------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 364,400 404,771
- ------------------------------------------------------------------------------------------------------------------------------------
Total equity and liabilities $4,724,667 $4,693,539
- ------------------------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 5 and 9)
- ------------------------------------------------------------------------------------------------------------------------------------
49
Statements of Capitalization
December 31, 2001 and 2000
(dollars in thousands)
2001 2000
- ------------------------------------------------------------------------------------------------------------------------------------
Long-term debt (Note 5):
Mortgage notes payable to the Federal Financing Bank (FFB) at interest rates
varying from 2.48% to 8.43% (average rate of 6.32% at December 31, 2001) due
in quarterly installments through 2023 $ 2,141,746 $ 2,248,502
Mortgage notes payable to the Rural Utilities Service (RUS) at an interest rate of
5% due in monthly installments through 2021 12,919 13,344
Mortgage notes issued in conjunction with the sale by public authorities of pollution
control revenue bonds (PCBs):
o Series 1992A
Serial bonds, 6.05% to 6.80%, due serially from 2002 through 2012 101,555* 107,820*
o Series 1993
Serial bonds, 4.50% to 5.25%, due serially from 2002 through 2013 32,060* 33,410*
o Series 1993A
Adjustable tender bonds, 1.60%, due 2002 through 2016 189,660* 192,420*
o Series 1993B
Serial bonds, 4.50% to 5.05%, due serially from 2002 through 2008 96,900* 105,980*
o Series 1994
Serial bonds, 6.15% to 7.125%, due serially from 2002 through 2015 8,560* 8,930*
Term bonds, 7.15%, due 2016 to 2021 11,550* 11,550*
o Series 1994A
Adjustable tender bonds, 1.60%, due 2002 to 2019 118,270* 120,500*
o Series 1994B
Serial bonds, 6.15% to 6.45%, due serially from 2002 through 2005 5,970* 7,585*
o Series 1998A
Adjustable tender bonds, 1.30% to 2.60%, due 2019 116,925* 116,925*
o Series 1998B
Adjustable tender bonds, 1.30% to 1.95%, due 2019 100,000* 100,000*
o Series 1999A
Adjustable tender bonds, 1.90%, due 2020 20,070 20,070
o Series 1999B
Adjustable tender bonds, 1.90%, due 2020 68,705 68,705
o Series 2000
Adjustable tender bonds, 1.90%, due 2021 21,950 21,950
Unsecured notes issued in conjunction with the sale by public authorities of pollution
control revenue bonds:
o Series 2001
Adjustable tender bonds, 1.90%, due 2022 22,825 -
CoBank, ACB notes payable:
o Headquarters mortgage note payable: fixed at 5.01% through January 31, 2002,
due in quarterly installments through January 1, 2009 2,823 3,212
o Transmission mortgage note payable: fixed at 6.04% through February 28, 2002; due in
bi-monthly installments through November 1, 2018 1,740 1,770
o Transmission mortgage note payable: fixed at 6.04% through February 28, 2002; due in
bi-monthly installments through September 1, 2019 6,713 6,815
o Medium-term loan, variable at 3.21% to 4.90%, due at various maturities
through September 2002, 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
- ------------------------------------------------------------------------------------------------------------------------------------
3,173,071 3,281,618
*Less: Portion (16.86%) of PCBs assumed by Georgia Transmission Corporation (131,784) (135,775)
- ------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt, net 3,041,287 3,145,843
Less: Long-term debt due within one year (111,971) (126,824)
- ------------------------------------------------------------------------------------------------------------------------------------
Long-term debt, excluding amount due within one year 2,929,316 3,019,019
Obligation under capital leases, long-term (Note 4) 373,837 387,756
Obligation under Rocky Mountain transactions, long-term (Note 1) 68,032 63,665
Patronage capital and membership fees (Note 1) 367,668 392,682
- ------------------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 3,738,853 $ 3,863,122
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
50
Statements of Cash Flows
For the years ended December 31, 2001, 2000 and 1999
(dollars in thousands)
2001 2000 1999
- ------------------------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
Net margin $ 18,417 $ 19,978 $ 19,938
- ------------------------------------------------------------------------------------------------------------------------------------
Adjustments to reconcile net margin to net cash provided by
operating activities:
Depreciation and amortization 178,946 188,870 177,065
Interest on decommissioning reserve 168 11,007 12,266
Amortization of deferred gains (2,475) (2,475) (2,474)
Amortization of net benefit of sale of income tax benefits (11,195) (11,195) (11,195)
Allowance for equity funds used during construction (290) (204) (180)
Deferred income taxes (63,485) 283 -
Gain on sale of generation equipment (221) - -
Other 1,215 453 1,465
Change in operating assets and liabilities:
Receivables 70,315 (33,649) 1,214
Inventories (6,379) 14,377 (12,983)
Prepayments and other current assets 713 2,398 2,102
Accounts payable (35,105) 45,409 22,879
Power marketer reserve 36,000 - -
Accrued interest (59,601) 17,192 40,128
Accrued and withheld taxes 4 648 (188)
Other current liabilities (14,770) 13,698 (8,584)
- ------------------------------------------------------------------------------------------------------------------------------------
Total adjustments 93,840 246,812 221,515
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 112,257 266,790 241,453
- ------------------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Property additions (69,824) (70,738) (41,829)
Activity in decommissioning fund - Purchases (532,355) (735,352) (608,471)
- Proceeds 530,660 722,620 591,851
Activity in bond, reserve and construction funds - Purchases (22,710) (12,699) (23,325)
- Proceeds 23,699 15,319 24,053
Increase in other short-term investments (6,423) (4,181) (3,718)
Increase in investment in associated organizations (2,190) (2,078) (1,688)
Decrease (increase) in notes receivable 2 (143) 97
Other - generation equipment deposits (16,783) (42,929) -
Proceeds from sale of generation equipment 26,204 - -
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (69,720) (130,181) (63,030)
- ------------------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Debt proceeds, net 22,931 26,260 18,196
Debt payments (127,381) (100,729) (68,517)
(Decrease) increase in notes payable (Note 5) 275,198 (9,997) 37,493
Decrease (increase) in note receivable (Note 5) (268,121) 55,665 (49,016)
- ------------------------------------------------------------------------------------------------------------------------------------
Net cash (used in) provided by financing activities (97,373) (28,801) (61,844)
- ------------------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and temporary cash investments (54,836) 107,808 116,579
Cash and temporary cash investments at beginning of year 330,622 222,814 106,235
- ------------------------------------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year $ 275,786 $ 330,622 $ 222,814
- ------------------------------------------------------------------------------------------------------------------------------------
Supplemental cash flow information:
Cash paid for -
Interest (net of amounts capitalized) $ 278,785 $ 219,702 $ 189,056
Income taxes - - -
Non cash transaction -
Capital lease - 126,990 -
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
51
Statements of Patronage Capital and Membership Fees and Accumulated Other
Comprehensive Margin\
For the years ended December 31, 2001, 2000 and 1999
(dollars in thousands)
Patronage Accumulated
Capital and Other
Membership Comprehensive
Fees Margin (Loss) Total
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 $ 351,696 $ 1,005 $ 352,701
- ------------------------------------------------------------------------------------------------------------------------------------
Components of comprehensive margin in 1999
Net margin 19,938 19,938
Unrealized gain on available-for-sale securities (2,614) (2,614)
- ------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive margin 17,324
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 371,634 (1,609) 370,025
- ------------------------------------------------------------------------------------------------------------------------------------
Components of comprehensive margin in 2000
Net margin 19,978 19,978
Unrealized gain on available-for-sale securities 2,679 2,679
- ------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive margin 22,657
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 391,612 1,070 392,682
- ------------------------------------------------------------------------------------------------------------------------------------
Components of comprehensive margin in 2001
Net margin 18,417 18,417
Cumulative effect of accounting change to record unrealized
loss on interest rate swap arrangements as of January 1, 2001 (33,515) (33,515)
Unrealized loss on interest rate swap arrangements (3,344) (3,344)
Unrealized gain on available-for-sale securities 965 965
Unrealized loss on financial gas hedges (7,537) (7,537)
- ------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive margin (loss) (25,014)
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 $ 410,029 $ (42,361) $ 367,668
- ------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
52
Notes to Financial Statements
For the years ended December 31, 2001, 2000 and 1999
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 power, on a not-for-profit basis, to 39
of Georgia's 42 Electric Membership Corporations (EMCs) from a combination of
generating units totaling 3,660 megawatts (MW) of capacity and power purchase
agreements totaling 750 MW of capacity. These 39 electric distribution
cooperatives (Members) in turn distribute energy on a retail basis to
approximately 3.7 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.
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, 2001 and 2000
and the reported amounts of revenues and expenses for each of the three years
ending December 31, 2001. 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 other comprehensive margin, excluding securities held in the
decommissioning fund. For 2001, 2000 and 1999 the unrealized gain or loss in
other comprehensive margin was ($42,361,000), $1,070,000 and ($1,609,000),
respectively. (See "Fair value of financial instruments" in Note 2.) 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 1999 through 2001 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 whole sale power contracts which Oglethorpe maintains with each of its
Members. These wholesale power contracts obligate each Member to pay Oglethorpe
for capacity and energy furnished in accordance with rates established by
Oglethorpe. Energy furnished is determined based on meter readings which are
conducted at the end of each month. Actual energy costs are compared, on a
monthly basis, to the billed energy costs, and an adjustment to revenues is made
such that energy revenues are equal to actual energy costs.
53
Revenues from Jackson EMC and Cobb EMC, two of Oglethorpe's Members,
accounted for 12.1% and 11.6% in 2001, 11.8% and 11.9% in 2000, 11.8% and 11.7%
in 1999, 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 2001, 2000 and 1999 amounted to $47,143,000, $47,105,000 and
$46,226,000, 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. 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 into 2010 and Plant Vogtle spent fuel storage is expected to be sufficient
into 2014. Oglethorpe expects that procurement of on-site dry storage capacity
at Plants Hatch and Vogtle will commence in sufficient time to maintain pool
full-core discharge capability.
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
$8,111,000, which is being amortized to nuclear fuel expense over the next 6
years. Oglethorpe has also recorded an obligation to DOE which approximated
$5,904,000 at December 31, 2001.
g. Nuclear decommissioning
Nuclear decommissioning cost estimates are based on site studies and assume
prompt dismantlement and removal of both the radiated and non-radiated portions
of the plant from service. Actual decommissioning costs may vary from these
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. Information with respect to Oglethorpe's portion of the
estimated costs of decommissioning co-owned nuclear facilities is 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 2034 2038 2027 2029
Estimated costs based
on site study:
In year 2000 dollars $ 139,000 $ 175,000 $ 137,000 $ 171,000
In projected future
dollars 660,000 1,007,000 475,000 650,000
- ------------------------------------------------------------------------------------------------------------------------------------
In projecting future costs, the escalation rate for labor, materials and
equipment was assumed to be 4.72%.
Oglethorpe's objective is to provide a reserve for nuclear decommissioning
at least equal to the Nuclear Regulatory Commission (NRC) minimum funding
requirement and to fund, on a periodic basis, such minimum in an external trust
fund. The external trust fund is maintained in compliance with NRC regulation to
provide for minimum funding levels based on average expected cost to
decommission only the radiated portions of a typical nuclear facility. At
December 31, 2001, the NRC minimum funding requirement was approximately
$172,000,000. In calculating the minimum funding requirement, future costs were
projected using the same escalation rate used in the site study estimate
referred to above and were discounted at a rate of 8%. Oglethorpe has not
recorded any provision for decommissioning during the years 2001, 2000 and 1999
because its decommissioning reserve has exceeded the NRC minimum funding
requirement.
54
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 2001,
2000 and 1999 were as follows:
- ------------------------------------------------------------------------------------------
2001 2000 1999
- ------------------------------------------------------------------------------------------
Steam production 1.98% 1.98% 2.15%
Nuclear production 2.68% 2.68% 2.69%
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% 2.00-33.33%
- ------------------------------------------------------------------------------------------
In January 2002, the operating license for Plant Hatch was extended for 20
years. Due to the license extension, effective January 2002, the depreciation
rate for Plant Hatch has been revised from 2.99% to 1.92%.
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,
2001 and 2000, 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, 2001 and 2000, $22,940,000 and $22,241,000 were restricted
by PCBs trust indentures and were utilized in January 2002 and 2001 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, 2001 and 2000, fossil fuels inventories were $18,829,000
and $15,565,000, respectively. Inventories for spare parts at December 31, 2001
and 2000 were $62,939,000 and $59,824,000, 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, 2001 and 2000 were
$17,313,000 and $19,897,000, 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 $2,538,000 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.
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
55
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 pumped
storage hydro facility (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, 2001 and 2000:
- --------------------------------------------------------------------------------
(dollars in thousands)
2001 2000
- --------------------------------------------------------------------------------
Premium and loss on reacquired debt $ 162,690 $ 175,944
Deferred amortization of capital leases 107,254 103,732
Discontinued projects 6,463 9,490
Other regulatory assets 20,461 28,141
Net benefit of sale of income tax benefits (2,002) (10,012)
Net benefit of Rocky Mountain transactions (79,633) (82,819)
- --------------------------------------------------------------------------------
$ 215,233 $ 224,476
- --------------------------------------------------------------------------------
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 the
current year presentation. Certain balance sheet amounts at December 31, 2000
have been restated as explained in Note 4, "Capital leases".
q. New accounting pronouncement
In July 2001, the Financial Accounting Standards Board (FASB) issued
Statements of Financial Accounting Standards No. 141, "Business Combinations",
and No. 142, "Goodwill and Other Intangible Assets". Under these new standards
the FASB eliminated accounting for certain mergers and acquisitions as poolings
of interests, eliminated amortization of goodwill and indefinite life intangible
assets, and established new impairment measurement procedures for goodwill. For
calendar-year reporting companies, the standards become effective for all
acquisitions completed on or after June 30, 2001. Changes in financial statement
treatment for goodwill and intangible assets arising from mergers and
acquisitions completed prior to June 30, 2001 become effective January 1, 2002.
These pronouncements currently do not effect Oglethorpe's financial statements.
In October of 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment
or Disposal of Long-Lived Assets", which is effective for fiscal years beginning
after December 15, 2001. This statement supercedes FASB Statement No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of". However, it retains the fundamental provisions of SFAS No. 121
for the recognition and measurement of the impairment of long-lived assets to be
held and used and the measurement of long-lived assets to be disposed of by
sale. Impairment of Goodwill is not included in the scope of SFAS No. 144 and
will be treated in accordance with the accounting standards established in SFAS
No. 142, "Goodwill and Other Intangible Assets". According to SFAS No. 144,
long-lived assets are to be measured at the lower of carrying amount or fair
56
value less cost to sell, whether reported in continuing or discontinued
operations. The statement applies to all long-lived assets, including
discontinued operations, and replaces the provisions of APB Opinion No. 30,
"Reporting the Results of Operations - Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions", for the disposal of segments of a business. Oglethorpe
will be required to adopt this statement no later than January 1, 2002. This
pronouncement currently does not effect Oglethorpe's financial statements.
In June of 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations". The statement provides accounting and reporting
standards for recognizing obligations related to asset retirement costs
associated with the retirement of tangible long-lived assets. Under this
statement, legal obligations associated with the retirement of long-lived assets
are to be recognized at their fair value in the period in which they are
incurred if a reasonable estimate of fair value can be made. The fair value of
the asset retirement costs is capitalized as part of the carrying amount of the
long-lived asset and subsequently allocated to expense using a systematic and
rational method over the assets' useful life. Any subsequent changes to the fair
value of the liability due to passage of time or changes in the amount or timing
of estimated cash flows is recognized as an accretion expense. Oglethorpe will
be required to adopt this statement no later than January 1, 2003. Oglethorpe's
management is currently assessing the impact of this statement on its results of
operations and financial condition.
2. Fair value of financial instruments:
A detail of the estimated fair values of Oglethorpe's financial instruments
as of December 31, 2001 and 2000 is as follows:
- ------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
2001 2000
Fair Fair
Cost Value Cost Value
- ------------------------------------------------------------------------------------------------------------------
Cash and temporary
cash investments:
Commercial paper $ 238,514 $ 238,514 $ 330,052 $ 330,052
Cash and money
market securities 37,272 37,272 570 570
- ------------------------------------------------------------------------------------------------------------------
Total $ 275,786 $ 275,786 $ 330,622 $ 330,622
- ------------------------------------------------------------------------------------------------------------------
Other short term
investments $ 87,277 $ 88,589 $ 80,854 $ 81,715
- ------------------------------------------------------------------------------------------------------------------
Bond, reserve and
construction funds:
U. S. Government
securities $ 20, 860 $ 21,583 $ 25,397 $ 25,608
Repurchase
agreements 7,108 7,108 3,559 3,559
- ------------------------------------------------------------------------------------------------------------------
Total $ 27,968 $ 28,691 $ 28,956 $ 29,167
- ------------------------------------------------------------------------------------------------------------------
Decommissioning
fund:
U. S. Government
securities $ 30,767 $ 31,088 $ 29,674 $ 31,049
Foreign government
securities 1,514 1,542 1,173 1,161
Commercial paper 4,259 4,261 6,183 6,180
Corporate bonds 13,036 13,575 6,784 6,929
Equity securities 71,176 77,062 80,795 85,225
Asset-backed
securities 9,389 9,470 12,156 12,406
Other bonds - - - -
Cash and money
market securities 13,670 13,670 5,350 5,350
- ------------------------------------------------------------------------------------------------------------------
Total $ 143,811 $ 150,668 $ 142,115 $ 148,300
- ------------------------------------------------------------------------------------------------------------------
Long-term debt $ 2,929,316 $ 3,118,974 $ 3,019,019 $ 3,221,692
- ------------------------------------------------------------------------------------------------------------------
Interest rate swap $ - $ (36,859) $ - $ (33,515)
- ------------------------------------------------------------------------------------------------------------------
Financial gas
hedges $ - $ (7,537) $ - $ -
- ------------------------------------------------------------------------------------------------------------------
57
The contractual maturities of debt securities available for sale at
December 31, 2001 and 2000, regardless of their balance sheet classification,
are as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
2001 2000
Fair Fair
Cost Value Cost Value
- --------------------------------------------------------------------------------
Due within one year $14,215 $14,211 $ 3,559 $ 3,559
Due after one year
through five years 31,965 33,080 39,583 40,022
Due after five years
through ten years 14,511 14,858 12,499 12,904
Due after ten years 21,983 22,217 23,102 24,227
- --------------------------------------------------------------------------------
$82,674 $84,366 $78,743 $80,712
- --------------------------------------------------------------------------------
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.
Effective 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 certain derivatives as assets or
liabilities on 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 classified as a hedge and if so,
the type of hedge.
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, 2001 was $189,660,000 (includes
the portion assumed by GTC) and the fixed swap rate is 5.67% (the variable rate
at December 31, 2001 and 2000 was 1.60% and 4.9%, respectively). With respect to
the Series 1994A notes, the notional principal at December 31, 2001 was
$118,270,000 (includes the portion assumed by GTC) and the fixed swap rate is
6.01% (the variable rate at December 31, 2001 and 2000 was 1.60% and 4.95%,
respectively). The notional principal amount is used to measure the amount of
the swap payments and does not represent additional principal due to the
counterparty. The swap arrangements extend for the life of the refunding bonds,
with reductions in the outstanding principal amounts of the refunding bonds
causing corresponding reductions in the notional amounts of the swap payments.
A portion (16.86%) of the interest rate swap arrangements was assumed by
Georgia Transmission Corporation (GTC) in connection with a corporate
restructuring. Oglethorpe has classified its portion of two interest rate swap
arrangements, pursuant to SFAS No. 133, as cash flow hedges. Accordingly, as of
January 1, 2001 Oglethorpe recorded as a cumulative effect adjustment an
unrealized loss in other comprehensive margin of $33,515,000 and a corresponding
increase in other liabilities. Oglethorpe's portion of the estimated fair value
of the swap arrangements at December 31, 2001 was an unrealized loss of
$36,859,000 representing the estimated payment Oglethorpe would pay if the swap
arrangements were terminated.
During 2001, Oglethorpe entered into natural gas financial contracts that
are classified, pursuant to SFAS 133, as cash flow hedges.
58
Oglethorpe utilizes natural gas financial contracts in managing its exposure to
fluctuations in the market price of natural gas. The fair value of Oglethorpe's
financial gas hedges is based on the quoted market value for such natural gas
financial contracts. At December 31, 2001, Oglethorpe recorded an unrealized
loss in other comprehensive margin of $7,537,000 and a corresponding increase in
other current liabilities related to these natural gas financial contracts.
Oglethorpe may be exposed to losses in the event of nonperformance of the
counterparties to its derivative instruments, 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, 2001
were $12,569,000 and $3,677,000, respectively. 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. For 2001, 2000 and 1999 proceeds from sales of
available-for-sale securities totaled $531,649,000, $725,240,000 and
$592,579,000, respectively. Gross realized gains and losses from the 2001 sales
were $14,585,000 and $17,378,000, 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 1999 sales were $29,429,000 and $22,167,000,
respectively.
Investments in associated companies were as follows at December 31, 2001
and 2000:
- --------------------------------------------------------------------------------
(dollars in thousands)
2001 2000
- --------------------------------------------------------------------------------
National Rural Utilities
Cooperative Finance Corp. (CFC) $13,476 $13,476
CoBank, ACB 3,419 2,407
Georgia Transmission
Corporation (GTC) 4,899 3,815
Other 393 299
- --------------------------------------------------------------------------------
Total $22,187 $19,997
- --------------------------------------------------------------------------------
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.
59
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 patronage and non-patronage
activities.
In November 2001, Oglethorpe changed its Bylaws to provide allocation of
patronage on a tax basis method rather than the historical book basis method.
This change is effective starting January 1, 2002. Due to this change,
Oglethorpe anticipates that all future patronage source income will be offset by
the patronage exclusion. Accordingly, it is expected that substantially all of
Oglethorpe's taxable temporary differences will be patronage sourced and subject
to offset. Therefore, as of December 31, 2001, Oglethorpe has reversed
$63,485,000 of net deferred income tax liabilities and has recognized this
reversal as a deferred income tax credit of $63,485,000.
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 2001, 2000 and 1999 is shown
as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
2001 2000 1999
- --------------------------------------------------------------------------------
Current
Federal $ - $ (283) $ -
State - - -
- --------------------------------------------------------------------------------
- (283) -
- --------------------------------------------------------------------------------
Deferred
Federal (63,485) 283 -
State - - -
- --------------------------------------------------------------------------------
(63,485) 283 -
- --------------------------------------------------------------------------------
Income taxes charged
to operations $(63,485) $ - $ -
- --------------------------------------------------------------------------------
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:
- --------------------------------------------------------------------------------
2001 2000 1999
- --------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Patronage exclusion (376.0%) (35.8%) (35.6%)
Other 0.0% 0.8% 0.6%
- --------------------------------------------------------------------------------
Effective income tax rate (341.0%) 0.0% 0.0%
- --------------------------------------------------------------------------------
The components of the net deferred tax liabilities as of December 31, 2001
and 2000 were as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
2001 2000
- --------------------------------------------------------------------------------
Deferred tax assets
Net operating losses $ 482,058 $ 478,497
Member loss carryforwards 7,310 44,341
Tax credits (alternative minimum tax
and other) 196,452 196,452
Accounting for Rocky Mountain
transactions 315,717 312,441
Accounting for sale of income tax benefits 3,594 16,702
Accrued nuclear decommissioning expense 64,611 64,545
Accounting for asset dispositions 18,450 20,010
Other 3,838 3,000
- --------------------------------------------------------------------------------
1,092,030 1,135,988
Less: Valuation allowance (1,084,720) (194,145)
- --------------------------------------------------------------------------------
7,310 941,843
- --------------------------------------------------------------------------------
Deferred tax liabilities
Depreciation (7,310) (738,313)
Accounting for Rocky Mountain
transactions - (195,376)
Accounting for debt extinguishment - (57,042)
Other - (14,597)
- --------------------------------------------------------------------------------
(7,310) (1,005,328)
- --------------------------------------------------------------------------------
Net deferred tax liabilities $ - $ (63,485)
- --------------------------------------------------------------------------------
60
As of December 31, 2001, 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
- --------------------------------------------------------------------------------
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 - - 4,362
2021 - - 9,602
None 2,307 - -
- --------------------------------------------------------------------------------
$2,307 $ 186,881 $1,239,224
- --------------------------------------------------------------------------------
The NOL expiration dates start in the year 2002 and end in the year 2021.
Due to the change to the tax basis method for allocating patronage and as shown
by the above valuation allowance, it is not likely that the tax credits, NOLs,
and deferred tax assets will be realized, with the exception of $7,310,000
deferred tax asset related to member loss carryforwards. The change in the
valuation allowance from 2000 to 2001 was the result of the change to allocating
patronage on a tax basis. It is not likely that the AMT credit will be utilized.
4. Capital leases:
In 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.
In 2000, Oglethorpe entered into a power purchase and sale agreement with
Doyle I, LLC (Doyle Agreement) to purchase all of the output from a five-unit
generation facility (Plant Doyle) for a period of 15 years. Oglethorpe has the
option to purchase Plant Doyle at the end of the 15 year term for $10,000,000,
which is considered a bargain purchase price.
The minimum lease payments under the capital leases together with the
present value of the net minimum lease payments as of December 31, 2001 are as
follows:
- --------------------------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
Scherer Plant
Unit No. 2 Doyle Total
- --------------------------------------------------------------------------------
2002 $ 31,867 $ 12,447 $ 44,314
2003 31,875 12,447 44,322
2004 31,863 12,447 44,310
2005 31,863 12,447 44,310
2006 31,817 12,447 44,264
2007-2021 345,844 117,871 463,715
- --------------------------------------------------------------------------------
Total minimum lease
payments 505,129 180,106 685,235
Less: Amount
representing interest (235,949) (59,799) (295,748)
- --------------------------------------------------------------------------------
Present value of net
minimum lease
payments 269,180 120,307 389,487
Less: Current portion (10,275) (5,375) (15,650)
- --------------------------------------------------------------------------------
Long-term balance $ 258,905 $ 114,932 $ 373,837
- --------------------------------------------------------------------------------
The interest rate on the Scherer No. 2 lease obligation is 8.39%. For Plant
Doyle, the lease payments vary to the extent the interest rate on the lessor's
debt varies from 6.00%. At December 31, 2001, the weighted average interest rate
on the Plant Doyle lease obligation was 6.48%.
The Scherer No. 2 lease and the Doyle Agreement meet the definitional
criteria to be reported as capital leases. For rate-making purposes, however,
Oglethorpe treats these capital leases as operating leases. Accordingly,
Oglethorpe includes the actual lease payments in its cost of service. The excess
of the lease payments over the aggregate of the amortization on the capital
lease asset and the interest on the capital lease obligation is recognized as a
regulatory asset on the balance sheet pursuant to SFAS No. 71.
In Oglethorpe's financial statements as of and for the year ended December
31, 2000, the Doyle Agreement was accounted for as an operating lease. As
described above, Oglethorpe now believes that the Doyle Agreement meets the
61
definitional criteria to be reported as a capital lease and has restated its
financial statements as of and for the year ended December 31, 2000 to reflect
capital lease treatment retroactively. As noted above, for rate-making purposes,
Oglethorpe includes the lease payments in cost of service. Therefore, the
restatement had no effect on net margin. The balance sheet at December 31, 2000
was restated to include the following:
- --------------------------------------------------------------------------------
(dollars in thousands)
- --------------------------------------------------------------------------------
Assets
Capital lease asset, net (included
in electric plant) $124,391
Regulatory asset (deferred amortization
of capital leases) 978
Liabilities
Obligation under capital leases 120,307
Long-term debt and capital leases due
within one year 5,062
- --------------------------------------------------------------------------------
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.
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. The
net obligation is reflected on Oglethorpe's balance sheet.
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 $46,065,000 each. Oglethorpe ultimately expects
to refinance the two medium-term loans with an issuance of PCBs in the fall of
2002.
In October 2001, Oglethorpe completed a current refunding transaction
whereby $22,825,000 of PCBs were issued. The proceeds were used to make
principal payments due January 1, 2002.
GTC agreed with Oglethorpe not to participate in this $22,825,000
refinancing to the extent of their assumed obligation in the PCBs. Pursuant to
this agreement, Oglethorpe will provide a discount to GTC of approximately
$1,155,000 on the $3,849,000 of principal payments due from GTC in connection
with such refinancings. This $1,155,000 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 2002 is estimated to be $215,000,000.
Maturities for the long-term debt and amortization of the capital lease
obligations through 2006 are as follows:
- ------------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
2002 2003 2004 2005 2006
- ------------------------------------------------------------------------------------------------------------------------------------
FFB and RUS $ 91,167 $ 96,748 $101,700 $108,999 $115,980
CoBank 540 46,623 580 603 630
PCBs(1) 20,264 25,835 27,855 28,146 30,000
CFC - 46,065 - - -
Capital leases(2) 15,650 15,161 16,445 17,905 19,429
- ------------------------------------------------------------------------------------------------------------------------------------
Total $127,621 $230,432 $146,580 $155,653 $166,039
- ------------------------------------------------------------------------------------------------------------------------------------
<FN>
(1) Does not contain portion assumed by GTC
(2) Represents principal portion of obligations under capital leases
</FN>
The weighted average interest rate for 2001 for long-term debt and capital
leases and notes payable is 5.52%.
Oglethorpe has a commercial paper program under which it may issue
commercial paper not to exceed a $355,000,000 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.
62
Oglethorpe is providing loans to Talbot EMC and Chattahoochee EMC to fund,
on an interim basis, a portion of the construction cost of the six combustion
turbines and the combined cycle facility. Oglethorpe is funding these loans
under its commercial paper program, and at December 31, 2001, $354,000,000 of
commercial paper was outstanding for this purpose. At March 31, 2002, the amount
of commercial paper outstanding declined to $338,000,000. The loans are included
in Notes receivable on Oglethorpe's balance sheet. These generation facilities
are expected to be completed by Summer 2002 and 2003.
The expected combined cost of constructing the six combustion turbines and
the combined cycle facility totals approximately $600,000,000. Oglethorpe
expects to have approximately $300,000,000 of commercial paper outstanding into
early 2003 in conjunction with the interim financing for these facilities. Two
bridge loans have been secured to fund the remaining portion of the cost of
constructing these facilities. The National Rural Utilities Cooperative Finance
Corporation (NRUCFC) is providing a $141,000,000 bridge loan to Talbot EMC, and
Pitney Bowes Credit Corporation is providing a $160,000,000 bridge loan to
Chattahoochee EMC. Oglethorpe's loans to Talbot EMC and Chattahoochee EMC are
subordinated to the NRUCFC and Pitney Bowes loans, respectively. Oglethorpe is
providing a guarantee on the $160,000,000 bridge loan to Chattahoochee EMC.
In 2000, Oglethorpe submitted loan applications to RUS to provide permanent
financing for these facilities. The loan applications were made on behalf of any
entity that may ultimately own these facilities, and Talbot EMC and
Chattahoochee EMC are now the applicants for RUS financing. Oglethorpe expects
RUS to act on these loan applications later in 2002. If approved by RUS, funding
is expected to occur for both projects by mid-2003. The proceeds of the RUS
permanent financing will be used first to repay the bridge loans and then the
loans from Oglethorpe. If RUS funding is delayed or denied, Oglethorpe will
assist Talbot EMC and Chattahoochee EMC to pursue alternative financing.
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, 2001 is as follows:
- -------------------------------------------------------------------------------------
(dollars in thousands)
Accumulated
Plant Investment Depreciation
- -------------------------------------------------------------------------------------
In-service
Owned property
Vogtle Units No. 1 & No. 2
(Nuclear - 30% ownership) $2,734,723 $ 997,888
Hatch Units No. 1 & No. 2
(Nuclear - 30% ownership) 538,365 263,270
Wansley Units No. 1 & No. 2
(Fossil - 30% ownership) 174,898 96,140
Scherer Unit No. 1
(Fossil - 60% ownership) 427,356 234,941
Rocky Mountain Units No. 1,
No. 2 & No. 3
(Hydro - 74.6% ownership) 556,808 72,848
Tallassee (Harrison Dam)
(Hydro - 100% ownership) 9,270 2,685
Wansley (Combustion Turbine -
30% ownership) 3,629 1,735
Generation step-up substations 63,014 28,066
Other 91,961 40,273
Property under capital lease
Plant Doyle (Combustion Turbine -
100% leasehold) 126,991 10,399
Scherer Unit No. 2
(Fossil - 60% leasehold) 302,177 133,673
- -------------------------------------------------------------------------------------
Total in-service $5,029,192 $1,881,918
- -------------------------------------------------------------------------------------
Construction work in progress
Generation improvements $ 35,833
Other 2,731
- -------------------------------------------------------------------------------------
Total construction work in progress $ 38,564
- -------------------------------------------------------------------------------------
63
Oglethorpe, as of December 31, 2001, estimates property additions
(excluding capitalized interest and nuclear fuel) to be approximately
$112,000,000 in 2002, $51,000,000 in 2003 and $26,000,000 in 2004, primarily for
replacements and additions to generation facilities.
Oglethorpe's proportionate share of direct expenses of joint operation of
the above plants is included in the corresponding operating expense captions
(e.g., fuel, production or depreciation) on the accompanying statements of
revenues and expenses.
7. Employee benefit plans:
Oglethorpe has a money purchase plan which became effective January 1,
1999. Under this plan, Oglethorpe contributes 5%, subject to IRS limitations, of
each employee's annual compensation. In addition, older employees who
participated in the now-terminated defined benefit pension plan receive an
additional 1% to 2% of compensation. Oglethorpe's contributions to the plan were
approximately $498,000 in 2001 and $ 444,000 in 2000 and $365,000 in 1999.
Oglethorpe has a contributory employee retirement savings plan (a 401(k)
plan) covering substantially all employees. The employee may contribute, subject
to IRS limitations, up to 16% of his annual compensation (the maximum
contribution percentage rises to 60% of annual compensation in April of 2002).
Oglethorpe, at its discretion, may match the employee's contribution and has
done so each year of the plan's existence. Oglethorpe's current policy is to
match the employee's contribution as long as there is sufficient margin to do
so. The match, which is calculated each pay period, currently can be equal to as
much as three-quarters of the first 6% of the employee's annual compensation,
depending on the amount and timing of the employee's contribution. Oglethorpe's
contributions to the plan were approximately $463,000 in 2001, $261,000 in 2000
and $226,000 in 1999.
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 $7,210,000 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 $8,425,000.
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 provided by American Nuclear Insurers (ANI) (in the
amount of $200,000,000 for each plant, the maximum amount currently available)
64
is carried by GPC for the benefit of all the co-owners of Plants Hatch and
Vogtle. Agreements of indemnity have been entered into by and between each of
the co-owners and the NRC. In the event of a nuclear incident involving any
commercial nuclear facility in the country involving total public liability in
excess of $200,000,000, a licensee of a nuclear power plant could be assessed a
deferred premium of up to $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.
Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their insurance. Both companies, however, revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12 month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is $200,000,000 in a policy year.
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. After
considering resources made available to LEM and Morgan Stanley, Oglethorpe
estimates that about 30% of its power supply capability will be provided by
these contracts in 2002.
In February 2001, LEM and its affiliates initiated a binding arbitration
process to resolve certain issues relating to the interpretation and
administration of the LEM agreement and a similar agreement with Oglethorpe that
expired by its terms in 1999. On November 5, 2001, the arbitration panel issued
an order on an issue-by-issue basis as to liability, ruling in Oglethorpe's
favor on some issues and in LEM's favor on some issues. Oglethorpe expects a
decision on the damage aspects of these issues in June 2002. Oglethorpe has
recorded a $36,000,000 accrual to purchase power costs, and a corresponding
increase in current liabilities, for estimated damages payable to LEM. If the
arbitration panel adopts all of LEM's proposed remedies, Oglethorpe believes the
award could be approximately $60,000,000.
In addition, Oglethorpe has entered into various long-term power purchase
agreements. As of December 31, 2001, 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)
- --------------------------------------------------------------------------------
2002 $ 58,451
2003 45,355
2004 46,019
2005 46,810
2006 46,749
Thereafter 336,895
- --------------------------------------------------------------------------------
65
Oglethorpe's power purchases from these agreements amounted to
approximately $130,110,000 in 2001, $149,617,000 in 2000 and $132,721,000 in
1999.
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, 2001,
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)
- --------------------------------------------------------------------------------
2002 $ 2,877
2003 2,877
2004 2,877
2005 2,877
2006 2,877
Thereafter 38,234
- --------------------------------------------------------------------------------
10. Quarterly financial data (unaudited):
Summarized quarterly financial information for 2001 and 2000 is as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
First Second Third Fourth
Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
2001
Operating revenues $ 306,607 $ 279,911 $ 319,580 $ 233,191
Operating margin 66,765 48,934 45,316 53,717
Net margin 15,283 (1,211) (4,031) 8,376
2000
Operating revenues $ 274,882 $ 285,026 $ 314,433 $ 325,056
Operating margin 61,527 61,569 52,163 51,680
Net margin 9,188 9,624 (323) 1,489
- --------------------------------------------------------------------------------
The negative net margin for the second and third quarters of 2001 is the
result of reductions to revenue requirements of $17,252,000 and $18,270,000,
respectively, approved by Oglethorpe's Board of Directors.
66
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, 2001 and
2000, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2001 in conformity with accounting
principles generally accepted 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
auditing standards generally accepted 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,
March 1, 2002, except for Note 9 as to which the date is March 29, 2002.
67
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....... 60 Chairman of the Board
of Directors, Member
Director, Statewide
Thomas A. Smith......... 47 President and Chief
Executive Officer
Michael W. Price........ 41 Chief Operating Officer
W. Clayton Robbins...... 55 Senior Vice President,
Finance and
Administration
Elizabeth B. Higgins.... 33 Vice President, Group
Executive
Larry N. Chadwick....... 61 Member Director,
Northwest Region
Benny W. Denham......... 71 Member Director,
Southwest Region
Sammy M. Jenkins........ 75 Member Director,
Southeast Region
Mac F. Oglesby.......... 69 Member Director,
Northeast Region and
Treasurer
J. Sam L. Rabun......... 70 Member Director,
Central Region and
Vice Chairman
Ashley C. Brown......... 56 Outside Director
Wm. Ronald Duffey....... 60 Outside Director
John S. Ranson.......... 72 Outside Director
Jeffrey D. Tranen....... 55 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
68
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
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 and Chief Executive Officer of Sunbelt
Fasteners, Inc., which sells specialty tools and fasteners to the commercial
construction trade. He is Vice Chairman of the Board of Directors of 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, a Director of the Georgia Chamber of Commerce, and a Director
of En-Touch Systems, Inc. in Houston, Texas. 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, Group Executive 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 &
69
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
served on the Board of Directors of Oglethorpe since July 1989. His present term
will expire in March 2005. 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 2004. 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 is a
member of the Audit Committee 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 term expired in March 2002. Mr. Jenkins will
continue to serve until he is reelected or until his successor is appointed.
Mac F. Oglesby is the Member Director from the Northeast Region and the
Treasurer of Oglethorpe. He is a member of the Compensation 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 Audit 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 2004. 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. Mr. Rabun is Vice-Chairman of the Board
of the Georgia Energy Cooperative.
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 2005. 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 has been Of Counsel to
the law firm of LeBoeuf, Lamb, Greene and MacRae since May 1997. 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
70
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 2004. Mr. Duffey is the President and Chief
Executive Officer and a director of Peachtree National Bank in Peachtree City,
Georgia, a wholly owned subsidiary of Synovus Financial Corp. Prior to his
employment in 1985 with Peachtree National Bank, Mr. Duffey served as Executive
Vice President and Member of the Board of Directors for First National Bank in
Newnan, Georgia. He holds a Bachelor of Business Administration from Georgia
State College with a concentration in finance and has completed banking courses
at the Banking School of the South, the American Bankers Association School of
Bank Investments, and The Stonier Graduate School of Banking, Rutgers
University. 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 2005. 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 from 1999 to 2000. 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 and Earth First Technology Corporation. Mr. Tranen has a
Bachelor of Science in Electrical Engineering and a Master of Science in
Electrical Engineering from the Massachusetts Institute of Technology.
71
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, 2001, 2000 and 1999.
Annual Compensation All Other
------------------- ---------
Name and Principal Position Year Salary Bonus Compensation(1)
- --------------------------- ---- ------ ----- ---------------
Thomas A. Smith...................................... 2001 $292,500 87,320 90,529 (2)
President and Chief Executive Officer 2000 275,000 82,800 14,005
1999 202,008 65,283 14,237
Michael W. Price(3).................................. 2001 182,008 54,464 26,527 (4)
Chief Operating Officer 2000 157,667 50,912 23,583
1999 0 0 0
W. Clayton Robbins(5)................................ 2001 169,417 44,160 17,640
Senior Vice President, Finance and 2000 163,000 42,476 11,335
Administration 1999 23,341 35,945 1,259
Elizabeth B. Higgins................................. 2001 143,333 26,825 15,401
Vice President, Group Executive 2000 126,125 24,975 11,846
1999 88,431 22,233 9,457
<FN>
________________
(1) Figures for 2001 consist of contributions made by Oglethorpe under the
401(k) Retirement Savings Plan on behalf of Mr. Smith, Mr. Price, Mr.
Robbins and Ms. Higgins of $6,592, $7,650, $7,650 and $6,758, respectively;
contributions under Oglethorpe's Money Purchase Pension Plan on behalf of
Mr. Smith, Mr. Price, Mr. Robbins and Ms. Higgins of $8,500, $8,500, $8,500
and $8,415, respectively; and insurance premiums paid on term life insurance
on behalf of Mr. Smith, Mr. Price, Mr. Robbins and Ms. Higgins of $437,
$377, $1,490 and $227, respectively.
(2) Includes a contribution under Oglethorpe's Executive Supplemental Retirement
Plan of $75,000.
(3) Mr. Price became an Oglethorpe employee on February 1, 2000.
(4) Includes a bonus of $10,000 paid in 2001.
(5) Mr. Robbins became an Oglethorpe employee on November 16, 1999.
</FN>
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.
Beginning in 2001, Mr. Tranen was given a special assignment by the Board
of Directors in his capacity as a Director of Oglethorpe to work with
Oglethorpe's staff and consultants on an evaluation of matters relating to
member scheduling issues, system operations, and pool operations. Mr. Tranen is
72
paid a per diem fee of $5,500 for each meeting relating to this assignment, plus
an additional 20 percent for preparing for each meeting. Upon approval of the
Chairman of the Board, he may also be paid a per diem of $5,500 for other work
relating to this assignment. Out-of-pocket expenses incurred in connection with
the assignment are reimbursed. During 2001, Mr. Tranen was paid approximately
$185,000 for fees and expenses relating to this assignment.
Employment Contracts
Oglethorpe entered into an Employment Agreement with Thomas A. Smith,
Oglethorpe's President and Chief Executive Officer, effective March 15, 2002.
The agreement extends until December 31, 2004, and automatically renews for
successive one-year periods unless either party gives notice of termination 24
months prior to the expiration of the agreement or any extension of the
agreement. Mr. Smith's minimum base salary is $325,000 per year, and is annually
adjusted by the Board of Directors of Oglethorpe. Mr. Smith was paid a bonus of
$100,000 in March 2002 in connection with entering into the agreement. Mr. Smith
is entitled to bonuses totaling $100,000 if he remains employed by Oglethorpe
through 2002, 2003 and 2004. 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. If Mr. Smith resigns for any reason other than those described above,
he will be entitled to a severance payment equal to twelve months' salary (if he
resigns prior to December 31, 2002) or six months' salary (if he resigns between
January 1 and December 31, 2003).
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
73
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. If Ms. Higgins resigns for any reason other than those described
above on or before December 31, 2003, she will be entitled to severance pay
equal to her base salary for one year, payable in semi-monthly installments.
Compensation Committee Interlocks and Insider Participation
J. Calvin Earwood, John S. Ranson and Mac F. Oglesby served as members of
the Oglethorpe Power Corporation Compensation Committee in 2002. Mr. Earwood has
served as an executive officer of Oglethorpe since 1984 and has served as the
Chairman of the Board since 1989.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
74
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, 2001, 2000 and 1999........................................................ 47
Balance Sheets, As of December 31, 2001 and 2000................................ 48
Statements of Capitalization, As of December 31, 2001 and 2000.......................... 50
Statements of Cash Flows, For the Years Ended
December 31, 2001, 2000 and 1999..................................................... 51
Statements of Patronage Capital and Membership Fees
And Accumulated Other Comprehensive Margin For the Years Ended
For the Years Ended December 31, 2001, 2000 and 1999................................. 52
Notes to Financial Statements........................................................... 53
Report of Management.................................................................... 67
Report of Independent Accountants....................................................... 67
(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 November 14,
2001.
75
*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.)
76
*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.)
77
*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.
4.7.1(p) -- Fifteenth Supplemental Indenture, dated as of January
1, 2002, made by Oglethorpe to SunTrust Bank, as
trustee, relating to the Series 2001 (Burke) Note.
4.7.1(q) -- Sixteenth Supplemental Indenture, dated as of January
1, 2002, made by Oglethorpe to SunTrust Bank, as
trustee, relating to the Series 2001 (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.
78
4.9.5(1) -- Liquidity Guaranty Agreement, dated as of December 1,
1992, by and between Oglethorpe and AIG Financial
Products Corp. relating to Development Authority of
Burke County Adjustable Tender Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1993A, and one other substantially
identical agreement.
4.9.6(1) -- Standby Bond Purchase Agreement, dated as of December
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.
79
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.
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
80
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.)
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.)
81
*10.1.3(a) -- Supporting Assets Lease No. 2, dated December 30,
1985, between Oglethorpe, Lessor, and Wilmington
Trust Company and William J. Wade, as Owner Trustees,
under Trust Agreement No. 2, dated December 30, 1985,
with Ford Motor Credit Company, Lessee, together with
a Schedule identifying three substantially identical
Supporting Assets Leases. (Filed as Exhibit 10.1.3 to
the Registrant's Form S-1 Registration Statement,
File No. 33-7591.)
*10.1.3(b) -- First Amendment to Supporting Assets Lease No. 2,
dated as of November 19, 1987, together with a
Schedule identifying three substantially identical
First Amendments to Supporting Assets Leases. (Filed
as Exhibit 10.1.3(a) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1987, File No.
33-7591.)
*10.1.3(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.)
82
*10.1.6 -- Assignment of Interest in Ownership Agreement and
Operating Agreement No. 2, dated December 30, 1985,
between Oglethorpe, Assignor, and Wilmington Trust
Company and William J. Wade, as Owner Trustees under
Trust Agreement No. 2, dated December 30, 1985, with
Ford Motor Credit Company, Assignee, together with
Schedule identifying three substantially identical
Assignments of Interest in Ownership Agreement and
Operating Agreement. (Filed as Exhibit 10.1.6 to the
Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.1.7 -- Consent, Amendment and Assumption No. 2 dated
December 30, 1985, among Georgia Power Company and
Oglethorpe and Municipal Electric Authority of
Georgia and City of Dalton, Georgia and Gulf Power
Company and Wilmington Trust Company and William J.
Wade, as Owner Trustees under Trust Agreement No. 2,
dated December 30, 1985, with Ford Motor Credit
Company, together with a Schedule identifying three
substantially identical Consents, Amendments and
Assumptions. (Filed as Exhibit 10.1.9 to the
Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.1.7(a) -- Amendment to Consent, Amendment and Assumption No. 2,
dated as of August 16, 1993, among Oglethorpe,
Georgia Power Company, Municipal Electric Authority
of Georgia, City of Dalton, Georgia, Gulf Power
Company, Jacksonville Electric Authority, Florida
Power & Light Company and Wilmington Trust Company
and NationsBank of Georgia, N.A., as Owner Trustees
under Trust Agreement No. 2, dated December 30, 1985,
with Ford Motor Credit Company, together with a
Schedule identifying three substantially identical
Amendments to Consents, Amendments and Assumptions.
(Filed as Exhibit 10.1.9(a) to the Registrant's Form
10-Q for the quarterly period ended September 30,
1993, File No. 33-7591.)
*10.2.1 -- Section 168 Agreement and Election dated as of April
7, 1982, between Continental Telephone Corporation
and Oglethorpe. (Filed as Exhibit 10.2 to the
Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.2.2 -- Section 168 Agreement and Election dated as of April
9, 1982, between 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.)
83
*10.3.1(d) -- Amendment Number Three to the Plant Robert W. Scherer
Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia
and City of Dalton, Georgia, dated as of August 1,
1988. (Filed as Exhibit 10.6.1(b) to the Registrant's
Form 10-Q for the quarterly period ended September
30, 1993, File No. 33-7591.)
*10.3.1(e) -- Amendment Number Four to the Plant Robert W. Scherer
Units Number One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia
and City of Dalton, Georgia, dated as of December 31,
1990. (Filed as Exhibit 10.6.1(c) to the Registrant's
Form 10-Q for the quarterly period ended September
30, 1993, File No. 33-7591.)
*10.3.2(a) -- Plant Robert W. Scherer Units Numbers One and Two
Operating Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia
and City of Dalton, Georgia, dated as of May 15,
1980. (Filed as Exhibit 10.6.2 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.3.2(b) -- Amendment to Plant Robert W. Scherer Units Numbers
One and Two Operating Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of
Georgia and City of Dalton, Georgia, dated as of
December 30, 1985. (Filed as Exhibit 10.1.7 to the
Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*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.)
84
*10.4.1(c) -- Amendment Number Two, dated February 24, 1977, to the
Alvin W. Vogtle Nuclear Units Numbers One and Two
Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia.
(Filed as Exhibit 10.7.4 to the Registrant's Form
10-K for the fiscal year ended December 31, 1986,
File No. 33-7591.)
*10.4.2 -- Alvin W. Vogtle Nuclear Units Numbers One and Two
Operating Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia
and City of Dalton, Georgia, dated as of August 27,
1976. (Filed as Exhibit 10.7.2 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.5.1 -- Plant Hal Wansley Purchase and Ownership
Participation Agreement between Georgia Power Company
and Oglethorpe, dated as of March 26, 1976. (Filed as
Exhibit 10.8.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.5.2(a) -- Plant Hal Wansley Operating Agreement between Georgia
Power Company and Oglethorpe, dated as of March 26,
1976. (Filed as Exhibit 10.8.2 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.5.2(b) -- Amendment, dated as of January 15, 1995, to the Plant
Hal Wansley Operating Agreements by and among Georgia
Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia.
(Filed as Exhibit 10.5.2(a) to the Registrant's Form
10-Q for the quarterly period ended September 30,
1996, File No. 33-7591.)
*10.5.3 -- Plant Hal Wansley Combustion Turbine Agreement
between Georgia Power Company and Oglethorpe, dated
as of August 2, 1982 and Amendment No. 1, dated
October 20, 1982. (Filed as Exhibit 10.18 to the
Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*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.)
85
*10.8.1 -- Amended and Restated Wholesale Power Contract, dated
as of August 1, 1996, between Oglethorpe and Altamaha
Electric Membership Corporation and all schedules
thereto, together with a Schedule identifying 37
other substantially identical Amended and Restated
Wholesale Power Contracts, and an additional Amended
and Restated Wholesale Power Contract that is not
substantially identical. (Filed as Exhibit 10.8.1 to
the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.8.2 -- Amended and Restated Supplemental Agreement, dated as
of August 1, 1996, by and between Oglethorpe,
Altamaha Electric Membership Corporation and the
United States of America, together with a Schedule
identifying 38 other substantially identical Amended
and Restated Supplemental Agreements. (Filed as
Exhibit 10.8.2 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No.
33-7591.)
*10.8.3 -- Supplemental Agreement to the Amended and Restated
Wholesale Power Contract, dated as of January 1,
1997, by and among Georgia Power Company, Oglethorpe
and Altamaha Electric Membership Corporation,
together with a Schedule identifying 38 other
substantially identical Supplemental Agreements.
(Filed as Exhibit 10.8.3 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
*10.8.4 -- Supplemental Agreement to the Amended and Restated
Wholesale Power Contract, dated as of March 1, 1997,
by and between Oglethorpe and Altamaha Electric
Membership Corporation, together with a Schedule
identifying 36 other substantially identical
Supplemental Agreements, and an additional
Supplemental Agreement that is not substantially
identical. (Filed as Exhibit 10.8.4 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.8.5 -- Supplemental Agreement to the Amended and Restated
Wholesale Power Contract, dated as of March 1, 1997,
by and between Oglethorpe and Coweta-Fayette Electric
Membership Corporation, together with a Schedule
identifying 1 other substantially identical
Supplemental Agreement. (Filed as Exhibit 10.8.5 to
the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*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.)
86
*10.10 -- Letter of Commitment (Firm Power Sale) Under Service
Schedule J--Negotiated Interchange Service between
Alabama Electric Cooperative, Inc. and Oglethorpe,
dated March 31, 1994. (Filed as Exhibit 10.11(b) to
the Registrant's Form 10-Q for the quarter ended June
30, 1994, File No. 33-7591.)
*10.11.1 -- Assignment of Power System Agreement and Settlement
Agreement, dated January 8, 1975, by Georgia Electric
Membership Corporation to Oglethorpe. (Filed as
Exhibit 10.20.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.11.2 -- Power System Agreement, dated April 24, 1974, by and
between Georgia Electric Membership Corporation and
Georgia Power Company. (Filed as Exhibit 10.20.2 to
the Registrant's Form S-1 Registration Statement,
File No. 33-7591.)
*10.11.3 -- Settlement Agreement, dated April 24, 1974, by and
between Georgia Power Company, Georgia Municipal
Association, Inc., City of Dalton, Georgia Electric
Membership Corporation and Crisp County Power
Commission. (Filed as Exhibit 10.20.3 to the
Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.12 -- Long-Term Firm Power Purchase Agreement between Big
Rivers Electric Corporation and Oglethorpe, dated as
of December 17, 1990. (Filed as Exhibit 10.24.3 to
the Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*10.13 -- 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).
87
*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.)
*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.)
88
*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.)
*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.)
89
*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.)
*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.)
90
*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.)
*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 March 15, 2002,
between Oglethorpe and Thomas A. Smith.
*10.26(3) -- Employment Agreement, dated July 25, 2000, between
Oglethorpe and Michael W. Price. (Filed as Exhibit
10.26 to the Registrant's Form 10-K for the fiscal
year ended December 31, 2001, File No. 33-7591.)
*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.)
*10.28.1(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.)
*10.28.2(3) -- Amendment to Employment Agreement, dated May 8, 2001,
between Oglethorpe and Elizabeth Higgins. (Filed as
Exhibit 10.30 to the Registrant's Form 10-Q for the
quarterly period ended June 30, 2001, 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 2001.
91
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 31st day of
March, 2002.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
By: /s/ J. CALVIN EARWOOD
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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 31, 2002
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J. CALVIN EARWOOD (Principal Executive Officer)
/s/ THOMAS A. SMITH President and Chief Executive Officer March 31, 2002
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THOMAS A. SMITH (Principal Executive Officer)
/s/ MAC F. OGLESBY Treasurer, Director (Principal Financial March 31, 2002
- -------------------
MAC F. OGLESBY Officer)
/s/ W. CLAYTON ROBBINS Senior Vice President, Finance and March 31, 2002
- ----------------------- Administration (Principal Financial Officer)
W. CLAYTON ROBBINS
/s/ MARK CHESLA Controller March 31, 2002
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MARK CHESLA
/s/ ASHLEY C. BROWN Director March 31, 2002
- --------------------
ASHLEY C. BROWN
/s/ LARRY N. CHADWICK Director March 31, 2002
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LARRY N. CHADWICK
/s/ BENNY W. DENHAM Director March 31, 2002
- --------------------
BENNY W. DENHAM
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Signature Title Date
--------- ----- ----
/s/ WM. RONALD DUFFEY Director March 31, 2002
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WM. RONALD DUFFEY
/s/ SAMMY M. JENKINS Director March 31, 2002
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SAMMY M. JENKINS
/s/ J. SAM L. RABUN Director March 31, 2002
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J. SAM L. RABUN
/s/ JOHN S. RANSON Director March 31, 2002
- -------------------
JOHN S. RANSON
/s/ JEFFREY D. TRANEN Director March 31, 2002
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JEFFREY D. TRANEN
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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.
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