Back to GetFilings.com
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
i
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
ii
PART I
ITEM 1. BUSINESS
OGLETHORPE POWER CORPORATION
General
Oglethorpe Power Corporation (An Electric Membership Corporation)
("Oglethorpe") is a Georgia electric membership corporation incorporated in 1974
and headquartered in metropolitan Atlanta. Oglethorpe is owned by 39 retail
electric distribution cooperative members (the "Members"). 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
1
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
2
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
3
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.
4
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
7
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
- ----------
(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.")
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
=======
- ----------
(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".
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 --
- --------------
(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.
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
===== ===== ===== ===== ===== ===== ===== ===== ====== === =====
(1) Based on nameplate ratings.
Georgia Power Company
GPC is a wholly owned subsidiary of The Southern Company, a registered
holding company under the Public Utility Holding Company Act, and is engaged
primarily in the generation and purchase of electric energy and the
transmission, distribution and sale of such energy. GPC distributes and sells
energy within the State of Georgia at retail in over 600 communities (including
Athens, Atlanta, Augusta, Columbus, Macon, Rome and Valdosta), as well as in
rural areas, and at wholesale to Oglethorpe, MEAG and two municipalities. GPC is
the largest supplier of electric energy in the State of Georgia. (See
"OGLETHORPE POWER CORPORATION--Relationship with GPC" in Item 1.) GPC is subject
to the informational requirements of the Securities Exchange Act of 1934, as
amended, and, in accordance therewith, files reports and other information with
the Commission.
Municipal Electric Authority of Georgia
MEAG, an instrumentality of the State of Georgia, was created for the
purpose of providing electric capacity and energy to those political
subdivisions of the State of Georgia that owned and operated electric
distribution systems at that time. MEAG, also known as MEAG Power, has entered
into power sales contracts with each of 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