SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
FOR ANNUAL AND TRANSITION REPORTS
PURSUANT TO SECTIONS 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
(Mark One)
[ X ][X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20002002
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__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][ X ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes No X
----- -----
State the aggregate market value of the voting and non-voting common equity
held by non-affiliates computed by reference to the price at which the common
equity was last sold, or the average bid and asked price of such common equity,
as of the registrant.last business day of the registrant's most recently completed second
fiscal quarter. 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
20002002 FORM 10-K ANNUAL REPORT
Table of Contents
ITEM Page
PART I
1 Business ................................................................1
Oglethorpe Power Corporation...........................................1
Oglethorpe's Power Supply Resources....................................7
The Members and Their Power Supply Resources..........................12
Factors Affecting the Electric Utility Industry.......................17
2 Properties..............................................................22
3 Legal Proceedings.......................................................28
4 Submission of Matters to a Vote of Security Holders.....................28
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters...29
6 Selected Financial Data.................................................29
7 Management's Discussion and Analysis of Financial Condition and Results
of Operations...........................................................30
7A Quantitative and Qualitative Disclosures About Market Risk..............40
8 Financial Statements and Supplementary Data.............................44
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................................64
PART III
10 Directors and Executive Officers of the Registrant......................64
11 Executive Compensation..................................................68
12 Security Ownership of Certain Beneficial Owners and Management..........70
13 Certain Relationships and Related Transactions..........................70
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K........71
ITEM Page
- ---- ----
PART I
1 Business .................................................................. 1
Oglethorpe Power Corporation............................................. 1
Oglethorpe's Power Supply Resources...................................... 8
The Members and Their Power Supply Resources............................. 12
Factors Affecting the Electric Utility Industry.......................... 17
2 Properties................................................................. 23
3 Legal Proceedings.......................................................... 29
4 Submission of Matters to a Vote of Security Holders........................ 29
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters...... 30
6 Selected Financial Data.................................................... 30
7 Management's Discussion and Analysis of Financial Condition and Results
of Operations.............................................................. 31
7A Quantitative and Qualitative Disclosures About Market Risk................. 46
8 Financial Statements and Supplementary Data................................ 51
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................................... 73
PART III
10 Directors and Executive Officers of the Registrant......................... 73
11 Executive Compensation..................................................... 77
12 Security Ownership of Certain Beneficial Owners and Management............. 79
13 Certain Relationships and Related Transactions............................. 79
14 Controls and Procedures.................................................... 79
PART IV
15 Exhibits, Financial Statement Schedules, and Reports on Form 8-K........... 80
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 160173 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 1.41.5 million
electric consumers (meters) representing approximately 3.43.7 million people. For
information on the Members, see(See
"THE MEMBERS AND THEIR POWER SUPPLY RESOURCES.")
In the second quarter of 2003, Oglethorpe expects to acquire two gas-fired
generation facilities (aggregating approximately 1086 MW) utilizing $589 million
from loans guaranteed by the Rural Utilities Service (the "RUS"). In connection
with the acquisition, Oglethorpe also would enter into limited amendments to its
existing Amended and Restated Wholesale Power Contracts with each of the Members
(the "Wholesale Power Contracts") and other agreements with its Members
regarding the services provided by Oglethorpe. (See "Expected Facilities
Acquisitions, RUS Loans and Other New Arrangements.")
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) towhich constitutes margins. The margins increase its patronage capital,
which is the equity component of itsa cooperative's capitalization. Any such
margins are considered capital contributions (that is, equity) from the members
and are held for the accounts of the members and returned to them when the board
of directors of the cooperative deems it prudent to do so. The timing and amount
of any actual return of capital to the members depends on the financial goals of
the cooperative and the cooperative's loan and security agreements.
Power Supply Business
Oglethorpe provides wholesale electric service to the 39 Members for a
substantial portion of their requirements from a combination of owned and leased
1
generating plantsits generation
assets and power purchased from power marketers and other suppliers and power marketers.
Thissuppliers. Oglethorpe
provides this service is provided pursuant to long-term, take-or-pay Wholesale Power
Contracts described below. The Wholesale Power Contracts obligate the Members on
a joint and several basis to pay rates sufficient to payrecover all the costs of
owning and operating Oglethorpe's power supply business. ThePursuant to the
Wholesale Power Contracts, the Members may satisfy all or a portion of their
requirements above their existing Oglethorpe purchase obligations with purchases from
Oglethorpe or other suppliers. TheBecause many Members have exercised this option and other
1
Members are now purchasing varying portionsanalyzing this option, Oglethorpe is not currently engaged in
long-term resource procurement for any Member other than in connection with the
anticipated acquisition of their requirements from other suppliers.the two generation facilities described above. (See
"OGLETHORPE'S POWER SUPPLY RESOURCES--Future Power Resources" and
"THE MEMBERS AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources" and "--Future
Power Resources.")
Oglethorpe owns or leaseshas undivided interests in thirteenseventeen generating units. These
units provide Oglethorpe with a total of 3,3353,658 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 and 15 MW of oil-fired combustion
turbine capacity and 2 MW of conventional hydroelectric
capacity. In addition,
Oglethorpe purchases a total of approximately 1,200550 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
growth in the Members' requirements, representing about 30% of Oglethorpe's
power supply capability in 2003. 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. GTC provides transmission services to the Members for
delivery of the Members' power purchases. (See "Relationship with GTC" herein, "OGLETHORPE'S POWER SUPPLY RESOURCES" and
"PROPERTIES--Generating Facilities" in Item 2.)
Oglethorpe has entered into power supply arrangements with two power
marketers to reduce the cost of capacity and energy delivered to the Members.
(See "OGLETHORPE'S POWER SUPPLY RESOURCES--Power Marketer Arrangements.")
In 2000,2002, Cobb EMC and Jackson EMC accounted for 11.9%11.3% and 11.8%11.2% of
Oglethorpe's total revenues, respectively. None of the other Members accounted
for as much as 10% of Oglethorpe's total revenues in 2000.2002.
Wholesale Power Contracts
In 1997, Oglethorpe entered intohas 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 allocationpercentage of Oglethorpe'sthe capacity costs
for its existing(referred to as a "percentage capacity responsibility") of each of Oglethorpe's
generation and purchased power resources, as
well as the costs with respect to any future resources in which such Member
elects to participate.resources. 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 forto 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 beis 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, Oglethorpe is not obligated to provide
all of the Members' capacity and energy requirements and Members have the option
of satisfying all or a portion of their requirements above their Oglethorpe
purchase obligations from other suppliers. The Members also have various options
regarding the purchase of joint planning and resource management services and
participation in a capacity and energy pool. For more information about these
options see "Expected Facilities Acquisition, RUS Loans and other New
Arrangements", "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."
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
2
Oglethorpe when due, all amounts payable by the Member under its Wholesale Power
Contract and (ii) any and all other amounts payable from, or which might
constitute a charge or a lien upon, the revenues and receipts derived from the
Member's electric system, including all operation and maintenance expenses and
the principal of, premium, if any, and interest on all indebtedness related to
the Member's electric system.
Under the Wholesale Power Contracts, Oglethorpe is not obligated to provide
all of the Members' capacity or energy requirements. The Members also have
various options regarding services provided by Oglethorpe. These options
include:
o whether to have Oglethorpe provide joint planning and resource management
services,
o whether to participate in a capacity and energy pool or to separately
schedule their resources, and
o whether to satisfy all or a portion of their power requirements above
their existing Oglethorpe purchase obligations from Oglethorpe or from
other suppliers.
For more information about these options see "OGLETHORPE'S POWER SUPPLY
RESOURCES--Future Power Resources" and "--Capacity and Energy Pool" and "THE
MEMBERS AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources."
Electric Rates
Each Member is required to pay Oglethorpe for capacity and energy furnished
under its Wholesale Power Contract in accordance with rates established by
Oglethorpe. Oglethorpe reviews its rates at such intervals as it deems
appropriate but is required to do so at least once every year. Oglethorpe is
required to revise its rates as necessary so that the revenues derived from its
rates, together with its revenues from all other sources, will be sufficient to
pay all costs of its system, to provide for reasonable reserves and to meet all
financial requirements.
Oglethorpe's principal financial requirements are contained in the
Indenture, dated as of March 1, 1997, from Oglethorpe to SunTrust Bank
("SunTrust"), as trustee (as supplemented, the "Mortgage Indenture"). Under the
Mortgage Indenture, Oglethorpe is required, subject to any necessary regulatory
approval, to establish and collect rates which are reasonably expected, together
with other revenues of Oglethorpe, to yield a Margins for Interest Ratio for
each fiscal year equal to at least 1.10. "Margins for Interest Ratio" is the
ratio of "Margins for Interest" to total "Interest Charges" for a given period.
Margins for Interest is the sum of:
o net margins of Oglethorpe (which includes revenues of Oglethorpe subject to
refund at a later date but excludes provisions for (i) non-recurring
charges to income, including the non-recoverability of assets or expenses,
except to the extent Oglethorpe determines to recover such charges in
rates, and (ii) refunds of revenues collected or accrued subject to
refund), plus
o interest charges, whether capitalized or expensed, on all indebtedness
secured under the Mortgage Indenture or by a lien equal or prior to the
lien of the Mortgage Indenture, including amortization of debt discount or
premium on issuance, but excluding interest charges on indebtedness assumed
by GTC ("Interest Charges"), plus
o any amount included in net margins for accruals for federal or state income
taxes imposed on income after deduction of interest expense.
Margins for Interest takes into account any item of net margin, loss, gain
or expenditure of any affiliate or subsidiary of Oglethorpe only if Oglethorpe
has received such net margins or gains as a dividend or other distribution from
such affiliate or subsidiary or if Oglethorpe has made a payment with respect to
such losses or expenditures.
3
The formulary rate established by Oglethorpe in the rate schedule to the
Wholesale Power Contracts employs a rate methodology under which all categories
of costs are specifically separated as components of the formula to determine
Oglethorpe's revenue requirements. The rate schedule also implements the
responsibility for fixed costs assigned to each Member (that is, the Member's
percentage capacity responsibility). The monthly charges for capacity and other
non-energy charges are based on Oglethorpe's annual budget. Such capacity and
other non-energy charges may be adjusted by the Board of Directors, if
necessary, during the year through an adjustment to the annual budget. Energy
charges reflect the pass-through of actual energy costs, including fuel costs,
variable operations and maintenance costs and purchased energy costs. (See
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--General--Rates and Regulation" in Item 7.)
The rate schedule formula also includes a prior period adjustment mechanism
designed to ensure that Oglethorpe achieves the minimum 1.10 Margins for
Interest Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum
1.10 Margins for Interest Ratio are accrued as of December 31 of the applicable
year and collected from the Members during the period April through December of
3
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"),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").
Expected Facilities Acquisitions, RUS Loans and Other New Arrangements
In the second quarter of 2003, Oglethorpe expects to acquire two generation
facilities now owned and being developed by Talbot EMC and Chattahoochee EMC.
Talbot EMC and Chattahoochee EMC were formed in 2001 as Georgia electric
membership corporations. Talbot EMC is owned by 30 Members and is developing a
six-unit gas-fired combustion turbine facility designed to provide 618 MW of
capacity. Four of the units have been operating since June 2002, and the other
two units are expected to be operational by June 2003. Chattahoochee EMC is
owned by 28 Members and has developed a gas-fired combined cycle facility
designed to provide 468 MW of capacity, which became operational in February
2003. (See "Relationship with Smarr EMC, Talbot EMC and Chattahoochee EMC".)
Oglethorpe expects to finance these acquisitions with loans guaranteed by
RUS, for which Oglethorpe has obtained commitments in the amount of $589
million. These loans would be secured under the Mortgage Indenture (See
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Financial Condition--Capital Requirement--Financing for Talbot EMC
and Chattahoochee EMC" in Item 7.)
Oglethorpe's acquisition of these facilities has received requisite Board
and Member approval, subject to final RUS approval and implementation of certain
new arrangements among Oglethorpe and the Members as described below.
Proposed New Arrangements
Oglethorpe and the Members have developed definitive terms of agreements to
implement the acquisition of the Talbot EMC and Chattahoochee EMC generating
facilities, to document the conditions to that acquisition and to provide for
the new arrangements among Oglethorpe and the Members. At the time of the
acquisition of the facilities and the initial advances under the RUS-guaranteed
loans, Oglethorpe and the Members would enter into Amended and Restated
Wholesale Power Contracts and a New Business Model Member Agreement.
Amended and Restated Wholesale Power Contracts. The proposed Amended and
Restated Wholesale Power Contracts (the "Proposed Wholesale Power Contracts")
contain limited amendments and would not change the unconditional obligation of
each Member, on an express "take-or-pay" basis, to pay for a fixed percentage
responsibility of the costs of Oglethorpe's generation and purchased power
resources. In the same way as the existing Wholesale Power Contracts, the
Proposed Wholesale Power Contracts would continue to provide that each Member
would be jointly and severally responsible for all costs and expenses of all
resources (which would include the Talbot EMC and Chattahoochee EMC generation
facilities). To acquire future resources, in addition to the approval of 75% of
Oglethorpe's Directors and 75% of the Members that is now required, Oglethorpe
would be required to obtain the approval of Members representing 75% of the
patronage capital of Oglethorpe. Certain resource modifications that now must be
approved by 75% of Oglethorpe's Directors and 75% of the Members could be made
by Oglethorpe if approved by more than 50% of the Members. The Proposed
Wholesale Power Contracts would no longer address Oglethorpe's obligations with
respect to power supply planning services and operating a capacity and energy
pool. The New Business Model Member Agreement would address these services.
4
New Business Model Member Agreement. The proposed New Business Model Member
Agreement would require Member approval for Oglethorpe to undertake certain
activities but would not limit Oglethorpe's ability to own, manage, control and
operate its resources or perform its functions under the Proposed Wholesale
Power Contracts. No later than March 31, 2005, Oglethorpe would discontinue
operating its capacity and energy pool, providing natural gas hedging for pool
and non-pool participants and providing power supply planning services to
Members electing to receive these services.
Oglethorpe would not provide services unrelated to its resources or its
functions under the Proposed Wholesale Power Contracts if such services would
require it to incur indebtedness, provide a guarantee or make any loan or
investment, unless approved by 75% of Oglethorpe's Board of Directors, 75% of
the Members, and Members representing 75% of the patronage capital of
Oglethorpe. Oglethorpe could provide any other such service to a Member so long
as (1) doing so would not create a conflict of interest with respect to other
Members, (2) such service was being provided to all Members or (3) such service
received the three-part 75% approval described above.
Status of Arrangements
Oglethorpe, Talbot EMC, Chattahoochee EMC, and their respective Members
have approved these arrangements, including the Proposed Wholesale Power
Contracts and the New Business Model Member Agreement. RUS, whose approval of
certain of these arrangements is required, has indicated its satisfaction with
these arrangements but is not expected to deliver its formal approval until the
closing of the first advance under the RUS-guaranteed loans. The closing of the
acquisition of the Talbot EMC and Chattahoochee EMC generation facilities and
the delivery of the Proposed Wholesale Power Contracts and the New Business
Model Member Agreement would take place at that time. The development and
execution of final documentation for the RUS-guaranteed loans, and the
satisfaction of all loan conditions, is currently expected to occur in April
2003, but could take place later.
While Oglethorpe currently expects that the Talbot EMC and Chattahoochee
EMC generation facilities will be acquired by Oglethorpe and financed by RUS,
Oglethorpe cannot state with certainty that RUS loan conditions can be
satisfied. If for any reason these new arrangements are not implemented,
Oglethorpe would continue to own, operate, manage and control its existing
resources, including generating facilities and purchased power resources.
Oglethorpe would not acquire the Talbot EMC and Chattahoochee EMC generation
facilities, but would continue to manage those facilities under existing
management contracts. (See "Relationships with Smarr EMC, Talbot EMC and
Chattahoochee EMC".)
Relationships with Smarr EMC, Talbot EMC and Chattahoochee EMC
Smarr EMC, Talbot EMC and Chattahoochee EMC are Georgia electric membership
corporations owned by 37, 30 and 28 of Oglethorpe's 39 Members, respectively.
Smarr EMC owns two combustion turbine facilities with aggregate capacity of 709
MW. Talbot EMC owns a combustion turbine facility designed to provide 618 MW of
capacity. Chattahoochee EMC owns a combined cycle facility designed to provide
468 MW of capacity. Oglethorpe provides construction, operations, financial and
management services for Smarr EMC, Talbot EMC and Chattahoochee EMC. (See "THE
MEMBERS AND THEIR POWER SUPPLY Resources--Member Power Supply Resources")
Oglethorpe is providing interim loans to Talbot EMC and Chattahoochee EMC
to finance approximately fifty percent of the cost of the construction of their
generating facilities. Oglethorpe is guaranteeing an interim financing
5
arrangement between Chattahoochee EMC and a financial institution providing up
to fifty percent of the cost of Chattahoochee EMC's generating facility.
Oglethorpe expects to acquire the generating facilities now owned by Talbot EMC
and Chattahoochee EMC in the second quarter of 2003. (See "Expected Facilities
Acquisitions, RUS Loans And Other New Arrangements" and "MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Financial
Condition--Capital Requirements--Financing for Talbot EMC and Chattahoochee EMC"
in Item 7.)
Relationship with GTC
Oglethorpe and the 39 Members are members of GTC.Georgia Transmission
Corporation (An Electric Membership Corporation) ("GTC"), which was formed in
1997 to own and operate the transmission business previously owned by
Oglethorpe. 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.Georgia System Operations
Corporation ("GSOC"), which was formed in 1997 to own and operate the system
operations business previously owned by Oglethorpe. GSOC operates the system
control center and currently provides system operations services and
administrative support services to Oglethorpe and to GTC. Oglethorpe has also
contracted with GSOC to operate anOglethorpe's electric capacity and energy pool
for scheduling and dispatching Oglethorpeto schedule and Memberdispatch Oglethorpe's resources. (See "OGLETHORPE'S POWER
SUPPLY RESOURCES--Capacity and Energy Pool"). Since January 1, 2000, GSOC has been providingprovides support services to
Oglethorpe in the areas of accounting, auditing, communications, human
resources, facility management, telecommunications and information technology at
cost-based rates.
4
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.
RelationshipAs Oglethorpe has worked with Smarr EMC
In providing joint planningGSOC in the implementation of resource
scheduling elections by Members, a need to consider changes in the relationships
among Oglethorpe, GSOC 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.Members has been recognized. GSOC, Oglethorpe and
the Members determined that such facilities should be
owned,are beginning a process of evaluating how GSOC implements the
operations necessary to permit Members to schedule energy from Oglethorpe's
resources. This evaluation could result in changes in the Operation Services
Agreement between Oglethorpe and GSOC, as well as changes in the contractual
relationships among GSOC and the Members. It would not, by Oglethorpe, but by a separate Member-owned entity. Accordingly,
Smarr EMC was formed as a Georgia electric membership corporation in 1998 and is
now owned by 37however, change the
terms of Oglethorpe's 39Wholesale Power Contracts with the Members. Oglethorpe is providing operation
and financial management services for Smarr Energy Facility and Sewell Creek
Energy Facility, the gas-fired combustion turbine projects currently owned by
Smarr EMC.
Relationship with GPC
Oglethorpe's relationship with GPC is a significant factor in several
aspects of Oglethorpe's business. All of Oglethorpe's co-owned generating
facilities, except Rocky Mountain, are operated by GPC on behalf of itself as a
co-owner and as agent for the other co-owners. GPC and Oglethorpe, through the
Members, are competitors in the State of Georgia for electric service to new
customers that have a choice of supplier under the Georgia Territorial Electric
Service Act, which was enacted in 1973 (the "Territorial Act"). GPC is also one
of Oglethorpe's suppliers of purchased power. For further information regarding
the relationships and agreements with GPC, see "THE MEMBERS AND THEIR POWER
SUPPLY RESOURCES--Service Area and Competition" and "OGLETHORPE'S POWER SUPPLY
RESOURCES--Power Purchase and Sale Arrangements--Power Purchases from GPC." Also
see "PROPERTIES--Fuel Supply," "--Co-Owners of the Plants--Georgia Power
Company" and "--The Plant Agreements" in Item 2.
Relationship with RUS
Historically, federal loan programs administered by RUS have provided the
principal source of financing for electric cooperatives. Loans guaranteed by RUS
and made by the Federal Financing Bank ("FFB") have been a major source of
funding for Oglethorpe.
(See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--Financial Condition--Capital Requirements"
and "--Liquidity and Sources of Capital" in Item 7.)6
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.
5
Oglethorpe has submitted loan applicationsobtained commitments for RUS-guaranteed loans to RUS to provide permanent
financing for six new combustion turbines and a combined cycle facility being
constructed to meet future requirementsfinance the
acquisition of the Members. Thegeneration facilities may
ultimately benow owned by Talbot EMC and
Chattahoochee EMC. (See "Expected Facilities Acquisitions, RUS Loans And Other
New Arrangements" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--Financial Condition--Capital Requirements--
Financing for Talbot EMC and Chattahoochee EMC" in Item 7.)
Relationship with GPC
Oglethorpe's relationship with GPC is a subsidiarysignificant factor in several
aspects of Oglethorpe,Oglethorpe's business. All of Oglethorpe's co-owned generating
facilities, except Rocky Mountain, are operated by Smarr EMC or by a similar
separate entity. The loan applications were madeGPC 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 entitynew customer that may ultimately own these facilities. (See "OGLETHORPE'S POWER SUPPLY
RESOURCES--Future Power Resources"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--FutureRESOURCES--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 Resources.")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 hassales have 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.
67
OGLETHORPE'S POWER SUPPLY RESOURCES
General
Oglethorpe supplies capacity and energy to the Members from a combination
of owned and leased generating plants and from power purchased under long-term contracts with other power suppliers and power marketers.contracts.
Oglethorpe has also entered into power supplyhas 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 thirteenseventeen generating units consist of 30% undivided interests
in the Edwin I. Hatch Plant ("Plant Hatch"), the Alvin W. Vogtle Plant ("Plant
Vogtle") and the Hal B. Wansley Plant ("Plant Wansley"), a 60% undivided
interest in the Robert W. Scherer Unit No. 1 ("Scherer Unit No. 1"), a 60%
undivided interest inand the
Robert W. Scherer Unit No. 2 ("Scherer Unit No. 2"), a 100% interest in the Tallassee Project at the Walter W. Harrison Dam
("Tallassee") and a 74.61% undivided interest
in Rocky Mountain.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. ParticipantsPlant Doyle consists of five gas-fired combustion
turbine units with an aggregate nominal contract capacity of 325 MW. In 2002,
Oglethorpe decided to discontinue operations at the Tallassee Project, a 2.1 MW
conventional hydroelectric facility ("Tallassee"). Oglethorpe expects to acquire
the generation facilities of Talbot EMC and Chattahoochee EMC in the second
quarter of 2003.
MEAG, Dalton and GPC also have interests in Plants Hatch, Vogtle and
Wansley and Scherer Units No. 1 and No. 2 also include MEAG, Dalton and GPC.2. GPC serves as operating agent for
these units. GPC is also a participanthas 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 toare benefiting 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. 7
After taking into account the
Oglethorpe resources made available to LEM and Morgan Stanley for their use,
Oglethorpe estimates that about 30% of its power supply capability in 2003 will
be provided by these contracts.
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.,
8
which is a diversified energy services company headquartered in Louisville,
Kentucky. In December 2000, LG&E Energy Corp. completed a merger with Powergen
plc, a British public limited company, under which LG&E Energy Corp. becameis now an indirect wholly owned subsidiary of
Powergen plc.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 has2011, but pursuant to its
rights under 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
rightgiven notice to terminate the agreement as
of December 31, 2004 or any December 31
after that. In February 2001, LEM initiated the contractually defined
arbitration process to resolve a number of issues relating to the administration
of the LEM agreement. (See "LEGAL PROCEEDINGS" in Item 3.)2004.
Morgan Stanley Agreement
Effective May 1, 1997, Oglethorpe entered into a power marketer agreement
with Morgan Stanley with respect to 50% of the Members' then forecasted load
requirements. The agreement obligates Oglethorpe to purchase fixed quantities of
energy at fixed prices. Each Member selected a term for its obligation, as well
as the portion of its then forecasted requirements to be purchased as a fixed
quantity. Oglethorpe is obligated to sell and Morgan Stanley is obligated to buy
50% of the output, in contractually fixed amounts, of each Member's percentage
capacity responsibility share (for the term and portion selected) of the "must
run" units (primarily nuclear units). Oglethorpe is also obligated to make
available the same share of most of Oglethorpe's other resources, in
contractually fixed amounts, which Morgan Stanley may schedule for each 24-hour
day. This schedule is set the day prior based on availability limitations in the
contract. Morgan Stanley pays a contractually fixed amount each month and an
amount for the scheduled energy based on contractually fixed prices. The
agreement has a term extending to March 31, 2005, but the purchases for certain
Members decline to zero prior to that date.
Oglethorpe manages the portion of the system resources covered by the
Morgan Stanley agreement on behalf of the
"pool" participants in its electricity capacity
and energy pool through scheduling and dispatching such resources. Oglethorpe
makes purchases and sales on behalf of the "pool"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 Capital Group, Inc. is a subsidiary of Morgan Stanley, Dean Witter, Discover &
Co., a
diversified investment banking and financial services company. Morgan 8
Stanley Dean Witter, Discover & Co. is
subject to the informational requirements of the Securities Exchange Act of
1934, as amended, and, in accordance therewith, files reports and other
information with the Commission.
Power Purchase and Sale Arrangements
Power Purchases
from GPC
Oglethorpe has an agreement with GPC to purchase capacity and associated
energy on a take-or-pay basis. Under this agreement, Oglethorpe purchased
capacityis purchasing
and associated energy from GPC as follows: 750 MW through May 31, 2000,
500 MW from June 1, 2000 to August 31, 2000 and 375 MW from September 1, 2000 to
December 31, 2000. Oglethorpe will continue to purchase 375 MW of capacity and
associated energy under this agreement through August 31, 2001, and will
purchase 250 MW from September 1, 2001 tountil March 31, 2006.
Other Power Purchases
Oglethorpe purchases 100 MW of capacity from each of Entergy Power, Inc.
("Entergy Power") and Big Rivers Electric Corporation ("Big Rivers"), under
agreements extending through June and July 2002, respectively. The availability
of capacity under the Entergy Power contract is dependent on the availability of
two specific generating units available to Entergy Power. The Tennessee Valley
Authority ("TVA") provides the transmission service to deliver the power from
the Big Rivers electric system to the Integrated Transmission System. TVA and
Southern Company Services, as agent for Alabama Power Company and Mississippi
Power Company, provide the transmission service necessary to deliver the power
from Entergy Power to the Integrated Transmission System.
Oglethorpe has a contract through 2019 to purchase approximately 300 MW of
capacity from Hartwell Energy Limited Partnership, a joint venture between
9
Dynegy Inc. and American National Power, Inc., a subsidiary of National Power,
PLC. This capacity is provided by two 150 MW gas-fired combustion turbine
generating units on a site near Hartwell, Georgia. Oglethorpe has the right to
dispatch the units fully.units.
Oglethorpe has an agreement with Doyle I, LLC, a limited liability company
owned by an affiliatealso purchased 100 MW of Enron North America Corp.capacity from each of Entergy Power,
Inc. ("Entergy Power") and one of Oglethorpe's
Members, to purchase the output of a 325 MW gas-fired combustion turbine
generating facility over a 15-year term. Delivery commenced May 15, 2000.
Oglethorpe has the right to dispatch the units fully.Big Rivers Electric Corporation ("Big Rivers"), under
agreements that terminated in June and July 2002, respectively.
See Note 9 of Notes to Financial Statements in Item 8 for a discussion of
Oglethorpe's commitments under these power purchase agreements.
In addition, Oglethorpe also purchases small amounts of capacity and energy
from "qualifying facilities" under the Public Utility Regulatory Policies Act of
1978 ("PURPA"). Under a waiver order from the Federal Energy Regulatory
Commission ("FERC"), Oglethorpe historically made all purchases the Members
would have otherwise been required to make under PURPA and Oglethorpe was
relieved of its obligation to sell certain services to "qualifying facilities"
so long as the Members make those sales. Oglethorpe historically provided the
Members with the necessary services to fulfill these sale obligations. Purchases
by Oglethorpe from such qualifying facilities provided less than 0.1% of
Oglethorpe's energy requirements for the Members in 2000.2002. Under their Wholesale
Power Contracts, the Members may make such purchases instead of Oglethorpe.
Long-Term Power Sales
Oglethorpe has an agreement to sell 100 MW of base capacity to Alabama
Electric Cooperative, Inc. through December 31, 2005. During the term of the
power marketer agreements, LEM and Morgan Stanley will beare responsible for supplying
Oglethorpe with sufficient power to fulfill this power sale.
9
Other Power System Arrangements
Oglethorpe has interchange, transmission and/or short-term capacity and
energy purchase or sale agreements with over 80approximately 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. Oglethorpe engages in these types of transactions for the
benefit of Members that participate in Oglethorpe's capacity and energy pool.
Oglethorpe is currently actively trading with only about half of these
counterparties due to Oglethorpe's risk management policies with respect to
netting provisions and credit levels. The development of and access to the
Integrated Transmission System and the interconnections with other utilities,
through transmission contracts with GTC and others, are key elements in
Oglethorpe's ability to make off-system sales and purchases through its transmission contract with
GTC and to competefor the benefit of
the Members participating in an increasingly competitive market.the pool.
Future Power Resources
Although the existing long-term power marketer arrangements with LEM and
Morgan Stanley were designed to provide substantially all of the Members'
requirements during their contract terms, in fact the Members' requirements have
exceeded the amounts provided by these arrangements. Oglethorpe expects that the
Members' requirements will continue to exceed contracted purchases over the next
several years. The Members also have significant additional requirements beyond
the term of the power marketer arrangements.Supply
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.
SomeThirty-eight Members are currentlyhave elected not participating in joint planning and resource management services.to receive these services for 2003.
Oglethorpe is in the process of arranging the necessary power supply for
Members that currently participate in jointproviding certain basic planning and resource management
services. In this regard, Oglethorpe has entered into agreements to acquire and
construct six gas-fired combustion turbines designed to provide 618 MW of
capacity andservices under a gas-fired combined cycle facility designed to provide 468 MW of
capacity. Four of the combustion turbines are scheduled for completion in 2002,separate
contract with the other two to be completed in 2003. The combined cycle facility is
scheduled for completion in 2003. Oglethorpe also has an agreement to purchase
equipment for a possible 2005 gas-fired combined cycle project. Members have
subscribed for all of the capacity and energy from these facilities except for
the capacity and associated energy of a 2003 combustion turbine and the capacity
and energy of the possible 2005 combined cycle project. Oglethorpe is evaluating
options with respect to the unsubscribed portions, which include seeking
additional subscriptions from Members, contracting to sell some of the output of
the facilities to non-Members, or selling the equipment.
Althoughremaining Member. Oglethorpe plans forto discontinue providing
these services at a future date. (See "OGLETHORPE POWER CORPORATION--Expected
Facilities Acquisitions, RUS Loans and procures power supply resources for
electing Members, Oglethorpe will not necessarily own these resources. For a
number of reasons, these facilities may be owned by a subsidiary of Oglethorpe,
by Smarr EMC or by a similar separate entity owned by those Members who
participate in the facilities. Oglethorpe has submitted loan applications to RUS
for FFB loans to permanently finance the 2002Other New Arrangements" and 2003 combustion turbine
facilities and the 2003 combined cycle facility. The loan applications were made
on behalf of any entity that may ultimately own these facilities. Oglethorpe
expects RUS to act on these loan applications later in 2001. See "THE MEMBERS
AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources" and "--Future
Power Resources" for a discussion of capacity purchased by the Members from
sources other than Oglethorpe. See also "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF Operations--Financial Condition--Capital
Requirements" in Item 7.
Oglethorpe is also investigating other power supply options to meet the
remainder of the projected requirements of those Members for which it is
currently providing joint planning and resource management services. Based on
the current load forecasts of these Members, the projected additional
requirements could be as much as 1300 MW in 2005, with increases thereafter.
Because Members can elect whether or not to receive these services from
10
Oglethorpe on an annual basis, the projections may change significantly if
Members change their elections in future years. Current load forecasts for the
Members may not accurately predict the Members' actual load in the future, due
to changes in growth in the Members' service territories and the competitive
environment in the electric utility industry, among other reasons.
Oglethorpe's current power procurement efforts for these projected
requirements include initial discussions with a number of entities regarding
contractual power supply arrangements. These arrangements could take a form
similar to Oglethorpe's existing power marketer arrangements or a form more like
traditional power purchase arrangements. Oglethorpe may also evaluate other
alternatives for meeting future power supply requirements. (See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Miscellaneous--Competition" in Item 7).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, for scheduling and dispatching Oglethorpe and Member
resources.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
separately10
to schedule and dispatchpseudo-dispatch separately the capacity represented by the
Member's percentage capacity responsibility under the Wholesale Power Contract.Contracts.
The Members may also elect to include all or part of their other resources in
the pool. Some Members have electedOglethorpe plans to be self-scheduling Members. Seediscontinue providing these services at a future
date. (See "OGLETHORPE POWER CORPORATION--Expected Facilities Acquisitions, RUS
Loans And Other New Arrangements" and "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 is a member of ACES Power Marketing, which acts as
Oglethorpe's agent to perform these services pursuant to a service agreement.
(See "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK--Commodity
Price Risk--Risk Management.") Oglethorpe has contracted with GSOC to operate
the pool. Oglethorpe and
GSOC maintain, and in conjunction with the Members are currently refining,
policies and procedures relating to the pool and self-scheduling Members.
11
THE MEMBERS AND THEIR POWER SUPPLY RESOURCES
Member Demand and Energy Requirements
The Members are listed below and include 39 of the 42 electric distribution
cooperatives in the State of Georgia.
Altamaha EMC Habersham EMC Planters EMC
Amicalola EMC Hart EMC Rayle EMC
Canoochee EMC Irwin EMC Satilla Rural EMC
Carroll EMC Jackson EMC Sawnee EMC
Central Georgia EMC Jefferson Energy Cooperative, an EMC Slash Pine EMC
Coastal EMC Lamar EMC Snapping Shoals EMC
Cobb EMC Little Ocmulgee EMC Sumter EMC
Colquitt EMC Middle Georgia EMC Three Notch EMC
Coweta-Fayette EMC Mitchell EMC Tri-County EMC
Excelsior EMC Ocmulgee EMC Troup EMC
Flint EMC Oconee EMC Upson County
Altamaha EMC GreyStone Power Corporation, an EMC Pataula EMC
Amicalola EMC Habersham EMC Planters EMC
Canoochee EMC Hart EMC Rayle EMC
Carroll EMC Irwin EMC Satilla Rural EMC
Central Georgia EMC Jackson EMC Sawnee EMC
Coastal EMC d/b/a Coastal Electric Cooperative Jefferson Energy Cooperative, an EMC Slash Pine EMC
Cobb EMC Lamar EMC Snapping Shoals EMC
Colquitt EMC Little Ocmulgee EMC Sumter EMC
Coweta-Fayette EMC Middle Georgia EMC Three Notch EMC
Diverse Power, Incorporated, an EMC (f/k/a Mitchell EMC Tri-County EMC
Troup EMC)
Excelsior EMC Ocmulgee EMC Upson EMC
Flint EMC d/b/a Flint Energies Oconee EMC Walton EMC
Grady EMC Okefenoke Rural EMC Walton EMC
GreyStone Power Pataula EMC Washington EMC
Corporation, an EMC
The Members serve approximately 1.41.5 million electric consumers (meters)
representing approximately 3.43.7 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 20002002 amounted to approximately 2730 million MWh, with
approximately 66% to residential consumers, 31%32% to commercial and industrial
consumers and 3%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 19982000 through 20002002 of 5%4% in number of
consumers, 7%5% in MWh sales and 5%6% in electric revenues.
The following table shows the aggregate peak demand and energy requirements
of the Members for the years 19982000 through 2000,2002, and also shows the amounts of
energy requirements supplied by Oglethorpe. From 19982000 through 2000,2002, demand and
energy requirements of the Members increased at an average annual compound
growth rate of 7.3%3% and 7.4%5%, respectively.
Member Member Energy
Demand (MW) Requirements (MWh)
----------- -------------------------------------------
Total(1) Total(2) Supplied by Oglethorpe(3)
-------- -------- -------------------------
2000............. 6,703 28,221,306 27,232,641
2001............. 6,532 28,332,257 26,950,149
2002............. 7,153 31,271,101 27,924,856
- ----------
(1) System peak hour 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 Member Energy
Demand (MW) Requirements (MWh)
----------------------------------------------------------------
Total(1) Total(2) Supplied by
------- ------- Oglethorpe(3)
------------
1998 5,816 24,494,807 23,315,950
1999 6,452 25,760,322 24,755,812
2000 6,703 28,210,327 27,232,641
(1) System peak demand of the Members measured at the Members' delivery points
(net of system losses), adjusted to include Members' resources behind the
delivery points.
(2) Retail requirements served by Members' resources, adjusted to
include 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.")
12
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"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
13
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 (1) after any such
distribution, the Member's total equity will equal at least 40% (30%30% (40% in the case
of Members that have the newolder form of RUS loan documents, discussed below)documents) of its total assets,
except thator (2) distributions may be made of up todo not exceed 25% of the margins and patronage capital
received by the Member in the preceding year (provided
thatand equity is at least 20% in the case of(the 20%
13
equity requirement does not apply to Members that have the newolder 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--WholesaleCorporation--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 maintainand an
Operating Times Interest Earned Ratio and an Operating Debt Service Coverage
Ratio of not less than 1.10, in each case for the two highest out of every three
successive years. Members that have the older form of RUS loan documents are not
required to maintain the Operating ratios.
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, TroupDiverse Power,
Incorporated, an EMC ("Diverse Power") 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
14
municipal bonds with comparable maturities. Certain borrowers with either low
consumer density or higher-than-average rates and lower-than-average consumer
income are eligible for special loans at 5%. Distribution borrowers are also
eligible for loans made by FFB or other lenders and guaranteed by RUS.
Oglethorpe cannot predict the future cost, availability and amount of RUS direct
and guaranteed loans whichthat 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.
14
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 2000,2002, the
aggregate SEPA allocation to the Members was 543564 MW plus associated energy. An
additional aggregate of 54 MW is available to the Members pending arrangement of
firm transmission service. Each Member must schedule its energy allocation, and
each Member has designated Oglethorpe to perform this function. Pursuant to a
separate agreement, Oglethorpe will schedule, through GSOC, the Members' SEPA
power deliveries. Further, each Member may be required, if certain conditions
are met, to contribute funds for capital improvements for Corps of Engineers
projects from which its allocation is derived in order to retain the allocation.
Smarr EMC
The Members participating in the facilities owned by Smarr EMC purchase the
output of those facilities pursuant to long-term, take-or-pay power purchase
agreements. Smarr EMC owns Smarr Energy Facility, a two-unit, 217 MW gas-fired
combustion turbine facility (with 36 participating Members), and Sewell Creek
Energy Facility, a four-unit, 492 MW gas-fired combustion turbine facility (with
31 participating Members). Smarr Energy Facility began commercial operation in
June 1999, and Sewell Creek Energy Facility began commercial operation in June
2000.
Other Member Resources
TwoTalbot EMC and Chattahoochee EMC
Thirty of Oglethorpe's Members formed an entity that has constructed and continuesTalbot EMC, a Georgia electric
membership corporation, in 2001 to construct and own a six-unit gas-fired
combustion turbine capacity. Oglethorpe anticipates that these two
Members will use a portion of this capacity to serve some or all of their load
growth.
15
In addition, a number of Members have installed and may continue to install
small diesel generators and gas-fired microturbines on their distribution
systems.
Future Power Resources
Oglethorpe has entered into agreements on behalf of participating Members
to acquire and construct six gas-fired combustion turbinesfacility designed to provide 618 MW of capacitycapacity. Four of the
combustion turbines have been operating since June 2002, and the other two units
are expected to be operational by June 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 pay all costs of constructing, owning and
operating the facility and are 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. Four of the combustion turbines are targeted for completion
in 2002, with the other two to be completed in 2003. The combined
cycle facility is targeted for completionbecame operational in February 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 pay all costs of constructing,
owning and operating the facility and are entitled to the output of the
facility.
15
For information regarding services and financial support that Oglethorpe
has an agreementprovides to purchase
equipment for a possible 2005 gas-fired combined cycle project. AlthoughTalbot EMC and Chattahoochee EMC and the expected acquisition of
their generation facilities by Oglethorpe, plans for and procures generating resources for electing Members,
these generating resources may not necessarily be owned by Oglethorpe. For a
number of reasons, the facilities may be owned by a subsidiary of Oglethorpe, bysee "OGLETHORPE POWER
CORPORATION--Expected Facilities Acquisitions, RUS Loans And Other New
Arrangements", "--Relationships with Smarr EMC, or by a similar separate entity owned by those Members who participateTalbot EMC and Chattahoochee
EMC" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS--Financial Condition--Capital Requirements--Financing for
Talbot EMC and Chattahoochee EMC " in the facilities. For information on financing for these facilities, see
"OGLETHORPE'S POWER SUPPLY RESOURCES--Future Power Resources.")
SeveralItem 7.
GPC Block Purchase
Thirty Members have entered into long-term power supply contracts with aGPC,
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.
Other Member Resources
Members not participating in Oglethorpe's capacity and energy pool obtain
their power supply requirements above their Oglethorpe purchase obligations from
other sources. A number of Members have entered into contracts with third
partyparties for all of their future incremental power requirements. Other Members,
may do soincluding participants in the future.pool, have developed their own generation
facilities or have other power purchase contracts.
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.
Member Memorandum of Understanding
One of Oglethorpe's Members, Cobb EMC, has provided Oglethorpe a copy of a
Memorandum of Understanding between it and another of Oglethorpe's Members,
Diverse Power entered into in September 2002. The Memorandum of Understanding
calls for the two Members to use their best efforts to enter into definitive
agreements for a proposed transaction in which Cobb EMC would assume Diverse
Power's rights and obligations under its Wholesale Power Contract with
Oglethorpe beginning April 1, 2005. In consideration, Diverse Power would assume
Cobb EMC's rights and obligations regarding allocations of hydroelectric power
from the Southeastern Power Administration on the same date. See "Member Power
Supply Resources - Contracts with SEPA". Among other elements of the proposed
transaction, Diverse Power has a stated objective of being relieved of all
liability under its Wholesale Power Contract with Oglethorpe.
Neither of the Members has asked Oglethorpe to take any action with respect
to the Memorandum of Understanding. Oglethorpe has existing provisions for a
Member to withdraw and to assign its rights and obligations under its Wholesale
Power Contract with Oglethorpe to another person. These provisions require the
assignee to have certain published credit ratings and to assume all of the
withdrawing Member's obligations under its Wholesale Power Contract with
Oglethorpe. Any such assignment must be approved by Oglethorpe's Board of
Directors and RUS. Diverse Power has not asked to withdraw from Oglethorpe in
accordance with these procedures.
In 2002, Diverse Power represented approximately 1.4 %, and Cobb EMC
represented approximately 11.3 %, of Oglethorpe's revenues from Members.
Oglethorpe cannot predict whether Diverse Power will request to withdraw or
whether the two Members will request that Oglethorpe take any action with
respect to the transaction as proposed in the Memorandum of Understanding.
16
FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY
General
The electric utility industry has been and in the future will continue to
be affected by a number of factors whichthat 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 difficulties in the development of efficient 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 and electricity market design,
o uncertaincredit quality of utilities and power marketers,
o tightening of access to low costfinancing for capital forexpenditures and 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.energy, and
o the threat of terrorist attacks on electric generation facilities and
corresponding increases in security and insurance costs.
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"OPERATIONS--Miscellaneous --Competition" in Item 7.)
Environmental and Other Regulation
General
As is typical for electric utilities, Oglethorpe is subject to various
federal, state and local air and water quality requirements which, among other
things, regulate emissions of pollutants, such as particulate matter, sulfur
dioxide and nitrogen oxides into the air and discharges of other pollutants,
including heat, into waters of the United States. Oglethorpe is also subject to
federal, state and local waste disposal requirements that regulate the manner of
transportation, storage and disposal of various types of waste.
17
In general, environmental requirements are becoming increasingly stringent.
New requirements may substantially increase the cost of electric service, by
requiring changes in the design or operation of existing facilities or changes
or delays in the location, design, construction or operation of new facilities.
Failure to comply with these requirements could result in the imposition of
civil and criminal penalties as well as the complete shutdown of individual
generating units not in compliance. There is noOglethorpe cannot provide assurance that Oglethorpe's
units will always remain subject to the regulations currently in effect orit
will always be in compliance with current and future regulations.
17
Compliance with environmental standards will continue to be reflected in
Oglethorpe's capital expenditures and operating costs. Oglethorpe made
environmental-related capital expenditures of approximately $3$40 million in 2000,2002
and expects to spend $28$53 million in 20012003 and $66$2 million in 20022004 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 are included
in stringent nitrogen oxides emissions averaging plans, requiring the co-owners
of the plants to install new control equipment at both plants no later than May
2003. Installation of control equipment to comply with these requirements is on
schedule. 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 most significant of theseactions that appear to be the following.
First, because nitrogen oxidesmost significant are
considered to be a precursor to ozone,
coupled with the fact that metropolitan Atlanta is classified as a "serious
nonattainment area" under the one hour ozone National Ambient Air Quality
Standards ("NAAQS"), EPA and the State of Georgia have imposed further limits on
such emissions. Recently, both Plants Wansley and Scherer were made subject to
stringent nitrogen oxides averaging plans, which will cause the co-owners of the
plants to install new control equipment at both plants no later than May 2003.
Oglethorpe expects to incur significant capital expenditures over the next three
years to install this equipment.
Second,described below.
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 U.S. Supreme Court reversed a successful challenge of these
revised NAAQS, and remanded the case back to theNAAQS. The Court of Appeals denied further petitions for further
disposition. This decision may result in tighteningreview, leaving
EPA to proceed with implementation of the standards for both 18
ozone and particulate matter. Other challenges to both NAAQS are still pending
at the Court of Appeals level. In addition, withNAAQS. With respect to the ozone
NAAQS, EPA must harmonize provisions in the Clean Air Act imposing the old ozone
NAAQS with its proposed standard before the new standard can be implemented. Third,In
conjunction with these NAAQS, EPA plans to designate areas as attainment or
nonattainment with these standards in 2004, based on air quality data collected
for 2001 through 2003. Some areas that will be designated as nonattainment for
either ozone or particulate matter may require further reductions on nitrogen
oxides, sulfur dioxide, or both from Plants Wansley and/or Scherer. The impact
of any new designations will depend on the development and implementation of
18
applicable regulations and cannot be determined at this time.
In 1998, EPA issued a regulation calling for regional reductions in
nitrogen oxides emissions from 22 states, including Georgia, which imposes a
fixed cap on nitrogen oxides emissions from such states beginning in the year
2004.2005. States remain free to choose the sources on which to impose reductions
needed to stay below the cap. The Georgia Environmental Protection Division has
indicated that if Georgia must adhere to the regulation, it will require large
fossil fuel-fired units, including those at Plants Wansley and Scherer, to
participate in achieving the required reductions. On appeal, EPA's regulation
was upheld in part, with that portion of the rule that would have applied to
Georgia sent back to EPA for further consideration. EPA recently indicated its
intention to finalize shortlyhas proposed a rule
reinstating the cap for Georgia. AsGeorgia, which would delay implementation until 2005. In
a result,related rulemaking, EPA issued a final rule that concluded that the growth
rates used to compute the cap for Georgia and other states were reasonable. That
second rule has been challenged by various parties in the Court of Appeals,
seeking to have it remanded back to EPA for further consideration. This
challenge may delay Georgia's implementation date. Georgia's implementation plan
for this regulation will depend on how this new rulemaking.proposed rulemaking is finalized and
how the current litigation is resolved. Therefore, it is not yet known what
additional controls, if any, would be needed at Plants Wansley and/or Scherer to
comply with this regional nitrogen oxides reduction program. Fourth,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.
EPA has also announced its intention to propose a regional transport
regulation for particulate matter by the end of 2003, and to finalize the
regulation by 2005. This rule would likely require year round reductions in
emissions of sulfur dioxide and nitrogen oxide from power plants, perhaps as
early as 2010. The rule could affect Georgia's plans for attaining the NAAQS for
ozone and particulate matter discussed above, which in turn could lead to
further controls on Plants Wansley and/or Scherer.
In 1999, EPA promulgated a new regional haze rule, which affectswould have
affected 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 challengedAs a result of challenges to this rule, however, the
Court of Appeals has vacated part of the rule, and some have
also petitionedremanding it back to EPA for
further consideration consistent with its opinion. Until further rulemaking in
response to reconsider the rule. Until such litigationthis decision is resolved,conducted, Oglethorpe will not know what controls,
if any, must be installed at Plants Wansley and/or Scherer to comply with this
rule.
Fifth, althoughAlthough 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, severalSeveral studies required by the Clean Air Act examined the health effects
of power plant emissions of certain hazardous air pollutants. In late 2000, EPA
concluded that mercury emissions from coal and oil-fired electric utility steam
generating units should be regulated. Emissions of other hazardous air
pollutants, such as nickel and cadmium, may also become regulated. EPA expects
to follow a rulemaking schedule that would require compliance by 2007-2008.
Depending on the outcome of such rulemaking, significant capital expenditures
might be incurred at Plants Wansley and/or Scherer.
On November 3, 1999, the United States Justice Department, on behalf of
EPA, filed lawsuits against GPC and some of its affiliates, as well as other
utilities. The lawsuits allege violations of the new source review provisions
and the new source performance standards of the Clean Air Act at, among other
facilities, Plant Scherer Unit Nos. 3 and 4. Oglethorpe is not currently named in the
lawsuits and Oglethorpe does not have an ownership interest in the named units
of Plant Scherer. However, Oglethorpe can give no assurance that units in which
Oglethorpe has an ownership interest will not be named inaffected by this or a related
lawsuit in the future. The resolution of this matter is highly uncertain at this
19
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.
On December 30, 2002, the Sierra Club, Physicians for Social
Responsibility, Georgia Forest Watch and one individual filed suit in Federal
Court in Georgia against GPC, alleging violations of the Clean Air Act at Plant
Wansley. The complaint alleges violations of opacity limits at both the coal
fired units, in which Oglethorpe is a co-owner, and other violations at several
of the combined cycle units where neither Oglethorpe nor Chattahoochee EMC has
an ownership interest. This civil action requests injunctive and declaratory
relief, civil penalties, a supplemental environmental project and attorneys'
fees. While Oglethorpe believes that Plant Wansley has complied with applicable
laws and regulations, resolution of this matter is uncertain at this time, as is
any responsibility of Oglethorpe for a share of any penalties or other costs
that might be assessed against GPC.
On January 16, 2003, the Sierra Club appealed an unsuccessful challenge to
an air operating permit for the combined cycle facility owned by Chattahoochee
EMC to the United States Court of Appeals for the Eleventh Circuit. Oglethorpe
expects to acquire this facility in the second quarter of 2003. See "OGLETHORPE
POWER CORPORATION--Expected Facilities Acquisitions, RUS Loans and Other New
Arrangements." Oglethorpe has intervened in the appeal. The petitioner seeks to
have the air permit invalidated and remanded back to EPA and the Georgia
Environmental Protection Division ("EPD"). Although Oglethorpe believes that a
favorable outcome in this appeal is likely, an unfavorable ruling could
temporarily affect the ability of the facility to continue to operate.
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--PowerResources--Power Marketer Arrangements.") Because of the
uncertainty associated with these various developments, Oglethorpe cannot now
predict the effect that any of these potential requirements may have on the
operations of Plants Wansley and Scherer.
19
Compliance with the requirements of the Clean Air Act may also require
increased capital or operating expenses on the part of GPC. Any increases in
GPC's capital or operating expenses may cause an increase in the cost of power
purchased from GPC. (See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--Power
Purchase and Sale Arrangements--Power Purchases from GPC.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 20142034 and 20182038 and 2027 and 2029, respectively. On February 29, 2000, Southern Nuclear Operating Company ("SONOPCO"), the
operator ofThe licenses for Plant
Hatch filed an application with the NRCwere extended to extend the
operating licenses for each unit of Plant Hatch, until 2034 and 2038,
respectively. The NRC has published a timetable that indicates a decision will
be made by the end of Marchtheir current expiration dates in January 2002.
Pursuant to the Nuclear Waste Policy Act of 1982, as amended, the Federalfederal
government has the regulatory responsibility for the final disposition of
commercially produced high-level radioactive waste materials, including spent
20
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 fuelspent-fuel wet storage
capacity.
Effective June 2000,capacity and Plant Hatch has an on-site dry storage facility for Plant Hatch became
operational.facility. Based on normal
operations and retention of all spent fuel in the reactor, sufficient capacity
is believed to be available to continue dry storage operations at Plant Hatch
for the currently anticipated life of the plant, andplant. Plant VogtleVogtle's spent fuel pool
storage is expected to be sufficient intountil 2014. In addition, SONOPCO, as agent
forOglethorpe expects that
procurement of on-site dry storage capacity at Plant Vogtle will commence in
sufficient time to maintain full-core discharge capability to the co-owners of the plant, is a member of Private Fuel Storage, LLC, a
joint utility effort to develop a private spent fuel
storage facility for
temporary storage of spent nuclear fuel. This facility is planned to begin
operation as early as the year 2003.pool. (See Note 1 of Notes to Financial Statements in Item 8.)
For information concerning nuclear insurance, see Note 8 of Notes to
Financial Statements in Item 8. For information regarding NRC's regulation
relating to decommissioning of nuclear facilities and regarding DOE's
assessments pursuant to the Energy Policy Act for decontamination and
decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to
Financial Statements in Item 8.
20
Other Environmental Regulation
In 1993, EPA issued a ruling confirming the non-hazardous status of coal
ash. That ruling may apply, however, only to situations where those wastes are
not co-managed, i.e., not mixed with other wastes. Pursuant to court order, EPA
had until the Spring of 1999 to classify co-managed utility wastes as either
hazardous or non-hazardous. Recently, EPA decidedhas now indicated that although these wastescoal ash should be considered
non-hazardous, national regulations wereare 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.
Under the Clean Water Act, EPA is developing new rules intended to reduce
the impingement and entrainment of fish and fish larvae at cooling water intake
structures. As proposed, those rules will require numerous biological studies
and perhaps retrofits to some intake structures at existing power plants,
including Plants Wansley and Scherer. The new rule was proposed in February 2002
and is scheduled to be finalized in 2004. The impact of any new standards will
depend on the development and implementation of such rules.
Also under the Clean Water Act, EPA and state environmental agencies are
developing total maximum daily loads (TMDLs) for certain impaired state waters.
The establishment of TMDLs and/or additional measures to control non-point
source pollution may result in a tightening of limits in water discharge permits
for power plants, including Plants Wansley and Scherer. As the impact will
depend on the actual TMDLs and the corresponding permit limitations that are
established, the effects of such developments cannot be predicted at this time.
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
21
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. 21Oglethorpe,
or generating facilities in which Oglethorpe has an interest, are also subject,
from time to time, to claims relating to emissions of pollutants, including
actions by citizens to enforce environmental regulations and claims for personal
injury due to emissions from the facilities. Oglethorpe cannot predict the
outcome of current or future actions, the responsibility of Oglethorpe for a
share of any damages awarded or any impact on facility operations. Oglethorpe,
however, does not believe that the current actions will have a material adverse
effect on the financial position or results of operations of Oglethorpe.
22
ITEM 2. PROPERTIES
Generating Facilities
The following table sets forth certain information with respect to
theOglethorpe's generating facilities, in which Oglethorpe currently has ownership or leasehold
interests, all of which are in commercial operation.
Oglethorpe's
Share of
NamePlate Commercial License
Type of Percentage Capacity Operation Expiration
Facilities Fuel Interest (MW) Date Date
- ----------------------------------------------------------------------------------------------------------------
---------- ---- -------- ---- ---- ----
Plant Hatch (near Baxley, Ga.)
Unit No. 1........................1.......................... Nuclear 30 243.0 1975 2014(1)2034
Unit No. 2........................2.......................... Nuclear 30 246.0 1979 2018(1)2038
Plant Vogtle (near Waynesboro, Ga.)
Unit No. 1........................1.......................... Nuclear 30 348.0 1987 2027
Unit No. 2........................2.......................... Nuclear 30 348.0 1989 2029
Plant Wansley (near Carrollton, Ga.)
Unit No. 1........................1.......................... Coal 30 259.5 1976 N/A(2)A(1)
Unit No. 2........................2.......................... Coal 30 259.5 1978 N/A(2)A(1)
Combustion Turbine................Turbine.................. Oil 30 14.8 1980 N/A(2)A(1)
Plant Scherer (near Forsyth, Ga.)
Unit No. 1........................1.......................... Coal 60 490.8 1982 N/A(2)A(1)
Unit No. 2........................2.......................... Coal 60 490.8 1984 N/A(2)
Tallassee (near Athens, Ga.)......... Hydro 100 2.1 1986 2023A(1)
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 3,335.03,657.9
=======
- --------------------------
----------
(1) Southern Nuclear Operating Company, the operator of Plant Hatch, has filed
an application with the NRC to extend the licenses with respect to Plant
Hatch by 20 years. (See "FACTORS AFFECTING THE ELECTRIC UTILITY
INDUSTRY--Environmental and Other Regulation--Nuclear Regulation" in Item
1.)
(2) Coal-firedFossil-fired units and combustion turbines do not operate under operating licenses similar to those
granted to nuclear units by the NRC and to hydroelectric plants by FERC.
(2) Nominal plant capacity identified in the Power Purchase and Sale Agreement
with Doyle I, LLC. See "The Plant Agreements--Doyle".
22Oglethorpe expects to acquire a six-unit, 618 MW gas-fired combustion
turbine facility and a 468 MW gas-fired combined cycle facility in the second
quarter of 2003. See "OGLETHORPE POWER CORPORATION--Expected Facilities
Acquisitions, RUS Loans And Other New Arrangements" in Item 1.
23
Plant Performance
The following table sets forth certain operating performance information of
each of Oglethorpe's generating facilities:
Equivalent
Availability(1) Capacity Factor(2)
--------------- ------------------
Unit 2002 2001 2000 2002 2001 2000
- ---- ---- ---- ---- ---- ---- ----
Plant Hatch
Unit No. 1 87% 99% 84% 88% 99% 85%
Unit No. 2 97 86 89 97 86 90
Plant Vogtle
Unit No. 1 84 99 86 86 101 91
Unit No. 2 82 92 100 84 94 102
Plant Wansley
Unit No. 1 88 83 83 80 78 77
Unit No. 2 79 87 78 74 81 72
Plant Scherer
Unit No. 1 95 81 100 78 58 79
Unit No. 2 83 94 90 66 71 73
Rocky
Mountain(3)
Unit No. 1 99 94 94 15 24 26
Unit No. 2 91 99 91 18 21 20
Unit No. 3 100 95 94 27 17 17
Plant
Doyle(3,4)
Unit No. 1 100 100 100 8 4 2
Unit No. 2 100 100 97 8 5 8
Unit No. 3 100 100 92 7 4 7
Unit No. 4 100 100 100 11 6 9
Unit No. 5 100 100 100 10 6 8
- ----------
(1) Equivalent Availability is a measure of the major generating facilitiespercentage 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 whichlow capacity factors.
(4) 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
currently has
ownership or leasehold interests:
Equivalent Availability(1) Capacity Factor(2)
--------------------------- --------------------------
Unit 2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ---- ----
Plant Hatch
Unit No. 1........... 84% 81% 100% 85% 83% 99%
Unit No. 2........... 89 92 81 90 94 81
Plant Vogtle
Unit No. 1........... 86 92 100 91 94 102
Unit No. 2........... 100 88 82 102 89 82
Plant Wansley
Unit No. 1........... 83 91 86 77 73 56
Unit No. 2........... 78 86 92 72 66 50
Plant Scherer
Unit No. 1........... 100 86 93 79 67 70
Unit No. 2........... 90 95 89 73 79 75
Rocky Mountain(3)
Unit No. 1........... 94 97 90 26 23 24
Unit No. 2........... 91 96 95 20 16 13
Unit No. 3........... 94 91 94 17 19 22
- -----------------------
(1) Equivalent Availability is a measure of the percentage of time that a unit
was available to generate if called upon, adjusted for periods when the
unit is partially derated from the "maximum dependable capacity" rating.
(2) Capacity Factor is a measure of the output of a unit as a percentage of the
maximum output, based on the "maximum dependable capacity" rating, over the
period of measure.
(3) As a pumped storage plant, Rocky Mountain primarily operates as a peaking
plant, which results in a low capacity factor.
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, 2001,2003, there was a
26-day30-day coal supply at Plant Wansley based on nameplate rating.
Low-sulfur "compliance" coal for Scherer Units No. 1 and No. 2 is purchased
under long-term contracts and in spot market transactions. As of February 28,
2001,2003, the coal stockpile at Plant Scherer contained a 50-day33-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
overapproximately 700 rail cars to transport coal to Plants Scherer and Wansley.Wansley and
has plans to acquire approximately 500 additional rail cars in 2003.
The Plant Scherer and Wansley ownership and operating agreements allow each
co-owner (i) to dispatch separately its respective ownership interest in
conjunction with contracting separately for long-term coal purchases procured by
GPC and (ii) to procure separately long-term coal purchases. Oglethorpe
separately dispatches Plant Scherer and Plant Wansley, but continues to use GPC
as its agent for fuel procurement.
23
For information relating to the impact that the Clean Air Act will have on
Oglethorpe, see "FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY--Environmental
and Other Regulations--Clean Air Act" in Item 1.
Nuclear Fuel. GPC, as operating agent, has the responsibility to procure
nuclear fuel for Plants Hatch and Vogtle. GPC has contracted with Southern
Nuclear Operating Company ("SONOPCO"), a subsidiary of The Southern Company
specializing in nuclear services, to operate these plants, including nuclear fuel
procurement. SONOPCO employs both spot purchases and long-term contracts to
satisfy nuclear fuel requirements. The nuclear fuel supply and related services
are expected to be adequate to satisfy current and future nuclear generation
requirements.
24
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 "OGLETHORPE POWER CORPORATION--Expected
Facilities Acquisitions, RUS Loans And Other New Arrangements" in Item 1 and
"QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK--Commodity Price
Risk." in Item 7A
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 4748 cities and one county in the State of
Georgia. Such political subdivisions, located in 39 of the State's 159 counties,
collectively serve approximately 283,000290,000 electric consumers (meters).
24
City of Dalton, Georgia
The City of Dalton, located in northwest Georgia, supplies electric
capacity and energy to consumers in Dalton, and presently serves more than
10,000 residential, commercial and industrial customers.
25
The Plant Agreements
Hatch, Wansley, Vogtle and Scherer
Oglethorpe's rights and obligations with respect to Plants Hatch, Wansley,
Vogtle and Scherer are contained in a number of contracts between Oglethorpe and
GPC and, in some instances, MEAG and Dalton. Oglethorpe is a party to four
Purchase and Ownership Participation Agreements ("Ownership Agreements") under
which it acquired from GPC a 30% undivided interest in each of Plants Hatch,
Wansley and Vogtle, a 60% undivided interest in Scherer Units No. 1 and No. 2
and a 30% undivided interest in those facilities at Plant Scherer intended to be
used in common by Scherer Units No. 1, No. 2, No. 3 and No. 4 (the "Scherer
Common Facilities"). Oglethorpe has also entered into four Operating Agreements
("Operating Agreements") relating to the operation and maintenance of Plants
Hatch, Wansley, Vogtle and Scherer, respectively. The Ownership Agreements and
Operating Agreements relating to Plants Hatch and Wansley are two-party
agreements between Oglethorpe and GPC. The Ownership Agreements and Operating
Agreements relating to Plants Vogtle and Scherer are agreements among
Oglethorpe, GPC, MEAG and Dalton. The parties to each Ownership Agreement and
Operating Agreement are referred to as "participants" with respect to each such
agreement.
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. Oglethorpe also has fair
market value purchase options at specified dates, including 2013 and the end of
lease renewal terms. These transactions are treated as capital leases by
Oglethorpe for financial reporting purposes. (See Note 4 of Notes to Financial
Statements in Item 8.) (In the following discussion, references to participants
"owning" a specified percentage of interests include Oglethorpe's rights as a
deemed owner with respect to its leased interests in Scherer Unit No. 2.)
The Ownership Agreements appoint GPC as agent with sole authority and
responsibility for, among other things, the planning, licensing, design,
construction, renewal, addition, modification and disposal of Plants Hatch,
Vogtle, Wansley and Scherer Units No. 1 and No. 2 and the Scherer Common
Facilities. Each Operating Agreement gives GPC, as agent, sole authority and
responsibility for the management, control, maintenance and operation of the
plant to which it relates. Each Operating Agreement also provides for the use of
power and energy from the plant and the sharing of the costs of the plant by the
participants in accordance with their respective interests in the plant. In
performing its responsibilities under the Ownership and Operating Agreements,
GPC is required to comply with prudent utility practices. GPC's liabilities with
respect to its duties under the Ownership and Operating Agreements are limited
by the terms thereof.
Under the Ownership Agreements, Oglethorpe is obligated to pay a percentage
of capital costs of the respective plants, as incurred, equal to the percentage
interest which it owns or leases at each plant. GPC has responsibility for
budgeting capital expenditures for Scherer Units No. 1 and 2 subject to certain
limited rights of the participants to disapprove capital budgets proposed by GPC
and to substitute alternative capital budgets. GPC has responsibility for
budgeting capital expenditures for Plants Hatch and Vogtle, subject to the right
of any co-owner to disapprove large discretionary capital improvements.
In 1993, the co-owners of Plants Hatch and Vogtle entered into the Amended and
Restated Nuclear Managing Board Agreement, which provides for a managing board
to coordinate the implementation and administration of the Plant Hatch and Plant
Vogtle Ownership and Operating Agreements, provides for increased rights for the
co-owners regarding certain decisions and allows GPC to contract with a 25
third
party for the operation of the nuclear units. In March 1997, GPC designated
26
SONOPCO as the operator of Plants Hatch and Vogtle, pursuant to the Nuclear
Operating Agreement between GPC and SONOPCO, which the co-owners had previously
approved. In connection with the amendments to the Plant Scherer Ownership and
Operating Agreements, the co-owners of Plant Scherer entered into the Plant
Scherer Managing Board Agreement which provides for a managing board to
coordinate the implementation and administration of the Plant Scherer Ownership
and Operating Agreements and provides for increased rights for the co-owners
regarding certain decisions, but does not alter GPC's role as agent with respect
to Plant Scherer.
The Operating Agreements provide that Oglethorpe is entitled to a
percentage of the net capacity and net energy output of each plant or unit equal
to its percentage undivided interest owned or leased in such plant or unit. GPC,
as agent, schedules and dispatches Plants Hatch and Vogtle. Oglethorpe
separately dispatches its ownership share of Scherer Units No. 1 and No. 2 and
of Plant Wansley. (See "Fuel Supply" herein.)
For Plants Hatch and Vogtle, each participant is responsible for a
percentage of Operating Costs (as defined in the Operating Agreements) and fuel
costs of each plant or unit equal to the percentage of its undivided interest
which is owned or leased in such plant or unit. For Scherer Units No. 1 and No.
2 and for Plant Wansley, each party is responsible for its fuel costs and for
variable Operating Costs in proportion to the net energy output for its
ownership interest, and is responsible for a percentage of fixed Operating Costs
equal to the percentage of its undivided interest which is owned or leased in
such plant or unit. GPC is required to furnish budgets for Operating Costs, fuel
plans and scheduled maintenance plans. In the case of Scherer Units No. 1 and
No. 2, the participants have limited rights to disapprove such budgets proposed
by GPC and to substitute alternative budgets. The Ownership Agreements and
Operating Agreements provide that, should a participant fail to make any payment
when due, among other things, such nonpaying participant's rights to output of
capacity and energy would be suspended.
The Operating Agreement for Plant Hatch will remain in effect with respect
to Hatch Units No. 1 and No. 2 until 2009 and 2012, respectively. Oglethorpe anticipates thathas
entered into an agreement with GPC, subject to RUS approval, to extend the
Operating Agreement will be extended if thefor so long as an NRC operating license exists for Plant Hatch is extended.each
unit. (See "FACTORS AFFECTING THE ELECTRIC UTILITY Industry--EnvironmentalINDUSTRY--Environmental and
Other Regulation--Nuclear Regulation.") The Operating Agreement for Plant Vogtle
will remain in effect with respect to each unit at Plant Vogtle until 2018. The
Operating Agreement for Plant Wansley will remain in effect with respect to
Wansley Units No. 1 and No. 2 until 2016 and 2018, respectively. The Operating
Agreement for Scherer Units No. 1 and No. 2 will remain in effect with respect
to Scherer Units No. 1 and No. 2 until 2022 and 2024, respectively. Upon
termination of each Operating Agreement, following any extension agreed to by
the parties, GPC will retain such powers as are necessary in connection with the
disposition of the property of the applicable plant, and the rights and
obligations of the parties shall continue with respect to actions and expenses
taken or incurred in connection with such disposition.
Rocky Mountain
Oglethorpe owns a 74.61% undivided interest in Rocky Mountain and GPC owns
the remaining 25.39% undivided interest.
The Rocky Mountain Pumped Storage Hydroelectric Ownership Participation
Agreement, by and between Oglethorpe and GPC (the "Rocky Mountain Ownership
Agreement") appoints Oglethorpe as agent with sole authority and responsibility
for, among other things, the planning, licensing, design, construction,
operation, maintenance and disposal of Rocky Mountain. The Rocky Mountain Pumped
Storage Hydroelectric Project Operating Agreement (the "Rocky Mountain Operating
Agreement") gives Oglethorpe, as agent, sole authority and responsibility for
the management, control, maintenance and operation of Rocky Mountain.
2627
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. 27For more information about the structure of these lease transactions,
see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Financial Condition--Capital Requirements--Off-Balance Sheet
Arrangements" in Item 7.
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 also obligated to pay the actual operation and maintenance costs
and the costs of capital improvements. 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. (See Note 4 of
Notes to Financial Statements in Item 8.)
28
ITEM 3. LEGAL PROCEEDINGS
On June 17, 1997, PECO Energy Company-Power Team ("PECO") filed an
application with FERC pursuant to Section 211 of the Federal Power Act
requesting FERC to compel Oglethorpe and/or GTC to provide PECO with 250 MW of
firm point-to-point transmission service from the TVA-Integrated Transmission
System ("TVA-ITS") interface to the Florida-Integrated Transmission System
interface for an initial three-year period, with an automatic roll-over
provision. PECO also seeks $10,000 per day in penalties from Oglethorpe and/or
GTC, alleging bad faith and delays in negotiations. In their response to FERC,
GTC and Oglethorpe contend that they negotiated with PECO in good faith, and
thus there is no reasonable basis for imposing the penalties sought by PECO. GTC
also responded that it does not have firm "available transfer capability" at the
TVA-ITS interface to fulfill PECO's request, after taking into account the need
to protect system reliability, existing firm commitments, and use of the TVA-ITS
interface to serve "native load," in accordance with North American Electric
Reliability Council guidelines. Since this action involves transmission access
to the ITS and is exclusively a transmission matter, Oglethorpe has requested
that FERC dismiss the action as to Oglethorpe. In the event GTC is ordered by
FERC to provide the requested service, PECO would be required to compensate GTC
at rates set by FERC in the order. As a consequence of any such order, power
purchased by Oglethorpe for delivery through the TVA-ITS interface would
probably be curtailed (based on past operational experience at that interface),
and could result in higher purchased power cost than would otherwise be the
case. Although FERC transmission pricing policy is designed to ensure that a
transmission provider is fully compensated for the cost of providing
transmission service, potentially including opportunity cost, there can be no
assurance that rates ordered by FERC for service to PECO would fully compensate
GTC, Oglethorpe and the Members for the use of the transmission system and for
any resulting effect on reliability or increase in the cost of power.
As previously reported, Oglethorpe and LEM have been addressing a number of
issues relating to administration of the power marketer agreement entered into
in 1997. In February 2001, LEM initiated the contractually defined arbitration
process to resolve these issues. Oglethorpe continues to receive power under the
LEM agreement. Oglethorpe's management does not expect the ultimate resolution
of these issues will have a material adverse effect on its financial condition
or results of operations. For a discussion of the LEM agreement, see
"OGLETHORPE'S POWER SUPPLY RESOURCES--Power Marketer Arrangements--LEM
Agreement" in Item 1.
Oglethorpe is a party to various other actions and proceedings incidental to its
normal business. Liability in the event of final adverse determinations in any
of these matters is either covered by insurance or, in the opinion of
Oglethorpe's management, after consultation with counsel, should not in the
aggregate have a material adverse effect on the financial position or results of
operations of Oglethorpe.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
2829
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY ANDEQUITYAND RELATED STOCKHOLDER MATTERS.MATTERS
Not applicable.Applicable.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected historical financial data of Oglethorpe.
The financial data presented as of the end of and for each year in the five-year
period ended December 31, 2000,2002, 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)
2002 2001 2000 1999 1998
1997 1996
-----------------------------------------------------------------------------------================================================================================================================================
Operating revenues:
Operating revenues:
Sales to Members $ 1,127,519 $ 1,080,478 $ 1,146,064 $ 1,122,336 $ 1,095,904
$ 1,000,319 $ 1,023,094
Sales to non-Members 35,802 58,811 53,333 53,896 48,263
47,533 78,343
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,163,321 1,139,289 1,199,397 1,176,232 1,144,167
1,047,852 1,101,437
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating expenses:
Fuel 216,952225,008 221,449 230,729 196,182 191,399
206,315 206,524
Production 215,834232,312 218,480 220,221 215,517 198,378
181,923 173,497
Purchased power 403,574357,491 414,382 377,805 401,719 387,662 266,875 229,089
Depreciation and amortization 142,082140,058 133,731 143,703 130,883 124,074
126,730 163,130
Other operating expensesIncome taxes - (63,485) - - -
6,334 46,448
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 978,442954,869 924,557 972,458 944,301 901,513
788,177 818,688
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating margin 220,955208,452 214,732 226,939 231,931 242,654 259,675 282,749
Other income, net 60,83935,911 51,345 62,431 50,545 42,293 46,646 65,334
Net interest charges (261,816)(226,823) (247,660) (269,392) (262,538) (263,867)
(283,916) (326,331)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net margin $ 17,540 $ 18,417 $ 19,978 $ 19,938 $ 21,080
$ 22,405 $ 21,752
- -----------------------------------------------------------------------------------------------------------------------------================================================================================================================================
Electric plant, net:
In service $ 3,214,9743,123,630 $ 3,224,634 $ 3,339,364 $ 3,312,669 $ 3,429,704
$ 3,588,204 $ 4,345,200
Construction work in progress 62,35769,282 38,564 24,841 18,299 20,948
13,578 31,181
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total electric plant $ 3,277,3313,192,912 $ 3,263,198 $ 3,364,205 $ 3,330,968 $ 3,450,652
$ 3,601,782 $ 4,376,381
- -----------------------------------------------------------------------------------------------------------------------------================================================================================================================================
Total assets $ 4,568,1704,518,551 $ 4,564,6224,712,831 $ 4,506,2654,681,194 $ 4,509,8574,551,711 $ 5,362,175
- -----------------------------------------------------------------------------------------------------------------------------4,494,228
================================================================================================================================
Capitalization:
Long-term debt $ 2,835,997 $ 2,929,316 $ 3,019,019 $ 3,103,590 $ 3,177,883
$ 3,258,046 $ 4,052,470
Obligation under capital leases 267,449358,676 373,837 387,756 275,224 282,299
288,638 293,682
Other obligations 72,698 68,032 63,665 59,579 55,755 52,176 41,685
Patronage capital and membership fees 371,818 367,668 392,682 370,025 352,701
330,509 356,229
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 3,742,8153,639,189 $ 3,738,853 $ 3,863,122 $ 3,808,418 $ 3,868,638
$ 3,929,369 $ 4,744,066
- -----------------------------------------------------------------------------------------------------------------------------================================================================================================================================
Property additions $ 108,254100,145 $ 69,824 $ 70,738 $ 41,829 $ 43,904
$ 63,527 $ 93,704
- -----------------------------------------------------------------------------------------------------------------------------================================================================================================================================
Energy supply (megawatt-hours):
Generated 19,565,92518,969,282 19,157,910 19,802,501 18,295,514 17,781,896
17,722,059 17,866,143
Purchased 11,401,07110,845,701 11,448,219 11,234,860 7,971,583 8,544,714
6,377,643 6,606,931
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Available for sale 30,966,99629,814,983 30,606,129 31,037,361 26,267,097 26,326,610
24,099,702 24,473,074
- -----------------------------------------------------------------------------------------------------------------------------================================================================================================================================
Member revenue per kWh sold 4.21 cents 4.53 cents 4.70 cents 4.83 cents 5.11 cents
- -----------------------------------------------------------------------------------------------------------------------------4.04(cent) 4.01(cent) 4.21(cent) 4.53(cent) 4.70(cent)
================================================================================================================================
2930
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
General
MarginsSummary of Critical Accounting Policies and Patronage CapitalCooperative Operations
Basis of Accounting
Oglethorpe Power Corporation (An Electric Membership Corporation)
("Oglethorpe")(Oglethorpe) follows generally accepted accounting principles and the practices
prescribed in the Uniform System of Accounts of the Federal Energy Regulatory
Commission (FERC) as modified and adopted by the Rural Utilities Service (RUS).
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities as of December 31, 2002 and 2001
and the reported amounts of revenues and expenses for each of the three years
ending December 31, 2002. Actual results could differ from those estimates.
Regulatory Assets and Liabilities. Oglethorpe is subject to the provisions
of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for
the Effects of Certain Types of Regulation." SFAS No. 71 permits Oglethorpe to
record regulatory assets and regulatory liabilities to reflect future cost
recovery or refunds that Oglethorpe has a right to pass through to the Members.
At December 31, 2002, Oglethorpe's regulatory assets and liabilities totaled
$289 million and $76 million, respectively. See Note 1 of Notes to Financial
Statements. In the event that competitive or other factors result in cost
recovery practices under which Oglethorpe can no longer apply the provisions of
SFAS No. 71, Oglethorpe would be required to eliminate all regulatory assets and
liabilities that could not otherwise be recognized as assets and liabilities by
businesses in general. In addition, Oglethorpe would be required to determine
any impairment to other assets, including plant, and write-down those assets, if
impaired, to their fair value.
Nuclear Decommissioning. Oglethorpe owns interests in two nuclear
facilities, Plant Vogtle and Plant Hatch. Oglethorpe will incur costs to
decommission these plants when their licenses expire. Oglethorpe currently
expects that Plant Vogtle and Plant Hatch will begin the decommissioning process
in 2027 and 2034, respectively. Based on a 2000 site study, Oglethorpe estimates
its portion of the costs of decommissioning to be $308 million for Plant Vogtle
and $314 million for Plant Hatch. The decommissioning cost estimates are based
on prompt dismantlement and removal of the plant from service. The actual
decommissioning costs may vary from these estimates because of changes in the
assumed date of decommissioning, changes in regulatory requirements, changes in
technology, and changes in costs of labor, materials and equipment.
In compliance with NRC regulations, Oglethorpe maintains an external trust
fund to provide for a portion of the cost of decommissioning its nuclear
facilities. The NRC regulations require funding levels based on average expected
cost to decommission only the radioactive portions of a typical nuclear
facility. Based on the most recent Nuclear Regulatory Commission (NRC) funding
requirement, the balance in the decommissioning reserve at December 31, 2002 was
approximately $11.5 million less than the NRC minimum funding requirement
primarily due to unrealized losses in the market value of certain investments
held in Oglethorpe's external decommissioning trust fund. These projections are
based on an assumed cost escalation rate of 4.72% and an assumed return on trust
assets of 8%. Oglethorpe is currently examining the allocation of funding
between nuclear units, a possible license extension at Plant Vogtle and
investment earnings assumptions to determine whether additional contributions to
the external fund may be necessary in the future. Oglethorpe's management
believes that any increase in cost estimates of decommissioning can be recovered
in future rates.
Accounting for Asset Retirement Obligations. In June of 2001, the Financial
Accounting Standards Board (FASB) issued SFAS No. 143, "Accounting for Asset
Retirement Obligations." The statement provides accounting and reporting
standards for recognizing obligations related to costs associated with the
retirement of long-lived assets. SFAS No. 143 requires obligations associated
with the retirement of long-lived assets to be recognized at their fair value in
31
the period in which they are incurred if a reasonable estimate of fair value can
be made. The fair value of the asset retirement costs must be capitalized as
part of the carrying amount of the long-lived asset and subsequently allocated
to expense using a systematic and rational method over the asset's useful life.
Any subsequent changes to the fair value of the liability due to passage of time
or changes in the amount or timing of estimated cash flows must be recognized as
an accretion expense.
In January 2003, Oglethorpe adopted SFAS No. 143. The fair value of the
legal obligation recognized under SFAS No. 143 primarily relates to Oglethorpe's
nuclear facilities. In addition, Oglethorpe recognized retirement obligations
for ash handling facilities at the coal-fired plants and solid waste landfills
located at certain generating facilities. The cumulative effect of adoption
resulted in Oglethorpe recording a regulatory asset of approximately
$23,700,000, capitalized asset retirement costs, net of accumulated
amortization, of approximately $45,100,000 and increased asset retirement
obligations of approximately $68,800,000. At December 31, 2002, Oglethorpe's
recognized liability for nuclear decommissioning was $166,299,000. Oglethorpe
continues to recognize the accumulated removal costs for other obligations
(regulatory liabilities) as part of the accumulated depreciation and
amortization reserve in accordance with RUS prescribed regulatory treatment for
these costs. At December 31, 2002, that amount was $38,200,000.
Under SFAS No. 71, Oglethorpe may record an offsetting regulatory asset or
liability to reflect the difference in timing of recognition of the costs of
decommissioning for financial statement purposes and for ratemaking purposes for
both the cumulative effect of adoption and for future periods timing
differences. While RUS has not issued regulatory guidance for adoption of SFAS
No. 143, Oglethorpe's management expects to receive permission from RUS to
implement the provisions SFAS No. 71 with respect to timing differences arising
from cost recognition under SFAS No. 143 and for ratemaking purposes. Oglethorpe
estimates that the annual difference will be approximately $5,000,000.
Accounting for Derivatives. As of January 1, 2001, Oglethorpe adopted SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities." The
standard establishes accounting and reporting requirements for derivative
instruments, including certain derivative instruments embedded in other
contracts, and hedging activities. It requires the recognition of all derivative
instruments as assets or liabilities in Oglethorpe's balance sheet and
measurement of those instruments at fair value. The accounting treatment of
changes in fair value is dependent upon whether or not a derivative instrument
is designated as a hedge and if so, the type of hedge. Oglethorpe's interest
rate swap arrangements in place at December 31, 2002 are designated as cash flow
hedges. Adoption of SFAS No. 133 on January 1, 2001, resulted in recording
$33,515,000 of decline in fair value to accumulated other comprehensive income
and a comparable increase in other liabilities related to the interest rate
swaps. The fair value of the interest rate swap arrangements at December 31,
2002 was an unrealized loss of $58,443,000. See Note 2 of Notes to Financial
Statements.
Oglethorpe has entered into natural gas financial contracts that are
classified as cash flow hedges. Oglethorpe utilizes natural gas financial
contracts in managing its exposure to fluctuations in the market price of
natural gas. At December 31, 2002, Oglethorpe recorded an unrealized gain in
other comprehensive margin of $8,507,000 and a corresponding increase in other
current assets related to these natural gas financial contracts.
The application of new rules for SFAS No. 133 is still evolving and further
guidance from the Financial Accounting Standards Board is expected which could
further impact Oglethorpe's financial statements. In addition, Oglethorpe will
continue to evaluate its use of derivatives, including their effectiveness for
hedging, and to apply appropriate procedures and methods for valuing them.
Margins and Patronage Capital
Oglethorpe provides wholesale electric service to its 39 retail electric
distribution cooperative members ("Members")(Members). Oglethorpe operates on a
not-for-profit basis and, accordingly, seeks only to generate revenues
sufficient to recover its cost of service and to generate margins sufficient to
establish reasonable reserves and meet certain financial coverage requirements.
Revenues in excess of current period costs in any year are designated as net
32
margin in Oglethorpe's statements of revenues and expenses and patronage
capital. Retained net margins are designated on Oglethorpe's balance sheets as
patronage capital, which is allocated to each of the Members on the basis of its
electricity purchases from Oglethorpe. Since its formation in 1974, Oglethorpe
has generated a positive net margin in each year and had a balance, excluding
accumulated other comprehensive loss, of $393$428 million in patronage capital as of
December 31, 2000.2002. Oglethorpe's equity ratio, (patronagecalculated as patronage capital
and membership fees (excluding accumulated other comprehensive loss) divided by
total capitalization)capitalization, increased from 9.7%10.8% at December 31, 19992001 to 10.5%11.7% at
December 31, 2000.2002.
Patronage capital constitutes the principal equity of Oglethorpe. Any
distributions of patronage capital are subject to the discretion of the Board of
Directors. However, under the Indenture, dated as of March 1, 1997, from
Oglethorpe to SunTrust Bank, as trustee ("Mortgage Indenture")(Mortgage Indenture), Oglethorpe is
prohibited from making any distribution of patronage capital to the Members if,
at the time of or after giving effect to the distribution, (i) an event of
default exists under the Mortgage Indenture, (ii) Oglethorpe's equity as of the
end of the immediately preceding fiscal quarter is less than 20% of Oglethorpe's
total capitalization, or (iii) the aggregate amount expended for distributions
on or after the date on which Oglethorpe's equity first reaches 20% of
Oglethorpe's total capitalization exceeds 35% of Oglethorpe's aggregate net
margins earned after such date. This last restriction, however, will not apply
if, after giving effect to such distribution, Oglethorpe's equity as of the end
of the immediately preceding fiscal quarter is not less than 30% of Oglethorpe's
total capitalization.
Rates and Regulation
Pursuant to the Amended and Restated Wholesale Power Contracts, dated
August 1, 1996 ("Wholesale(Wholesale Power Contracts")Contracts) entered into between Oglethorpe and
each of the Members, Oglethorpe is required to design capacity and energy rates
that generate sufficient revenues to recover all costs, to establish and
maintain reasonable margins and to meet its financial coverage requirements.
Oglethorpe reviews its capacity rates at least annually to ensure that it meets
its net margin goals.
The rate schedule under the Wholesale Power Contracts implements on a
long-term basis the assignment to each Member of responsibility for fixed costs.
The monthly charges for capacity and other non-energy charges are based on a
rate formula using the Oglethorpe budget. The Board of Directors may adjust
these charges during the year through an adjustment to the annual budget. Energy
charges are based on actual energy costs, including fuel costs, variable
operations and maintenance costs, and purchased energy costs.
Under the Mortgage Indenture, Oglethorpe is required, subject to any
necessary regulatory approval, to establish and collect rates that are
reasonably expected, together with other revenues of Oglethorpe, to yield a
Margins for Interest Ratio for each fiscal year equal to at least 1.10. The
Margins for Interest Ratio is determined by dividing Margins for Interest by
Interest Charges. Margins for Interest equal the sum of (i) Oglethorpe's net
margins (after certain defined adjustments), (ii) Interest Charges and (iii) any
amount included in net margins for accruals for federal or state income taxes.
The definition of Margins for Interest takes into account any item of net
margin, loss, gain or expenditure of any affiliate or subsidiary of Oglethorpe
only if Oglethorpe has received such net margins or gains as a dividend or other
distribution from such affiliate or subsidiary or if Oglethorpe has made a
payment with respect to such losses or expenditures.
30
The rate schedule also includes a prior period adjustment mechanism
designed to ensure that Oglethorpe achieves the minimum 1.10 Margins for
Interest Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum
1.10 Margins for Interest Ratio would be accrued as of December 31 of the
applicable year and collected from the Members during the period April through
December of the following year. The rate schedule formula is intended to provide
for the collection of revenues which, together with revenues from all other
sources, are equal to all costs and expenses recorded by Oglethorpe, plus
amounts necessary to achieve at least the minimum 1.10 Margins for Interest
Ratio.
For 2000, 19992002, 2001 and 1998,2000, Oglethorpe achieved a Margins for Interest Ratio
of 1.10.
33
Under the Mortgage Indenture and related loan contract with the Rural
Utilities Service ("RUS")(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")GPSC).
Results of Operations
Power Marketer Arrangements
Oglethorpe is utilizing power marketer arrangements to reduce the cost of
power to the Members. Oglethorpe has a power marketer agreement with LG&E Energy
Marketing Inc. ("LEM")(LEM), for approximately 50% of the load requirements of 37 of
the Members and an additional power marketer agreement with Morgan Stanley
Capital Group Inc. ("Morgan Stanley")(Morgan Stanley), effective May 1, 1997, with respect to 50%
of the 39 Members' then forecasted load requirements. The LEM agreement is based
on the actual requirements of the participating Members during the contract
term, whereas the Morgan Stanley agreement represents a fixed supply obligation.
Generally, these arrangements reduce the cost of supplying power tobenefit the Members by limiting the risk of unit
availability by providing a guaranteed
benefit for the use of excess resources and by providing future power needs at a fixed price. Most of
Oglethorpe's generating facilities and power purchase arrangements are available
for use by LEM and Morgan Stanley. Oglethorpe continues tto be responsible for
all of the costs of its system resources but receives revenue from LEM and
Morgan Stanley for the use of the resources. After taking into account the
Oglethorpe resources made available toLEM and Morgan Stanley for their use,
Oglethorpe estimates that about 30% of its power supply capability in 2003 will
be provided by these contracts.
In February 2001, LEM and its affiliates initiated the contractually defineda binding arbitration
process to resolve a number ofcertain issues relating to the interpretation and
administration of the agreement.LEM agreement and a similar agreement with Oglethorpe that
expired by its terms in 1999. In April 2002, Oglethorpe and LEM settled this
arbitration. As part of the settlement, Oglethorpe paid LEM approximately
$48,500,000. Oglethorpe recorded a reserve of $36,000,000 in 2001 and an
additional expense of $12,500,000 in 2002.
Operating Revenues
Sales to Members. RevenuesOglethorpe's operating revenues generally fluctuate from
period to period based on factors including weather and other seasonal factors,
growth in the service territories of Oglethorpe's 39 retail electric
distribution cooperative members (the Members), operating costs, availability of
electric generation resources, Oglethorpe's decisions of whether to dispatch its
owned or purchased resources or Member-owned resources over which it has
dispatch rights and by Members' decisions of whether to purchase a portion of
their growth requirements from Oglethorpe or from other suppliers and whether to
schedule separately their resources. A large number of Members are collected pursuanthave now elected
to the
Wholesale Power Contractsschedule separately their percentage capacity responsibilities (their
pro-rata shares) in Oglethorpe resources to serve their retail and are a functionwholesale
customers, although approximately half of the demand for power by the
Members' consumers and Oglethorpe's cost of service. Revenueselections were not effective until
June 1, 2002.
Total revenues from sales to Members increased by 2.1%4.4% for 20002002 compared to
19992001 and increaseddecreased by 2.4%5.7% for 19992001 compared to 1998. Kilowatt-hours (kWh) sales to Members were 10.0% higher
in 2000 compared to 1999 and 6.2% higher in 1999 compared to 1998. The average
revenue per kWh from sales to Members decreased 7.1% for 2000 compared to 1999
and decreased 3.6% for 1999 compared to 1998.2000. The components of Member
revenues were as follows:
- -----------------------------------------------------------------2002 2001 2000
---- ---- ----
(dollars in thousands)
2000 1999 1998
- -----------------------------------------------------------------
Capacity revenues $ 624,537592,621 $ 613,974537,392 $ 623,464624,537
Energy revenues 534,898 543,086 521,527
508,362 472,440
- --------------------------------------------------------------------------- ---------- ---------
Total $1,127,519 $1,080,478 $1,146,064
$1,122,336 $1,095,904
- -----------------------------------------------------------------========== ========== ==========
Capacity revenues from Members increased from 1999 to 2000 primarily due to
capacity charges incurred for new power purchase agreements and higher
depreciation and amortization offset10.3% in part by higher investment income. For
19992002 compared to 1998, Member capacity2001 and
decreased by 14.0% from 2000 to 2001. Capacity revenues decreased duein 2001 were lower
primarily as a result of a credit to lower interest
costs and higher investment income offset in part by higher production expenses.tax expense.
Energy revenues from Members decreased by 1.5% from 2001 to 2002 and
increased by 2.6%4.1% from 19992000 to 2000 and by
7.6% from 1998 to 1999. The increases in2001. Member energy revenues over the past
two years were higher in 2001
primarily due to greater volumes of energy soldhigher purchased power costs related to Members.
31an accrual for
estimated damages payable to LEM resulting from the arbitration ruling.
34
The following table summarizes the amounts of kWh sold to Members and total
revenues per kWh during each of the past three years:
- ------------------------------------------------------------------------------
(in thousands)
Kilowatt-hours Cents per
(in thousands) Kilowatt-hour
- ------------------------------------------------------------------------------2002 27,924,856 4.04
2001 26,950,149 4.01
2000 27,232,641 4.21
1999 24,755,812 4.53
1998 23,315,950 4.70
- ------------------------------------------------------------------------------
In 2000,2002 kWh sales to Members increased 3.6% as a cold Novemberresult of higher sales to
both scheduling Members and DecemberMembers who participate in Oglethorpe's capacity and
energy pool. In 2001 mild weather, combined with an increase in energy supplied
by Member-owned resources, mitigated by continued growth in the Members' service
territories, resulted in a 10.0% increase1.0% decrease in kWh sales to Members. The 6.2% increase inaverage
revenue per kWh from sales to Members in 1999increased 0.7% for 2002 compared to 1998 was due2001
and decreased 4.8% for 2001 compared to continued sales growth in the Members' service territories. In addition,
Oglethorpe provided the Members with additional energy in 1999 to offset lower
delivery of hydroelectric power from Southeastern Power Administration due to
lower than normal rainfall.2000.
The energy portion of Member revenues per kWh decreased 6.8%4.9% in 20002002
compared to 19992001 and increased 1.4%5.2% in 19992001 compared to 1998.2000. Oglethorpe passes
through actual energy costs to the Members such that energy revenues equal
energy costs. The decrease in 20002002 of energy revenues per kWh was primarily due
to the pass-through of lower purchased power costs. The increase in 19992001 for the
cost of energy supplied to the Members resulted primarily from higher purchased
power costs. See "Operating Expenses" below.
Sales to non-Members. The following table summarizes non-Member revenues
for the past three years:
- -----------------------------------------------------------------2002 2001 2000
---- ---- ----
(dollars in thousands)
2000 1999 1998
- -----------------------------------------------------------------
Sales to other utilities $46,952 $46,186 $28,890
Sales to power marketers 6,381 7,710 19,373
- -----------------------------------------------------------------
Total $53,333 $53,896 $48,263
- -----------------------------------------------------------------$34,522 $55,057 $46,952
companies
Sales to other utilitiesLEM and 1,280 3,754 6,381
------- ------- -------
Morgan Stanley
Total $35,802 $58,811 $53,333
======= ======= =======
Sales to power companies represent sales made directly by Oglethorpe.
Oglethorpe sells for its own account any energy available from the portion of
its resources dedicated to Morgan Stanley that is not scheduled by Morgan
Stanley pursuant to its power marketer arrangements. SalesScheduling Members are
entitled to other utilities
were higher in 1999 compared to 1998 partly due to receiving a full year ofschedule energy available from their percentage capacity
revenues in 1999 under an agreement entered into with Alabama Electric
Cooperative to sell 100 megawatts ("MW") of capacityresponsibilities for the period June 1998
through December 2005both retail sales and partly due to higher energy prices experiencedfor resale in the wholesale electricity markets during 1999.market.
More of the Members were scheduling Members in 2002 than in 2001, resulting in
less energy being available to Oglethorpe to sell directly to non-Members.
Sales to power marketers represent the net energy transmitted on behalf of
LEM and Morgan Stanley off-system on a dailyan hourly basis from Oglethorpe's total
resources.resources under the LEM and Morgan Stanley power marketer arrangements.
Oglethorpe sold this energy to LEM at Oglethorpe's cost, subject to certain
limitations, and to Morgan Stanley at a contractually fixed price. The volume of
sales to power marketers depends primarily on the power marketers' decisions for
servicing their load requirements.
Operating Expenses
Oglethorpe's operating expenses increased 3.6%3.3% in 20002002 compared to 19992001 and
increased 4.7%decreased 4.9% in 19992001 compared to 1998. Operating2000. The increased operating expenses in
2002 resulted primarily from higher production expenses and depreciation and
amortization costs offset somewhat by lower purchased power costs. The decrease
in operating expenses in 2001 resulted primarily from lower fuel costs,
depreciation and amortization costs and from a credit to income tax expense
offset somewhat by higher purchased power costs.
Production expenses increased 6.3% in 2002 compared to 2001. The higher
production expenses resulted primarily from higher operation and maintenance
(O&M) costs. The higher O&M costs resulted from (1) a forced outage and diesel
generator repairs at Plant Hatch, (2) increased security costs at Plants Vogtle
and Hatch related to the events of September 11, 2001, (3) one-time costs
incurred due to the Southern Nuclear Operating Company engineering
reorganization efforts and (4) forced outages at Plants Scherer and Wansley.
Total fuel costs decreased 4.0% in 2001 compared to 2000 primarily as a
result of higher fuel and depreciation and amortization costs.
The higher operating expensesa 3.1% decrease in 1999 as compared to 1998 were primarily
attributable to increases in production expenses and purchased power costs.
For 2000 compared to 1999 total fuel costs increased 10.6% primarily as a
result of a 7.4% increase in MWhs of generation. For 2000 compared to 1999
output of nuclear generation was 4.3% higher and output of fossil generation was
9.9% higher. The larger portion of fossil generation, with its higher average
fuel cost compared to nuclear generation, yielded a 3.0% increase in average
fuel cost. Total fuel costs increased 2.5% in 1999 compared to 1998 primarily as
a result of a 2.4% increase in generation.
The increase in production expenses in 1999 as compared to 1998 was
primarily due to three factors: (1) write-off of $3.6 million of obsolete
inventory at Plants Vogtle, Hatch , Wansley and Scherer; (2) approximately $2
million in expenses resulting from a Georgia Power Company ("GPC") workforce
reduction at Plants Vogtle and Hatch; and (3) expenses incurred for the LEM
arbitration and other special projects totaling $4.9 million.
32
Purchased power costs increased 0.5%decreased 13.7%
in 20002002 compared to 19992001 and increased 3.6%9.7% in 19992001 compared to 19982000 as follows:
- -------------------------------------------------------------------35
2002 2001 2000
---- ---- ----
(dollars in thousands)
2000 1999 1998
- -------------------------------------------------------------------
Capacity costs $105,763 $ 97,616 $115,599$74,232 $88,463 $93,771
Energy costs 297,811 304,103 272,063
- -------------------------------------------------------------------283,259 325,919 284,034
-------- -------- --------
Total $403,574 $401,719 $387,662
- -------------------------------------------------------------------$357,491 $414,382 $377,805
======== ======== ========
The increasedecrease in purchased power capacity costs for 2000 as2002 compared to 1999
were2001
resulted primarily a resultfrom the termination of capacity charges incurred for newvarious power purchase agreements, including an agreement with Doyle I, LLC.agreements.
Purchased power capacity costs were 15.6% lowerdecreased in 19992001 as compared to 19982000 primarily
due to the elimination on September 1, 2001 of 1998125 megawatts of a 250 MW component block (coal-fired units) of powercapacity under a
power purchase agreement between Oglethorpe and GPC.
Purchased power energy costs decreased 2.1%13.1% in 20002002 compared to 19992001 and
increased by 11.8%14.7% in 19992001 compared to 1998.2000. The average cost of purchased power
energy per MWhkWh decreased 31.5%8.3% in 20002002 compared to 19992001 and increased 19.8%12.6% in
19992001 compared to 1998. The decrease in average cost in 2000 resulted from a
combination of lower prices in the wholesale electricity markets and from
purchases made under new power purchase agreements during 2000. The increasehigher average costs in average cost in 1999 compared2001 were primarily due to 1998 resultedan
accrual for estimated amounts payable to LEM resulting from slightly higher energy
prices.settlement of an
arbitration proceeding regarding the LEM power marketing arrangement. The
volumes of purchased power increased 43.0%decreased 5.3% in 20002002 compared to 19992001 and decreased by 6.7%increased
1.9% in 19992001 compared to 1998. The higher volumes of purchased
power in 2000 were utilized to serve Member load that was not contractually
provided by the power marketers.2000.
Purchased power expenses for the years 19982000 through 20002002 include the cost
of capacity and energy purchases under various long-term power purchase
agreements. These long-term agreements have, in some cases, take-or-pay minimum
energy requirements. For 19982000 through 2000,2002, Oglethorpe utilized its energy from
these power purchase agreements in excess of the take-or-pay requirements.
Oglethorpe's capacity and energy expenses under these agreements amounted to
approximately $176$101 million in 2000, $1332002, $130 million in 19992001 and $173$150 million in
1998.2000. For a discussion of the power purchase agreements, see Note 9 of Notes to
Financial Statements.
Depreciation and amortization increased 4.7% in 2002 compared to 2001
primarily due to $9.2 million in accelerated depreciation to write down Plant
Tallassee's net book value and for estimated costs associated with early
retirement. The increase inhigher depreciation and amortization in 2000 was primarily due
to $10.3 million of Board approved accelerated amortization of project costs for
the Vogtle radioactive waste facility. The increase in depreciation and
amortization for 1999 compared to 1998 resulted from the amortization of
the Vogtle radioactive waste facility. The amortization of these project costs
commenced January 1, 1999. For further discussion of the Vogtle radioactive
waste facility see Note 1 of Notes to Financial Statements.
The credit to income tax expense in 2001 resulted from a change in
Oglethorpe's Bylaws to determine its allocation of patronage on a tax basis
method rather than the historical book basis method. Due to this change,
Oglethorpe anticipates that all future patronage source income will be offset by
the patronage exclusion. Therefore, Oglethorpe has reversed $63,485,000 of net
deferred tax liabilities and has recognized an income tax credit in the same
amount. See Note 3 of Notes to Financial Statements.
Other Income (Expense)
The higher investmentInvestment income for 2000decreased 25.9% in 2002 compared to 19992001 and decreased
27.8% in 2001 compared to 2000. The decrease in 2002 was partly due to higherlower
cash and temporary cash investmentinvestments balances and higherpartly due to lower interest
earnings on those investments, partlythese investments. The decrease in 2001 was primarily due to higherlower
earnings from the decommissioning fund and partlyfund. Amortization of net benefit of sale of
income tax benefits decreased $6 million in 2002 compared to 2001 due to interest earnings on the
note receivable from Smarr EMC
relatingamortization of the safe harbor lease ending in March 2002. See Note 1 of Notes
to the Sewell Creek Energy Facility. Investment income was higher in
1999 compared to 1998 partly due to higher earnings from the decommissioning
fund and partly due to interest earnings on the notes and interim financing
receivable from Smarr EMC relating to the Smarr Energy Facility and the Sewell
Creek Energy Facility. For 1999, the increase in income under the caption
"Other" is due in part to a gain of $849,000 from the sale of rail cars and a
$1,005,000 increase in patronage allocation from GTC.Financial Statements.
Interest Charges
Interest on long-term debt and capital leases decreased 5.2%6.9% in 19992002
compared to 19982001 primarily as a result of interest costscost savings from refinancing transactions.lower variable
interest rates on long-term debt. Other interest expense increased 18.5%decreased 50.6% in 20002001
compared to 1999 and increased 53.3%2000. The lower other interest expense in 1999 compared to 1998. The increase in
20002001 was primarily as a
result of interest charges incurred on commercial paper
33
issued as interim financing for the construction of combustion turbine
facilities owned by Smarr EMC. The increase for 1999 compared to 1998 was partly
due to interest charges incurred on commercial paper issued as interim financing
for Smarr EMC and partly due to an increasea decrease in interest expense for decommissioning (which is recorded
as an offset to interest earnings on the decommissioning fund). The increase in amortizationAmortization of
debt discount and expense for 1999decreased 26.5% in 2002 compared to 1998 was2001 primarily due
to the accelerated amortization of $7 million and $24 million in premiums paid to
the Federal Financing Bank (FFB) for refinancing $89 million and $424 million of
mortgage notes payable in 1999. These cost are being amortized over a period1999 and 1998, respectively. Such amortization ended
in the third and fourth quarters of approximately 3 years beginning in 1999.2001, respectively.
36
Net Margin and Comprehensive Margin
Oglethorpe's net margin for 2002, 2001 and 2000 1999 and 1998 was $20.0$17.5 million, $19.9$18.4
million and $21.1$20.0 million, respectively. Oglethorpe's margin requirement is
based on a ratio applied to interest charges. For 19992002 compared to 1998,2001 and for
2001 compared to 2000, the reduction in interest charges reduced Oglethorpe's
margin requirement.
Comprehensive margin for Oglethorpe is net margin adjusted for the net change in
unrealized gains and losses on investments in available-for-sale securities.
Financial Condition
General
The principal changes in Oglethorpe's financial condition in 20002002 were due
to property additions, an increase in patronage capital, a decrease in the
amount of commercial paper outstanding and a decrease in cash and temporary cash
investments and an
increase in patronage capital.investments.
Property additions, including nuclear fuel purchases, totaled $108$100 million
and were financed with funds from operationsoperations.
Oglethorpe achieved a net margin of $17.5 million in 2002, which increased
equity (patronage capital) by a like amount for total patronage capital,
excluding accumulated other comprehensive loss, of $428 million at December 31,
2002.
The amount of commercial paper outstanding decreased by $56 million from
December 31, 2001 to December 31, 2002 due to payments received from Talbot EMC
and short-term borrowings.Chattahoochee EMC in partial payment of interim loans being provided to them
by Oglethorpe.
Oglethorpe's cash and temporary cash investments increased by $108totaled $151 million at
December 31, 2002, a decrease of $124 million from the prior year-end balance.
The decrease was primarily attributable to three events, including 1) a payment
of $48.5 million to LEM in May 2002 relating to settlement of an arbitration
case, 2) a $35 million payment received from Chattahoochee EMC in December 2001
that was used in January 2002 to retire a like amount of Oglethorpe's commercial
paper, and 3) a transfer of $11.5 million in December 2002 from general funds to
the external nuclear decommissioning trust fund. Included in the $151 million
year-end cash balance was $31 million in proceeds from the issuance of pollution
control bonds ("PCBs") in December 2002. The PCB proceeds were used to repay a
like amount of PCB principal that matured on January 1, 2003.
In addition to the $151 million in cash and temporary cash investments,
Oglethorpe had, at December 31, 1999 to December 31, 2000.
Oglethorpe achieved a net margin of $202002, $94 million in 2000; however,
Oglethorpe's equity (patronage capital) increased by $23 million due toother short-term
investments which represents a net
changeportion of its general funds invested with an
external fund manager. The funds are invested primarily in unrealized gain on available-for-sale securities.high-quality
short-term notes and bonds with an average maturity of two years.
Capital Requirements
Capital Expenditures. As part of its ongoing capital planning, Oglethorpe
forecasts expenditures required for generationgenerating facilities and other capital
projects. The table below details these expenditure forecasts for 20012003 through
2003.2005. Actual construction costs may vary from the estimates listed below because
of factors such as changes in business conditions, fluctuating rates of load
growth, environmental requirements, design changes and rework required by
regulatory bodies, delays in obtaining necessary federal and other regulatory approvals,
construction delays, cost of capital, equipment, material and labor, and
decisions whether to purchase or construct additional generation capacity.
- ----------------------------------------------------------------------Capital Expenditures(1)
(dollars in thousands)
Capital Expenditures(1)
- ----------------------------------------------------------------------
Year Existing FutureEnvironmental Nuclear General
Year Generation(2) Generation(3)Compliance Fuel Plant Total
2001- ---- ------------- ---------- ---- ----- -----
2003 $ 43,11422,000 $ 280,00053,000 $ 47,247 $ 7,612 $377,973
2002 83,979 141,500 45,768 4,000 275,247
2003 44,413 23,200 48,660 4,120 120,39348,000 $2,000 $125,000
2004 26,000 2,000 42,000 2,000 72,000
2005 23,000 5,000 48,000 2,000 78,000
- ------------------------------------------------------------------------------------------------------------------------------------------------------
Total $ 171,50671,000 $ 444,700 $141,675 $15,732 $773,61360,000 $138,000 $6,000 $275,000
================================================================================
- --------------------------------------------------------------------------------
(1) Excludes allowance for funds used during construction.
(2) Consists of capital expenditures required for environmental compliance and
for replacements and additions to facilities in-service.
(3) Expenditures relateOglethorpe plans to new generation facilities that may ultimately be
owned byacquire approximately 500 rail cars for coal
transportation in 2003 at a subsidiarycost of Oglethorpe, by Smarr EMCapproximately $29 million and is currently
analyzing whether to lease or by a similar separate
entity.purchase the rail cars. This planned expenditure
is not reflected in the table above.
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $3.3$3.2 billion as of December 31, 2000. Expenditures for property2002. Property additions during
20002002 amounted to $108$100 million and were funded with a
combination of funds from operations and short-term borrowings.operations. These
expenditures were primarily for additions and replacements to existing
37
generation facilities, construction of new generation facilities (as discussed
below) and for purchases of nuclear fuel.
Over the past several years, Oglethorpe has been providing interim funding
through its commercial paper programfuel and compliance with
environmental regulations.
Financing for twoTalbot 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 generation
facilities that were builtfacility designed to
meet the growthprovide 618 MW of a majoritycapacity. Four of the Members.
Thesesix combustion turbines were placed
in-service in June 2002, with the other two facilities are now ownedexpected to be in-service by Smarrthe
summer of 2003.
Twenty-eight of Oglethorpe's Members formed Chattahoochee EMC, a separate entity created
specifically for this purpose thatGeorgia
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 was placed in-service on February 15, 2003.
The expected combined cost of constructing the six combustion turbines and
the combined cycle facility totals approximately $600 million. Oglethorpe is
owned by 37 of Oglethorpe's 39 Members.
Smarrproviding loans to Talbot EMC secured permanent financing for these facilities, the proceeds of
which were used to reimburse Oglethorpe for the interim commercial paper
financings.
34
Oglethorpe continuesand Chattahoochee EMC to fund, on an interim
basis, the construction of new
generation facilities on behalfapproximately fifty percent of the participating Members. Ascost of each facility. Oglethorpe is
funding these loans under its commercial paper program, and at December 31,
2000, $782002, $298 million of commercial paper was outstanding for this purpose. The
projects currently being funded include six combustion turbines (totaling 618
MW) and a 468 MW combined cycle facility. Four of the six combustion turbinesloans are expected to be in-serviceincluded in the summer of 2002, and the two remaining
combustion turbines and the combined cycle facility are expected to be
in-service in the summer of 2003. The costs associated with the combustion
turbines are reflected in construction work in progress and the costs associated
with the combined cycle facility are reflected in prepayments and other current
assetsNotes receivable on Oglethorpe's balance sheet at December 31, 2000. Itsheet.
Two bridge loans are funding the remaining portion of the cost of
constructing these facilities. The National Rural Utilities Cooperative Finance
Corporation (CFC) is anticipated
that these new facilities will ultimately be owned byproviding a subsidiary$141 million bridge loan to Talbot EMC, and
Pitney Bowes Credit Corporation is providing a $160 million bridge loan to
Chattahoochee EMC. Oglethorpe's loans to Talbot EMC and Chattahoochee EMC are
subordinated to the CFC and Pitney Bowes loans, respectively. Oglethorpe is
providing a guarantee of Oglethorpe, Smarr EMC, or a similar separate entity.
Oglethorpe expectsthe $160 million bridge loan to issue the maximum amount of its commercial paper
($260 million) by the fall of 2001 in conjunction with the interim financing of
these new generation facilities.Chattahoochee EMC.
In 2000, Oglethorpe has submitted loan applications to RUS to provide permanent
financing for these projectstwo facilities. The loan applications were initially
submitted on behalf of either Oglethorpe or related entities that might
ultimately own these facilities. During the process of evaluating the terms
proposed by RUS for providing loans to Talbot EMC and expects a responseChattahoochee EMC, it was
determined that the terms of the financing would be more favorable if Oglethorpe
owned the facilities and obtained the RUS financing. In September 2002, RUS
issued two RUS-guaranteed loan commitments totaling $589 million to Oglethorpe
for these generating facilities. The proceeds from these RUS laterloans will first be
used to repay the bridge loans and then to retire Oglethorpe's outstanding
commercial paper.
Concurrently with the funding of these loans, which is expected to occur in
2001. If RUS funding is delayed or denied,the second quarter of 2003, Oglethorpe will continueacquire the two generating
facilities of Talbot EMC and Chattahoochee EMC. Oglethorpe's acquisition of the
facilities is conditioned upon implementation of new arrangements among
Oglethorpe and the Members, including 1) limited amendments to financethe Wholesale
Power Contracts that do not involve any change in the payment obligations of the
Members and 2) other agreements as to the future provision of services to the
Members by Oglethorpe. The definitive agreements regarding these projectsnew
arrangements have been approved by the Members. Certain of the arrangements must
be approved by RUS, prior to funding of the loans. RUS has indicated its
satisfaction with funds from operationsthese arrangements but is not expected to deliver its formal
approval until the loans are funded.
The acquisition of these generating facilities will increase Oglethorpe's
assets and liabilities by approximately $600 million. The new debt will seekbe
secured under Oglethorpe's Mortgage Indenture. Since Oglethorpe's margin
requirement is based on a ratio applied to interest charges incurred for debt
secured under the Mortgage Indenture, the increase in debt will result in an
increase in the margin requirement of less than $3 million in the first year of
the loan. The increase in assets and debt will decrease Oglethorpe's equity to
capitalization ratio and equity to asset ratio by approximately 3% and 2%,
respectively.
Contractual Obligations. In addition to the capital expenditures and
interim financing for Talbot EMC and Chattahoochee EMC discussed above, the
table below summarizes, as of December 31, 2002, Oglethorpe's contractual
obligations for the periods indicated.
38
================================================================================
Contractual 2008
Obligations and
As of 12/31/02 2003 2004-2007 beyond Total
- --------------------------------------------------------------------------------
Long-Term Debt $123,197 $573,171 $2,262,826 $2,959,194
Capital Leases 44,322 177,202 419,399 640,923
Operating
Leases 2,877 11,757 35,108 49,742
Unconditional
Power Purchases 46,239 152,599 327,839 526,677
Rocky Mountain
Transactions (1) 72,698 NA NA 72,698
- --------------------------------------------------------------------------------
Total $289,333 $914,729 $3,045,172 $4,249,234
================================================================================
1) Oglethorpe's balance sheet contains an identical asset representing a
funding agreement entered into with a triple-A rated entity to fund this
obligation. For additional construction financing until permanent financing is obtained.information, see "Off-Balance Sheet
Arrangements."
Contingent Commitments. Oglethorpe is also making payments under an agreementliable, on a contingent basis,
for certain other contractual obligations. In each case, another party is liable
for these obligations, and Oglethorpe would be expected to purchase equipment
for a possible combined cycle facility for 2005. At December 31, 2000, $9
million of commercial paper was outstanding that was issued for this purpose,
andpay only if the paymentsother
party fails to satisfy the obligations. These obligations are reflected in prepayments and other current assetsnot shown on
Oglethorpe's balance sheet.
Several of these contingent liabilities are in connection with Oglethorpe's
transfer of the generation facilities under construction to Talbot EMC and
Chattahoochee EMC and the related assignment of contracts. As discussed above,
at the time the RUS loan is funded, the Talbot and Chattahoochee generation
facilities will be acquired by Oglethorpe. At that point, the related contingent
liabilities will become direct obligations of Oglethorpe.
The contingent liabilities under construction contracts for Talbot EMC and
Chattahoochee EMC were $15 million and $15 million, respectively, as of March 7,
2003. Substantially all of these amounts will be paid by the final acceptance of
the respective facilities. As discussed above, bridge loans to Talbot EMC and
Chattahoochee EMC are funding the remaining cost of construction.
Oglethorpe also remains liable, on a contingent basis, for obligations
under other operational agreements relating to the Chattahoochee EMC facility.
The combined obligation under these agreements totals $54 million through 2004,
and $20 million annually thereafter through approximately 2015.
In connection with a corporate restructuring in 1997 in which Oglethorpe
sold its transmission assets to GTC, GTC assumed a portion of the indebtedness
associated with PCBs. Oglethorpe was not legally released from its obligation to
pay this debt. See Note 5 of Notes to Financial Statements. Oglethorpe also has
contractual commitments on a corresponding portion of Oglethorpe's interest rate
swaps assumed by GTC.
Oglethorpe has entered into natural gas hedges with respect to Smarr EMC,
Talbot EMC and Chattahoochee EMC. See "QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK" in Item 7A.
Off-Balance Sheet Arrangements. In December 1996 and January 1997,
Oglethorpe entered into a total of six lease transactions relating to its 74.61%
undivided interest in Rocky Mountain pumped storage hydroelectric project
("Rocky Mountain"). In each transaction, Oglethorpe leased a portion of its
undivided interest in Rocky Mountain to an owner trust for the benefit of an
investor for a term equal to 120% of the estimated useful life of Rocky
Mountain, in exchange for one-time rental payments aggregating $794 million made
at the time the leases were entered into. Each owner trust financed a portion of
its payment to Oglethorpe through a loan from a bank. Immediately following the
leases to the owner trusts, the owner trusts leased their undivided interests in
Rocky Mountain to an Oglethorpe subsidiary, Rocky Mountain Leasing Corporation
("RMLC"), for a term of 30 years under separate leases (the "Facility Leases").
RMLC then subleased the undivided interests back to Oglethorpe for an identical
term also under separate leases (the "Facility Subleases").
Oglethorpe used a portion of the one-time rental payments paid to it by the
owner trusts to acquire the capital stock of RMLC and to make a $698 million
capital contribution to RMLC. RMLC in turn used the capital contribution to
enter into payment undertaking agreements and funding agreements that provide
for third parties (whose claims paying abilities or senior debt obligations are
rated "AAA" by S&P and "Aaa" by Moody's) to pay substantially all of:
o RMLC's periodic basic rent payments under the Facility Leases; and
39
o the fixed purchase price of the undivided interests in Rocky Mountain at
the end of the terms of the Facility Leases if Oglethorpe causes RMLC to
exercise its option to purchase these interests at that time.
As a result of these lease transactions, after making the capital
contribution to RMLC, Oglethorpe had $92 million remaining of the amount paid by
the owner trusts which it used to prepay FFB indebtedness while retaining
possession of, and entitlement to, its portion of the output of Rocky Mountain.
The Facility Subleases require Oglethorpe to make semi-annual rental
payments to RMLC. In turn, RMLC is required to make equal rental payments to the
owner trusts under the Facility Leases. In 2002, the amount of the rental
payments under the Facility Subleases and Facility Leases each totaled $49
million. The payment undertaking agreements require the other party (the
"payment undertaker") to pay the rent payments directly to the lender of the
owner trust in satisfaction of RMLC's rent payment obligation under the Facility
Lease and the applicable owner trust's repayment obligation under the loan to
it. Because RMLC funds these rent payments through the payment undertaking
agreements, RMLC returns to Oglethorpe amounts received by it pursuant to the
Facility Subleases. RMLC remains liable for all rental payments under the
Facility Leases if the payment undertaker fails to make such payments, although
the owner trusts have agreed to use due diligence to pursue the payment
undertaker before pursuing payment from RMLC or Oglethorpe.
As a wholly owned subsidiary of Oglethorpe, the financial condition and
results of operations of RMLC are fully consolidated into Oglethorpe's financial
statements. The financial statements of RMLC and Oglethorpe do not reflect the
payment undertaking agreements, the payments made by the payment undertaker or
the payment of rent under the Facility Subleases or Facility Leases. At December
31, 2002, if RMLC's rent payment obligations under the Facility Leases and
RMLC's interests in the related payment undertaking agreements were reflected on
the financial statements of RMLC and Oglethorpe, both amounts would equal $705
million.
At the end of the term of each Facility Lease, Oglethorpe has the option to
cause RMLC to purchase any owner trust's undivided interests in Rocky Mountain
at fixed purchase option prices that aggregate $1.088 billion for all six
Facility Leases. The payment undertaking agreements and funding agreements would
fund $716 million and $372 million of this amount, respectively, and these
amounts would be paid to the owner trusts over five installments in 2027. If
Oglethorpe and the Membersdoes not elect to build this
project,cause RMLC to purchase any owner trust's undivided
interest in Rocky Mountain, GPC has an option to purchase that undivided
interest.
If Oglethorpe anticipatesreturns through RMLC any undivided interest in Rocky Mountain
to an owner trust, that owner trust has several options it can elect. Each of
these options is structured to assure that the owner trust's net economic
benefit will continue to provide interim
construction funding until permanent financing is obtained. The estimated
capital expenditures related to this project, which are not includedbe no less than if RMLC had purchased that undivided interest in
Rocky Mountain under the purchase option set forth in the capital expenditure table above, are approximately $215 million overapplicable Facility
Lease. The options available to the next
three years. If this project is not ultimately built,owner trust include:
o causing RMLC and Oglethorpe will pursueto renew the related Facility Lease and
Facility Sublease for up to an additional 16 years and provide collateral
satisfactory to the owner trusts,
o leasing its undivided interest to a salethird party under a replacement lease,
or
o retaining the undivided interest for its own benefit.
Under the first two of these options Oglethorpe must arrange new financing
for the outstanding loans to the owner trusts. The aggregate amount of the
equipment.
In additionoutstanding loans to the funds needed for capital expenditures, approximately
$453 million will be required over the next three years (2001-2003) for current
sinking fund requirements and maturities of long-term debt. Of this amount, $294
million, or 65%, relates to the repayment of RUS and FFB debt. In addition,
Oglethorpe anticipates that it will refund $143 millionall of the $453 million due
overowner trusts at the next three years with proceeds fromend of the issuanceterm of the
Facility Leases is anticipated to be $666 million. If new tax-exempt
pollution control bonds ("PCBs").financing cannot be
arranged, the owner trusts can ultimately cause Oglethorpe to purchase 49%, in
the case of the first option above, or all, in the case of the second option
above, of the debt or cause RMLC to exercise its purchase option or RMLC and
Oglethorpe to renew the Facility Leases and Facility Subleases, respectively.
40
Liquidity and Sources of Capital
In the past,Sources of Capital. Oglethorpe has obtained the majority of its long-term
financing from RUS-guaranteedRUS guaranteed loans funded by FFB. Oglethorpe has also obtained
a substantial portion of its long-term financing requirements from the issuance
of PCBs.
In addition, Oglethorpe's operations have consistently provided a sizable
contribution to its funding of capital requirements, such that internally
generated funds have provided interim funding or long-term capital for nuclear
fuel reloads, general plant facilities, replacements and additions to existing
facilities, and retirement of long-term debt. Oglethorpe anticipates that it
will continue to meet these types of capital requirements through 20032005 primarily
with funds generated from operations.operations and, if necessary, with short-term
borrowings. However, in the future Oglethorpe may also pursue long-term
financing for these types of capital expenditures. In addition, Oglethorpe may
finance some of its prior and future environmental-related capital expenditures
by issuing long-term debt, some of which may be tax-exempt.
As discussed above, Oglethorpe is currently providing interim financing,
through its commercial paper program, for approximately fifty percent of the
cost of the new generation facilities with a combination of
short-term borrowingsowned by Talbot EMC and funds from operationsChattahoochee EMC.
This interim financing will remain in place until permanent financingfunding under the
RUS loan commitments is obtained.obtained, which is expected to occur in the second
quarter of 2003.
To meet short-term cash needs and liquidity requirements, Oglethorpe had,
as of December 31, 2000,2002, (i) approximately $331$151 million in cash and temporary
cash investments, (ii) $82$94 million in other short-term investments and (iii) up
to $232$72 million available under the following committed credit facilities:
- ---------------------------------------------------------------------------
(dollars in thousands)--------------------------------------------------------------------------------
Committed Short-Term Authorized Available Short-TermExpiration
Credit Facilities Amount Amount Date
- ---------------------------------------------------------------------------
Committed line--------------------------------------------------------------------------------
(dollars in millions)
Line of credit:
Commercialcredit
supporting commercial
paper $320(1) $22 9/24/03
CFC Line of credit $ 260,000 $ 182,000
Uncommitted line of credit:
National Rural Utilities
Cooperative Finance
Corporation 50,000 50,00050 $50 8/14/03
- ---------------------------------------------------------------------------
35
--------------------------------------------------------------------------------
1) Amount reduces to $290 million by June 30, 2003
Under its commercial paper program, Oglethorpe may issue commercial paper
not to exceed $260the amount of the backup line of credit facility, thereby
providing 100% credit support. The current $320 million outstanding at any one time. The commercial paper is
backed 100% by committed linesline of credit facility
is provided by a group of six banks that was syndicated by Bank of America.
Oglethorpe has minimum liquidity requirements in conjunctionAlong with certain
financial agreements currently in place. These agreements include the CFC line of credit, the facility supporting the commercial paper
may also be used for general working capital needs.
The commercial paper line of credit facility is structured such that the
commitment amount is reduced to $290 million upon the earlier to occur of (i)
June 30, 2003, or (ii) receipt by Oglethorpe of funds totaling $350 million
under the RUS loans for the Talbot and Chattahoochee generating facilities. As
discussed above, Oglethorpe anticipates that the RUS will provide this funding
prior to June 30, 2003. If the committed amount is reduced before the funding of
the RUS loans, Oglethorpe would use its cash or another line of credit to fund
the difference between the amount of its outstanding loans to Talbot EMC and
Chattahoochee EMC and the reduced availability of commercial paper. This amount
would be approximately $10 million.
Liquidity Covenants. Oglethorpe currently has three financial agreements in
place which contain liquidity covenants. These agreements include interest rate
swap arrangementsswaps relating to two PCB transactions and the Rocky Mountain lease
transactions. The maximum amount of liquidity that could be required under these agreements is $80 million. Aswas $76
million as of December 31, 2000,2002, and Oglethorpe had sufficient liquidity to
satisfy these requirements.
Credit Rating Risk
Oglethorpe has financial agreements and commercial contracts containing
provisions which, upon a credit rating downgrade below specified levels, may
require the posting of collateral (in the form of either letters of credit,
surety bonds or cash) or termination of the agreement. The table below sets
forth Oglethorpe's current ratings and the more significant ratings triggers
contained in Oglethorpe's agreements and contracts.
41
S&P Moody's Fitch
- --------------------------------------------------------------------------------
Oglethorpe Ratings
Senior Secured A A3 A
Senior Unsecured NRA(1) Baa1(2) NRA(1)
Short-term A-1 P-2 F-1
- --------------------------------------------------------------------------------
Rating Triggers
Interest Rate Swaps
Senior Secured BBB- Baa3 NA (3)
Rocky Mountain Lease
Senior Secured BBB Baa2 BBB
Senior Unsecured BBB- Baa3 BBB-
Morgan Stanley Power Mar-
Keting Agreement
Senior Secured BBB+ Baa1 BBB+
- --------------------------------------------------------------------------------
1) NRA = no rating assigned
2) Moody's also assigns Oglethorpe an "Issuer Rating" of Baa1
3) NA = rating not included as a trigger in agreement
Under the interest rate swap arrangements, if Oglethorpe's rating from
Standard & Poor's or Moody's falls below the levels shown in the table above,
the swap counterparty has the option of 1) making swap payments based on an
index rather than the actual variable rate on the bonds, or 2) causing an early
termination of the swaps. In the event of a termination, either party could owe
the other party a termination payment depending on the market value of the swap
position. Oglethorpe estimates that as of December 31, 2002, a termination of
the swap would require Oglethorpe to make a termination payment of approximately
$58 million. Except in situations where Oglethorpe voluntarily elects to
terminate the interest rate swaps early, Oglethorpe has the right to pay a
termination payment due to the swap counterparty over a term of up to five
years.
Provisions in the Rocky Mountain lease transactions could require
Oglethorpe to put up additional surety bonds or letters of credit in the amount
of $50 million if Oglethorpe fails to maintain at least two of the three ratings
shown in the table above or if it fails to maintain $50 million in liquidity.
Under the Morgan Stanley power marketing arrangements, which expire March
31, 2005, Oglethorpe could be required amount was $78 million.to provide credit assurance up to $45
million if Oglethorpe fails to maintain at least two of the three ratings shown
in the table above.
Provisions in other loan and power purchase agreements of Oglethorpe
contain covenants based on credit ratings that could result in increased
interest rates or restrictions on issuing debt, or could require Oglethorpe to
give performance assurances, but would not result in acceleration of any
obligations or termination of any agreements. The ratings triggers in these
agreements are at or below the minimum levels required by the agreements
reflected in the table above.
Given its current level of ratings, Oglethorpe's management does not
believe that the rating triggers contained in any of its agreements and
contracts will have a material adverse effect on its results of operations or
financial condition. However, Oglethorpe's ratings reflect the views of the
rating agencies and not of Oglethorpe, and therefore Oglethorpe cannot give any
assurance that its ratings will be maintained at current levels for any period
of time.
Refinancing Transactions
Oglethorpe has a program under which it is refinancing, on a continued
tax-exempt basis, the annual principal maturities of serial bonds and the annual
sinking fund payments of term bonds originally issued on behalf of Oglethorpe by
the Development Authority of Burke County and the Development Authority of
Monroe County.various county development authorities. The refinancing of these PCB principal
maturities allows Oglethorpe to preserve a low-cost source of financing. To
date, Oglethorpe has refinanced approximately $111$164 million under this program,
including $22$31 million of PCB principal whichthat matured on January 1, 2001.2003.
Oglethorpe also has Board
approvalplans to refinance Burke and Monroecontinue this refinancing program through at least 2007,
covering an additional $141 million in PCB principal of $23 million maturing on
January 1, 2002.
In connection with a corporate restructuring in 1997 in which Oglethorpe
sold its transmission assets to GTC, GTC assumed a portion of the indebtedness
associated with PCBs.maturities.
Under an indemnity agreement executed in connection with thisGTC's assumption
of PCB indebtedness in the 1997 corporate restructuring, GTC is entitled to
participate in any refinancing of this PCB debt by Oglethorpe by agreeing to
42
assume a portion of the refinancing debt. However, to-date GTC has agreed not to
participate in Oglethorpe's refinancing of the Burke
and MonroePCB principal payments due January 1, 2000, 2001 and 2002.maturities.
Pursuant to this agreement, Oglethorpe provided a discount of approximately $1.1$1.5
million and received cash of $2.6$3.6 million on the $3.7$5.1 million due from GTC in
connection with the Burke and Monroe principal payments due January 1, 2001.2003. GTC has also elected
not to participate in the refinancing of the PCB principal maturities through
2007.
Oglethorpe issued $92 million of tax-exempt PCBs in October 2002 to
refinance two medium-term loans, one from CoBank and one from CFC, of $46
million each. Proceeds from the medium-term loans were used to legally defease
$92 million of Series 1992 tax-exempt PCB's in connection with Oglethorpe's
corporate restructuring in 1997. The funds from the defeasance were put into an
escrow account, and the remaining amounts in escrow at January 1, 2003 were used
to fully redeem the outstanding Series 1992 PCBs.
The average interest rate on long-term debt, capital lease obligations and
notes payable was 6.21%5.33% at December 31, 2000.2002.
Other Planned Financings
Oglethorpe is currently considering a financing in 2003 of approximately
$100 million of capital expenditures previously made or to be made in complying
with environmental regulations at its fossil and nuclear facilities. A small
portion of this amount may be eligible to finance as tax-exempt PCBs, with the
remainder financed as taxable debt. If issued, this debt will be secured under
the Mortgage Indenture.
Miscellaneous
Competition
The electric utility industry in the United States continues to undergo
fundamental changes and continues to become increasingly competitive.changes. These changes have been promoted by:by several factors,
including:
o the Energy Policy Act of 1992;
o Federal Energy Regulatory Commission ("FERC") policies regarding mergers,
transmission access and pricing, and regional transmission organizations;organizations and
electricity market design;
o federal and state deregulation initiatives;
o increased consolidation and mergers of electric utilities;
o credit quality of utilities and power marketers;
o difficulties in the proliferationdevelopment of efficient energy trading markets;
o the presence of power marketers and independent power producers;
o generation surpluses and deficits and transmission constraints in certain
regional markets;
o improvements in generation technology;technology.
Oglethorpe is not obligated to provide all of the Members' requirements and
othe Members have the option to satisfy all or a portion of their existing
Oglethorpe purchase obligations from other factors.suppliers. As a consequence of
Members' exercise of options under the Wholesale Power Contracts, Oglethorpe is
not currently engaged in long-term resource procurement for any Member other
than in connection with the anticipated acquisition of the Talbot EMC and
Chattahoochee EMC generation facilities. A number of Members have entered into
long-term contracts with third parties for all of their future requirements.
Accordingly, Oglethorpe does not expect to have significant direct exposure to
future changes in electricity prices or competition from other wholesale
suppliers.
Recently, many power marketers and traders have experienced financial
difficulties, which has reduced the liquidity of electric energy markets.
Oglethorpe has not suffered any material adverse effect in the energy trading it
conducts through ACES Power Marketing on behalf of Members that participate in
Oglethorpe's pool. Some of the Members may, however, have exposure to increased
market prices due to these developments.
Some states have implemented varying forms of retail competition among
power suppliers. Most other states are either in the process of implementing
retail competition or are studying options relating to retail competition.
Proposed federal legislation could mandate or encourage retail competition in
every state and otherwise deregulate the industry. No legislation related to retail competition has yet been
enacted in Georgia, and no bill is currently pending in the Georgia legislature
which would amend the Georgia Territorial Electric Service Act (the "Territorial
Act") or otherwise affect the exclusive right of the Members to supply power to
their current service territories. As a
36
result of the GPSC's order in the 1998 GPC rate case, the GPSC opened a docket
to address the mechanics of how stranded costs and stranded benefits should be
calculated, the estimated range of stranded costs and benefits, the proper level
of cost recovery, and the proper disposition of any stranded benefits. The GPSC does not have the authority under
43
Georgia law to order retail competition or amend the Territorial Act. Oglethorpe and the Members have voluntarily provided
information and are participating in the GPSC proceedings. Oglethorpe and the
Members are also actively monitoring and studying legislative initiatives in
Congress and in other states to take advantage of the experiences of
cooperatives and other utilities in other states to protect their interests in
any future legislative activities in Georgia.
Under current Georgia law, the Members generally have the exclusive right
to provide retail electric service in their respective territories. Since 1973,
however, the Territorial Act has permitted limited competition among electric
utilities located in Georgia for sales of electricity to certain large
commercial or industrial customers. The owner of any new facility may receive
electric service from the power supplier of its choice if the facility is
located outside of municipal limits and has a connected load upon initial full
operation of 900 kilowatts or more. The Members, with Oglethorpe's support, are
actively engaged in competition with other retail electric suppliers for these
new commercial and industrial loads. While the competition for 900-kilowatt
loads represents only limited competition in Georgia, this competition has given
Oglethorpe and the Members the opportunity to develop resources and strategies
to prepare for an increasingly competitive market.
Oglethorpe cannot predict at this time the outcome of the various
developments that may lead to increased competition in the electric utility
industry or the effect of such developments on Oglethorpe or the Members.
Nonetheless, Oglethorpe has taken several steps to prepare for and adapt to the
fundamental changes that have occurred or appear likely to occur in the electric
utility industry and to reduce stranded costs. In 1997, Oglethorpe divided
itself into separate generation, transmission and system operations companies in
order to better serve its Members in a deregulated and competitive environment.
Oglethorpe also has pursued an interest cost reduction program, which has
included refinancings and prepayments of various debt issues, and that has
provided significant cost savings. Oglethorpe has also entered into arrangements
with power marketers to reduce power costs and to provide for future load
requirements without taking all the risk associated with traditional suppliers.
(See "Results of Operations--Power Marketer Arrangements.")
Oglethorpe andand/or the Members continue to consider and evaluate a wide array of other
potential actions to meet future power supply needs, to reduce costs, to reduce
risks of the increasingly competitive generation business and to respond more
effectively to increasing competition. Among the alternatives
subject to such consideration are:Alternatives that could be considered
include:
o additional power marketing arrangements or other alliance arrangements;
o whether potential load fluctuation risks in a competitive retail
environment can be shifted to other wholesale suppliers;
o whether power supply requirements will continue to be met by the current
mix of ownership and purchase arrangements;
o whether future power supply resources will be owned by Oglethorpe or by
other entities;
o whether disposition of existing assets or asset classes would be advisable;
o the effects of nuclear license extensions;
o ways to facilitateextend the prepaymentmaturity of RUS-guaranteed indebtedness;indebtedness in connection
with extension(s) of plant operating licenses;
o the potential to prepay debt;
o the effects of proliferation of non-core services offered by electric
utilities; and
o other regulatory and business changes that may affect relative values of
generation classes or have impacts on the electric industry.
These activities are in various stages of study and consideration. Such
studies and consideration necessarily would take account of and are subject to legal,
regulatory and contractual (including financing and plant co-ownership
arrangements) considerations.
Under the Wholesale Power Contracts, the Members may satisfy all or a
portion of their requirements above their existing Oglethorpe purchase
obligations with purchases from Oglethorpe or other suppliers. The Members are
now purchasing varying portions of their requirements from other suppliers.
37
Many Members are also providing or considering proposals to provide
non-traditional products and services such as telecommunications and other
services. In 2002, the Georgia legislature enacted legislation empowering the
GPSC to authorize Member affiliates to market natural gas. The GPSC is required
to condition such authorization on terms designed to ensure that
cross-subsidizations do not occur between the electricity services of a Member
and the gas activities of its gas affiliates.
44
Depending on the nature of future competition in Georgia, there could be
reasons for the Members to separate their physical distribution business from
their energy business, or otherwise restructure their current businesses to
operate more effectively under retail competition.
Oglethorpe's ongoing consideration ofOglethorpe will continue to consider industry trends and developments, in
general, and specifically its strategic alternatives with respect to existing
and future power supply arrangements and its efforts to explore debt prepayments
with RUS, may present opportunities for Oglethorpe to reduce costs, reduce risks
and otherwise to respond more effectively to increasing competition. However,
Oglethorpebut
cannot predict at this time the results of these matters or any action
Oglethorpe might take based thereon.
Oglethorpe has deferred recognitionOther New Accounting Pronouncements
In April 2002, the FASB issued SFAS No. 145, "Rescission of certain costsFASB Statements
No. 4, 44, and 64, Amendment of providing servicesFASB Statement No. 13, and Technical
Corrections." Among other things, this statement rescinds SFAS No. 4, "Reporting
Gains and Losses from Extinguishment of Debt" (SFAS No. 4), which required all
gains and losses from extinguishment of debt to be aggregated and, if material,
classified as an extraordinary item, net of the Members and certainrelated income items pursuant to Statementtax effect. As a
result, the criteria in Accounting Principles Board Opinion No. 30, "Reporting
the Results of Financial
Accounting Standards (SFAS) No. 71, "Accounting forOperations - Reporting the Effects of Certain TypesDisposal of Regulation.a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," Note 1which requires gains and losses on extinguishments of Notesdebt to Financial Statements sets forth thebe
classified as income or loss from continuing operations, will now be applied.
SFAS No. 71 permits Oglethorpe to record gains and losses from early
extinguishment of debt as regulatory assets and liabilities reflected on Oglethorpe's balance sheet asregulatory liabilities.
Oglethorpe anticipates that any future gains and losses from early
extinguishment of December 31, 2000. Regulatory assets represent certain costs that are assured to
be recoverable by Oglethorpe from the Members in the future through the
ratemaking process. Regulatory liabilities represent certain items of income
that are being retained by Oglethorpe and thatdebt will be applied in the future to
reduce Member revenue requirements. (See "General--Rates and Regulation.") In
the event that competitive or other factors result in cost recovery practices
under which Oglethorpe can no longer apply the provisions of SFAS No. 71,
Oglethorpe would be required to eliminate allrecorded as regulatory assets and liabilities
that could not otherwise be recognized as assets and liabilities by businesses
in general. In addition,regulatory
liabilities. Oglethorpe would beis required to determine any
impairment to other assets, including plant, and write-down those assets, if
impaired, to their fair value.
Decommissioning Costs
The staff ofadopt SFAS No. 145 effective January 1,
2003.
In July 2002, the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry regarding
the recognition, measurement and classification of decommissioning costs for
nuclear generating facilities in financial statements of electric utilities. In
response to these questions, the Financial Accounting Standards Board hasFASB issued an Exposure Draft of a proposed Statement onSFAS No. 146, "Accounting for Certain Liabilities
Related to ClosureCosts
Associated with Exit or Removal of Long-Lived Assets." The proposed Statement
would require the recognition of the entire obligation for decommissioning at
its present value as a liability in theDisposal Activities"(SFAS No.146), which addresses
financial statements. Rate-regulated
utilities would also recognize an offsetting asset for differences in the timing
of recognition of the costs of decommissioning for financial reporting and
ratemaking purposes. Oglethorpe's management does not believe that this proposed
Statement would have an adverse effect on results of operations due to its
current and future ability to recover decommissioning costs through rates.
Assuming extensions of the respective licenses are not obtained, it is
expected that Plant Hatch and Plant Vogtle will begin the decommissioning
process in 2014 and 2027, respectively. The expected timing of payments for
decommissioning costs will extend for a period of 9 to 14 years. Oglethorpe's
management does not expect such payments to have an adverse impact on liquidity
or capital resources due to available amounts that have been placed in reserves
for this purpose.
New Accounting Pronouncement
As of January 1, 2001, Oglethorpe adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The standard establishes accounting and reporting for costs associated with exit or disposal
activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring" (EITF 94-3). The
principal difference between SFAS No. 146 and EITF 94-3 relates to SFAS No.
146's requirements for derivative instruments, including
certain derivative instruments embedded in other contracts, and hedging
activities. It requires the recognition of all derivative instruments as assetsa liability for a cost associated with an
exit or liabilities in Oglethorpe's balance sheet and measurement of those
instruments at fair value. The accounting treatment of changes in fair value is
38
dependent upon whether or not a derivative instrument is designated as a hedge
and if so, the type of hedge. Oglethorpe's interest rate swap arrangements in
place at December 31, 2000 are designated as cash flow hedges. Adoption ofdisposal activity. SFAS No. 133 on146 requires that a liability for a cost
associated with an exit or disposal activity be recognized when the liability is
incurred. Under EITF 94-3, a liability for an exit cost as generally defined in
EITF 94-3 was recognized at the date of an entity's commitment to an exit plan.
Oglethorpe is required to adopt SFAS No. 146 effective January 1, 2001, resulted in recording $33,515,000 of decline in fair
value to accumulated other comprehensive income and a comparable increase in
other liabilities.2003. This
pronouncement currently does not affect Oglethorpe's financial statements.
Inflation
As with utilities generally, inflation has the effect of increasing the
cost of Oglethorpe's operations and construction program. Operating and
construction costs have been less affected by inflation over the last few years
because rates of inflation have been relatively low.
Forward-Looking Statements and Associated Risks
This Annual Report on Form 10-K contains forward-looking statements,
including statements regarding, among other items, (i) anticipated trends in
Oglethorpe's business, (ii) Oglethorpe's and the Members' future power supply
requirements, resources and arrangements and (iii) disclosures regarding market
risk included in Item 7A. Some forward-looking statements can be identified by
use of terms such as "may," "will," "expects," "anticipates," "believes,"
"intends," "projects""projects," "plans" or similar terms. These forward-looking
statements are based largely on Oglethorpe's current expectations and are
subject to a number of risks and uncertainties, certainsome of which are beyond
Oglethorpe's control. For certainsome of the factors that could cause actual results to
differ materially from those anticipated by these forward-looking statements,
see "Competition""Summary of Critical Accounting Policies and Cooperative Operations" and
"Miscellaneous-Competition" herein and
"OGLETHORPE'S POWER SUPPLY RESOURCES--Future Power Resources", "THE MEMBERS AND
THEIR POWER SUPPLY RESOURCES--Future Power Resources" and "FACTORS AFFECTING THE ELECTRIC UTILITY
INDUSTRINDUSTRY" in Item 1. In light of these risks and uncertainties, Oglethorpe can
give no assurance that events anticipated by the forward-looking statements
contained in this Annual Report will in fact transpire.
3945
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oglethorpe is exposed to market risk, including changes in interest rates,
in the value of equity securities, and in the market price of electricity.
Oglethorpe's use of derivative financial or commodity instruments is for the
purpose of mitigating business risks and is not for tradingspeculative purposes.
Oglethorpe has established aOglethorpe's Risk Management Committee to provideprovides general management
oversight and policy decision over all risk management activities, including
commodity trading, fuels management, insurance, debt management and investment
portfolio management. The committee consists of senior executive officers,
including the Chief Executive Officer and the Chief Operating Officer. The
committee has implemented a comprehensive risk management policy, which includes
authority limits and credit policies. The committee regularly meets, reviews
risk management reports and reports activities to the Audit Committee of the
Board of Directors.
Interest Rate Risk
Oglethorpe is exposed to the risk of changes in interest rates due to the
significant amount of financing obligations it has entered into, including fixed
and variable rate debt and interest rate swap transactions. Oglethorpe's
objective in managing interest rate risk is to maintain a balance of fixed and
variable rate debt that will lower its overall borrowing costs within reasonable
risk parameters. As part of this debt management strategy, Oglethorpe has a
guideline of having between 15% and 30% variable rate debt to total debt. At
December 31, 2000,2002, Oglethorpe had 14%23% of its debt in a variable rate mode. The
amount of variable rate debt is expected to decrease to approximately 13% when
the RUS-guaranteed loans fund the acquisition of the Talbot EMC and
Chattahoochee EMC generation facilities and Oglethorpe uses the proceeds to
retire commercial paper, which is expected to occur in the second quarter of
2003.
The table below details Oglethorpe's existing debt instruments and provides
the fair value at December 31, 2000,2002, the outstanding balance at the beginning
and end of each year and the annual principal maturities and associated average
interest rates.
(dollars in thousands)
Fair Value Cost
----------- ------------------------------------------------------------------------------
2000 2001---------- ------------------------------------------------------------------------------------
2002 2003 2004 2005 2006 2007 Thereafter
---- ---- ---- ---- ---- ---- ----------
Fixed Rate Debt
- ---------------
Beginning of year $2,438,663 $2,321,527 $2,219,056 $2,059,686 $1,939,763 $1,810,010$ 2,186,016 $ 2,071,836 $ 1,951,023 $ 1,820,377 $ 1,684,081 $ 1,539,888
Maturities (117,136) (102,471) (159,370) (119,923) (129,753)
--------- --------- --------- --------- ---------(114,180) (120,813) (130,646) (136,296) (144,193)
----------- ----------- ----------- ----------- -----------
End of year $2,644,443 $2,321,527 $2,219,056 $2,059,686 $1,939,763 $1,810,010
========= ========= ========= ========= =========$ 2,657,314 $ 2,071,836 $ 1,951,023 $ 1,820,377 $ 1,684,081 $ 1,539,888
----------- ----------- ----------- ----------- -----------
Average interest rate 6.09% 6.07% 6.18%rate(1) 6.02% 6.04% 6.06% 6.08% 6.09% 6.48%6.11% 6.47%
Variable Rate Debt
- ------------------
Beginning of year $ 447,031521,758 $ 441,492517,625 $ 436,911513,471 $ 386,218509,293 $ 381,545 $376,810505,088 $ 500,853
Maturities (5,539) (4,581) (50,693) (4,673) (4,735)
--------- --------- --------- --------- ---------(4,133) (4,154) (4,178) (4,205) (4,235)
----------- ----------- ----------- ----------- -----------
End of year $443,924 $ 441,492469,245 $ 436,911517,625 $ 386,218513,471 $ 381,545509,293 $ 376,810
========= ========= ========= ========= =========505,088 $ 500,853
----------- ----------- ----------- ----------- -----------
Average interest rate(1) 5.37% 5.35% 5.46% 5.51% 5.46% 4.71%(2) 4.41% 4.58% 4.58% 4.79% 4.79% 3.94%
Interest Rate Swaps(2)
- -------------------Swaps
Beginning of year $ 260,149 $ 256,001 $ 251,420 $ 246,536 $ 241,315 $238,343
Maturities (4,148) (4,581) (4,884) (5,221) (2,972)
--------- --------- --------- --------- ---------
End of year $260,149 $ 256,001 $ 251,420 $ 246,536 $ 241,315 $ 238,343 ========= ========= ========= ========= =========$ 232,191 $ 222,086
Maturities (4,884) (5,221) (2,972) (6,152) (10,105)
----------- ----------- ----------- ----------- -----------
End of year $ 251,420 $ 246,536 $ 241,315 $ 238,343 $ 232,191 $ 222,086
----------- ----------- ----------- ----------- -----------
Average interest rate 5.82%rate(1) 5.83% 5.83% 5.67% 5.83% 5.67%5.77% 5.80%
Unrealized loss on swaps ($33,515)$ (58,443)
- ----------
(1) Average interest rates relate to the applicable principal maturities.
(2) Future variable debt interest rates are adjusted based on a forward U.S.
Treasury yield curve.
(2) The interest rate swaps converted variable rate underlying debt to a fixed
rate.
4046
Interest Rate Swap Transactions
To refinance high-interest rate PCBs, Oglethorpe entered intohas two interest rate swap transactions with a swap
counterparty, AIG Financial Products Corp. ("AIG-FP"), which were designed to
create a contractual fixed rate of interest on $322 million of variable rate
PCBs. These transactions were entered into in early 1993 on a forward basis,
pursuant to which approximately $200 million of variable rate PCBs were issued
on November 30, 1993 and approximately $122 million of variable rate PCBs were
issued on December 1, 1994. Oglethorpe is obligated to pay the variable interest
rate that accrues on these PCBs; however, the swap arrangements provide a
mechanism for Oglethorpe to achieve a contractual fixed rate which is lower than
Oglethorpe would have obtained had it issued fixed rate bonds. Oglethorpe's use
of interest rate derivatives is currently limited to these two swap
transactions.
In connection with GTC's assumption of liability on a portion of the PCBs
pursuant to the corporate restructuring by which GTC became a separate company,
commencing April 1, 1997, GTC assumed and agreed to pay 16.86% of any amounts
due from Oglethorpe under these swap arrangements, including the net swap
payments and termination payments described below. Should GTC fail to make such
payments under the assumption, Oglethorpe remains obligated for the full amount
of such payments.
Under the swap arrangements, Oglethorpe is obligated to make periodic
payments to AIG-FP based on a notional principal amount equal to the aggregate
principal amount of the bonds outstanding during the period and a contractual
fixed rate ("Fixed Rate"), and AIG-FP is obligated to make periodic payments to
Oglethorpe based on a notional principal amount equal to the aggregate principal
amount of the bonds outstanding during the period and a variable rate equal to
the variable rate of interest accruing on the bonds during the period ("Variable
Rate"). These payment obligations are netted, such that if the Variable Rate is
less than the Fixed Rate, Oglethorpe makes a net payment to AIG-FP. Likewise, if
the Variable Rate is higher than the Fixed Rate, Oglethorpe receives a net
payment from AIG-FP. Thus, although changes in the Variable Rate affect whether
Oglethorpe is obligated to make payments to AIG-FP or is entitled to receive
payments from AIG-FP, the effective interest rate Oglethorpe pays with respect
to the PCBs is not affected by changes in interest rates. The Fixed Rate for the
$200 million of variable rate bonds issued in 1993 is 5.67% and the Fixed Rate
for the $122 million of variable rate bonds issued in 1994 is 6.01%. At December
31, 2000,2002, the bonds issued in 1993 carried a variable rate of interest of 4.90%1.5%
and the bonds issued in 1994 carried a variable rate of interest of 4.95%1.6%. For
the three years ended December 31, 1998, 19992000, 2001 and 2000,2002, Oglethorpe has made in
connection with both interest rate swap arrangements combined net swap payments
to AIG-FP (net of amounts assumed by GTC) of $6.3$4.3 million, $8.1 million and
$6.7 million, and
$4.3$11.2 million, respectively.
The swap arrangements extend for the life of these PCBs. If the swap
arrangements were to be terminated while the PCBs are still outstanding,
Oglethorpe or AIG-FP may owe the other party a termination payment depending on
a number of factors, including whether the fixed rate then being offered under
comparable swap arrangements is higher or lower than the Fixed Rate. Under the
terms of the swap agreements, AIG-FP has limited rights to terminate the swaps
only upon the occurrence of specified events of default or a reduction in
ratings on Oglethorpe's PCBs, without credit enhancement, to a level that is
below investment grade. Oglethorpe estimates that its maximum aggregate
liability (net of GTC's assumed percentage) for termination payments under both
swap arrangements had such payments been due on December 31, 20002002 would have
been approximately $33.5$58 million. Scherer Unit No. 2Except in situations where Oglethorpe
voluntarily elects to terminate the interest rate swaps early, Oglethorpe has
the right to a term-out of any termination payment due to the swap counterparty
for a term of up to five years.
47
Capital LeaseLeases
In December 1985, Oglethorpe sold and subsequently leased back from four
purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The
capital leases provide that Oglethorpe's rental payments vary to the extent of
interest rate changes associated with the debt used by the lessors to finance
their purchase of undivided ownership shares in the unit. The debt currently
consists of $224,702,000$169,185,000 in serial facility bonds due June 30, 2011 with a 6.97%
fixed rate of interest.
41
Oglethorpe entered into a power purchase and sale agreement with Doyle I,
LLC (Doyle Agreement) to purchase all of the output from a five-unit gas-fired
generation facility. The Doyle Agreement is reported on Oglethorpe's balance
sheet as a capital lease. The lease payments vary to the extent the interest
rate on the lessor's debt varies from 6.00%. At December 31, 2002, the weighted
average interest rate on the lease obligation was 6.61%.
Equity Price Risk
Oglethorpe maintains trust funds, as required by the NRC, to fund certain
costs of nuclear decommissioning. (See Note 1 of Notes to Financial Statements
in Item 8.Statements.)
As of December 31, 2000,2002, these funds were invested primarily in
domestic equity securities, U.S. Government
and corporate debt securities and asset-backed securities and domestic equity
securities. By maintaining a portfolio that includes long-term equity
investments, Oglethorpe intends to maximize the returns to be utilized to fund
nuclear decommissioning, which in the long-term will better correlate to
inflationary increases in decommissioning costs. However, the equity securities
included in Oglethorpe's portfolio are exposed to price fluctuation in equity
markets. A 10% decline in the value of the fund's equity securities as of
December 31, 20002002 would result in a loss of value to the fund of approximately
$9$7 million. Oglethorpe actively monitors its portfolio by benchmarking the
performance of its investments against certain indexes and by maintaining, and
periodically reviewing, established target allocation percentages of the assets
in its trusts to various investment options. Because realized and unrealized
gains and losses from investment securities held in the decommissioning fund are
directly added to or deducted from the decommissioning reserve, fluctuations in
equity prices or interest rates do not affect Oglethorpe's net margin in the short-term.
Commodity Price Risk
Electricity
The market price of electricity is subject to price volatility associated
with changes in supply and demand in electricity markets. Oglethorpe's exposure
to electricity price risk relates to managing the supply of energy to the
Members. To secure a firm supply of electricity and to limit price volatility
associated with electricity purchases, Oglethorpe has taken several actions.
Oglethorpe suppliesobtains substantially all of the Members' requirementspower it supplies to the Members
from a combination of owned and leased generating plants and power purchased under long-term
contracts with power marketers and other power suppliers and power marketers.suppliers. Therefore, only a
small percentage of Oglethorpe's requirements is purchased in the short-term
market, and further only a small portion of these requirements is covered by
derivative commodity instruments. Oglethorpe enters into short-term options and
forward contracts for the delivery of energy on behalf of Members that
participate in Oglethorpe's pool. Oglethorpe's market price risk exposure on
these instruments is not material. Oglethorpe has entered into a service agreement with ACES Power Marketing
("APM") under which APM acts as Oglethorpe's agentSee "OGLETHORPE POWER Corporation--Expected
Facilities Acquisitions, RUS Loans And Other New Arrangements" in the purchase and sale of
short-term wholesale power. APM also provides related risk management services.
APM is subject to Oglethorpe's risk management policies, including trading
authority limits. APM is an organization owned by several generation and
transmission cooperatives that provides energy trading services to rural
electric cooperatives.Item 1.
Coal
Oglethorpe is also exposed to risks of changing prices for fuels, including
coal and natural gas. Oglethorpe has interests in 1,501 MW of coal-fired
capacity.capacity (Plants Scherer and Wansley). Oglethorpe purchases coal under long-term
contracts and in spot-market transactions. Oglethorpe's long-term coal contracts
provide volume flexibility and fixed prices. Oglethorpe anticipates that its
existing long-term contracts will provide fixed prices for substantially all of
its coal requirements for Plant Wansley through 2005. Additionally, such
contracts will provide about 50% of the forecasted coal requirements for Plant
48
Scherer in 2004 and 2005 and all of the expected requirements for Plant Scherer
in 2003.
The objective of Oglethorpe's coal procurement strategy is to ensure
reliable coal supply and some price stability for the Members. Its strategy
focuses on hedging requirements over a three-year time horizon, but permits
opportunities to make purchases up to six years into the future. The procurement
guidelines provide for layering in fixed prices by annually entering into
forward contracts for between 25% and 35% of the forecasted requirements, for a
rolling three-year period.
Natural Gas
Oglethorpe has severaltwo power purchase contracts under which approximately 805625
MW of capacity and associated energy is supplied by gas-fired facilities, including the
power purchase contracts with Doyle I (which Oglethorpe treats as a capital
lease) and Hartwell. Under these contracts, Oglethorpe is exposed to variable
energy charges, which incorporate each facility's actual operation and
maintenance and fuel costs. Oglethorpe has the right to purchase natural gas for
the Doyle and Hartwell facilities and exercises this right from time to time to
actively manage the cost of energy supplied from these contracts and the
underlying natural gas price and operational risks.
In providing operation management services for Smarr EMC, Oglethorpe
negotiatespurchases natural gas, supplyincluding transportation and transportation contractsother related services, on
behalf of Smarr EMC and ensures that the Smarr facilities have fuel available
for operations, and
42
assists Smarr EMC in managing its exposure to natural gas price and operational
risks.operations. Oglethorpe expects to provideis providing similar services for the gas-fired
combustion turbineTalbot EMC and
combined cycle projects currently under construction.Chattahoochee EMC. (See "OGLETHORPE POWER CORPORATION--Expected Facilities
Acquisitions, RUS Loans And Other New Arrangements" and "THE MEMBERS AND THEIR
POWER SUPPLY RESOURCES--Member Power Supply Resources" in Item 1 and
"PROPERTIES--Generating Facilities" and "--Fuel Supply" in Item 2.)
Oglethorpe purchaseshas entered into natural gas swap arrangements (1) to manage its
exposure to fluctuations in the market price of natural gas related to
Oglethorpe resources and (2) to assist Members in managing such exposure related
to Smarr EMC, Talbot EMC and Chattahoochee EMC. Under these swap agreements,
Oglethorpe pays the counterparty contractually a fixed price for specified
natural gas quantities and receives a payment for such quantities based on a
market price index. These payment obligations are netted, such that if the
market price index is lower than the fixed price, Oglethorpe will make a net
payment, and if the market price index is higher than the fixed price,
Oglethorpe will receive a net payment. If the natural gas swaps had been
terminated at December 31, 2002, Oglethorpe would have received a net payment of
$972,000 on the portion of the natural gas swaps related to Oglethorpe
resources. This amount does not include a net payment of $3,011,000 that
Oglethorpe would have received for the above purposesportion of the natural gas swaps related
to Smarr EMC, Talbot EMC and Chattahoochee EMC. Oglethorpe remains fully
obligated for any payments due under the swaps related to Smarr EMC, Talbot EMC
and Chattahoochee EMC, but is entitled to recover such amounts from Smarr EMC,
Talbot EMC and Chattahoochee EMC. Oglethorpe's market price risk exposure on
these agreements is not material. Oglethorpe expects to continue to manage
exposures to natural gas price risks only for a few of its Members that have
elected to receive such services.
ACES Power Marketing
Oglethorpe has a service agreement with ACES Power Marketing ("APM") under
which APM acts as Oglethorpe's agent in the purchase and sale of short-term
contractswholesale power on behalf of Members that cannot be settledparticipate in cash.the Oglethorpe currentlycapacity
and energy pool. (See "OGLETHORPE'S POWER SUPPLY RESOURCES--Capacity and Energy
Pool" in Item 1.) APM also provides related risk management services. APM is
subject to Oglethorpe's risk management policies, including trading authority
limits. APM is an organization owned by several generation and transmission
cooperatives (including Oglethorpe) that provides energy trading and natural gas
management services to rural electric cooperatives and others.
Oglethorpe has no derivative
commodity instrumentsan additional service agreement with respectAPM under which APM
provides services related to coal or natural gas.gas planning and procurement and acts as
49
Oglethorpe's agent for executing emergency system balancing transactions.
Changes in Risk Exposure
Oglethorpe's exposure to changes in interest rates, the price of equity
securities it holds, and electricitycommodity prices have not changed materially from the
previous reporting period. Oglethorpe is not aware of any facts or circumstances
that would significantly impact such exposurethese exposures in the near future.
4350
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index To Financial Statements
Page
Statements of Revenues and Expenses,
For the Years Ended December 31, 2000, 19992002, 2001 and 1998................... 45
Statements of Patronage Capital,
For the Years Ended December 31, 2000, 1999 and 1998................... 452000.................. 53
Balance Sheets, As of December 31, 20002002 and 1999.......................... 462001......................... 54
Statements of Capitalization, As of December 31, 20002002 and 1999............ 482001........... 56
Statements of Cash Flows,
For the Years Ended December 31, 2002, 2001 and 2000 1999................. 57
Statements of Patronage Capital and 1998 .................. 49Membership Fees
and Accumulated Other Comprehensive Margin
For the Years Ended December 31, 2002, 2001 and 2000 ................. 58
Notes to Financial Statements............................................. 50Statements............................................ 59
Report of Management...................................................... 63Management..................................................... 72
Report of Independent Accountants......................................... 63
44Accountants........................................ 72
51
[This Page Intentionally Left Blank]
52
STATEMENTS OF REVENUES AND EXPENSES
For the years ended December 31, 2002, 2001 and 2000
STATEMENTS OF REVENUES AND EXPENSES
For the years ended December 31, 2000, 1999 and 1998
(dollars in thousands)
2002 2001 2000
1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
====================================================================================================================================
Operating revenues (Note 1):
Sales to Members $ 1,146,0641,127,519 $ 1,122,3361,080,478 $ 1,095,9041,146,064
Sales to non-Members 35,802 58,811 53,333
53,896 48,263
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,163,321 1,139,289 1,199,397
1,176,232 1,144,167
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating expenses:
Fuel 216,952 196,182 191,399225,008 221,449 230,729
Production 215,834 215,517 198,378232,312 218,480 220,221
Purchased power (Note 9) 403,574 401,719 387,662357,491 414,382 377,805
Depreciation and amortization 142,082 130,883 124,074140,058 133,731 143,703
Income taxes (Note 3) - (63,485) -
- - -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 978,442 944,301 901,513954,869 924,557 972,458
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Operating margin 220,955 231,931 242,654208,452 214,732 226,939
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Other income (expense):
Investment income 42,897 33,262 27,76723,787 32,113 44,489
Amortization of deferred gains (Notes 1 and 4) 2,475 2,475 2,4862,475
Amortization of net benefit of sale of income
tax benefits (Note 1) 11,1955,188 11,195 11,195
Allowance for equity funds used during
construction (Note 1) 452 290 204
180 158
Other 4,009 5,272 4,068
3,433 687
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total other income 60,839 50,545 42,29335,911 51,345 62,431
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Interest charges:
Interest on long-term debt and capital leases 221,893 224,489 236,692205,360 220,525 227,877
Other interest 10,594 10,839 21,954 18,531 12,086
Allowance for debt funds used during construction (Note 1) (3,522) (1,570) (1,679)(3,152) (2,786) (1,930)
Amortization of debt discount and expense 14,021 19,082 21,491
21,088 16,768
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net interest charges 261,816 262,538 263,867226,823 247,660 269,392
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net margin $ 17,540 $ 18,417 $ 19,978
19,938 21,080
Net change in unrealized gain (loss) on
available-for-sale securities 2,679 (2,614) 1,112
- -----------------------------------------------------------------------------------------------------------------------------
Comprehensive margin $ 22,657 $ 17,324 $ 22,192
- -----------------------------------------------------------------------------------------------------------------------------
STATEMENTS OF PATRONAGE CAPITAL
For the years ended December 31, 2000, 1999 and 1998
(dollars in thousands)
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
Patronage capital and membership fees -
beginning of year (Note 1) $ 370,025 $ 352,701 $ 330,509
Comprehensive margin 22,657 17,324 22,192
- -----------------------------------------------------------------------------------------------------------------------------
Patronage capital and membership fees - end of year $ 392,682 $ 370,025 $ 352,701
- -----------------------------------------------------------------------------------------------------------------------------====================================================================================================================================
The accompanying notes are an integral part of these financial statements.
4553
BALANCE SHEETS
December 31, 2002 and 2001
BALANCE SHEETS
December 31, 2000 and 1999
(dollars in thousands)
2000 1999
- -----------------------------------------------------------------------------------------------------------------------------2002 2001
===================================================================================================================================
Assets
Electric plant (Notes 1, 4 and 6):
In service $ 4,883,6805,030,333 $ 4,854,0375,029,192
Less: Accumulated provision for depreciation (1,752,176) (1,625,933)(1,983,950) (1,881,918)
- -----------------------------------------------------------------------------------------------------------------------------
3,131,504 3,228,104-----------------------------------------------------------------------------------------------------------------------------------
3,046,383 3,147,274
Nuclear fuel, at amortized cost 83,470 84,56577,247 77,360
Construction work in progress 62,357 18,29969,282 38,564
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total electric plant 3,277,331 3,330,9683,192,912 3,263,198
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Investments and funds (Notes 1 and 2):
Decommissioning fund, at market 148,300 135,703154,061 150,668
Deposit on Rocky Mountain transactions, at cost 63,665 59,57972,698 68,032
Bond, reserve and construction funds, at market 29,167 31,15826,505 28,691
Investment in associated companies, at cost 19,997 17,919
Other, at cost 1,513 2,53528,244 22,918
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total investments and funds 262,642 246,894281,508 270,309
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Current assets:
Cash and temporary cash investments, at cost (Note 1) 330,622 222,814151,311 275,786
Other short-term investments, at market 81,715 75,48294,301 88,589
Receivables 143,353 109,70591,798 73,039
Inventories, at average cost (Note 1) 75,389 89,76683,219 81,768
Notes receivable (Note 5) 1,032 94,070310,662 340,396
Prepayments and other current assets 59,824 19,2933,841 4,346
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total current assets 691,935 611,130735,132 863,924
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Deferred charges:
Premium and loss on reacquired debt, being amortized (Note 5) 175,944 196,289151,118 162,690
Deferred amortization of Scherer leaseholdcapital leases (Note 4) 102,753 101,404
Discontinued projects, being amortized (Note 1) 9,490 28,020109,567 107,254
Deferred debt expense, being amortized 16,968 17,070
Other (Note 1) 31,107 32,84718,376 16,475
Deferred nuclear outage costs, being amortized (Note 1) 22,778 17,313
Other 7,160 11,668
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total deferred charges 336,262 375,630308,999 315,400
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total assets $ 4,568,1704,518,551 $ 4,564,622
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
464,712,831
===================================================================================================================================
The accompanying notes are an integral part of these financial statements.
54
BALANCE SHEETS
(dollars in thousands)
2000 1999
- -----------------------------------------------------------------------------------------------------------------------------2002 2001
====================================================================================================================================
Equity and Liabilities
Capitalization (see accompanying statements):
Patronage capital and membership fees (Note 1) $ 392,682371,818 $ 370,025367,668
Long-term debt 3,019,019 3,103,5902,835,997 2,929,316
Obligation under capital leases (Note 4) 267,449 275,224358,676 373,837
Obligation under Rocky Mountain transactions (Note 1) 63,665 59,57972,698 68,032
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total capitalization 3,742,815 3,808,4183,639,189 3,738,853
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Current liabilities:
Long-term debt and capital leases due within one year (Note 5) 136,053 129,419140,241 127,621
Accounts payable 114,964 69,55553,283 68,023
Notes payable (Note 5) 78,482 88,479297,776 353,680
Power marketer reserve (Note 9) - 36,000
Accrued interest 67,394 50,2016,958 7,793
Other current liabilities 23,691 9,34413,267 16,461
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 420,584 346,998511,525 609,578
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities:
Gain on sale of plant, being amortized (Note 4) 53,332 55,80748,383 50,858
Net benefit of sale of income tax benefits, being amortized (Note 1) 10,012 18,021- 2,002
Net benefit of Rocky Mountain transactions, being amortized (Note 1) 82,819 86,004
Accumulated deferred income taxes (Note 3) 63,485 63,20376,448 79,633
Decommissioning reserve (Note 1) 174,553 164,510166,299 174,506
Interest rate swap arrangements (Note 2) 58,443 36,859
Other 20,570 21,66118,264 20,542
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 404,771 409,206367,837 364,400
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total equity and liabilities $ 4,568,170 $ 4,564,622
- -----------------------------------------------------------------------------------------------------------------------------$4,518,551 $4,712,831
====================================================================================================================================
Commitments and Contingencies (Notes 41, 5 and 9)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
4755
STATEMENTS OF CAPITALIZATION
December 31, 2002 and 2001
STATEMENTS OF CAPITALIZATION
December 31, 2000 and 1999
(dollars in thousands)
2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
2002 2001
====================================================================================================================================
Long-term debt (Note 5):
Mortgage notes payable to the Federal Financing Bank (FFB) at interest
rates varying from 4.66%2.81% to 8.43% (average rate of 6.40%6.34% at December
31, 2000)2002) due
in quarterly installments through 2023 $2,248,502 $2,326,730$ 2,050,969 $ 2,141,746
Mortgage notes payable to the Rural Utilities Service (RUS) at an interest rate of
5% due in monthly installments through 2021 13,344 13,74912,473 12,919
Mortgage notes issued in conjunction with the sale by public authorities of pollution
control revenue bonds (PCBs):
o Series 1992A
Serial bonds, 5.95%6.20% to 6.80%, due serially from 20012003 through 2012 107,820* 113,745*94,915 101,555*
o Series 1993
Serial bonds, 4.35%4.60% to 5.25%, due serially from 20012003 through 2013 33,410* 34,544*30,510 32,060*
o Series 1993A
Adjustable tender bonds, 4.90%1.50%, due 20012003 through 2016 192,420* 195,015*186,710 189,660*
o Series 1993B
Serial bonds, 4.35%4.60% to 5.05%, due serially from 20012003 through 2008 105,980* 113,750*86,525 96,900*
o Series 1994
Serial bonds, 6.0%6.25% to 7.125%, due serially from 20012003 through 2015 8,930* 9,315*8,560 8,560*
Term bonds, 7.15%, due 2016 to 2021 11,550*11,550 11,550*
o Series 1994A
Adjustable tender bonds, 4.95%1.60%, due 20012003 to 2019 120,500* 122,740*115,710 118,270*
o Series 1994B
Serial bonds, 6.00%6.25% to 6.45%, due serially from 20012003 through 2005 7,585* 9,125*5,670 5,970*
o Series 1998A Adjustable tender bonds, 4.10% to 4.40%, due 2019 116,925* 116,925*
o Seriesand 1998B
Adjustable tender bonds, 4.10%1.05% to 4.45%1.70%, due 2019 100,000* 100,000*216,925 216,925*
o Series 1999A Adjustable tender bonds, 5.10%, due 2020 20,070 20,070
o Seriesand 1999B
Adjustable tender bonds, 5.10%1.80%, due 2020 68,705 68,70588,775 88,775
o Series 2000
Adjustable tender bonds, 1.80%, due 2021 21,950 21,950
o Series 2001
Adjustable tender bonds, 1.80%, due 2022 22,825 22,825
o Series 2002A and 2002B
Auction rate bonds, 1.40% to 1.45%, due 2018 91,990 -
Unsecured notes issued in conjunction with the sale by public authorities of pollution
control revenue bonds:
o Series 20002002 and 2002C
Adjustable tender bonds, 5.10%1.60% to 1.80%, due 2021 21,9502018 30,075 -
CoBank, ACB notes payable:
o Headquarters mortgage note payable: fixed at 7.52%3.90% through July 31, 2001,February 2, 2003,
due in quarterly installments through January 1, 2009 3,212 3,6022,433 2,823
o Transmission mortgage note payable: fixed at 8.13%3.81% through February 28, 2001;March 2, 2003, due in
bi-monthlybimonthly installments through November 1, 2018 1,770 1,7971,705 1,740
o Transmission mortgage note payable: fixed at 8.13%3.81% through February 28, 2001;March 2, 2003, due in
bi-monthlybimonthly installments through September 1, 2019 6,815 6,9066,597 6,713
o Medium-term loan, variable at 7.23% to 7.36%, due at various maturities
through October 2001,Medium Term Loan
Variable rate, due March 31, 2003 46,065- 46,065
National Rural Utilities Cooperative Finance Corporation mortgage note payable:
o Medium-term loan, fixed at 6.575%,Fixed rate, due March 31, 2003 46,065- 46,065
- -----------------------------------------------------------------------------------------------------------------------------
3,281,618 3,360,398
*Less:------------------------------------------------------------------------------------------------------------------------------------
3,086,867 3,173,071
Less: Portion (16.86%) of PCBs assumed by Georgia Transmission Corporation (135,775) (135,775)(127,673) (131,784)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt, net 3,145,843 3,224,6232,959,194 3,041,287
Less:Long-term debt due within one year (126,824) (121,033)(123,197) (111,971)
- -----------------------------------------------------------------------------------------------------------------------------
Long-term------------------------------------------------------------------------------------------------------------------------------------
Total long-term debt, excluding amount due within one year 3,019,019 3,103,5902,835,997 2,929,316
Obligation under capital leases, long-term (Note 4) 267,449 275,224358,676 373,837
Obligation under Rocky Mountain transactions, long-term (Note 1) 63,665 59,57972,698 68,032
Patronage capital and membership fees (Note 1) 392,682 370,025371,818 367,668
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total capitalization $3,742,815 $3,808,418
- -----------------------------------------------------------------------------------------------------------------------------$ 3,639,189 $ 3,738,853
====================================================================================================================================
The accompanying notes are an integral part of these financial statements.
4856
STATEMENTS OF CASH FLOWS
For the years ended December 31, 2002, 2001 and 2000
STATEMENTS OF CASH FLOWS
For the years ended December 31, 2000, 1999 and 1998
(dollars in thousands)
2002 2001 2000
1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
====================================================================================================================================
Cash flows from operating activities:
Net margin $ 17,540 $ 18,417 $ 19,978
$ 19,938 $ 21,080
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Adjustments to reconcile net margin to net cash provided by
operating activities:
Depreciation and amortization 188,870 177,065 170,466189,607 198,113 213,351
Interest on decommissioning reserve 851 168 11,007 12,266 9,716
Amortization of deferred gains (2,475) (2,474) (2,486)(2,475) (2,475)
Amortization of net benefit of sale of income tax benefits (11,195)(5,188) (11,195) (11,195)
Allowance for equity funds used during construction (452) (290) (204) (180) (158)
Deferred income taxes - (63,485) 283
Gain on sale of generation equipment - 86(221) -
Other (1,274) 1,215 453 1,465 491
Change in net currentoperating assets excluding long-term debt due
within one year:and liabilities:
Receivables (18,758) 70,315 (33,649)
1,214 (5,025)
Inventories (1,451) (6,379) 14,377 (12,983) (11,255)
Prepayments and other current assets 2,398 2,102 (8,865)505 204 1,832
Accounts payable 45,409 22,879 (4,427)(14,740) (34,596) 45,975
Power marketer reserve (36,000) 36,000 -
Accrued interest (835) (59,601) 17,192 40,128 (2,887)
Accrued and withheld taxes (622) 4 648 (188) (302)
Other current liabilities 5,936 (14,770) 13,698
(8,584) 9,472Deferred nuclear outage costs (29,139) (19,167) (24,481)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Total adjustments 85,965 93,840 246,812
221,515 143,631
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 103,505 112,257 266,790
241,453 164,711
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Property additions (108,254) (41,829) (43,904)(100,145) (69,824) (70,738)
Activity in decommissioning fund - Purchases (812,473) (532,355) (735,352) (608,471) (504,720)
- Proceeds 800,960 530,660 722,620 591,851 490,450
Activity in bond, reserve and construction funds - Purchases - (22,710) (12,699) (23,325) -
- Proceeds 1,677 23,699 15,319
24,053 893
Decrease (increase)Increase in other short-term investments (5,516) (6,423) (4,181) (3,718) 24,137
Increase in investment in associated organizations (6,057) (2,190) (2,078) (1,688) (291)
Decrease (increase) in notes receivable 63 2 (143) 97 60
Other - generation equipment deposits - (16,783) (42,929)
Proceeds from sale of generation equipment - 26,204 -
- - -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities (167,697) (63,030) (33,375)(121,491) (69,720) (130,181)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Debt proceeds, net 31,772 22,931 26,260 18,196 15,958
Debt payments (112,028) (127,381) (100,729) (68,517) (86,889)
Premium paid on refinancing of debt - - (24,041)
(Decrease) increase in notes payable (Note 5) (55,904) 275,198 (9,997)
37,493 50,986
Decrease (increase)Increase (decrease) in note receivable under interim financing
agreement (Note 5) 93,181 (49,016) (44,330)29,671 (268,121) 55,665
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in)used in financing activities 8,715 (61,844) (88,316)(106,489) (97,373) (28,801)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net (decrease) increase in cash and temporary cash investments (124,475) (54,836) 107,808 116,579 43,020
Cash and temporary cash investments at beginning of year 275,786 330,622 222,814
106,235 63,215
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year $330,622 $ 222,814151,311 $ 106,235
- -----------------------------------------------------------------------------------------------------------------------------275,786 $ 330,622
====================================================================================================================================
Supplemental cash flow information:
Cash paid for:for -
Interest (net of amounts capitalized) $212,126 $ 189,056212,787 $ 240,270278,785 $ 219,702
Income taxes - - -
Non cash transaction -
-----------------------------------------------------------------------------------------------------------------------------Capital lease - - 126,990
====================================================================================================================================
The accompanying notes are an integral part of these financial statements.
57
STATEMENTS OF PATRONAGE CAPITALAND MEMBERSHIP FEES AND ACCUMULATED OTHER
COMPREHENSIVE MARGIN
For the years ended December 31, 2002, 2001 and 2000
(dollars in thousands)
Patronage Accumulated
Capital and Other
Membership Comprehensive
Fees Margin (Loss) Total
====================================================================================================================================
Balance at December 31, 1999 $ 371,634 $ (1,609) $ 370,025
- ------------------------------------------------------------------------------------------------------------------------------------
Components of comprehensive margin in 2000
Net margin 19,978 19,978
Unrealized gain on available-for-sale securities 2,679 2,679
- ------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive margin 22,657
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 391,612 1,070 392,682
- ------------------------------------------------------------------------------------------------------------------------------------
Components of comprehensive margin in 2001
Net margin 18,417 18,417
Cumulative effect of accounting change to record unrealized
loss on interest rate swap arrangements as of January 1, 2001 (33,515) (33,515)
Unrealized loss on interest rate swap arrangements (3,344) (3,344)
Unrealized gain on available-for-sale securities 965 965
Unrealized loss on financial gas hedges (7,537) (7,537)
- ------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive margin (25,014)
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 410,029 (42,361) 367,668
- ------------------------------------------------------------------------------------------------------------------------------------
Components of comprehensive margin in 2002
Net margin 17,540 17,540
Unrealized loss on interest rate swap arrangements (21,584) (21,584)
Unrealized loss on available-for-sale securities (313) (313)
Unrealized gain on financial gas hedges 8,507 8,507
- ------------------------------------------------------------------------------------------------------------------------------------
Total comprehensive margin 4,150
- ------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 $ 427,569 $ (55,751) $ 371,818
====================================================================================================================================
49The accompanying notes are an integral part of these financial statements.
58
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2000, 19992002, 2001 and 19982000
1. Summary of significant accounting policies:
a. Business description
Oglethorpe Power Corporation (Oglethorpe) is an electric membership
corporation incorporated in 1974 and headquartered in suburban Atlanta.
Oglethorpe provides wholesale electric service,power, on a not-for-profit basis, to 39
of Georgia's 42 Electric Membership Corporations (EMCs). from a combination of
generating units totaling 3,657.9 megawatts (MW) of capacity and power purchase
agreements totaling 550 MW of capacity. These 39 electric distribution
cooperatives (Members) in turn distribute energy on a retail basis to
approximately 3.43.7 million people across two-thirds of the State. Oglethorpe is
the nation's largest electric cooperative in terms of operating revenues,
assets, kilowatt-hour sales and, through its Members, consumers served.
Oglethorpe owns or leases undivided interests in thirteen generating units
totaling 3,335 megawatts (MW) of capacity. Oglethorpe also purchases a total of
1200 MW of capacity pursuant to power purchase agreements.
b. Basis of accounting
Oglethorpe follows generally accepted accounting principles and the
practices prescribed in the Uniform System of Accounts of the Federal Energy
Regulatory Commission (FERC) as modified and adopted by the Rural Utilities
Service (RUS).
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities as of December 31, 20002002 and 19992001
and the reported amounts of revenues and expenses for each of the three years
ending December 31, 2000.2002. Actual results could differ from those estimates.
c. Patronage capital and membership fees
Oglethorpe is organized and operates as a cooperative. The Members paid a
total of $195 in membership fees. Patronage capital includes retained net margin
of Oglethorpe and the unrealized gain or loss on available-for-sale securities,other comprehensive margin, excluding securities held in the
decommissioning fund. For 2000, 19992002, 2001 and 19982000 the unrealized gain or loss on available-for-sale securities werein
other comprehensive margin was ($55,751,000), ($42,361,000), and $1,070,000,
($1,609,000) and $1,005,000, respectively. As provided(See "Fair value of financial instruments" in the bylaws, anyNote 2.) Any excess
of revenue over expenditures from operations is treated as advances of capital
by the Members and is allocated to each of them on the basis of their
electricity purchases from Oglethorpe.
Any distributions of patronage capital are subject to the discretion of the
Board of Directors, subject to Mortgage Indenture requirements. Under the
Mortgage Indenture, Oglethorpe is prohibited from making any distribution of
patronage capital to the Members if, at the time thereof or giving effect
thereto, (i) an event of default exists under the Mortgage Indenture, (ii)
Oglethorpe's equity as of the end of the immediately preceding fiscal quarter is
less than 20% of Oglethorpe's total capitalization, or (iii) the aggregate
amount expended for distributions on or after the date on which Oglethorpe's
equity first reaches 20% of Oglethorpe's total capitalization exceeds 35% of
Oglethorpe's aggregate net margins earned after such date. This last
restriction, however will not apply if, after giving effect to such
distribution, Oglethorpe's equity as of the end of the immediately preceding
fiscal quarter is not less than 30% of Oglethorpe's total capitalization.
d. Margin policy
For the years 19982000 through 20002002 under the Mortgage Indenture, Oglethorpe
was required to produce a Margins for Interest (MFI) Ratio of at least 1.10.
e. Operating revenues
Operating revenues consist primarily of electricity sales pursuant to
long-term wholesale power contracts which Oglethorpe maintains with each of its
Members. These wholesale power contracts obligate each Member to pay Oglethorpe
for capacity and energy furnished in accordance with rates established by
Oglethorpe. Energy furnished is determined based on meter readings which are
50
conducted at the end of each month. Actual energy costs are compared, on a
monthly basis, to the billed energy costs, and an adjustment to revenues is made
such that energy revenues are equal to actual energy costs.
Revenues from JacksonCobb EMC and CobbJackson EMC, two of Oglethorpe's Members,
accounted for 11.8%11.3% and 11.2% in 2002, 11.6% and 12.1% in 2001, 11.9% and 11.8%
in 2000, 11.8% and 11.7% in 1999, and 11.4% and
12.8% in 1998, respectively, of Oglethorpe's total operating revenues.
f. Nuclear fuel cost
The cost of nuclear fuel, including a provision for the disposal of spent
fuel, is being amortized to fuel expense based on usage. The total nuclear fuel
expense for 2000, 19992002, 2001 and 19982000 amounted to $47,105,000, $46,226,000$43,931,000, $47,143,000 and
$46,751,000,$47,105,000, respectively.
Contracts with the U.S. Department of Energy (DOE) have been executed to
provide for the permanent disposal of spent nuclear fuel. DOE failed to begin
disposing of spent fuel in January 1998 as required by the contracts, and
Georgia Power Company (GPC), as agent for the co-owners of the plants, is
pursuing legal remedies against DOE for breach of contract. Effective June 2000,
an on-site dry storage facility for Plant Hatch became operational. SufficientBased on
normal operations and retention of all spent fuel in the reactor, sufficient
59
capacity is believed to be available to continue dry storage operations at Plant
Hatch throughfor the life of the plant. The Plant VogtleVogtle's spent fuel pool storage is
expected to be sufficient intountil 2014. In addition, GPC, as agent forOglethorpe expects that procurement of
on-site dry storage at Plant Vogtle will commence in sufficient time to maintain
full-core discharge capability to the
co-owners of the plant, is a member of Private Fuel Storage, LLC, a joint
utility effort to develop a private spent fuel storage facility for temporary
storage of spent nuclear fuel. This facility is planned to begin operation as
early as the year 2003; however, the timing of availability is uncertain.pool.
The Energy Policy Act of 1992 required that utilities with nuclear plants
be assessed over a 15-year period an amount which will be used by DOE for the
decontamination and decommissioning of its nuclear fuel enrichment facilities.
The amount of each utility's assessment was based on its past purchases of
nuclear fuel enrichment services from DOE. Based on its ownership in Plants
Hatch and Vogtle, Oglethorpe has a remaining nuclear fuel asset of approximately
$9,463,000,$6,759,000, which is being amortized to nuclear fuel expense over the next 106
years. Oglethorpe has also recorded an obligation to DOE which approximated
$7,085,000$4,723,000 at December 31, 2000.2002.
g. Nuclear decommissioning
Oglethorpe's portion of the costs of decommissioning co-owned nuclear
facilities is estimated as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
Hatch Hatch Vogtle Vogtle
Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2
- --------------------------------------------------------------------------------
Year of site study 2000 2000 2000 2000
Expected start date
of decommissioning 2014 2018 2027 2029
Decommissioning cost:
Discounted $139,000 $175,000 $137,000 $171,000
Undiscounted 265,000 400,000 475,000 650,000
- --------------------------------------------------------------------------------
TheNuclear decommissioning cost estimates are based on site studies and assume
prompt dismantlement and removal of both the radiated and non-radiated portions
of the plant from service. The actual decommissioningActual decommis-sioning costs may vary from the abovethese
estimates because of changes in the assumed date of decommissioning, changes in
regulatory requirements, changes in technology, and changes in costs of labor,
materials and equipment. Based onInformation with respect to Oglethorpe's portion of the
most recentestimated costs of decommissioning co-owned nuclear facilities is as follows:
==============================================================================================================
(dollars in thousands)
Hatch Hatch Vogtle Vogtle
Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2
==============================================================================================================
Year of site study 2000 2000 2000 2000
Expected start date
of decommissioning 2034 2038 2027 2029
Estimated costs based on site study:
In year 2000 dollars $ 139,000 $ 175,000 $ 137,000 $ 171,000
In projected future
dollars 666,000 1,007,000 475,000 650,000
==============================================================================================================
In projecting future costs, the escalation rate for labor, materials and
equipment was assumed to be 4.72%.
Oglethorpe's objective is to provide a reserve for nuclear decommis-sioning
at least equal to the Nuclear Regulatory Commission (NRC) minimum funding
requirement and to fund, on a periodic basis, such minimum in an external trust
fund. The external trust fund is maintained in compliance with NRC regulation to
provide for minimum funding levels based on average expected cost to
decommission only the radiated portions of a typical nuclear facility. At
December 31, 2002, the NRC minimum funding requirement was approximately
$177,828,000. In calculating the minimum funding requirement, future costs were
projected using the same escalation rate used in the site study estimate
referred to above and were discounted at a rate of 8%. Oglethorpe has determined thatnot
recorded any provision for decommissioning during the years 2002, 2001 and 2000
because its existing decommmissioningdecommissioning reserve together with expected earnings onhas exceeded the NRC minimum funding
requirement. At December 31, 2002, the balance in the decommissioning reserve
was approximately $11.5 million less than the NRC minimum funding requirement
primarily due to unrealized losses in the market value of certain investments
held in Oglethorpe's external funds, should be
sufficient to meetdecommissioning trust fund. Oglethorpe is
currently examining the current projected requiredallocation of funding levels forbetween nuclear units, a possible
license extension at Plant Vogtle and Plant Hatch. Therefore, Oglethorpe did not record an annual provision
for decommissioninginvestment earnings assumptions to
determine whether additional contributions to the external fund may be necessary
in 2000 and 1999. Based on current assumptions,the future. Oglethorpe's management does not expect to record an annual provision for decommissioning in
future years. The annual provision for decommissioning for 1998 was $2,597,000
and was accounted for as depreciation expense with an offsetting credit to a
decommissioning reserve. In developing the amount of the annual provision for
1999 and 2000, the escalation rate was assumed to be 3.6% and return on trust
assets was assumed to be 8%, respectively. Oglethorpe's management is of the
opinionbelieves that any changesincrease in cost
estimates of decommissioning can be recovered in future rates.
51
In compliance with a NRC regulation, Oglethorpe maintains an external trust
fund to provide for a portion of the cost of decommissioning its nuclear
facilities. The NRC regulation requires funding levels based on average expected
cost to decommission only the radioactive portions of a typical nuclear
facility.
h. Depreciation
Depreciation is computed on additions when they are placed in service using
the composite straight-line method. Annual depreciation rates in effect in 2000,
19992002,
2001 and 19982000 were as follows:
================================================================================
2002 2001 2000
1999 1998
- ------------------------------------------------------------================================================================================
Steam production 1.98% 2.15% 2.14%1.98% 1.98%
Nuclear production 2.48% 2.69% 2.77%2.52% 2.68% 2.68%
Hydro production 2.00% 2.00% 2.00%
Other production 3.75% 3.75% 3.75%
Transmission 2.75% 2.75% 2.75%
General 2.00-33.33% 2.00-33.33% 2.00-20.00%
- ------------------------------------------------------------2.00-33.33%
================================================================================
In January 2002, the operating license for Plant Hatch was extended for 20
years. Due to the license extension, effective January 2002, the depreciation
rate for Plant Hatch has been revised from 2.99% to 1.92%.
60
i. Electric plant
Electric plant is stated at original cost, which is the cost of the plant
when first dedicated to public service, plus the cost of any subsequent
additions. Cost includes an allowance for the cost of equity and debt funds used
during construction. The cost of equity and debt funds is calculated at the
embedded cost of all such funds.
Maintenance and repairs of property and replacements and renewals of items
determined to be less than units of property are charged to expense.
Replacements and renewals of items considered to be units of property are
charged to the plant accounts. At the time properties are disposed of, the
original cost, plus cost of removal, less salvage of such property, is charged
to the accumulated provision for depreciation.
j. Bond, reserve and construction funds
Bond, reserve and construction funds for pollution control revenue bonds
(PCBs) are maintained as required by Oglethorpe's bond agreements. Bond funds
serve as payment clearing accounts, reserve funds maintain amounts equal to the
maximum annual debt service of each bond issue and construction funds hold bond
proceeds for which construction expenditures have not yet been made. As of
December 31, 20002002 and 1999,2001, substantially all of the funds were invested in U.S.
Government securities.
k. Cash and temporary cash investments
Oglethorpe considers all temporary cash investments purchased with a
maturity of three months or less to be cash equivalents. Temporary cash
investments with maturities of more than three months are classified as other
short-term investments.
At December 31, 20002002 and 1999, $22,241,0002001, $30,101,000 and $20,155,000 were restricted
by PCBs trust indentures and$22,940,000 were utilized in
January 20012003 and 20002002 for payment of principal on certain PCBs, respectively.
l. Inventories
Oglethorpe maintains inventories of fossil fuels and spare parts for its
generation plants. These inventories are stated at weighted average cost on the
accompanying balance sheets.
At December 31, 20002002 and 1999,2001, fossil fuels inventories were $15,565,000$21,011,000
and $31,787,000,$18,829,000, respectively. Inventories for spare parts at December 31, 20002002
and 19992001 were $59,824,000$62,208,000 and $57,979,000,$62,939,000, respectively.
m. Deferred charges
Oglethorpe accounts for nuclear refueling outage costs on a normalized
basis. Under this method of accounting, refueling outage costs are deferred and
subsequently amortized to expense over the 18-month operating cycle of each
unit. Deferred nuclear outage costs at December 31, 20002002 and 19992001 were
$19,897,000$22,778,000 and $18,483,000,$17,313,000, respectively.
AsOglethorpe accounts for debt issuance cost as deferred debt expense.
Deferred debt expense is being amortized to expense on a resultstraight-line basis
over the life of the determination that the Plant Vogtle radioactive waste
facility has no usefulness as a radioactive waste storage facility, the
remaining project costs of $5,076,000 are reflected as deferred charges on the
accompanying balance sheets. In 1998, Oglethorpe's Board of Directors authorized
that these project costs be amortized and fully recovered through rates over a
period of four years beginning in 1999.
52
respective debt issues.
n. Deferred credits
In April 1982, Oglethorpe sold to three purchasers certain of the income
tax benefits associated with Scherer Unit No.1 and related common facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act of
1981. Oglethorpe received a total of approximately $110,000,000 from the safe
harbor lease transactions. Oglethorpe accountsaccounted for the net benefits as a
deferred credit and is amortizingamortized the amount over the 20-year term of the leases.
The amortization of the safe harbor lease ended in March 2002.
In December 1996 and January 1997, Oglethorpe entered into long-term lease
transactions for its 74.6% undivided ownership interest in Rocky Mountain pumped
storage hydro facility (Rocky Mountain), through a wholly owned subsidiary of
Oglethorpe, Rocky Mountain Leasing Corporation (RMLC). The lease transactions
are characterized as a sale and lease-back for income tax purposes, but not for
financial reporting purposes. As a result of these leases, Oglethorpe recorded a
net benefit of $95,560,000 which was deferred and is being amortized to income
over the 30-year lease-back period.
o. Regulatory assets and liabilities
Oglethorpe is subject to the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation." Regulatory assets represent certain costs that are assured to be
recoverable by Oglethorpe from the Members in the future through the ratemaking
process. Regulatory liabilities represent certain items of income that are being
retained by Oglethorpe and that will be applied in the future to reduce Member
revenue requirements. The following regulatory assets and liabilities were
61
reflected on the accompanying balance sheets as of December 31, 20002002 and 1999:
- --------------------------------------------------------------------------------2001:
(dollars in thousands)
2000 1999
- --------------------------------------------------------------------------------2002 2001
================================================================================
Premium and loss on reacquired debt $ 175,944151,118 $ 196,289162,690
Deferred amortization of Scherer leasehold 102,753 101,404capital leases 109,567 107,254
Discontinued projects 9,490 28,0203,430 6,463
Other regulatory assets 28,141 29,01725,424 20,461
Net benefit of sale of income tax benefits (10,012) (18,021)- (2,002)
Net benefit of Rocky Mountain transactions (82,819) (86,004)(76,448) (79,633)
- --------------------------------------------------------------------------------
$ 223,497213,091 $ 250,705
- --------------------------------------------------------------------------------215,233
================================================================================
In the event that competitive or other factors result in cost recovery
practices under which Oglethorpe can no longer apply the provisions of SFAS No.
71, Oglethorpe would be required to eliminate all regulatory assets and
liabilities that could not otherwise be recognized as assets and liabilities by
businesses in general. In addition, Oglethorpe would be required to determine
any impairment to other assets, including plant, and write-down those assets, if
impaired, to their fair value.
p. Presentation
Certain prior year amounts have been reclassified to conform with the
current year presentation.
q. New accounting pronouncement
Aspronouncements
In June of 2001, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for
Asset Retirement Obligations." The statement provides accounting and reporting
standards for recognizing obligations related to costs associated with the
retirement of long-lived assets. SFAS No. 143 requires obligations associated
with the retirement of long-lived assets to be recognized at their fair value in
the period in which they are incurred if a reasonable estimate of fair value can
be made. The fair value of the asset retirement costs is capitalized as part of
the carrying amount of the long-lived asset and subsequently allocated to
expense using a systematic and rational method over the asset's useful life. Any
subsequent changes to the fair value of the liability due to passage of time or
changes in the amount or timing of estimated cash flows is recognized as an
accretion expense.
Effective January 1, 2001,2003, Oglethorpe adopted SFAS No. 133,143. The fair value
of the legal obligation recognized under SFAS No. 143 primarily relates to
Oglethorpe's nuclear facilities. In addition, Oglethorpe recognized retirement
obligations for ash handling facilities at the coal-fired plants and solid waste
landfills located at certain generating facilities. The cumulative effect of
adoption resulted in Oglethorpe recording a regulatory asset of approximately
$23,700,000; capitalized asset retirement costs, net of accumulated
amortization, of approximately $45,100,000 and increased asset retirement
obligations of approximately $68,800,000. At December 31, 2002, Oglethorpe's
recognized liability for nuclear decommissioning was $166,299,000. Oglethorpe
continues to recognize the accumulated removal costs for other obligations
(regulatory liabilities) as part of the accumulated depreciation and
amortization reserve in accordance with RUS prescribed regulatory treatment for
these costs. At December 31, 2002, that amount was $38,200,000.
Under SFAS No. 71, Oglethorpe may record an offsetting regulatory asset or
liability to reflect the difference in timing of recognition of the costs of
decommissioning for financial statement purposes and for ratemaking purposes for
both the cumulative effect of adoption and for future periods timing
differences. While RUS has not issued regulatory guidance for adoption of SFAS
No. 143, Oglethorpe's management expects to receive permission from RUS to
implement the provisions SFAS No. 71 with respect to timing differences arising
from cost recognition under SFAS No. 143 and for ratemaking purposes. Oglethorpe
estimates that the annual difference will be approximately $5,000,000.
In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44 and 64, Amendment of FASB Statement No. 13, and Technical
Corrections." Among other things, this statement rescinds SFAS No. 4, "Reporting
Gains and Losses from Extinguishment of Debt" (SFAS No. 4), which required all
gains and losses from extinguishment of debt to be aggregated and, if material,
classified as an extraordinary item, net of the related income tax effect. As a
result, the criteria in Accounting Principles Board Opinion No. 30, "Reporting
the Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," which requires gains and losses on extinguishments of debt to be
classified as income or loss from continuing operations, will now be applied.
SFAS No. 71 permits Oglethorpe to record gains and losses from early
extinguishment of debt as regulatory assets and regulatory liabilities.
Oglethorpe anticipates that any future gains and losses from early
extinguishment of debt will be recorded as regulatory assets and regulatory
liabilities. Oglethorpe is required to adopt SFAS No. 145 effective January 1,
2003.
62
In July 2002, the FASB issued SFAS No. 146, "Accounting for Derivative Instruments and Hedging Activities." The standard establishesCosts
Associated with Exit or Disposal Activities" (SFAS No. 146), which addresses
financial accounting and reporting for costs associated with exit or disposal
activities and nullifies Emerging Issues Task Force Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring" (EITF 94-3). The
principal difference between SFAS No. 146 and EITF 94-3 relates to SFAS No.
146's requirements for derivative instruments, including
certain derivative instruments embedded in other contracts, and hedging
activities. It requires the recognition of all derivative instrumentsa liability for a cost associated with an
exit or disposal activity. SFAS No. 146 requires that a liability for a cost
associated with an exit or disposal activity be recognized when the liability is
incurred. Under EITF 94-3, a liability for an exit cost as assetsgenerally defined in
EITF 94-3 was recognized at the date of an entity's commitment to an exit plan.
Oglethorpe is required to adopt SFAS No. 146 effective January 1, 2003. This
pronouncement currently does not affect Oglethorpe's financial statements.
In November 2002, the FASB issued Interpretation No. 45, Accounting and
Disclosure Requirements for Guarantees. The disclosure provisions of the
interpretation are effective for financial statements of annual periods that end
after December 15, 2002. In addition, Interpretation No. 45 requires recognition
of a liability at inception for certain new or liabilities in Oglethorpe's balance sheet and measurement of those
instruments at fair value. The accounting treatment of changes in fair value is
dependent upon whethermodified guarantees issued after
or not a derivative instrument is designated as a hedge
and if so, the type of hedge. Oglethorpe's interest rate swap arrangements in
place atmodified after December 31, 20002002. As of December 31, 2002, in addition to
guarantees disclosed in Note 5 for a loan to Chattahoochee EMC and for PCBs
assumed by Georgia Transmission Corporation (GTC) in connection with a corporate
restructuring, Oglethorpe is liable on a contingent basis for certain other
contractual obligations.
All of these contingent liabilities are designated as cash flow hedges. Adoptionin connection with the generation
facilities under construction owned by Talbot EMC and Chattahoochee EMC and the
related operational contracts. The contingent liabilities under construction
contracts for Talbot EMC and Chattahoochee EMC were $15,000,000 and $15,000,000,
respectively. Oglethorpe also remains liable, on a contingent basis, for
obligations under other operational agreements relating to the Chattahoochee EMC
facility. The combined obligation under these agreements totals $94,000,000
through 2006, and $20,000,000 annually thereafter through approximately 2015. As
discussed in Note 5, at the time the RUS loan is funded, Oglethorpe will acquire
the generation facilities owned by Talbot EMC and Chattahoochee EMC. At that
point, the related contingent liabilities will become direct obligations of
SFAS
No. 133 on January 1, 2001, resulted in recording $33,515,000 of decline in fair
value to accumulated other comprehensive income and a comparable increase in
other liabilities. For information regarding the interest rate swap
arrangements, see Note 2.
53
Oglethorpe.
2. Fair value of financial instruments:
A detail of the estimated fair values of Oglethorpe's financial instruments as
of December 31, 20002002 and 19992001 is as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
2000 1999================================================================================
Fair Fair
Cost Value Cost Value
- --------------------------------------------------------------------------------================================================================================
Cash and temporary
cash investments:
Commercial paper $ 330,052150,247 $ 330,052150,247 $ 220,941238,514 $ 220,941238,514
Cash and money
market securities 570 570 1,873 1,8731,064 1,064 37,272 37,272
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------
Total $ 330,622151,311 $ 330,622151,311 $ 222,814275,786 $ 222,814
- --------------------------------------------------------------------------------275,786
================================================================================
Other short term
investments $ 80,85492,793 $ 81,71594,301 $ 76,67387,277 $ 75,482
- --------------------------------------------------------------------------------88,589
================================================================================
Bond, reserve and
construction funds:
U. S. Government
securities $ 25,3977,833 $ 25,6088,067 $ 25,44320,860 $ 25,02521,583
Repurchase
agreements 3,559 3,559 6,133 6,13318,458 18,438 7,108 7,108
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------
Total $ 28,95626,291 $ 29,16726,505 $ 31,57627,968 $ 31,158
- --------------------------------------------------------------------------------28,691
================================================================================
Decommissioning fund:
U. S. Government
securities $ 29,67438,525 $ 31,04939,884 $ 23,85830,767 $ 23,57431,088
Foreign government
securities 1,173 1,161 732 656616 680 1,514 1,542
Commercial paper 6,183 6,180 2,387 2,388- - 4,259 4,261
Corporate bonds 6,784 6,929 11,215 10,89112,242 13,098 13,036 13,575
Equity securities 80,795 85,225 69,944 77,14866,206 62,533 71,176 77,062
Asset-backed
securities 12,156 12,406 9,954 9,7513,905 3,979 9,389 9,470
Other bonds - -2,364 2,422 - -
Cash and money
market securities 5,350 5,350 11,293 11,29531,465 31,465 13,670 13,670
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------
Total $142,115 $148,300 $129,383 $135,703
- --------------------------------------------------------------------------------$ 155,323 $ 154,061 $ 143,811 $ 150,668
================================================================================
Long-term debt $3,019,019 $ 3,221,692 $3,103,590 $3,007,048
- --------------------------------------------------------------------------------2,835,997 $ 3,254,782 $2,929,316 $ 3,118,974
================================================================================
Interest rate swap (unrealized loss) $ - $ (33,515)(58,443) $ - $ (18,935)(36,859)
================================================================================
Financial gas
hedges $ - --------------------------------------------------------------------------------$ 970 $ - $ (7,537)
================================================================================
63
The contractual maturities of debt securities available for sale at
December 31, 20002002 and 1999, regardless of their balance sheet classification,2001 are as follows:
- -----------------------------------------------------------------------------================================================================================
(dollars in thousands)
2000 19992002 2001
Fair Fair
Cost Value Cost Value
- -----------------------------------------------------------------------------================================================================================
Due within one year $ 3,559 $ 3,559 $ 6,818 $ 6,866$35,698 $35,917 $14,215 $14,211
Due after one year
through five years 39,583 40,022 36,017 35,50919,565 20,118 31,965 33,080
Due after five years
through ten years 12,499 12,904 11,597 11,26211,425 12,445 14,511 14,858
Due after ten years 23,102 24,227 22,902 22,39315,527 16,366 21,983 22,217
- -----------------------------------------------------------------------------
$ 78,743 $ 80,712 $ 77,334 $76,030
- -------------------------------------------------------------------------------------------------------------------------------------------------------------
$82,215 $84,846 $82,674 $84,366
================================================================================
Oglethorpe uses the methods and assumptions described below to estimate the
fair value of each class of financial instruments. For cash and temporary cash
investments, the carrying amount approximates fair value because of the
short-term maturity of those instruments. The fair value of Oglethorpe's
long-term debt and the swap arrangements is estimated based on the quoted market
prices for the same or similar issues or on the current rates offered to
Oglethorpe for debt of similar maturities.
A portion (16.86%)Effective January 1, 2001, Oglethorpe adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The standard establishes
accounting and reporting requirements for derivative instruments, including
certain derivative instruments embedded in other contracts, and hedging
activities. It requires the recognition of certain derivatives as assets or
liabilities on Oglethorpe's balance sheet and measurement of those instruments
at fair value. The accounting treatment of changes in fair value is dependent
upon whether or not a derivative instrument is classified as a hedge and if so,
the interest rate swap arrangements was assumed by
Georgia Transmission Corporation (GTC) in connection with a corporate
restructuring.type of hedge.
Under the interest rate swap arrangements, Oglethorpe makes payments to the
counterparty based on the notional principal at a contractually fixed rate and
the counterparty makes payments to Oglethorpe based on the notional principal at
the existing variable rate of the refunding bonds. The differential to be paid
or received is accrued as interest rates change and is recognized as an
adjustment to interest expense. Oglethorpe entered into the swap arrangements
for the purpose of securing a fixed rate lower than otherwise would have been
available to Oglethorpe had it issued fixed rate bonds. For the Series 1993A
notes, the notional principal at December 31, 20002002 was $192,420,000$186,710,000 (includes
the portion assumed by GTC) and the fixed swap rate is 5.67% (the variable rate
at December 31, 20002002 and 19992001 was 4.90%1.50% and 5.40%1.60%, respectively). With respect
to the Series 1994A notes, the notional principal at December 31, 20002002 was
$120,500,000$115,710,000 (includes the portion assumed by GTC) and the fixed swap rate is
6.01% (the variable rate at December 31, 20002002 and 19992001 was 4.95%1.60% and 54
5.65%1.60%,
respectively). The notional principal amount is used to measure the amount of
the swap payments and does not represent additional principal due to the
counterparty. The swap arrangements extend for the life of the refunding bonds,
with reductions in the outstanding principal amounts of the refunding bonds
causing corresponding reductions in the notional amounts of the swap payments.
A portion (16.86%) of the interest rate swap arrangements was assumed by
GTC in connection with a corporate restructuring. Oglethorpe has classified its
portion of two interest rate swap arrangements, pursuant to SFAS No. 133, as
cash flow hedges. Accordingly, as of January 1, 2001, Oglethorpe recorded as a
cumulative effect adjustment an unrealized loss in other comprehensive margin of
$33,515,000 and a corresponding increase in other liabilities. Oglethorpe's
portion of the estimated fair value of the swap arrangements at December 31,
2000 and 19992002 was an unrealized loss of $33,515,000
and $18,935,000, respectively,$58,443,000 representing the estimated payment
Oglethorpe would pay if the swap arrangements were terminated.
Oglethorpe has entered into natural gas financial contracts that are
classified, pursuant to SFAS 133, as cash flow hedges. Oglethorpe utilizes
natural gas financial contracts in managing its exposure to fluctuations in the
market price of natural gas. The fair value of Oglethorpe's financial gas hedges
is based on the quoted market value for such natural gas financial contracts. At
December 31, 2002, Oglethorpe recorded an unrealized gain in other comprehensive
margin of $8,507,000 and a corresponding increase in other current assets
related to these natural gas financial contracts.
Oglethorpe may be exposed to losses in the event of nonperformancenonperfor-mance of the
counterparty,counterparties to its derivative instruments, but does not anticipate such
nonperformance.
Under SFAS No. 115, "Accounting for Certain Investments in Debt and Equity
Securities," investment securities held by Oglethorpe are classified as either
available-for-sale or held-to-maturity. Available-for-sale securities are
carried at market value with unrealized gains and losses, net of any tax effect,
added to or deducted from patronage capital. Unrealized gains and losses from
investment securities held in the decommissioning fund, which are also
classified as available-for-sale, are directly added to or deducted from the
decommissioning reserve. Held-to-maturity securities are carried at cost. All
realized and unrealized gains and losses are determined using the specific
identification method. Gross unrealized gains and losses at December 31, 20002002
were $15,937,000$8,008,000 and $8,681,000,$7,548,000, respectively. Gross unrealized gains and losses
at December 31, 19992001 were $11,451,000$12,569,000 and $6,740,000,$3,677,000, respectively. Gross
unrealized gains and losses at December 31, 19982000 were $12,182,000$15,937,000 and
$1,845,000,64
$8,681,000, respectively. For 2000, 19992002, 2001 and 19982000 proceeds from sales of
available-for-sale securities totaled $725,240,000, $592,579,000$802,637,000, $554,359,000 and
$491,343,000,$737,939,000, respectively. Gross realized gains and losses from the 20002002 sales
were $19,556,000$13,337,000 and $16,086,000,$15,342,000, respectively. Gross realized gains and losses
from the 19992001 sales were $29,429,000$14,585,000 and $22,167,000,$17,378,000, respectively. Gross
realized gains and losses from 19982000 sales were $12,892,000$19,556,000 and $6,602,000,$16,086,000,
respectively.
Investments in associated companies were as follows at December 31, 20002002
and 1999:
- --------------------------------------------------------------------------------2001:
================================================================================
(dollars in thousands)
2000 1999
- --------------------------------------------------------------------------------2002 2001
================================================================================
National Rural Utilities
Cooperative Finance Corp. (CFC) $ 13,476 $ 13,603$13,476 $13,476
CoBank, ACB 2,407 1,5773,373 3,419
Georgia Transmission
Corporation (GTC) 3,815 2,6156,601 4,899
Georgia System Operations
Corporation (GSOC) 3,560 731
Other 299 1241,234 393
- --------------------------------------------------------------------------------
Total $ 19,997 $ 17,919
- --------------------------------------------------------------------------------$28,244 $22,918
================================================================================
The CFC investments are in the form of capital term certificates and are
required in conjunction with Oglethorpe's membership in CFC. Accordingly, there
is no market for these investments. The investments in CoBank and GTC represent
capital credits. Any distributions of capital credits are subject to the
discretion of the Board of Directors of CoBank and GTC. The investments in GSOC
represent loan advances. The loan repayment schedule ends in December 2008.
The deposit, which is carried at cost, on the Rocky Mountain transactions
(see Note 1 where discussed) is invested in a guaranteed investment contract
which will be held to maturity (the end of the 30-year lease-back period). At
maturity, Oglethorpe intends to repurchase tax ownership and to retain all other
rights of ownership with respect to the plant if it is advantageous to do so.
The assets of RMLC are not available to pay creditors of Oglethorpe or its
affiliates.
In addition, from the proceeds of the Rocky Mountain transactions,
Oglethorpe paid $640,611,000 to a financial institution. In return, this
financial institution undertook to pay a portion of Oglethorpe's lease
obligations. Both Oglethorpe's interest in this payment undertaking agreement
and the corresponding lease obligations have been extinguished for financial
reporting purposes.
55
3. Income taxes:
Oglethorpe is a not-for-profit membership corporation subject to federal
and state income taxes. As a taxable electric cooperative, Oglethorpe has
annually allocated its income and deductions between Memberpatronage and non-Membernon-patronage
activities.
Any Member taxableIn November 2001, Oglethorpe changed its Bylaws to provide allocation of
patronage on a tax basis method rather than the historical book basis method.
This change is effective starting January 1, 2002. Due to this change,
Oglethorpe anticipates that all future patronage source income will be offset by
the patronage exclusion. Accordingly, it is expected that substantially all of
Oglethorpe's temporary differences will be patronage sourced and subject to
offset. Therefore, as of December 31, 2001, Oglethorpe reversed $63,485,000 of
net deferred income tax liabilities and has been offset withrecognized this reversal as a
patronage exclusion
and member loss carryforwards.deferred income tax credit of $63,485,000.
Oglethorpe accounts for its income taxes pursuant to SFAS No. 109. SFAS No.
109 requires the recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been included in the
financial statements or tax returns.
A detail of the provision for income taxes in 2000, 19992002, 2001 and 19982000 is shown
as follows:
- --------------------------------------------------------------------------------================================================================================
(dollars in thousands)
2002 2001 2000
1999 1998
- --------------------------------------------------------------------------------================================================================================
Current
Federal $ (283)- $ - $ (86)(283)
State - - -
- --------------------------------------------------------------------------------
(283) - (86)- (283)
- --------------------------------------------------------------------------------
Deferred
Federal 283 - 86(63,485) 283
State - - -
- --------------------------------------------------------------------------------
283 - 86(63,485) 283
- --------------------------------------------------------------------------------
Income taxes charged
to operations $ - $(63,485) $ -
$ -
- --------------------------------------------------------------------------------================================================================================
The difference between the statutory federal income tax rate on income
before income taxes and Oglethorpe's effective income tax rate is summarized as
follows:
- --------------------------------------------------------------------------------================================================================================
2002 2001 2000
1999 1998
- --------------------------------------------------------------------------------================================================================================
Statutory federal income tax rate 35.0% 35.0% 35.0%
Patronage exclusion (35.8%) (35.6%) (35.7%(376.0%) (35.8%)
Other 0.8% 0.6% 0.7%0.0% 0.8%
- --------------------------------------------------------------------------------
Effective income tax rate 0.0% (341.0%) 0.0%
0.0%
- --------------------------------------------------------------------------------================================================================================
65
The components of the net deferred tax liabilities as of December 31, 20002002
and 19992001 were as follows:
- --------------------------------------------------------------------------------================================================================================
(dollars in thousands)
2000 1999
- --------------------------------------------------------------------------------2002 2001
===============================================================================
Deferred tax assets
Net operating losses $ 478,497477,975 $ 477,817482,058
Member loss carryforwards 44,341 78,231- 7,310
Tax credits (alternative minimum tax
and other) 58,811 196,452
199,650
Accounting for Rocky Mountain
transactions 312,441 309,474
Accounting for sale of income tax benefits 16,702 27,909
Accrued nuclear decommissioning expense 64,545 60,264
Accounting for asset dispositions 20,010 28,185
Other 3,000 3,540
- --------------------------------------------------------------------------------
1,135,988 1,185,070-------------------------------------------------------------------------------
536,786 685,820
Less: Valuation allowance (194,145) (197,343)(536,786) (678,510)
- --------------------------------------------------------------------------------
941,843 987,727-------------------------------------------------------------------------------
- --------------------------------------------------------------------------------7,310
- -------------------------------------------------------------------------------
Deferred tax liabilities
Depreciation (738,313) (771,577)
Accounting for Rocky Mountain
transactions (195,376) (199,675)
Accounting for debt extinguishment (57,042) (64,362)
Other (14,597) (15,316)
- --------------------------------------------------------------------------------
(1,005,328) (1,050,930)(7,310)
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------
- (7,310)
- -------------------------------------------------------------------------------
Net deferred tax liabilities $ (63,485)- $ (63,203)
-
--------------------------------------------------------------------------------
56
===============================================================================
As of December 31, 2000,2002, Oglethorpe has federal tax net operating loss
carryforwards (NOLs), alternative minimum tax credits (AMT) and unused general
business credits (consisting primarily of investment tax credits) as follows:
- --------------------------------------------------------------------------------=================================================================
(dollars in thousands)
- --------------------------------------------------------------------------------=================================================================
Alternative
Minimum
Expiration Date Tax Credits Tax Credits NOLs
2001Credits
2003 $ - $ 7,264652 $ -
2002 - 130,377 7,102
2003 - 652 253,665
2004 - 55,663 114,285
2005 - 189 213,080
2006 - - 209,009
2007 - - 86,779
2008 - - 94,927
2009 - - 96,394
2010 - - 77,970
2018 - - 61,533
2019 - - 10,516
2020 - - 4,8094,362
2021 - - 6,207
None 2,307 - -
- -------------------------------------------------------------------------------------------------------------------------------------------------
$ 2,307 $ 194,145 $1,230,069
- --------------------------------------------------------------------------------
Oglethorpe has not recorded a valuation allowance with respect to its
deferred tax asset related to NOLs. Oglethorpe intends to implement available
tax planning strategies if necessary to utilize NOLs prior to their expiration
date. If any NOLs are not utilized prior to their expiration date, Oglethorpe
believes it has available options to offset the effect, if any, of NOLs
expiring.56,504 $ 1,228,727
=================================================================
The NOL expiration dates start in the year 20022003 and end in the year 2020. However,2021.
Due to the change to the tax basis method for allocating patronage and as reflected inshown
by the above valuation allowance, it is morenot likely
than not that the deferred tax assets
related to tax credits and NOLs will not be utilized before expiration.realized. The change in the valuation
allowance from 19992001 to 20002002 was the result of the reduction in deferred tax
assets due to the expiration of
$3,198,000 of tax credits in 2000.and net operating losses. It is morenot
likely than not that the AMT credit will be utilized.
4. Capital leases:
In December 1985, Oglethorpe sold and subsequently leased back from four purchasers
its 60% undivided ownership interest in Scherer Unit No. 2. The gain from the
sale is being amortized over the 36-year term of the leases.
In 2000, Oglethorpe entered into a power purchase and sale agreement with
Doyle I, LLC (Doyle Agreement) to purchase all of the output from a five-unit
generation facility (Plant Doyle) for a period of 15 years. Oglethorpe has the
option to purchase Plant Doyle at the end of the 15 year term for $10,000,000,
which is considered a bargain purchase price.
The minimum lease payments under the capital leases together with the
present value of the net minimum lease payments as of December 31, 20002002 are as
follows:
================================================================================
Year Ending December 31, (dollars in thousands)
================================================================================
Schererer Plant
Unit No. 2 Doyle Total
- --------------------------------------------------------------------------------
20012003 $ 37,629
2002 37,491
2003 37,33331,875 $ 12,447 $ 44,322
2004 37,15631,863 12,447 44,310
2005 36,961
2006-2021 420,23931,863 12,447 44,310
2006 31,817 12,447 44,264
2007 31,871 12,447 44,318
2008-2021 313,975 105,424 419,399
- --------------------------------------------------------------------------------
Total minimum lease
payments 606,809473,264 167,659 640,923
Less: Amount representing
interest at an assumed rate of 11.05% (330,131)(212,476) (52,727) (265,203)
- --------------------------------------------------------------------------------
Present value of net
minimum lease payments 276,678260,788 114,932 375,720
Less: Current portion (9,229)(11,338) (5,706) (17,044)
- --------------------------------------------------------------------------------
Long-term balance $ 267,449
- --------------------------------------------------------------------------------249,450 $ 109,226 $358,676
================================================================================
The capital leases provide that Oglethorpe's rentalinterest rate on the Scherer No. 2 lease obligation is 6.97%. For Plant
Doyle, the lease payments vary to the extent ofthe interest rate changes associated withon the lessor's
debt used byvaries from 6.00%. At December 31, 2002, the lessors to
finance their purchase of undivided ownership shares in Scherer Unit No. 2. In
December 1997, Oglethorpe refinanced the debt supporting the Scherer Unit No. 2
lease. The refunded debt consisted of $143,200,000 in serial facility bonds with
a 9.70% fixedweighted average interest rate
(pertaining to three ofon the lessors) and $81,500,000
in bank debt with variable interest rates ranging from 6.40% to 6.90%
(pertaining to the remaining lessor)Plant Doyle lease obligation was 6.61%.
The debt was refinanced through a
$224,700,000 issue of serial facility bonds due June 30, 2011 with a 6.97% fixed
interest rate. The transaction costs related to this transaction are reported as
deferred charges on the balance sheet and are being amortized over the remaining
life of the leases. Oglethorpe's future rental payments under its leases will
vary from amounts shown in the table above to the extent that the actual
interest rates associated with the debt of the lessors varies from the 11.05%
debt rate assumed in the table.
The Scherer Unit No. 2 lease meetsand the Doyle Agreement meet the definitional
criteria to be reported on Oglethorpe's balance sheets as a capital lease.leases. For rate-making purposes, however,
Oglethorpe treats this leasethese capital leases as an operating lease; that is,leases. Accordingly,
Oglethorpe considersincludes the actual rental payment on the leased assetlease payments in its cost of service. Oglethorpe's accounting treatment for thisThe excess
of the lease payments over the aggregate of the amortization on the capital
lease has been modified,
therefore, to reflect its rate-making treatment. Interest expense is applied to
57
asset and the obligation underinterest on the capital lease; then, amortization of the leaseholdlease obligation is recognized such that interest and amortization equal the actual rental payment.
Through 1994, the level of actual rental payments was such that amortization of
the Scherer Unit No. 2 leasehold calculated in this manner was less than zero.
Thereafter, the scheduled cash rental payments increase such that positive
amortization of the leasehold occurs and the entire cost of the leased asset is
recovered through the rate-making process. The difference in the amortization
recognized in this manner on the statements of revenues and expenses and the
straight-line amortization of the leasehold is reflected on Oglethorpe's balance
sheets as a
regulatory asset.
In 1991 and 1992, all four of the lessors received Notices of Proposed
Adjustments from the IRS proposing adjustments to the tax benefits claimed by
these lessors in connection with their purchase and ownership of an undivided
interest in Scherer Unit No. 2. In 1994, the IRS issued a revised Notice of
Proposed Adjustments to one of the lessors which reduced the proposed
adjustments. During 1995, this lessor advised Oglethorpe that it had settled
this issueasset on the basis of the revised Notice of Proposed Adjustments.
Oglethorpe subsequently made a lump sum indemnity payment of $362,000balance sheet pursuant to the
lessor in order to compensate for the reduction in the lessor's tax benefits
resulting from the sale and leaseback transaction. The IRS has indicated that it
will take consistent positions with the other three lessors. If the IRS's
current positions regarding the sale and leaseback transactions were ultimately
upheld, Oglethorpe would be required to indemnify the other three lessors.
Oglethorpe's indemnification liability to the three lessors is estimated to be
approximately $1,454,000 as of December 31, 2000. This liability has been
reflected on the accompanying balance sheet.SFAS No. 71.
66
5. Long-term debt:
Long-term debt consists of mortgage notes payable to the United States of
America acting through the Federal Financing Bank (FFB) and the RUS, mortgage
notes and unsecured notes issued in conjunction with the sale by public
authorities of PCBs mortgage notes and unsecured notes payable to CoBank, and mortgage notes payable to National Rural Utilities Cooperative Finance
Corporation (CFC).CoBank. Oglethorpe's
headquarters facility is pledged as collateral for the CoBank headquarters note;
substantially all of the owned tangible and certain of the intangible assets of
Oglethorpe are pledged as collateral for the FFB and RUS notes, the CoBank
mortgage notes the CFC notes, and the mortgage notes issued in conjunction with the sale of
PCBs. The detail of the two
medium-term notes is included in the statements of capitalization.
In connection with a corporate restructuring effective April 1, 1997,
16.86% of the then outstanding secured PCBs waswere assumed by GTC. Because
Oglethorpe was not legally released from its obligation to pay this debt, the
entire debt is shown in the Statement of Capitalization as a liability of
Oglethorpe with an offsetting amount reflecting the portion assumed by GTC. The
net obligation is reflected on Oglethorpe's balance sheet.
In connection with a corporate restructuring, Oglethorpe defeased
approximately $92,000,000$92,130,000 in principal amount of Series 1992 tax-exempt PCBs. Initially these
bonds were defeased with the proceeds from the issuance of approximately
$92,000,000 in commercial paper.paper which was deposited into an escrow account. In
March and April 1998, Oglethorpe refinancedrefi-nanced the commercial paper issuance with
two medium-term loans;loans of $46,065,000 each, one from CoBank and one from CFC,CFC. In
October 2002, Oglethorpe issued $91,990,000 of approximately $46,100,000 each. Oglethorpe ultimately expectstax-exempt PCBs, the proceeds of
which were used to refinancepre-pay the two medium-term loans with an issuanceloans. On January 1, 2003 (the
first optional call date of PCBsthe issue), the remaining funds in the fall of
2002.escrow
account were used to fully redeem the outstanding Series 1992 PCBs.
In October 2000,December 2002, Oglethorpe completed a current refunding transaction
whereby $21,950,000$30,075,000 of PCBs were issued. The proceeds were used to make
principal payments due January 1, 2001.2003.
GTC agreed with Oglethorpe not to participate in this $21,950,000$30,075,000
refinancing to the extent of their assumed obligation in the PCBs. Pursuant to
this agreement, Oglethorpe will provide a discount to GTC of approximately
$1,110,000$1,522,000 on the $3,701,000$5,072,000 of principal payments due from GTC in connection
with such refinancings. This $1,110,000$1,522,000 loss will be reported, together with the
unamortized transaction costs, as a deferred charge on the balance sheet and
will be amortized over four years.
The annual interest requirement for 20012003 is estimated to be $219,000,000.
58
$202,000,000.
Maturities for the long-term debt and amortization of the capital lease
obligations through 20052007 are as follows:
- --------------------------------------------------------------------------------================================================================================
(dollars in thousands)
2001 2002 2003 2004 2005 - --------------------------------------------------------------------------------2006 2007
================================================================================
FFB and RUS $106,623 $ 90,830 $ 96,424 $101,383 $108,71196,804 $101,754 $109,047 $116,023 $123,371
CoBank 523 540 46,623558 580 603 PCBs* 19,678 20,264630 661
PCBs(1) 25,835 27,855 28,146 CFC - - 46,065 - -30,000 34,501
Capital Leases 9,229 8,544 9,455 10,387 11,474leases(2) 17,044 16,445 17,905 19,429 21,081
- --------------------------------------------------------------------------------
Total $136,053 $120,178 $224,402 $140,205 $148,934
- --------------------------------------------------------------------------------
*Does$140,241 $146,634 $155,701 $166,082 $179,614
================================================================================
(1) Does not contain portion assumed by GTC
(2) Represents principal portion of obligations under capital leases
The weighted average interest rate for 20002002 for long-term debt and capital
leases due within one year and notes payable is 6.21%was 5.33%.
Oglethorpe has a $50,000,000 committed short-term line of credit with CFC.
No balance was outstanding on this line of credit at either December 31, 2002 or
2001.
Oglethorpe has a commercial paper program under which it may issue
commercial paper not to exceed a $260,000,000$320,000,000 balance outstanding at any time.
The commercial paper may be used for working capital requirements and for
general corporate purposes. Oglethorpe's commercial paper is backed 100% by
committed lines of credit. AsBy its terms, the amount of December 31, 2000 and 1999, approximately $78,000,000 and
$88,000,000, respectively,the lines of credit
supporting the commercial paper was outstanding. The majorityprogram reduce to $290,000,000 on the earlier of
$350,000,000 in loan funds being received from RUS under the amount outstanding at year-end 1999 relatesTalbot EMC and
Chattahoochee EMC loan commitments or June 30, 2003.
Oglethorpe is providing loans to commercial paper issuedTalbot EMC and Chattahoochee EMC to fund,
on an interim basis, approximately fifty percent of the construction cost of athe
six combustion turbine (CT) project
completed in Summer 2000. This projectturbines and the combined cycle facility. Oglethorpe is owned by a cooperative, Smarr EMC,
which is owned by 37funding
these loans under its commercial paper program, and at December 31, 2002,
$297,776,000 of Oglethorpe's 39 Members. The commercial paper was retiredoutstanding for this purpose. The loans are
included in October 2000 with proceeds from permanent financing secured by Smarr
EMCNotes receivable on a non-recourse basis to Oglethorpe. A majorityOglethorpe's balance sheet. Four of the commercial paper
outstanding at year-end 2000 was issued to fund, on an interim basis,
construction of additional generation facilitiessix
combustion turbines were placed in-service in summer 2002, with the other two
expected to be completedin-service by the summer of 2003. The combined cycle facility was
placed in Summerservice on February 15, 2003.
The expected combined cost of constructing the six combustion turbines and
the combined cycle facility totals approximately $600,000,000. Two bridge loans
have also been secured to fund the remaining portion of the cost of constructing
these facilities.
67
CFC is providing a $141 million bridge loan to Talbot EMC, and Pitney Bowes
Credit Corporation is providing a $160 million bridge loan to Chattahoochee EMC.
Oglethorpe's loans to Talbot EMC and Chattahoochee EMC are subordinated to the
CFC and Pitney Bowes loans, respectively. Oglethorpe is providing a guarantee of
the $160 million bridge loan to Chattahoochee EMC.
In 2000, Oglethorpe submitted loan applications to RUS to provide permanent
financing for these two facilities. The loan applications were initially
submitted on behalf of either Oglethorpe or related entities that might
ultimately own these facilities. During the process of evaluating the terms
proposed by RUS for providing loans to Talbot EMC and Chattahoochee EMC, it was
determined that the terms of the financing would be more favorable if Oglethorpe
owned the facilities and obtained the RUS financing. In September 2002, RUS
issued two RUS-guaranteed loan commitments totaling $589 million to Oglethorpe
for these generating facilities. The proceeds from these RUS loans will first be
used to repay the bridge loans and 2003. Itthen to retire Oglethorpe's outstanding
commercial paper. Concurrently with the funding of these loans, which is
expected that byto occur in the time these projects are
completed, permanent financingsecond quarter of 2003, Oglethorpe will have been securedacquire the two
generating facilities from Talbot EMC and Chattahoochee EMC. Oglethorpe's
acquisition of the facilities is conditioned upon implementation of new
arrangements among Oglethorpe and the proceeds used to
retire the commercial paper. It is anticipatedMembers.
The acquisition of these new generating facilities will increase Oglethorpe's
assets and liabilities by approximately $600 million. The new debt will be
owned eithersecured under Oglethorpe's Mortgage Indenture. Since Oglethorpe's margin
requirement is based on a ratio applied to interest charges incurred for debt
secured under the Mortgage Indenture, the increase in debt will result in an
increase in the margin requirement of less than $3,000,000 in the first year.
The increase in assets and debt will decrease Oglethorpe's equity to
capitalization ratio and equity to asset ratio by a subsidiary of Oglethorpe, Smarr EMC, or by a similar
separate entity.
Oglethorpe has a $50,000,000 uncommitted short-term line of credit with
CFC. No balance was outstanding on this line of credit at either December 31,
2000 or 1999.approximately 3% and 2%,
respectively.
6. Electric plant and related agreements:
Oglethorpe and GPC have entered into agreements providing for the purchase
and subsequent joint operation of certain of GPC's electric generating plants. A
summary of Oglethorpe's plant investments and related accumulated depreciation
as of December 31, 20002002 is as follows:
- --------------------------------------------------------------------------------============================================================================
(dollars in thousands)
Accumulated
Plant Investment Depreciation
- --------------------------------------------------------------------------------============================================================================
In-service
Owned property
Vogtle Units No. 1 & No. 2
(Nuclear - 30% ownership) $2,734,776 $ 931,5802,721,256 $ 1,042,409
Hatch Units No. 1 & No. 2
(Nuclear - 30% ownership) 531,655 249,097543,619 273,786
Wansley Units No. 1 & No. 2
(Fossil - 30% ownership) 173,119 95,067174,999 99,332
Scherer Unit No. 1
(Fossil - 60% ownership) 426,891 225,371436,566 245,156
Rocky Mountain Units No. 1,
No. 2 & No. 3
(Hydro - 74.6% ownership) 556,875 61,860
Tallassee (Harrison Dam)
(Hydro - 100% ownership) 9,270 2,508556,784 83,861
Wansley (Combustion Turbine -
30% ownership) 3,629 1,6001,872
Generation step-up substations 60,470 26,38762,978 29,462
Other 85,667 33,61795,497 47,269
Property under capital lease
Plant Doyle (Combustion Turbine -
100% leasehold) 126,990 18,199
Scherer Unit No. 2
(Fossil - 60% leasehold) 301,328 125,089308,015 142,604
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Total in-service $4,883,680 $1,752,176
- --------------------------------------------------------------------------------$ 5,030,333 $ 1,983,950
============================================================================
Construction work in progress
Generation improvements $ 24,033
New generation facilities 37,86867,652
Other 4561,630
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Total construction work in progress $ 62,357
- --------------------------------------------------------------------------------69,282
============================================================================
Oglethorpe, as of December 31, 2000,2002, estimates property additions
(excluding capitalized interest and nuclear fuel) to be approximately
$331,000,000$77,000,000 in 2001, $229,000,0002003, $30,000,000 in 20022004 and $72,000,000$30,000,000 in 2003,2005, primarily for
replacements and additions to generation facilities.
59
Oglethorpe's proportionate share of direct expenses of joint operation of
the above plants is included in the corresponding operating expense captions
(e.g., fuel, production or depreciation) on the accompanying statements of
revenues and expenses.
68
7. Employee benefit plans:
Effective December 31, 1998, Oglethorpe's Board of Directors approved
termination of the noncontributory defined benefit pension plan that covered
substantially all employees, resulting inOglethorpe has a net gain of $1,645,000. For 1998,
the plan's pension cost recognized was a credit of $163,000.
The defined benefit pension plan was replaced with a new money purchase pension plan which became effective January
1, 1999. Under this new plan, Oglethorpe contributes 5%, subject to IRS limitations,
of each employee's annual compensation. In addition, older employees who
participated in the now-terminated defined benefit pension plan receive an
additional 1% to 2% of compensation. Oglethorpe's contributions to the plan were
approximately $513,000 in 2002 and $498,000 in 2001 and $444,000 in 2000 and $365,000 in 1999.2000.
Oglethorpe has a contributory employee retirement savings401(k) plan covering substantially all
employees. The employee may contribute, subject to IRSlimitations,IRS limitations, up to 16%60% of
histheir annual compensation. Oglethorpe, willat its discretion, may match the
employee's contribution and has done so each year of the plan's existence.
Oglethorpe's current policy is to match the employee's contribution as long as
there is sufficient net margin to do so. The match, which is calculated each pay
period, currently can be equal to as much as one-halfthree-quarters of the first 6% of
the employee's annual compensation, depending upon the amount and
timing of the employee's contribution. Effective January 1, 2001, Oglethorpe
will match three-quarters of the first 6% of the employees contribution depending on the amount and timing of the
employee's contribution. Oglethorpe's contributions to the plan were
approximately $621,000 in 2002, $463,000 in 2001 and $261,000 in 2000, $226,000 in 1999
and $214,000 in 1998.2000.
8. Nuclear insurance:
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member
of Nuclear Electric Insurance, Ltd. (NEIL), a mutual insurer established to
provide property damage insurance coverage in an amount up to $500,000,000 for
members' nuclear generating facilities. In the event that losses exceed
accumulated reserve funds, the members are subject to retroactive assessments
(in proportion to their premiums). The portion of the current maximum annual
assessment for GPC that would be payable by Oglethorpe, based on ownership
share, is limited to approximately $3,421,000$6,890,000 for each nuclear incident.
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, has
coverage under NEIL II, which provides insurance to cover decontamination,
debris removal and premature decommissioning as well as excess property damage
to nuclear generating facilities for an additional $2,250,000,000 for losses in
excess of the $500,000,000 primary coverage described above. Under the NEIL
policies, members are subject to retroactive assessments in proportion to their
premiums if losses exceed the accumulated funds available to the insurer under
the policy. The portion of the current maximum annual assessment for GPC that
would be payable by Oglethorpe, based on ownership share, is limited to
approximately $4,000,000.$8,413,000.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
annually renewed on or after April 2, 1991 shall be dedicated first for the sole
purpose of placing the reactor in a safe and stable condition after an accident.
Any remaining proceeds are next to be applied toward the costs of
decontamination and debris removal operations ordered by the NRC, and any
further remaining proceeds are to be paid either to the company or to its bond
trustees as may be appropriate under the policies and applicable trust
indentures.
The Price-Anderson Act, as amended in 1988, limits public liability claims
that could arise from a single nuclear incident to $9,500,000,000 which amount
is to be covered by private insurance and a mandatory program of deferred
premiums that could be assessed against all owners of nuclear power reactors.
Such private insurance provided by American Nuclear Insurers (ANI) (in the
amount of $200,000,000$300,000,000 for each plant, the maximum amount currently available)
is carried by GPC for the benefit of all the co-owners of Plants Hatch and
Vogtle. Agreements of indemnity have been entered
60
into by and between each of
the co-owners and the NRC. In the event of a nuclear incident involving any
commercial nuclear facility in the country involving total public liability in
excess of $200,000,000, a licensee of a nuclear power plant could be assessed a
deferred premium of up to $88,095,000 per incident for each licensed reactor
operated by it, but not more than $10,000,000 per reactor per incident to be
paid in a calendar year. On the basis of its sell-back adjusted ownership
interest in four nuclear reactors, Oglethorpe could be assessed a maximum of
$105,714,000 per incident, but not more than $12,000,000 in any one year.
All retrospective assessments, whether generated for liability or property,
may be subject to applicable state premium taxes.
Following the terrorist attacks of September 2001, both ANI and NEIL
confirmed that terrorist acts against commercial nuclear power stations would be
covered under their insurance. Both companies, however, revised their policy
terms on a prospective basis to include an industry aggregate for all terrorist
acts. The NEIL aggregate, which applies to all claims stemming from terrorism
within a 12 month duration, is $3.24 billion plus any amounts that would be
available through reinsurance or indemnity from an outside source. The ANI cap
is a $300,000,000 shared industry aggregate.
69
9. Commitments:
a. Power purchase and sale agreements
Oglethorpe is utilizing power marketer arrangements to reduce the cost of
power to the Members. Oglethorpe has a power marketer agreement with LG&E Energy
Marketing Inc. ("LEM"), for approximately 50% of the load requirements of 37 of
the Members and an additional power marketer agreement with Morgan Stanley
Capital Group Inc. ("Morgan Stanley"), effective May 1, 1997, with respect to
50% of the 39 Members' then forecasted load requirements. The LEM agreement is
based on the actual requirements of the participating Members during the
contract term, whereas the Morgan Stanley agreement represents a fixed supply
obligation. Generally, these arrangements reduce the cost of supplying power tobenefit the Members by limiting the
risk of unit availability by providing a guaranteed
benefit for the use of excess resources and by providing future power needs at a fixed price.
Most of Oglethorpe's generating facilities and power purchase arrangements are
available for use by LEM and Morgan Stanley. Oglethorpe continues to be
responsible for all of the costs of its system resources but receives revenue
from LEM and Morgan Stanley for the use of the resources. After taking into
account the Oglethorpe resources made available to LEM and Morgan Stanley for
their use, Oglethorpe estimates that about 30% of its power supply capability in
2003 will be provided by these contracts.
The Morgan Stanley agreement has a term extending to March 31, 2005, but
the purchases for certain Members decline to zero prior to that date.
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. Pursuant to this provision, LEM has given notice to terminate the
agreement as of December 31, 2004.
In February 2001, LEM and its affiliates initiated the contractually defineda binding arbitration
process to resolve a number ofcertain issues relating to the interpretation and
administration of the agreement.LEM agreement and a similar agreement with Oglethorpe that
expired by its terms in 1999. In April 2002, Oglethorpe and LEM settled this
arbitration. As part of the settlement, Oglethorpe paid LEM approximately
$48,500,000. Oglethorpe recorded a reserve of $36,000,000 in 2001 and increased
the reserve by an additional $12,500,000 in 2002.
In addition, Oglethorpe has entered into various long-term power purchase
agreements. As of December 31, 2000,2002, Oglethorpe's minimum purchase commitments
under these agreements, without regard to capacity reductions or adjustments for
changes in costs, for the next five years and thereafter are as follows:
- --------------------------------------------------------------------------------================================================================================
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
2001 $95,400
2002 76,446================================================================================
2003 63,423$ 46,239
2004 64,86646,620
2005 66,329
- --------------------------------------------------------------------------------46,967
2006 31,998
2007 27,014
Thereafter 327,839
================================================================================
Oglethorpe's power purchases from these agreements amounted to
approximately $175,623,000$100,836,000 in 2000, $132,721,0002002, $130,110,000 in 19992001 and $172,897,000$149,617,000 in
1998.2000.
Oglethorpe has entered into an agreement with Alabama Electric Cooperative
to sell 100 MW of capacity for the period June 1998 through December 2005.
b. Operating leases
In December 1999, Oglethorpe sold existing coal rail cars and subsequently
entered into rental agreements with various terms and expiration dates for the
existing and for additional new coal rail cars. As of December 31, 2000,2002,
Oglethorpe's estimated minimum rental commitments for these operating leases
over the next five years and thereafter are as follows:
- --------------------------------------------------------------------------------================================================================================
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
2001================================================================================
2003 $ 2,877
2002 2,877
2003 2,877
2004 2,877
2005 2,877
2006 and beyond 40,489
- --------------------------------------------------------------------------------
612,877
2007 3,126
Thereafter 35,108
================================================================================
70
10. Environmental matters:
a. 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 current and future regulations.
b. New source review
In November 1999, the United States Justice Department, on behalf of the
Environmental Protection Agency (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.
c. Clean air act
On December 30, 2002, the Sierra Club, Physicians for Social
Responsibility, Georgia Forest Watch and one individual filed suit in Federal
Court in Georgia against GPC, alleging violations of the Clean Air Act at Plant
Wansley. The complaint alleges violations of opacity limits at both the coal
fired units, in which Oglethorpe is a co-owner, and other violations at several
of the combined cycle units where neither Oglethorpe nor Chattahoochee EMC has
an ownership interest.
Oglethorpe expects to acquire the combined cycle facility owned by Chattahoochee
EMC in the second quarter of 2003. This civil action requests injunctive and
declaratory relief, civil penalties, a supplemental environmental project and
attorneys' fees. While Oglethorpe believes that Plant Wansley has complied with
applicable laws and regulations, resolution of this matter is uncertain at this
time, as is any responsibility of Oglethorpe for a share of any penalties or
other costs that might be assessed against GPC.
On January 16, 2003, the Sierra Club appealed an unsuccessful challenge to
an air operating permit for the combined cycle facility owned by Chattahoochee
EMC to the United States Court of Appeals for the Eleventh Circuit. Oglethorpe
has intervened in the appeal. The petitioner seeks to have the air permit
invalidated and remanded back to EPA and the Georgia Environmental Protection
Division. Although Oglethorpe believes that a favorable outcome in this appeal
is likely, an unfavorable ruling could temporarily affect the ability of the
facility to continue to operate.
11. Quarterly financial data (unaudited):
Summarized quarterly financial information for 20002002 and 19992001 is as follows:
- --------------------------------------------------------------------------------================================================================================
(dollars in thousands)
First Second Third Fourth
Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
2000================================================================================
2002
Operating revenues $ 274,882287,878 $ 285,026279,527 $ 314,433325,706 $ 325,056270,210
Operating margin 61,527 60,986 49,396 49,04655,606 58,153 57,069 37,624
Net margin 9,188 9,624 (323) 1,489
19999,269 9,409 7,371 (8,509)
2001
Operating revenues $ 250,764306,607 $ 273,917279,911 $ 393,636319,580 $ 257,915233,191
Operating margin 62,293 58,342 59,961 51,33566,765 48,934 45,316 53,717
Net margin 8,099 4,483 6,241 1,115
- --------------------------------------------------------------------------------
Third quarter 200015,283 (1,211) (4,031) 8,376
================================================================================
The negative net margin was lower thanfor the same periodfourth quarter of 19992002 primarily as aresulted
from charges associated with the early retirement of Plant Tallassee. The
negative net margin for the second and third quarters of 2001 is the result of
a $10,500,000 reduction inreductions to revenue requirementrequirements of $17,252,000 and $18,270,000, respectively,
approved by Oglethorpe's Board of Directors.
Such reduction in revenues was recorded as a
reduction in sales to Members for the third quarter of 2000.
6271
REPORT OF MANAGEMENT
The management of Oglethorpe Power Corporation has prepared this report and
is responsible for the financial statements and related information. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
Oglethorpe maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions. Limitations exist in any system of
internal control based upon the recognition that the cost of the system should
not exceed its benefits. Oglethorpe believes that its system of internal
accounting control, together with the internal auditing function, maintains
appropriate cost/benefit relations.
Oglethorpe's system of internal controls is evaluated on an ongoing basis
by a qualified internal audit staff. The Corporation's independent public
accountants (PricewaterhouseCoopers LLP) also consider certain elements of the
internal control system in order to determine their auditing procedures for the
purpose of expressing an opinion on the financial statements.
PricewaterhouseCoopers LLP also provides an objective assessment of how
well management meets its responsibility for fair financial reporting.
Management believes that its policies and procedures provide reasonable
assurance that Oglethorpe's operations are conducted with a high standard of
business ethics. In management's opinion, the financial statements present
fairly, in all material respects, the financial position, results of operations,
and cash flows of Oglethorpe.
Thomas A. Smith
President and Chief Executive Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of Oglethorpe Power Corporation:
In our opinion, the accompanying balance sheets and statements of
capitalization and the related statements of revenues and expenses, patronage
capital and of cash flows present fairly, in all material respects, the
financial position of Oglethorpe Power Corporation at December 31, 20002002 and
1999,2001, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 20002002 in conformity with accounting
principles generally accepted accounting principles in the United States of America. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted auditing standards in the United States of America which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
PricewaterhouseCoopers LLP
Atlanta, Georgia
February 23, 2001
63March 14, 2003
72
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Oglethorpe has a ten-member board of directors consisting of six directors
elected from the Members (the "Member Directors") and four independent outside
directors (the "Outside Directors"). Each Member Director must be a director or
general manager of an Oglethorpe Member. Five of the six Member Directors must
be located in each of five geographical regions of the State of Georgia. The
sixth Member Director is elected statewide. None of the four Outside Directors
may be a director, officer or employee of GTC, GSOC or any Member. All ten
directors are nominated by representatives from each Member whose weighted
nomination is based on the number of retail customers served by each Member.
After nomination, the directors are elected by a majority vote of each Member,
voting on a one-Member, one-vote basis.
The Bylaws provide for staggered three-year terms of the directors by
dividing the number of directors into three groups. The terms of approximately
one-third of the directors expire each yearyear.
Oglethorpe is managed and operated under the direction of a President and
Chief Executive Officer, who is appointed by the Board of Directors. The Senior
Officers and Directors of Oglethorpe are as follows:
Name Age Position
J. Calvin Earwood............ 59 Chairman of the Board of Directors,
Member Director, Statewide- ---- --- --------
Thomas A. Smith.............. 46Smith......... 48 President and Chief Executive Officer
Michael W. Price............. 40Price........ 42 Chief Operating Officer
W. Clayton Robbins........... 54Robbins...... 56 Senior Vice President, FinanceAdministration and AdministrationRisk
Management
Elizabeth B. Higgins......... 32Higgins.... 34 Vice President, Corporate Strategy andPlanning, Rates & Analysis
Benny W. Denham......... 72 Chairman of the Board, Member ServicesDirector, Southwest
Region
Larry N. Chadwick............ 60Chadwick....... 62 Member Director, Northwest Region
Benny W. Denham.............. 70 Member Director, Southwest Region
Sammy M. Jenkins............. 74 Member Director, Southeast Region
Mac F. Oglesby............... 68Marshall S. Millwood.... 53 Member Director, Northeast Region
and
Treasurer
J. Sam L. Rabun.............. 69Rabun......... 71 Member Director, Central Region and Vice Chairman
Robert E. Rentfrow...... 48 Member Director, Southeast Region
H.B. Wiley, Jr.......... 58 Member Director Statewide
Ashley C. Brown.............. 55Brown......... 57 Outside Director
Wm. Ronald Duffey............ 59Duffey....... 61 Outside Director
John S. Ranson............... 71Ranson.......... 73 Outside Director
Jeffrey D. Tranen............ 54Tranen....... 56 Outside Director
J. Calvin Earwood is the Chairman of the Board and is the Member Director
elected statewide. Mr. Earwood has served as an executive officer of Oglethorpe
since March 1984 (from March 1984 to July 1986, as Vice President; from July
1986 to March 1989, as Vice Chairman of the Board; and since March 1989, as
Chairman of the Board). Mr. Earwood has served on the Board of Directors of
Oglethorpe since March 1981. His present term will expire in March 2003. He is
64
the Chairman of the Compensation Committee. From 1965 through 1982, Mr. Earwood
was a salesman and part owner of Builders Equipment Company. Since January 1983,
he has been the owner and President of Sunbelt Fasteners, Inc., which sells
specialty tools and fasteners to the commercial construction trade. He is also
Vice Chairman of the Board of Directors of both Community Trust Financial
Services and Community Trust Bank in Hiram, Georgia and a Director of GreyStone
Power Corporation.
Thomas A. Smith is the President and Chief Executive Officer of Oglethorpe
and has served in that capacity since September 1999. He previously served as
Senior Vice President and Chief Financial Officer of Oglethorpe from September
1998 to August 1999, Senior Financial Officer from 1997 to August 1998, Vice
President, Finance from 1986 to 1990, Manager of Finance from 1983 to 1986 and
Manager, Financial Services from 1979 to 1983. From 1990 to 1997, Mr. Smith was
73
Senior Vice President of the Rural Utility Banking Group of CoBank, where he
managed the bank's eastern division, rural utilities. Mr. Smith is a Certified
Public Accountant, has a Master of Science degree in Industrial
Management-Finance from the Georgia Institute of Technology, a Master of Science
degree in Analytical Chemistry from Purdue University and a Bachelor of Arts
degree in Mathematics and Chemistry from Catawba College. Mr. Smith is a
Director of GSOC, and a Director ofACES Power Marketing, the Georgia Chamber of Commerce.Commerce, and
En-Touch Systems, Inc. in Houston, Texas. Mr. Smith is also a member of the
Advisory Board of Mid-South Telecommunications, Inc. in Houston, Texas.
Michael W. Price is the Chief Operating Officer of Oglethorpe and has
served in that office since February 1, 2000. Mr. Price served GSOC from January
1999 to January 2000, first as Senior Vice President and then as Chief Operating
Officer. He served as Vice President of System Planning and Construction of GTC
from May 1997 to December 1998. He served as a manager of system control of GSOC
from January to May 1997. From 1986 to 1997, Mr. Price served Oglethorpe in the
areas of control room operations, system planning, construction and engineering,
and energy management systems. Prior to joining Oglethorpe, he was a field test
engineer with the TVA from 1983 to 1986. Mr. Price has a Bachelor of Science
degree in Electrical Engineering from Auburn University.
W. Clayton Robbins is the Senior Vice President, FinanceAdministration and AdministrationRisk
Management of Oglethorpe and has served in that office since October 2002. Mr.
Robbins served as Senior Vice President, Finance and Administration from
November 1999.1999 to October 2002. Mr. Robbins served as Senior Vice President and
General Manager of Intellisource, Inc. from February 1997 to November 1999.
Prior to that, Mr. Robbins held several positions at Oglethorpe since 1986,
including Senior Vice President, Support Services from December 1991 to January
1997 and Vice President, Market Research and Analysis from December 1989 to
December 1991. Before coming to Oglethorpe, Mr. Robbins spent 18 years with
Stearns-Catalytic World Corporation, a major engineering and construction firm,
including 13 years in management positions responsible for human resources,
information systems, contracts, insurance, accounting and project controls. Mr.
Robbins has a Bachelor of Arts degree in Business Administration from the
University of North Carolina in Charlotte.
Elizabeth B. Higgins is the Vice President, Corporate Strategy and Member
ServicesPlanning, Rates & Analysis of
Oglethorpe and has served in this office since July 2000. Ms. Higgins served as
the Vice President and Assistant to the Chief Executive Officer from October
1999 to July 2000 and served in other capacities for Oglethorpe from April 1997
to September 1999. Prior to that, Ms. Higgins served as Project Manager at
Southern Engineering from October 1995 to April 1997, as Senior Consultant at
Deloitte & Touche, LLP from April 1995 to October 1995, and as Senior Consultant
at Energy Management Associates from June 1991 to April 1995. In these
positions, Ms. Higgins was responsible for competitive bidding analyses, rate
designs, integrated resource planning studies, operational/dispatch studies,
bulk power market analysis, merger analyses and litigation support. Ms. Higgins
has a Bachelor of Industrial Engineering degree from the Georgia Institute of
Technology.
Benny W. Denham is Chairman of the Board and Member Director from the
Southwest Region. He has served on the Board of Directors of Oglethorpe since
December 1988. His present term will expire in March 2004. Mr. Denham has been
co-owner of Denham Farms in Turner County, Georgia since 1980. He serves as a
Board member and past Chairman of the Turner County Chamber of Commerce. Mr.
Denham is the Chairman of the Board of Directors of Community National Bank of
Ashburn, Georgia, and a Director of Georgia Electric Membership Corporation and
Irwin EMC.
Larry N. Chadwick is the Member Director from the Northwest Region. He has
been the owner of Chadwick's Hardware in Woodstock, Georgia since 1983. He has
65
served on the Board of Directors of Oglethorpe since July 1989. His present term
will expire in March 2002.2005. Mr. Chadwick is an engineer, with experience in the
design of hydrogen gas plants. He is Chairman of the Board of Cobb EMC.
Benny W. Denham is the Member Director from the Southwest Region. He has
served on the Board of Directors of Oglethorpe since December 1988. His present
term will expire in March 2001. Mr. Denham has been co-owner of Denham Farms in
Turner County, Georgia since 1980. He serves as the Chairman of the Turner
County Chamber of Commerce. Mr. Denham is a Director of Community National Bank
Holding Co., Cumberland National Bank, Georgia Electric Membership Corporation
and Irwin EMC.
Sammy M. Jenkins is the Member Director from the Southeast Region. He has
retired from farming after 25 years. In addition, from 1973 to 1995, he was
President of Jenkins Ford Tractor Co., Inc., a seller of farm machinery. He has
served on the Board of Directors of Oglethorpe since March 1988. His present
term will expire in March 2002.
Mac F. Oglesby74
Marshall S. Millwood is the Member Director from the Northeast Region and the
Treasurer of Oglethorpe.Region. He
is a member of the Audit Committee. He has served asbecame a member of the Board of Directors of Hart EMC since 1980in March 2003 and now serves as its
Chairman of the Board. He has served on the Board of Directors of Oglethorpe
since February 1987. His presenthis term will expire
in March 2003. Mr. Oglesby was2006. He has been the owner and operator of Marjomil Inc., a U.S. Postal Service Rural Carrier for 30 years until he retiredpoultry
and cattle farm in 1991.Forsyth County, Georgia, since 1998. He is a Director of
Sawnee EMC.
J. Sam L. Rabun is the Vice-Chairman of the Board and is the Member
Director from the Central Region. He is also a member of the CompensationAudit Committee. He
has been the owner and operator of a farm in Jefferson County, Georgia since
1979. He is also a 50% owner of R&R Livestock Farms, Inc. He has served on the
Board of Directors of Oglethorpe since March 1993. His present term will expire
in March 2001.2004. Mr. Rabun served as the President of the Board of Jefferson EMC
from 1993 to 1996, was employed as General Manager from 1974 to 1979 and as
Office Manager and Accountant from 1970 to 1974. Mr. Rabun is Vice-Chairman of
the PresidentBoard of the Georgia Energy Cooperative.
Robert E. Rentfrow is the Member Director from the Southeast Region. Mr.
Rentfrow became a Member of the Board of Directors of Oglethorpe in June 2002.
Mr. Rentfrow is a member of the Board's Audit Committee. Mr. Rentfrow's term on
the Board of Directors of Oglethorpe will expire in 2005. Mr. Rentfrow has been
the President and Chief Executive Officer of Satilla Rural EMC Directors' Association.since January
1996 and has been associated with EMCs in Georgia for the past 17 years. Mr.
Rentfrow serves as Director on the Governor's Workforce Investment Board and the
Regional Advisory Council. Mr. Rentfrow also serves as Chairman of the Bacon
County Industrial Building Authority and is a member of the Waycross College
Board of Trustees. Mr. Rentfrow is a graduate of Southern Technical Institute
and Georgia Southern College.
H.B. Wiley, Jr. is the Member Director elected statewide. He became a
member of the Board of Directors in March 2003 and his term will expire in March
2006. Mr. Wiley previously served as a member of the Board of Directors from
July 1994 until March 1997. Mr. Wiley has been an associate broker in real
estate since 1994. Prior to that he owned and operated a dairy farm in Oconee
County, Georgia from 1973 to 1994. During that time he served on the board of
Atlanta Dairies Cooperative and Georgia Milk Producers Board. He has been a
director of Walton EMC since June 1993, and has served as its Chairman of the
Board since June 2000. Mr. Wiley has Bachelor of Science degree from the
University of Georgia.
Ashley C. Brown is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. He is the Chairman of the Audit
Committee. His present term will expire in March 2002.2005. He has been Executive
Director of the Harvard Electricity Policy Group at Harvard University's John F.
Kennedy School of Government since 1993. In addition, he ishas been Of Counsel to
the law firm of LeBoeuf, Lamb, Greene and MacRae.MacRae since May 1997. From April 1983
through April 1993, Mr. Brown served as Commissioner of the Public Utilities
Commission of Ohio. Prior to his appointment to the Ohio Commission, he was
Coordinator and Counsel of the Montgomery County, Ohio, Fair Housing Center.
From 1979 to 1981, he was Managing Attorney for the Legal Aid Society of Dayton
(Ohio), Inc. From 1977 to 1979, he was Legal Advisor of the Miami Valley
Regional Planning Commission in Dayton, Ohio. In addition, Mr. Brown has
extensive teaching experience in public schools and universities and has
published widely in the field of utility regulation. Mr. Brown has a law degree
from the University of Dayton School of Law, a Master of Arts degree from the
University of Cincinnati, and a Bachelor of Science degree from Bowling Green
State University.
Wm. Ronald Duffey is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. He is a member of the Audit Committee.
His term will expire in March 2001.2004. Mr. Duffey is the President and Chief
Executive Officer and a director of Peachtree National Bank in Peachtree City,
Georgia, a wholly owned subsidiary of Synovus Financial Corp. Prior to his
employment in 1985 with Peachtree National Bank, Mr. Duffey served as Executive
Vice President and Member of the Board of Directors for First National Bank in
Newnan, Georgia. He holds a Bachelor of Business Administration from Georgia
State College with a concentration in finance and has completed banking courses
at the Banking School of the South, the American Bankers Association School of
66
Bank Investments, and The Stonier Graduate School of Banking, Rutgers
University. Mr. Duffey is a Director of Fayette Community Hospital.
John S. Ranson is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. His term will expire in March 2002.2005. He
is also a member of the Compensation Committee. He has been the President of
Ranson Municipal Consultants, L.L.C., a financial advisor in Wichita, Kansas,
since 1994. From 1990 to 1994, Mr. Ranson was Chairman of Ranson Capital Corp.
an investment banking firm. Mr. Ranson has approximately 48 years experiencebeen in the investment banking
business.business since 1953. His public finance clients have included the Kansas
Turnpike Authority, the Kansas Municipal Energy Agency, the Kansas Municipal Gas
Agency, and the Kansas City (Kansas) Board of Public Utilities. Mr. Ranson
received his Bachelor of Science in Business Administration from the University
of Kansas (Lawrence, Kansas) and attended the Navy Supply Corps School in
Bayonne, New Jersey.
75
Jeffrey D. Tranen is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 2000. His present term will expire in March
2003. Since May 2000, he has served as Senior Vice President of Lexecon, an
economic, regulatory and business strategy consulting firm. Prior to that, he
served as President and Chief Operating Officer of Sithe Northeast, a merchant
generation company.company from 1999 to 2000. Mr. Tranen served as the President and
Chief Executive Officer of the California Independent System Operator from 1997
to 1999. From 1970 to 1997, Mr. Tranen worked in several positions for the New
England Electric System, most recently as Senior Vice President of the New
England Electric System. He is currently a member of the Board of Directors of
Doble Engineering.Engineering Co. Mr. Tranen has a Bachelor of Science in Electrical
Engineering and a Master of Science in Electrical Engineering from the
Massachusetts Institute of Technology.
6776
ITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The following table sets forth, for Oglethorpe's President and Chief
Executive Officer and for the three other executive officers, all compensation
paid or accrued for services rendered in all capacities during the years ended
December 31, 2000, 19992002, 2001 and 1998.2000.
Annual Compensation All Other
------------------- ---------
Name and ------------------- All Other Principal Position Year Salary Bonus CompensationCompensation(1)
- --------------------------------------------- ---- ------ ----- ---------------------------
Thomas A. Smith(1)................................... 2000 $ 275,000 $ 82,800 $ 14,005(2)Smith...................................... 2002 $320,000 $115,349 $193,736 (2)
President and Chief Executive Officer 1999 202,008 65,283 14,237
1998 183,935 12,180 1,2472001 292,500 87,320 90,529
2000 275,000 82,800 14,005
Michael W. Price..................................... 2002 196,267 70,530 19,346
Chief Operating Officer 2001 182,008 54,464 26,527
2000 157,667 50,912 23,583
W. Clayton Robbins(3)................................Robbins................................... 2002 176,483 55,068 17,473
Senior Vice President, Administration and 2001 169,417 44,160 17,640
Risk Management 2000 163,000 42,476 11,335(2)
Senior Vice President and Finance Administration 1999 23,341 35,945 1,259
1998 0 0 0
Michael W. Price(4).................................. 2000 157,667 50,912 23,583(2)(5)
Chief Operating Officer 1999 0 0 0
1998 0 0 011,335
Elizabeth B. Higgins................................. 2002 148,434 46,381 16,165
Vice President, Planning, Rates and Analysis 2001 143,333 26,825 15,401
2000 126,125 24,975 11,846(2)
Vice President, Corporate Strategy and 1999 88,431 22,233 9,457
Member Services 1998 55,355 13,365 1,84511,846
- -------------------------------
(1) Prior to September 1, 1998, Mr. Smith provided services to Oglethorpe under
a contractual arrangement and the amounts reflectedFigures for 1998 include those
contract payments.
(2) Includes2002 consist of contributions made in 2000 by Oglethorpe under the
401(k) Retirement Savings Plan on behalf of Mr. Smith, Mr. Robbins,Price, Mr.
PriceRobbins and Ms. Higgins of $5,100, $2,073, $4,768$8,250, $6,812, $5,264 and $4,239,$7,076, respectively;
contributions under theOglethorpe's Money Purchase Pension Plan on behalf of
Mr. Smith, Mr. Robbins,Price, Mr. PriceRobbins and Ms. Higgins of $8,500, $8,500, $8,500$10,000, $12,123,
$10,648 and $7,418,$8,763, respectively; and insurance premiums paid on term life
insurance on behalf of Mr. Smith, Mr. Robbins,Price, Mr. PriceRobbins and Ms. Higgins of
$405, $762,
$315$486, $412, $1,562 and $189,$327, respectively.
(3) Mr. Robbins became an Oglethorpe employee on November 16, 1999.
(4) Mr. Price became an Oglethorpe employee on February 1, 2000.
(5)(2) Includes a signingcontribution under Oglethorpe's Executive Supplemental
Retirement Plan of $75,000 and a bonus of $10,000$100,000 paid in 2000.connection with
entering into a new employment agreement.
Compensation of Directors
Oglethorpe pays its Outside Directors a fee of $5,500 per Board meeting for
four meetings in a year; a fee of $1,000 per Board meeting will be paid for the
remaining other Board meetings in a year. Outside Directors are also paid $1,000
77
per day for attending committee meetings, annual meetings of the Members or
other official meetingsbusiness of Oglethorpe. Member Directors are paid a fee of $1,000
per Board meeting and $600 per day for attending committee meetings, annual
meetings of the Members or other official business of Oglethorpe. In addition,
Oglethorpe reimburses all Directors for out-of-pocket expenses incurred in
attending a meeting. All Directors are paid $50 per day when participating in
meetings by conference call. The Chairman of the Board is paid an additional 20%
of his Director's fee per Board meeting for time involved in preparing for the
meetings.
Beginning in 2001, Mr. Tranen was given a special assignment by the Board
of Directors in his capacity as a Director of Oglethorpe to work with
Oglethorpe's staff and consultants on an evaluation of matters relating to
member scheduling issues, system operations, and pool operations. During 2002,
Mr. Tranen was paid approximately $14,700 for fees and expenses relating to this
assignment.
Employment Contracts
Oglethorpe entered into an Employment Agreement with Thomas A. Smith,
Oglethorpe's President and Chief Executive Officer, effective SeptemberMarch 15, 1999.2002.
The agreement extends until December 31, 2002,2004, and automatically renews for
successive one-year periods unless either party gives notice of termination prior to December 31, 2000 or 2524
months prior to the expiration of the agreement or any extension
68
of the
agreement. The agreement has automatically renewed until December 31, 2005. Mr.
Smith's minimum base salary is $250,000$325,000 per year, and is annually adjusted by
the Board of Directors of Oglethorpe. Mr. Smith was paid a retention bonus of
$50,000 in January 2003 and is entitled to bonuses totaling $50,000 if he
remains employed by Oglethorpe through 2003 and 2004. In addition, Mr. Smith has
opportunities for variable pay for accomplishing goals set by Oglethorpe's Board
of Directors each year.
Upon the occurrence of any of the following events, Mr. Smith will be
entitled to a lump-sum severance payment: (1) Oglethorpe terminates Mr. Smith's
employment without cause; (2) Mr. Smith resigns within 180 days of a material
reduction or alteration of his title or responsibilities or a change in the
location of Mr. Smith's principal office by more than 50 miles; (3) Oglethorpe
is sold or Oglethorpe sells essentially all of its assets or control of its
assets, and the sale results in a termination of Mr. Smith's employment as
President and Chief Executive Officer of Oglethorpe or a material reduction of
his title or responsibilities; or (4) an event of default under Oglethorpe's RUS
loan contract occurs and is continuing and RUS requests that Oglethorpe
terminate Mr. Smith. The severance payment will equal Mr. Smith's base salary
through the rest of the term of the agreement (with a minimum of one year's pay
and a maximum of two years' pay) plus the cost of providing all health and
dental insurance for the longer of one year or the remaining term of the
agreement. In the case of (3) above, Oglethorpe also agrees to hireIf Mr. Smith asresigns for any reason other than those described above,
he will be entitled to a consultant for one year at a rateseverance payment equal to his then-applicable base salary.six months' salary if he
resigns before December 31, 2003.
Oglethorpe has also entered into Employment Agreements with Michael W.
Price, W. Clayton Robbins and Elizabeth B. Higgins, Oglethorpe's Chief Operating
Officer, Senior Vice President of FinanceAdministration and AdministrationRisk Management and Vice
President Corporate Strategyof Planning, Rates and Member Services,Analysis, respectively. Mr. Price's agreement was
effective February 1, 2000, and Mr. Robbins' and Ms. Higgins' agreements were
effective August 1, 2000. Each agreement extends until December 31, 2001, and
automatically renews for a successive one-year periodperiods ending each December 31
unless either party gives notice of termination prior to November 30, 2000 or 13 months prior to the
expiration of any extension of the Agreement. Minimum annual base salaries are
$172,000 for Mr. Price, $164,000 for Mr. Robbins and $135,000$165,000 for Ms. Higgins.
Ms. Higgins entered into an amendment to her employment agreement on February
19, 2003. The amendment provided for an immediate bonus of $30,000 and bonuses
totaling $50,000 if she remains employed by Oglethorpe through June 30, 2003 and
January 1, 2004. Salaries are annually adjusted by the Board of Directors of
Oglethorpe. Each executive has opportunities for variable pay for accomplishing
goals set by Oglethorpe's Board of Directors each year.
78
Under each Employment Agreement, the executive will be entitled to a
lump-sum severance payment if Oglethorpe terminates the executive without cause
or if the executive resigns after (1) a demotion or a material reduction or
alteration of the executive's title or responsibilities, (2) a reduction of the
executive's base salary or (3) a change in the location of the executive's
principal office by more than 50 miles. The severance payment will equal the
executive's base salary for one year, plus the equivalent of six months' medical
allowance.
Compensation Committee Interlocks and Insider Participation
J. Calvin Earwood, John S. Ranson and J. Sam L. RabunMac F. Oglesby served as members of
the Oglethorpe Power Corporation Compensation Committee in 2000.2002. Mr. Earwood has
served as an executive officer of Oglethorpe sincefrom 1984 until March 2003 and has
served as the Chairman of the Board since 1989.
69
from 1989 until March 2003.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
70Robert E. Rentfrow is a Director of Oglethorpe and the President and Chief
Executive Officer of Satilla Rural EMC. Satilla Rural EMC is a Member of
Oglethorpe and has a Wholesale Power Contract with Oglethrope. Satilla Rural
EMC's payments to Oglethorpe under the Wholesale Power Contract accounted for
approximately 3% of Oglethorpe's total revenues and 48% of Satilla Rural EMC's
total revenues in 2002.
ITEM 14. CONTROLS AND PROCEDURES
Within 90 days prior to the filing date of this report, Oglethorpe carried
out an evaluation, under the supervision and with the participation of its
management, including its President and Chief Executive Officer and Vice
President, Finance and Treasurer, of the effectiveness of the design and
operation of its disclosure controls and procedures (as defined in Rules
13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended).
Based on this evaluation, the President and Chief Executive Officer and the Vice
President, Finance and Treasurer concluded that Oglethorpe's disclosure controls
and procedures are effective to ensure that information required to be disclosed
by Oglethorpe in the reports that Oglethorpe files or submits under the
Securities Exchange Act is recorded, processed, summarized and reported within
the time periods required by the Securities Exchange Act and the rules
thereunder.
No significant changes occurred in Oglethorpe's internal controls or in
other factors that could significantly affect its internal controls since the
date of its evaluation. Oglethorpe has not found any significant deficiencies or
material weaknesses in these controls which require any corrective actions since
the date of Oglethorpe's evaluation.
79
PART IV
ITEM 14.15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Page
----
(a) List of Documents Filed as a Part of This Report.
(1) Financial Statements (Included under "Item 8. Financial Statements
and Supplementary Data")
Statements of Revenues and Expenses, For the Years Ended
December 31, 2000, 19992002, 2001 and 1998...............................45
Statements of Patronage Capital, For the Years Ended
December 31, 2000, 1999 and 1998...............................452000................................... 53
Balance Sheets, As of December 31, 20002002 and 1999.................462001................... 54
Statements of Capitalization, As of December 31, 20002002 and 1999...482001..... 56
Statements of Cash Flows, For the Years Ended
December 31, 2000, 19992002, 2001 and 1998...............................492000................................. 57
Statements of Patronage Capital and Membership Fees
And Accumulated Other Comprehensive Margin For the Years Ended
For the Years Ended December 31, 2002, 2001 and 2000............. 58
Notes to Financial Statements....................................50Statements...................................... 59
Report of Management.............................................63Management............................................... 72
Report of Independent Accountants................................63Accountants.................................. 72
(2) Financial Statement Schedules
None applicable.
(3) Exhibits
Exhibits marked with an asterisk (*) are hereby incorporated by reference
to exhibits previously filed by the Registrant as indicated in parentheses
following the description of the exhibit.
Number Description
*2.1 -- Second Amended and Restated Restructuring Agreement, dated February
24, 1997, by and among Oglethorpe, Georgia Transmission Corporation
(An Electric Membership Corporation) and Georgia System Operations
Corporation. (Filed as Exhibit 2.1 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1996, File No. 33-7591.)
*2.2 -- Member Agreement, dated August 1, 1996, by and among Oglethorpe,
Georgia Transmission Corporation (An Electric Membership Corporation),
Georgia System Operations Corporation and the Members of Oglethorpe.
(Filed as Exhibit 2.2 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*3.1(a)-- Restated Articles of Incorporation of Oglethorpe, dated as of July 26,
1988. (Filed as Exhibit 3.1 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1988, File No. 33-7591.)
*3.1(b)-- Amendment to Articles of Incorporation of Oglethorpe, dated as of
March 11, 1997. (Filed as Exhibit 3(i)(b) to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
80
*3.2 -- Bylaws of Oglethorpe, as amended on January 10, 2000.November 14, 2001. (Filed as
Exhibit 3.2 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1999,2001, File No. 33-7591.)
71
*4.1 -- Form of Serial Facility Bond Due June 30, 2011 (included in Collateral
Trust Indenture filed as Exhibit 4.2.)
*4.2 -- Collateral Trust Indenture, dated as of December 1, 1997, between OPC
Scherer 1997 Funding Corporation A, Oglethorpe and SunTrust Bank,
Atlanta, as Trustee. (Filed as Exhibit 4.2 to the Registrant's Form
S-4 Registration Statement, File No. 333-42759.)
*4.3 -- Nonrecourse Promissory Lessor Note No. 2, with a Schedule identifying
three other substantially identical Nonrecourse Promissory Lessor
Notes and any material differences. (Filed as Exhibit 4.3 to the
Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*4.4 -- Amended and Restated Indenture of Trust, Deed to Secure Debt and
Security Agreement No. 2, dated December 1, 1997, between Wilmington
Trust Company and NationsBank, N.A. collectively as Owner Trustee,
under Trust Agreement No. 2, dated December 30, 1985, with DFO
Partnership, as assignee of Ford Motor Credit Company, and The Bank of
New York Trust Company of Florida, N.A. as Indenture Trustee, with a
Schedule identifying three other substantially identical Amended and
Restated Indentures of Trust, Deeds to Secure Debt and Security
Agreements and any material differences. (Filed as Exhibit 4.4 to the
Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*4.5(a)-- Lease Agreement No. 2 dated December 30, 1985, between Wilmington
Trust Company and William J. Wade, as Owner Trustees under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, Lessor, and Oglethorpe, Lessee, with a Schedule identifying
three other substantially identical Lease Agreements. (Filed as
Exhibit 4.5(b) to the Registrant's Form S-1 Registration Statement,
File No. 33-7591.)
*4.5(b) -- First* 4.5(b)--First Supplement to Lease Agreement No. 2 (included as Exhibit B to
the Supplemental Participation Agreement No. 2 listed as 10.1.1(b)).
*4.5(c) -- First--First Supplement to Lease Agreement No. 1, dated as of June 30, 1987,
between The Citizens and Southern National Bank as Owner Trustee under
Trust Agreement No. 1 with IBM Credit Financing Corporation, as
Lessor, and Oglethorpe, as Lessee. (Filed as Exhibit 4.5(c) to the
Registrant's Form 10-K for the fiscal year ended December 31, 1987,
File No. 33-7591.)
*4.5(d) -- Second--Second Supplement to Lease Agreement No. 2, dated as of December 17,
1997, between NationsBank, N.A., acting through its agent, The Bank of
New York, as an Owner Trustee under the Trust Agreement No. 2, dated
December 30, 1985, among DFO Partnership, as assignee of Ford Motor
Credit Company, as the Owner Participant, and the Original Trustee, as
Lessor, and Oglethorpe, as Lessee, with a Schedule identifying three
other substantially identical Second Supplements to Lease Agreements
and any material differences. (Filed as Exhibit 4.5(d) to the
Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*4.6 -- Amended and Consolidated Loan Contract, dated as of March 1, 1997,
between Oglethorpe and the United States of America, together with
four notes executed and delivered pursuant thereto. (Filed as Exhibit
4.7 to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*4.7.1(a) -- Indenture,-Indenture, dated as of March 1, 1997, made by Oglethorpe to SunTrust
Bank, Atlanta, as trustee. (Filed as Exhibit 4.8.1 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
7281
*4.7.1(b) -- First-First Supplemental Indenture, dated as of October 1, 1997, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1997B (Burke) Note. (Filed as Exhibit 4.8.1(b) to the
Registrant's Form 10-Q for the quarterly period ended September 30,
1997, File No. 33-7591.)
*4.7.1(c) -- Second-Second Supplemental Indenture, dated as of January 1, 1998, made by
Oglethorpe to SunTrust Bank, as trustee, relating to the Series 1997C
(Burke) Note. (Filed as Exhibit 4.7.1(c) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1997, File No. 33-7591.)
*4.7.1(d) -- Third-Third Supplemental Indenture, dated as of January 1, 1998, made by
Oglethorpe to SunTrust Bank, as trustee, relating to the Series 1997A
(Monroe) Note. (Filed as Exhibit 4.7.1(d) to the Registrant's Form
10-K for the fiscal year December 31, 1997, File No. 33-7591.)
*4.7.1(e) -- Fourth-Fourth Supplemental Indenture, dated as of March 1, 1998, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1998A (Burke) and 1998B (Burke) Notes. (Filed as Exhibit
4.7.1(e) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1998, File No. 33-7591.)
*4.7.1(f) -- Fifth-Fifth Supplemental Indenture, dated as of April 1, 1998, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1998 CFC Note. (Filed as Exhibit 4.7.1(f) to the Registrant's
Form 10-K for the fiscal year ended December 31, 1998, File No.
33-7591.)
*4.7.1(g) -- Sixth-Sixth Supplemental Indenture, dated as of January 1, 1999, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1998C (Burke) Note. (Filed as Exhibit 4.7.1(g) to the
Registrant's Form 10-K for the fiscal year ended December 31, 1998,
File No. 33-7591.)
*4.7.1(h) -- Seventh-Seventh Supplemental Indenture, dated as of January 1, 1999, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1998A (Monroe) Note. (Filed as Exhibit 4.7.1(h) to the
Registrant's Form 10-K for the fiscal year ended December 31, 1998,
File No. 33-7591.)
*4.7.1(i) -- Eighth-Eighth Supplemental Indenture, dated as of November 1, 1999, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1999B (Burke) Note. (Filed as Exhibit 4.7.1(i) to the
Registrant's Form 10-K for the fiscal year ended December 31, 1999,
File No. 33-7591.)
*4.7.1(j) -- Ninth-Ninth Supplemental Indenture, dated as of November 1, 1999, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1999B (Monroe) Note. (Filed as Exhibit 4.7.1(j) to the
Registrant's Form 10-K for the fiscal year ended December 31, 1999,
File No. 33-7591.)
*4.7.1(k) -- Tenth-Tenth Supplemental Indenture, dated as of December 1, 1999, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1999 Lease Notes. (Filed as Exhibit 4.7.1(k) to the
Registrant's Form 10-K for the fiscal year ended December 31, 1999,
File No. 33-7591.)
*4.7.1(l) -- Eleventh-Eleventh Supplemental Indenture, dated as of January 1, 2000, made by
Oglethorpe to SunTrust Bank as trustee, relating to the Series 1999A
(Burke) Note. (Filed as Exhibit 4.7.1(l) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1999, File No. 33-7591.)
*4.7.1(m) -- Twelfth-Twelfth Supplemental Indenture, dated as of January 1, 2000, made by
Oglethorpe to SunTrust Bank as trustee, relating to the Series 1999A
(Monroe) Note. (Filed as Exhibit 4.7.1(m) to the Registrant's Form
10-K for the fiscal year ended December 31, 1999, File No. 33-7591.)
7382
4.7.1(n) -- Thirteenth*4.7.1(n)-Thirteenth Supplemental Indenture, dated as of January 1, 2001, made
by Oglethorpe to SunTrust Bank, as trustee, relating to the Series
2000 (Burke) Note. 4.7.1(o) -- Fourteenth(Filed as Exhibit 4.7.1(n) to the Registrant's Form
10-K for the fiscal year ended December 31, 2000, File No. 33-7591.)
*4.7.1(o)-Fourteenth Supplemental Indenture, dated as of January 1, 2001, made
by Oglethorpe to SunTrust Bank, as trustee, relating to the Series
2000 (Monroe) Note. (Filed as 4.7.1(o) to the Registrant's Form 10-K
for the fiscal year ended December 31, 2000, File No. 33-7591.)
*4.7.1(p)-Fifteenth Supplemental Indenture, dated as of January 1, 2002, made by
Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2001
(Burke) Note. (Filed as Exhibit 4.7.1(p) to the Registrant's Form 10-K
for the fiscal year ended December 31, 2001, File No. 33-7591.)
*4.7.1(q)-Sixteenth Supplemental Indenture, dated as of January 1, 2002, made by
Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2001
(Monroe) Note. (Filed as Exhibit 4.7.1(q) to the Registrant's Form
10-K for the fiscal year ended December 31, 2001, File No. 33-7591.)
4.7.1(r)--Seventeenth Supplemental Indenture, dated as of October 1, 2002, made
by Oglethorpe to SunTrust Bank, as trustee, relating to the Series
2002A (Burke) Note.
4.7.1(s)--Eighteenth Supplemental Indenture, dated as of October 1, 2002, made
by Oglethorpe to SunTrust Bank, as trustee, relating to the Series
2002B (Burke) Note.
4.7.1(t)--Nineteenth Supplemental Indenture, dated as of January 1, 2003, made
by Oglethorpe to SunTrust Bank, as trustee, relating to the Series
2002C (Burke) Note.
4.7.1(u)--Twentieth Supplemental Indenture, dated as of January 1, 2003, made by
Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2002
(Monroe) Note.
4.7.1(v)--Twenty-First Supplemental Indenture, dated as of January 1, 2003, made
by Oglethorpe to SunTrust Bank, as trustee, relating to the Series
2002 (Appling) Note.
*4.7.2 -- Security Agreement, dated as of March 1, 1997, made by Oglethorpe to
SunTrust Bank, Atlanta, as trustee. (Filed as Exhibit 4.8.2 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
4.8.1(1) -- Loan--Loan Agreement, dated as of October 1, 1992, between Development
Authority of Monroe County and Oglethorpe relating to Development
Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe
Power Corporation Scherer Project), Series 1992A, and five other
substantially identical loan agreements.
4.8.2(1) -- Note,--Note, dated October 1, 1992, from Oglethorpe to Trust Company Bank, as
trustee acting pursuant to a Trust Indenture, dated as of October 1,
1992, between Development Authority of Monroe County and Trust Company
Bank, and five other substantially identical notes.
4.8.3(1) -- Trust--Trust Indenture, dated as of October 1, 1992, between Development
Authority of Monroe County and Trust Company Bank, Trustee, relating
to Development Authority of Monroe County Pollution Control Revenue
Bonds (Oglethorpe Power Corporation Scherer Project), Series 1992A,
and five other substantially identical trust indentures.
83
4.9.1(1) -- Loan--Loan Agreement, dated as of December 1, 1992, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Adjustable Tender Pollution Control Revenue
Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and
one other substantially identical loan agreement.
4.9.2(1) -- Note,--Note, dated December 1, 1992, from Oglethorpe to Trust Company Bank,
as trustee acting pursuant to a Trust Indenture, dated as of December
1, 1992, between Development Authority of Burke County and Trust
Company Bank, and one other substantially identical note.
4.9.3(1) -- Trust--Trust Indenture, dated as of December 1, 1992, from Development
Authority of Burke County to Trust Company Bank, as trustee, relating
to Development Authority of Burke County Adjustable Tender Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A, and one other substantially identical trust indenture.
4.9.4(1) -- Interest--Interest Rate Swap Agreement, dated as of December 1, 1992, by and
between Oglethorpe and AIG Financial Products Corp. relating to
Development Authority of Burke County Adjustable Tender Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A, and one other substantially identical agreement.
4.9.5(1) -- Liquidity--Liquidity Guaranty Agreement, dated as of December 1, 1992, by and
between Oglethorpe and AIG Financial Products Corp. relating to
Development Authority of Burke County Adjustable Tender Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A, and one other substantially identical agreement.
74
4.9.6(1) -- Standby--Standby Bond Purchase Agreement, dated as of December 1, 1998, between
Oglethorpe and Bayerische Landesbank Girozentrale, relating to
Development Authority of Burke County Adjustable Tender Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A.
4.9.7(1) -- Standby--Standby Bond Purchase Agreement, dated as of November 30, 1994,
between Oglethorpe and Credit Local de France, Acting through its New
York Agency, relating to Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1994A.
4.10.1(1) -- Loan-Loan Agreement, dated as of October 1, 1996, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe
Power Corporation Vogtle Project), Series 1996, and one other
substantially identical loan agreements.
4.10.2(1) -- Note,-Note, dated October 1, 1996, from Oglethorpe to SunTrust Bank,
Atlanta, as trustee pursuant to an Indenture of Trust, dated as of
October 1, 1996, between Development Authority of Burke County and
SunTrust Bank, Atlanta, and one other substantially identical note.
4.10.3(1) -- Indenture-Indenture of Trust, dated as of October 1, 1996, between Development
Authority of Burke County and SunTrust Bank, Atlanta, as trustee,
relating to Development Authority of Burke County Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series
1996, and one other substantially identical indenture.
4.11.1(1) -- Loan-Loan Agreement, dated as of December 1, 1997, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe
Power Corporation Vogtle Project) Series 1997C, and three other
substantially identical loan agreements.
84
4.11.2(1) -- Note,-Note, dated January 14, 1998, from Oglethorpe to SunTrust Bank,
Atlanta, as trustee pursuant to an Indenture of Trust, dated as of
December 1, 1997, between Development Authority of Burke County and
SunTrust Bank, Atlanta, and three other substantially identical notes.
4.11.3(1) -- Indenture-Indenture of Trust, dated as of December 1, 1997, between Development
Authority of Burke County and SunTrust Bank, Atlanta, as trustee,
relating to Development Authority of Burke County Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series
1997C, and three other substantially identical indentures.
4.12.1(1) -- Loan-Loan Agreement, dated as of March 1, 1998, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe
Power Corporation Vogtle Project), Series 1998A, and one other
substantially identical loan agreement.
4.12.2(1) -- Note,-Note, dated March 17, 1998, from Oglethorpe to SunTrust Bank, Atlanta,
as trustee pursuant to a Trust Indenture, dated as of March 1, 1998,
between Development Authority of Burke County and SunTrust Bank,
Atlanta, and one other substantially identical note.
4.12.3(1) -- Trust-Trust Indenture, dated as of March 1, 1998, between Development
Authority of Burke County and SunTrust Bank, Atlanta, as trustee,
relating to Development Authority of Burke County Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series
1998A, and one other substantially identical indenture.
75
4.12.4(1) -- Standby-Standby Bond Purchase Agreement, dated March 17, 1998, between
Oglethorpe and Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A.,
"Rabobank Nederland", acting through its New York Branch, relating to
Development Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1998A, and one
other substantially identical agreement.
*4.13.1 --*4.13.1-- Indemnity Agreement, dated as of March 1, 1997, by and between
Oglethorpe and Georgia Transmission Corporation (An Electric
Membership Corporation). (Filed as Exhibit 4.13.1 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*4.13.2 --*4.13.2-- Indemnification Agreement, dated as of March 11, 1997, by Oglethorpe
and Georgia Transmission Corporation (An Electric Membership
Corporation) for the benefit of the United States of America. (Filed
as Exhibit 4.13.2 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
4.14.1(1) -- Master-Master Loan Agreement, dated as of March 1, 1997, between Oglethorpe
and CoBank, ACB, MLA No. 0459.
4.14.2(1) -- Consolidating-Consolidating Supplement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T1.
4.14.3(1) -- Promissory-Promissory Note, dated March 1, 1997, in the original principal amount
of $7,102,740.26, from Oglethorpe to CoBank, ACB, relating to Loan No.
ML0459T1.
4.14.4(1) -- Consolidating-Consolidating Supplement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T2.
4.14.5(1) -- Promissory-Promissory Note, dated March 1, 1997, in the original principal amount
of $1,856,475.12, made by Oglethorpe to CoBank, ACB, relating to Loan
No. ML0459T2.
4.14.6(1) -- Single Advance Term Loan Supplement, dated as of March 31, 1998,
between Oglethorpe and CoBank, ACB, relating to Loan No.
ML0459T3.
4.14.7(1) -- Promissory Note, dated March 31, 1998, in the original principal
amount of $46,065,000.00, made by Oglethorpe to CoBank, ACB,
relating to Loan No. ML0459T3.
*4.15.1 --*4.15.1-- Loan Agreement, Loan No. T-830404, between Oglethorpe and Columbia
Bank for Cooperatives, dated as of April 29, 1983. (Filed as Exhibit
4.18.1 to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*4.15.2 --85
*4.15.2-- Promissory Note, Loan No. T-830404-1, in the original principal amount
of $9,935,000, from Oglethorpe to Columbia Bank for Cooperatives,
dated as of April 29, 1983. (Filed as Exhibit 4.18.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*4.15.3 --*4.15.3-- Security Deed and Security Agreement, dated April 29, 1983, between
Oglethorpe and Columbia Bank for Cooperatives. (Filed as Exhibit
4.18.3 to the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.16 -- Exchange and Registration Rights Agreement, dated December 17, 1997,
by and among Oglethorpe, OPC Scherer 1997 Funding Corporation A, and
Goldman, Sachs & Co. as representative of the purchasers identified
therein. (Filed as Exhibit 4.15 to the Registrant's Form S-4
Registration Statement, File No. 333-42759.)
76
4.17.1 (1) -- Loan Agreement, dated as of April 1, 1998, between Oglethorpe and
the National Rural Utilities Cooperative Finance Corporation,
relating to Loan No. GA 109-1-9001.
4.17.2 (1) -- Series 1998 CFC Note, dated April 9, 1998, in the original
principal amount of $46,065,000.00, from Oglethorpe to the
National Rural Utilities Cooperative Finance Corporation,
relating to Loan No. GA 109-1-9001.
*10.1.1(a) -- Participation Agreement No. 2 among Oglethorpe as Lessee, Wilmington
Trust Company as Owner Trustee, The First National Bank of Atlanta as
Indenture Trustee, Columbia Bank for Cooperatives as Loan Participant
and Ford Motor Credit Company as Owner Participant, dated December 30,
1985, together with a Schedule identifying three other substantially
identical Participation Agreements. (Filed as Exhibit 10.1.1(b) to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.1(b) -- Supplemental Participation Agreement No. 2. (Filed as Exhibit
10.1.1(a) to the Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.1.1(c) -- Supplemental Participation Agreement No. 1, dated as of June 30, 1987,
among Oglethorpe as Lessee, IBM Credit Financing Corporation as Owner
Participant, Wilmington Trust Company and The Citizens and Southern
National Bank as Owner Trustee, The First National Bank of Atlanta, as
Indenture Trustee, and Columbia Bank for Cooperatives, as Loan
Participant. (Filed as Exhibit 10.1.1(c) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1987, File No. 33-7591.)
*10.1.1(d) -- Second Supplemental Participation Agreement No. 2, dated as of
December 17, 1997, among Oglethorpe as Lessee, DFO Partnership, as
assignee of Ford Motor Credit Company, as Owner Participant,
Wilmington Trust Company and NationsBank, N.A. as Owner Trustee, The
Bank of New York Trust Company of Florida, N.A. as Indenture Trustee,
CoBank, ACB as Loan Participant, OPC Scherer Funding Corporation, as
Original Funding Corporation, OPC Scherer 1997 Funding Corporation A,
as Funding Corporation, and SunTrust Bank, Atlanta, as Original
Collateral Trust Trustee and Collateral Trust Trustee, with a Schedule
identifying three substantially identical Second Supplemental
Participation Agreements and any material differences. (Filed as
Exhibit 10.1.1(d) to Registrant's Form S-4 Registration Statement,
File No. 333-4275.)
*10.1.2 --86
*10.1.2-- General Warranty Deed and Bill of Sale No. 2 between Oglethorpe,
Grantor, and Wilmington Trust Company and William J. Wade, as Owner
Trustees under Trust Agreement No. 2, dated December 30, 1985, with
Ford Motor Credit Company, Grantee, together with a Schedule
identifying three substantially identical General Warranty Deeds and
Bills of Sale. (Filed as Exhibit 10.1.2 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.1.3(a) -- Supporting Assets Lease No. 2, dated December 30, 1985, between
Oglethorpe, Lessor, and Wilmington Trust Company and William J. Wade,
as Owner Trustees, under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Lessee, together with a Schedule
identifying three substantially identical Supporting Assets Leases.
(Filed as Exhibit 10.1.3 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
77
*10.1.3(b) -- First Amendment to Supporting Assets Lease No. 2, dated as of November
19, 1987, together with a Schedule identifying three substantially
identical First Amendments to Supporting Assets Leases. (Filed as
Exhibit 10.1.3(a) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1987, File No. 33-7591.)
*10.1.3(c) -- Second Amendment to Supporting Assets Lease No. 2, dated as of October
3, 1989, together with a Schedule identifying three substantially
identical Second Amendments to Supporting Assets Leases. (Filed as
Exhibit 10.1.3(c) to the Registrant's Form 10-Q for the quarterly
period ended March 31, 1998, File No. 33-7591.)
*10.1.4(a) -- Supporting Assets Sublease No. 2, dated December 30, 1985, between
Wilmington Trust Company and William J. Wade, as Owner Trustees under
Trust Agreement No. 2 dated December 30, 1985, with Ford Motor Credit
Company, Sublessor, and Oglethorpe, Sublessee, together with a
Schedule identifying three substantially identical Supporting Assets
Subleases. (Filed as Exhibit 10.1.4 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.1.4(b) -- First Amendment to Supporting Assets Sublease No. 2, dated as of
November 19, 1987, together with a Schedule identifying three
substantially identical First Amendments to Supporting Assets
Subleases. (Filed as Exhibit 10.1.4(a) to the Registrant's Form 10-K
for the fiscal year ended December 31, 1987, File No. 33-7591.)
*10.1.4(c) -- Second Amendment to Supporting Assets Sublease No. 2, dated as of
October 3, 1989, together with a Schedule identifying three
substantially identical Second Amendments to Supporting Assets
Subleases. (Filed as Exhibit 10.1.4(c) to the Registrant's Form 10-Q
for the quarterly period ended March 31, 1998, File No. 33-7591.)
*10.1.5(a) -- Tax Indemnification Agreement No. 2, dated December 30, 1985, between
Ford Motor Credit Company, Owner Participant, and Oglethorpe, Lessee,
together with a Schedule identifying three substantially identical Tax
Indemnification Agreements. (Filed as Exhibit 10.1.5 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.5(b) -- Amendment No. 1 to the Tax Indemnification Agreement No. 2, dated
December 17, 1997, between DFO Partnership, as assignee of Ford Motor
Credit Company, as Owner Participant, and Oglethorpe, as Lessee, with
a Schedule identifying three substantially identical Amendments No. 1
to the Tax Indemnification Agreements and any material differences.
(Filed as Exhibit 10.1.5(b) to the Registrant's Form S-4 Registration
Statement, File No. 333-42759.)
*10.1.6 --87
*10.1.6-- Assignment of Interest in Ownership Agreement and Operating Agreement
No. 2, dated December 30, 1985, between Oglethorpe, Assignor, and
Wilmington Trust Company and William J. Wade, as Owner Trustees under
Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, Assignee, together with Schedule identifying three
substantially identical Assignments of Interest in Ownership Agreement
and Operating Agreement. (Filed as Exhibit 10.1.6 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
78
*10.1.7 --*10.1.7-- Consent, Amendment and Assumption No. 2 dated December 30, 1985, among
Georgia Power Company and Oglethorpe and Municipal Electric Authority
of Georgia and City of Dalton, Georgia and Gulf Power Company and
Wilmington Trust Company and William J. Wade, as Owner Trustees under
Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, together with a Schedule identifying three substantially
identical Consents, Amendments and Assumptions. (Filed as Exhibit
10.1.9 to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.1.7(a) -- Amendment to Consent, Amendment and Assumption No. 2, dated as of
August 16, 1993, among Oglethorpe, Georgia Power Company, Municipal
Electric Authority of Georgia, City of Dalton, Georgia, Gulf Power
Company, Jacksonville Electric Authority, Florida Power & Light
Company and Wilmington Trust Company and NationsBank of Georgia, N.A.,
as Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, together with a Schedule
identifying three substantially identical Amendments to Consents,
Amendments and Assumptions. (Filed as Exhibit 10.1.9(a) to the
Registrant's Form 10-Q for the quarterly period ended September 30,
1993, File No. 33-7591.)
*10.2.1 --*10.2.1-- Section 168 Agreement and Election dated as of April 7, 1982, between
Continental Telephone Corporation and Oglethorpe. (Filed as Exhibit
10.2 to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.2.2 --*10.2.2-- Section 168 Agreement and Election dated as of April 9, 1982, between
Rollins, Inc. and Oglethorpe. (Filed as Exhibit 10.4 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.3.1(a) -- Plant Robert W. Scherer Units Numbers One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit 10.6.1 to
the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.3.1(b) -- Amendment to Plant Robert W. Scherer Units Numbers One and Two
Purchase and Ownership Participation Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia and City
of Dalton, Georgia, dated as of December 30, 1985. (Filed as Exhibit
10.1.8 to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.3.1(c) -- Amendment Number Two to the Plant Robert W. Scherer Units Numbers One
and Two Purchase and Ownership Participation Agreement among Georgia
Power Company, Oglethorpe, Municipal Electric Authority of Georgia and
City of Dalton, Georgia, dated as of July 1, 1986. (Filed as Exhibit
10.6.1(a) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1987, File No. 33-7591.)
88
*10.3.1(d) -- Amendment Number Three to the Plant Robert W. Scherer Units Numbers
One and Two Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric Authority of
Georgia and City of Dalton, Georgia, dated as of August 1, 1988.
(Filed as Exhibit 10.6.1(b) to the Registrant's Form 10-Q for the
quarterly period ended September 30, 1993, File No. 33-7591.)
79
*10.3.1(e) -- Amendment Number Four to the Plant Robert W. Scherer Units Number One
and Two Purchase and Ownership Participation Agreement among Georgia
Power Company, Oglethorpe, Municipal Electric Authority of Georgia and
City of Dalton, Georgia, dated as of December 31, 1990. (Filed as
Exhibit 10.6.1(c) to the Registrant's Form 10-Q for the quarterly
period ended September 30, 1993, File No. 33-7591.)
*10.3.2(a) -- Plant Robert W. Scherer Units Numbers One and Two Operating Agreement
among Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia, dated as of May 15, 1980.
(Filed as Exhibit 10.6.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.3.2(b) -- Amendment to Plant Robert W. Scherer Units Numbers One and Two
Operating Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated as of
December 30, 1985. (Filed as Exhibit 10.1.7 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591.)
*10.3.2(c) -- Amendment Number Two to the Plant Robert W. Scherer Units Numbers One
and Two Operating Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton, Georgia,
dated as of December 31, 1990. (Filed as Exhibit 10.6.2(a) to the
Registrant's Form 10-Q for the quarterly period ended September 30,
1993, File No. 33-7591.)
*10.3.3 --*10.3.3-- Plant Scherer Managing Board Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia, City of Dalton,
Georgia, Gulf Power Company, Florida Power & Light Company and
Jacksonville Electric Authority, dated as of December 31, 1990. (Filed
as Exhibit 10.6.3 to the Registrant's Form 10-Q for the quarterly
period ended September 30, 1993, File No. 33-7591.)
*10.4.1(a) -- Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit 10.7.1
to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.4.1(b) -- Amendment Number One, dated January 18, 1977, to the Alvin W. Vogtle
Nuclear Units Numbers One and Two Purchase and Ownership Participation
Agreement among Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit
10.7.3 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1986, File No. 33-7591.)
*10.4.1(c) -- Amendment Number Two, dated February 24, 1977, to the Alvin W. Vogtle
Nuclear Units Numbers One and Two Purchase and Ownership Participation
Agreement among Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit
10.7.4 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1986, File No. 33-7591.)
*10.4.2 --89
*10.4.2-- Alvin W. Vogtle Nuclear Units Numbers One and Two Operating Agreement
among Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia, dated as of August 27, 1976.
(Filed as Exhibit 10.7.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
80
*10.5.1 --*10.5.1-- Plant Hal Wansley Purchase and Ownership Participation Agreement
between Georgia Power Company and Oglethorpe, dated as of March 26,
1976. (Filed as Exhibit 10.8.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.5.2(a) -- Plant Hal Wansley Operating Agreement between Georgia Power Company
and Oglethorpe, dated as of March 26, 1976. (Filed as Exhibit 10.8.2
to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.5.2(b) -- Amendment, dated as of January 15, 1995, to the Plant Hal Wansley
Operating Agreements by and among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton, Georgia.
(Filed as Exhibit 10.5.2(a) to the Registrant's Form 10-Q for the
quarterly period ended September 30, 1996, File No. 33-7591.)
*10.5.3 -- Plant--Plant Hal Wansley Combustion Turbine Agreement between Georgia Power
Company and Oglethorpe, dated as of August 2, 1982 and Amendment No.
1, dated October 20, 1982. (Filed as Exhibit 10.18 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.6.1 -- Edwin--Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation
Agreement between Georgia Power Company and Oglethorpe, dated as of
January 6, 1975. (Filed as Exhibit 10.9.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.6.2 --*10.6.2-- Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia Power
Company and Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit
10.9.2 to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.7.1 --*10.7.1-- Rocky Mountain Pumped Storage Hydroelectric Project Ownership
Participation Agreement, dated as of November 18, 1988, by and between
Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.1 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1988,
File No. 33-7591.)
*10.7.2 --*10.7.2-- Rocky Mountain Pumped Storage Hydroelectric Project Operating
Agreement, dated as of November 18, 1988, by and between Oglethorpe
and Georgia Power Company. (Filed as Exhibit 10.22.2 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1988,
File No. 33-7591.)
*10.8.1 --*10.8.1-- Amended and Restated Wholesale Power Contract, dated as of August 1,
1996, between Oglethorpe and Altamaha Electric Membership Corporation
and all schedules thereto, together with a Schedule identifying 37
other substantially identical Amended and Restated Wholesale Power
Contracts, and an additional Amended and Restated Wholesale Power
Contract that is not substantially identical. (Filed as Exhibit 10.8.1
to the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.8.2 --*10.8.2-- Amended and Restated Supplemental Agreement, dated as of August 1,
1996, by and between Oglethorpe, Altamaha Electric Membership
Corporation and the United States of America, together with a Schedule
identifying 38 other substantially identical Amended and Restated
Supplemental Agreements. (Filed as Exhibit 10.8.2 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
8190
*10.8.3 --*10.8.3-- Supplemental Agreement to the Amended and Restated Wholesale Power
Contract, dated as of January 1, 1997, by and among Georgia Power
Company, Oglethorpe and Altamaha Electric Membership Corporation,
together with a Schedule identifying 38 other substantially identical
Supplemental Agreements. (Filed as Exhibit 10.8.3 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.8.4 --*10.8.4-- Supplemental Agreement to the Amended and Restated Wholesale Power
Contract, dated as of March 1, 1997, by and between Oglethorpe and
Altamaha Electric Membership Corporation, together with a Schedule
identifying 36 other substantially identical Supplemental Agreements,
and an additional Supplemental Agreement that is not substantially
identical. (Filed as Exhibit 10.8.4 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.5 --*10.8.5-- Supplemental Agreement to the Amended and Restated Wholesale Power
Contract, dated as of March 1, 1997, by and between Oglethorpe and
Coweta-Fayette Electric Membership Corporation, together with a
Schedule identifying 1 other substantially identical Supplemental
Agreement. (Filed as Exhibit 10.8.5 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.6 --*10.8.6-- Supplemental Agreement to the Amended and Restated Wholesale Power
Contract, dated as of May 1, 1997 by and between Oglethorpe and
Altamaha Electric Membership Corporation, together with a Schedule
identifying 38 other substantially identical Supplemental Agreements.
(Filed as Exhibit 10.8.6 to the Registrant's Form 10-Q for the
quarterly period ended June 30, 1997, File No. 33-7591.)
*10.9(a) -- Joint--Joint Committee Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and the City of Dalton,
Georgia, dated as of August 27, 1976. (Filed as Exhibit 10.14(b) to
the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.9(b) -- First--First Amendment to Joint Committee Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia and the
City of Dalton, Georgia, dated as of June 19, 1978. (Filed as Exhibit
10.14(a) to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.10 --*10.10-- Letter of Commitment (Firm Power Sale) Under Service Schedule
J--Negotiated Interchange Service between Alabama Electric
Cooperative, Inc. and Oglethorpe, dated March 31, 1994. (Filed as
Exhibit 10.11(b) to the Registrant's Form 10-Q for the quarter ended
June 30, 1994, File No. 33-7591.)
*10.11.1 -- Assignment*10.11.1--Assignment of Power System Agreement and Settlement Agreement, dated
January 8, 1975, by Georgia Electric Membership Corporation to
Oglethorpe. (Filed as Exhibit 10.20.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.11.2 -- Power*10.11.2--Power System Agreement, dated April 24, 1974, by and between Georgia
Electric Membership Corporation and Georgia Power Company. (Filed as
Exhibit 10.20.2 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591.)
8291
*10.11.3 -- Settlement*10.11.3--Settlement Agreement, dated April 24, 1974, by and between Georgia
Power Company, Georgia Municipal Association, Inc., City of Dalton,
Georgia Electric Membership Corporation and Crisp County Power
Commission. (Filed as Exhibit 10.20.3 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.12 --*10.12-- Long-Term Firm Power Purchase Agreement between Big Rivers Electric
Corporation and Oglethorpe, dated as of December 17, 1990. (Filed as
Exhibit 10.24.3 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1990, File No. 33-7591.)
*10.13 --*10.13-- Revised and Restated Coordination Services Agreement between and among
Georgia Power Company, Oglethorpe and Georgia System Operations
Corporation, dated as of September 10, 1997. (Filed as Exhibit 10.14
to the Registrant's Form 10-K for the fiscal year ended December 31,
1997, File No. 33-7591.)
*10.14 -- ITSA, Power Sale and Coordination Umbrella Agreement between
Oglethorpe and Georgia Power Company, dated as of November 12, 1990.
(Filed as Exhibit 10.28 to the Registrant's Form 8-K, filed January 4,
1991, File No. 33-7591.)
*10.15 -- Amended and Restated Nuclear Managing Board Agreement among Georgia
Power Company, Oglethorpe Power Corporation, Municipal Electric
Authority of Georgia and City of Dalton, Georgia dated as of July 1,
1993. (Filed as Exhibit 10.36 to the Registrant's 10-Q for the
quarterly period ended September 30, 1993, File No. 33-7591.)
*10.16 -- Supplemental Agreement by and among Oglethorpe, Tri-County Electric
Membership Corporation and Georgia Power Company, dated as of November
12, 1990, together with a Schedule identifying 38 other substantially
identical Supplemental Agreements. (Filed as Exhibit 10.30 to the
Registrant's Form 8-K, filed January 4, 1991, File No. 33-7591.)
*10.17 -- Unit Capacity and Energy Purchase Agreement between Oglethorpe and
Entergy Power Incorporated, dated as of October 11, 1990. (Filed as
Exhibit 10.31 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*10.18 -- Power Purchase Agreement between Oglethorpe and Hartwell Energy
Limited Partnership, dated as of June 12, 1992. (Filed as Exhibit
10.35 to the Registrant's Form 10-K for the fiscal year ended December
31, 1992, File No. 33-7591).
*10.19(2) -- Power-Power Purchase and Sale Agreement among LG&E Power Marketing Inc.,
LG&E Energy Corp. and Oglethorpe, dated as of November 19, 1996.
(Filed as Exhibit 10.30 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.20(2) -- Power-Power Purchase and Sale Agreement among LG&E Power Marketing Inc.,
LG&E Power Inc. and Oglethorpe, dated as of January 1, 1997. (Filed as
Exhibit 10.31 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
83
*10.21.1 -- Participation*10.21.1--Participation Agreement (P1), dated as of December 30, 1996, among
Oglethorpe, Rocky Mountain Leasing Corporation, Fleet National Bank,
as Owner Trustee, SunTrust Bank, Atlanta, as Co-Trustee, the Owner
Participant named therein and Utrecht-America Finance Co., as Lender,
together with a Schedule identifying five other substantially
identical Participation Agreements. (Filed as Exhibit 10.32.1 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
*10.21.2 -- Rocky92
*10.21.2--Rocky Mountain Head Lease Agreement (P1), dated as of December 30,
1996, between Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other substantially
identical Rocky Mountain Head Lease Agreements. (Filed as Exhibit
10.32.2 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.21.3 -- Ground*10.21.3--Ground Lease Agreement (P1), dated as of December 30, 1996, between
Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee, together with a
Schedule identifying five other substantially identical Ground Lease
Agreements. (Filed as Exhibit 10.32.3 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.21.4 -- Rocky*10.21.4--Rocky Mountain Agreements Assignment and Assumption Agreement (P1),
dated as of December 30, 1996, between Oglethorpe and SunTrust Bank,
Atlanta, as Co-Trustee, together with a Schedule identifying five
other substantially identical Rocky Mountain Agreements Assignment and
Assumption Agreements. (Filed as Exhibit 10.32.4 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.5 -- Facility*10.21.5--Facility Lease Agreement (P1), dated as of December 30, 1996, between
SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain Leasing
Corporation, together with a Schedule identifying five other
substantially identical Facility Lease Agreements. (Filed as Exhibit
10.32.5 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.21.6 -- Ground*10.21.6--Ground Sublease Agreement (P1), dated as of December 30, 1996, between
SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain Leasing
Corporation, together with a Schedule identifying five other
substantially identical Ground Sublease Agreements. (Filed as Exhibit
10.32.6 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.21.7 -- Rocky*10.21.7--Rocky Mountain Agreements Re-assignment and Assumption Agreement (P1),
dated as of December 30, 1996, between SunTrust Bank, Atlanta, as
Co-Trustee and Rocky Mountain Leasing Corporation, together with a
Schedule identifying five other substantially identical Rocky Mountain
Agreements Re-assignment and Assumption Agreements. (Filed as Exhibit
10.32.7 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.21.8 -- Facility*10.21.8--Facility Sublease Agreement (P1), dated as of December 30, 1996,
between Oglethorpe and Rocky Mountain Leasing Corporation, together
with a Schedule identifying five other substantially identical
Facility Sublease Agreements. (Filed as Exhibit 10.32.8 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
84
*10.21.9 -- Ground*10.21.9--Ground Sub-sublease Agreement (P1), dated as of December 30, 1996,
between Rocky Mountain Leasing Corporation and Oglethorpe, together
with a Schedule identifying five other substantially identical Ground
Sub-sublease Agreements. (Filed as Exhibit 10.32.9 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.10 -- Rocky93
*10.21.10-Rocky Mountain Agreements Second Re-assignment and Assumption
Agreement (P1), dated as of December 30, 1996, between Rocky Mountain
Leasing Corporation and Oglethorpe, together with a Schedule
identifying five other substantially identical Rocky Mountain
Agreements Second Re-assignment and Assumption Agreements. (Filed as
Exhibit 10.32.10 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
*10.21.11 -- Payment*10.21.11-Payment Undertaking Agreement (P1), dated as of December 30, 1996,
between Rocky Mountain Leasing Corporation and Cooperatieve Centrale
Raiffeisen-Boerenleenbank B.A., New York Branch, as the Bank, together
with a Schedule identifying five other substantially identical Payment
Undertaking Agreements. (Filed as Exhibit 10.32.11 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.12 -- Payment*10.21.12-Payment Undertaking Pledge Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation, Fleet National Bank,
as Owner Trustee, and SunTrust Bank, Atlanta, as Co-Trustee, together
with a Schedule identifying five other substantially identical Payment
Undertaking Pledge Agreements. (Filed as Exhibit 10.32.12 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
*10.21.13 -- Equity*10.21.13-Equity Funding Agreement (P1), dated as of December 30, 1996, between
Rocky Mountain Leasing Corporation, AIG Match Funding Corp., the Owner
Participant named therein, Fleet National Bank, as Owner Trustee, and
SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Equity Funding
Agreements. (Filed as Exhibit 10.32.13 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.21.14 -- Equity*10.21.14-Equity Funding Pledge Agreement (P1), dated as of December 30, 1996,
between Rocky Mountain Leasing Corporation and SunTrust Bank, Atlanta,
as Co-Trustee, together with a Schedule identifying five other
substantially identical Equity Funding Pledge Agreements. (Filed as
Exhibit 10.32.14 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
*10.21.15 -- Deed*10.21.15-Deed to Secure Debt, Assignment of Surety Bond and Security Agreement
(P1), dated as of December 30, 1996, between Rocky Mountain Leasing
Corporation, SunTrust Bank, Atlanta, as Co-Trustee, together with a
Schedule identifying five other substantially identical Collateral
Assignment, Assignment of Surety Bond and Security Agreements. (Filed
as Exhibit 10.32.15 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
*10.21.16 -- Subordinated*10.21.16-Subordinated Deed to Secure Debt and Security Agreement (P1), dated as
of December 30, 1996, among Oglethorpe, AMBAC Indemnity Corporation
and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Subordinated Deed to
Secure Debt and Security Agreements. (Filed as Exhibit 10.32.16 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
85
*10.21.17 -- Tax*10.21.17-Tax Indemnification Agreement (P1), dated as of December 30, 1996,
between Oglethorpe and the Owner Participant named therein, together
with a Schedule identifying five other substantially identical Tax
Indemnification Agreements. (Filed as Exhibit 10.32.17 to the
Registrant's Form 10-K for the fiscal year ended December 31, 1996,
File No. 33-7591.)
*10.21.18 --94
*10.21.18- Consent No. 1, dated as of December 30, 1996, among Georgia Power
Company, Oglethorpe, SunTrust Bank, Atlanta, as Co-Trustee, and
Fleet National Bank, as Owner Trustee, together with a Schedule
identifying five other substantially identical Consents. (Filed
as Exhibit 10.32.18 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.21.19(a)-- OPC Intercreditor and Security Agreement No. 1, dated as of
December 30, 1996, among the United States of America, acting
through the Administrator of the Rural Utilities Service,
SunTrust Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing
Corporation, SunTrust Bank, Atlanta, as Co-Trustee, Fleet
National Bank, as Owner Trustee, Utrecht-America Finance Co., as
Lender and AMBAC Indemnity Corporation, together with a Schedule
identifying five other substantially identical Intercreditor and
Security Agreements. (Filed as Exhibit 10.32.19 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.21.19(b)-- Supplement to OPC Intercreditor and Security Agreement No. 1,
dated as of March 1, 1997, among the United States of America,
acting through the Administrator of the Rural Utilities Service,
SunTrust Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing
Corporation, SunTrust Bank, Atlanta, as Co-Trustee, Fleet
National Bank, as Owner Trustee, Utrecht-America Finance Co., as
Lender and AMBAC Indemnity Corporation, together with a Schedule
identifying five other substantially identical Supplements to OPC
Intercreditor and Security Agreements. (Filed as Exhibit
10.32.19(b) to the Registrant's Form S-4 Registration Statement,
File No. 333-42759.)
*10.22.1 --*10.22.1-- Member Transmission Service Agreement, dated as of March 1, 1997,
by and between Oglethorpe and Georgia Transmission Corporation
(An Electric Membership Corporation). (Filed as Exhibit 10.33.1
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*10.22.2 --*10.22.2-- Generation Services Agreement, dated as of March 1, 1997, by and
between Oglethorpe and Georgia System Operations Corporation.
(Filed as Exhibit 10.33.2 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.22.3 --*10.22.3-- Operation Services Agreement, dated as of March 1, 1997, by and
between Oglethorpe and Georgia System Operations Corporation.
(Filed as Exhibit 10.33.3 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23(2)-- Power Purchase and Sale Agreement between Morgan Stanley Capital
Group Inc. and Oglethorpe, dated as of April 7, 1997. (Filed as
Exhibit 10.34 to the Registrant's Form 10-Q for the quarterly
period ended March 31, 1997, File No. 33-7591.)
86
*10.24 -- Long Term Transaction Service Agreement Under Southern Companies'
Federal Energy Regulatory Commission Electric Tariff Volume No. 4
Market-Based Rate Tariff, between Georgia Power Company and
Oglethorpe, dated as of February 26, 1999. (Filed as Exhibit
10.27 to the Registrant's Form 10-Q for the quarterly period
ended March 31, 1999, File No. 33-7591.)
*10.25(3)-- Employment Agreement, dated as of SeptemberMarch 15, 1999,2002, between
Oglethorpe and Thomas A. Smith. (Filed as Exhibit 10.25 to the
Registrant's Form 10-K for the fiscal year ended December 31,
2001, File No. 33-7591.)
95
*10.26(3)-- Employment Agreement, dated July 25, 2000, between Oglethorpe and
Michael W. Price. (Filed as Exhibit 10.26 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1999,2001, File No.
33-7591.)
10.26(3) -- Employment Agreement, dated July 25, 2000, between Oglethorpe and
Michael W. Price.
*10.27(3)-- Employment Agreement, dated August 7, 2000, between Oglethorpe
and W. Clayton Robbins. (Filed as Exhibit 10.28 to the
Registrant's Form 10-Q for the quarterly period ended June 30,
2000, File No. 33-7591.)
*10.28(3) *10.28.1(3)-- Employment Agreement, dated August 7, 2000, between Oglethorpe
and Elizabeth Higgins. (Filed as Exhibit 10.29 to the
Registrant's Form 10-Q for the quarterly period ended June 30,
2000, File No. 33-7591.)
*10.28.2(3)-- Amendment to Employment Agreement, dated May 8, 2001, between
Oglethorpe and Elizabeth Higgins. (Filed as Exhibit 10.30 to the
Registrant's Form 10-Q for the quarterly period ended June 30,
2001, File No. 33-7591.)
10.28.3(3) -- Second Amendment to Employment Agreement, dated February 19,
2003, between Oglethorpe and Elizabeth Higgins.
*10.29(3) -- Oglethorpe Power Corporation Executive Supplemental Retirement
Plan, dated March 15, 2002. (Filed as Exhibit 10.29 to the
Registrant's Form 10-Q for the quarterly period ended March 31,
2002, File No. 33-7591.)
*10.30(3) -- Participation Agreement for the Oglethorpe Power Corporation
Executive Supplemental Retirement Plan, dated as of March 15,
2002, between Oglethorpe and Thomas A. Smith. (Filed as Exhibit
10.30 to the Registrant's Form 10-Q for the quarterly period
ended March 31, 2002, File No. 33-7591.)
21.1 -- Rocky Mountain Leasing Corporation, a Delaware corporation.
99.1 -- Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, by Thomas A. Smith
(Principal Executive Officer).
99.2 -- Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002, by Anne F. Appleby
(Principal Financial Officer).
- --------------------------------
(1) Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this document(s) is not filed
herewith; however the registrant hereby agrees that such document(s) will
be provided to the Commission upon request.
(2) Certain portions of this document have been omitted as confidential and
filed separately with the Commission.
(3) Indicates a management contract or compensatory arrangement required to be
filed as an exhibit to this Report.
(b) Reports on Form 8-K.
Oglethorpe filed no reports on Form 8-K during the fourth quarter of
2000.
872002.
96
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 16th27th day of
March, 2001.2003.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
By: /s/ J. CALVIN EARWOOD
---------------------------------
J. CALVIN EARWOOD
Chairman of the BoardTHOMAS A. SMITH
-------------------------------------
THOMAS A. SMITH
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
/s/ J. CALVIN EARWOOD Chairman of the Board, Director March 16, 2001
- ----------------------- (Principal Executive Officer)
J. CALVIN EARWOOD
Signature Title Date
--------- ----- ----
/s/ THOMAS A. SMITH President and Chief Executive Officer March 27, 2003
- ------------------------------------
THOMAS A. SMITH (Principal Executive Officer)
/s/ ANNE F. APPLEBY Vice President, Finance and Treasurer March 27, 2003
- ------------------------------------
ANNE F. APPLEBY (Principal Financial Officer)
/s/ MARK CHESLA Controller March 27, 2003
- ------------------------------------
MARK CHESLA
/s/ ASHLEY C. BROWN Director March 27, 2003
- ------------------------------------
ASHLEY C. BROWN
/s/ LARRY N. CHADWICK Director March 27, 2003
- ------------------------------------
LARRY N. CHADWICK
/s/ BENNY W. DENHAM Director March 27, 2003
- ------------------------------------
BENNY W. DENHAM
/s/ WM. RONALD DUFFEY Director March 27, 2003
- ------------------------------------
WM. RONALD DUFFEY
97
/s/ J. SAM L. RABUN Director March 27, 2003
- ------------------------------------
J. SAM L. RABUN
/s/ JOHN S. RANSON Director March 27, 2003
- ------------------------------------
JOHN S. RANSON
/s/ ROBERT E. RENTFROW Director March 27, 2003
- ------------------------------------
ROBERT E. RENTFROW
/s/ JEFFREY D. TRANEN Director March 27, 2003
- ------------------------------------
JEFFREY D. TRANEN
98
CERTIFICATIONS
I, Thomas A. Smith, certify that:
1. I have reviewed this annual report on Form 10-K of Oglethorpe Power
Corporation (An Electric Membership Corporation);
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 27, 2003
/s/ Thomas A. Smith
- --------------------------
Thomas A. Smith
President and Chief Executive Officer
March 16, 2001
- ----------------------- (Principal Executive Officer)
THOMAS A. SMITH99
I, Anne F. Appleby, certify that:
1. I have reviewed this annual report on Form 10-K of Oglethorpe Power
Corporation (An Electric Membership Corporation);
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities, particularly
during the period in which this annual report is being prepared;
(b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this annual
report (the "Evaluation Date"); and
(c) presented in this annual report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation as of the
Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal controls
or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.
Date: March 27, 2003
/s/ MACAnne F. OGLESBY Treasurer, Director (Principal March 16, 2001Appleby
- ----------------------- Financial Officer)
MAC---------------------------
Anne F. OGLESBY
/s/W. CLAYTON ROBBINS SeniorAppleby
Vice President, Finance and March 16, 2001
- ----------------------- AdministrationTreasurer
(Principal Financial W. CLAYTON ROBBINS Officer)
/s/ WILLIE B. COLLINS Controller and Chief Risk Officer March 16, 2001
- -----------------------
WILLIE B. COLLINS
/s/ ASHLEY C. BROWN Director March 16, 2001
- -----------------------
ASHLEY C. BROWN
/s/ LARRY N. CHADWICK Director March 16, 2001
- -----------------------
LARRY N. CHADWICK
/s/ BENNY W. DENHAM Director March 16, 2001
- -----------------------
BENNY W. DENHAM
88
Signature Title Date
/s/ WM. RONALD DUFFEY Director March 16, 2001
- ---------------------------------------
WM. RONALD DUFFEY
/s/ SAMMY M. JENKINS Director March 16, 2001
- ---------------------------------------
SAMMY M. JENKINS
/s/ J. SAM L. RABUN Director March 16, 2001
- ---------------------------------------
J. SAM L. RABUN
/s/ JOHN S. RANSON Director March 16, 2001
- ---------------------------------------
JOHN S. RANSON
/s/ JEFFREY D. TRANEN Director March 16, 2001
- ---------------------------------------
JEFFREY D. TRANEN
89100
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO
SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES
PURSUANT TO SECTION 12 OF THE ACT.
The registrant is a membership corporation and has no authorized or
outstanding equity securities. Proxies are not solicited from the holders of
Oglethorpe's public bonds. No annual report or proxy material has been sent to
such bondholders.
90101