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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
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FORM 10-K
(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, 19962000
OR
[_][ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From ___________ to _____________
Commission File No. 33-7591
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Oglethorpe Power Corporation
(An Electric Membership Corporation)
(Exact name of registrant as specified in its charter)
Georgia 58-1211925
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
Post Office Box 1349
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]
State the aggregate market value of the voting stockand non-voting common equity
held by nonaffiliatesnon-affiliates of the registrant. None
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. The Registrant is a
membership corporation and has no authorized or outstanding equity securities.
Documents Incorporated by Reference: None
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OGLETHORPE POWER CORPORATION
19962000 FORM 10-K ANNUAL REPORT
Table of Contents
ItemITEM Page
- ---- ----
PART I
1 Business ............................................................ 1................................................................1
Oglethorpe Power Corporation....................................... 1Corporation...........................................1
Oglethorpe's Power Supply Resources....................................7
The Members of Oglethorpe.......................................... 8
Member Requirements and Their Power Supply Resources..................... 12
Other Information.................................................. 16Resources..........................12
Factors Affecting the Electric Utility Industry.......................17
2 Properties........................................................... 17
Generating Facilities.............................................. 17
Co-Owners of the Plants and the Plant Agreements................... 20
Environmental and Other Regulations................................ 24Properties..............................................................22
3 Legal Proceedings.................................................... 29Proceedings.......................................................28
4 Submission of Matters to a Vote of Security Holders.................. 29Holders.....................28
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters.............................................................. 30Matters...29
6 Selected Financial Data.............................................. 30Data.................................................29
7 Management's Discussion and Analysis of Financial Condition and Results
of Operations................................................ 31Operations...........................................................30
7A Quantitative and Qualitative Disclosures About Market Risk..............40
8 Financial Statements and Supplementary Data.......................... 42Data.............................44
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................................. 62Disclosure................................................64
PART III
10 Directors and Executive Officers of the Registrant................... 62Registrant......................64
11 Executive Compensation............................................... 65Compensation..................................................68
12 Security Ownership of Certain Beneficial Owners and Management....... 68Management..........70
13 Certain Relationships and Related Transactions....................... 68Transactions..........................70
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K..... 698-K........71
i
SELECTED DEFINITIONS
When used herein theThe following terms willused in this report have the meanings indicated below:
Term Meaning
- ---- -------
ADSCR Annual Debt Service Coverage Ratio
BPSA Block Power Sale Agreement
CFC National Rural Utilities Cooperative Finance Corporation
CoBank CoBank, ACB, formerly known as the National Bank for
Cooperatives
Commission Securities and Exchange Commission
CSA Coordination Services Agreement
Dalton City of Dalton, Georgia
DSC Debt Service Coverage Ratio
EPI Entergy Power, Inc.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 ITS Integrated Transmission System
ITSA Revised and Restated Integrated Transmission System
Agreement
kWh Kilowatt-hours
LPM(An Electric Membership
Corporation)
LEM LG&E PowerEnergy Marketing Inc.
Members The 39 retail distribution cooperatives that are members
of Oglethorpe
MEAG Municipal Electric Authority of Georgia
MFI Margins for Interest
Morgan Stanley Morgan Stanley Capital Group
MW Megawatts
MWh Megawatt-hours
NRC Nuclear Regulatory Commission
Oglethorpe Oglethorpe Power Corporation (An Electric Membership
Corporation)
PCBs Pollution Control Revenue Bonds
PCR Percentage Capacity Responsibility
PURPA Public Utility Regulatory Policies Act
RUS Rural Utilities Service
SEPA Southeastern Power Administration
SONOPCO Southern Nuclear Operating Company
TIER Times Interest Earned RatioTVA Tennessee Valley Authority
ii
PART I
ItemITEM 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 entirely owned by its 39 retail
electric distribution cooperative members (the "Members"), who, in
turn, are entirely owned by their retail consumers.. 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. It is one of the ten largest electric utilities in the United States in terms of
land area served. Oglethorpe has 146 full-timeapproximately 160 employees.
Oglethorpe and 18 part-time employees, after
reflecting the effect ofMembers 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 a business alliance
transaction.leased
generation assets and purchased power resources. (See "Corporate Restructuring""Power Supply Business,"
"Relationship with GTC," and "Relationship with Intellisource" herein.GSOC" herein and "OGLETHORPE'S
POWER SUPPLY RESOURCES.")
As with cooperatives generally, Oglethorpe operates on a not-for-profit
basis. Oglethorpe's principal business is providing wholesale electric power to
the Members.
The Members are local consumer-owned distribution cooperatives providing
retail electric service on a not-for-profit basis. In general, the membershipcustomer base
of the distribution cooperative Members consists of residential, commercial and industrial consumers
within specific geographic areas. The Members serve approximately 1.21.4 million
electric consumers (meters) representing a total population of approximately 2.63.4 million people. Corporate RestructuringFor
information on the Members, see "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES."
Oglethorpe's mailing address is 2100 East Exchange Place, Post Office Box
1349, Tucker, Georgia 30085-1349, and its telephone number is (770) 270-7600.
Cooperative Principles
Cooperatives like Oglethorpe are business organizations owned by their
members, which are also either their wholesale or retail customers. As
not-for-profit organizations, cooperatives are intended to provide services to
their members at the lowest possible cost, in part by eliminating the need to
produce profits or a return on equity. Cooperatives may make sales to
non-members, the effect of which is generally to reduce costs to members. Today,
cooperatives operate throughout the United States in such diverse areas as
utilities, agriculture, irrigation, insurance and credit.
All cooperatives are based on similar business principles and legal
foundations. Generally, an electric cooperative designs its rates to recover its
cost-of-service and plans to collect a reasonable amount of revenues in excess
of expenses (that is, margins) to increase its patronage capital, which is the
equity component of its capitalization. Any such margins are considered capital
contributions (that is, equity) from the members and are held for the accounts
of the members and returned to them when the board of directors of the
cooperative deems it prudent to do so. The timing and amount of any actual
return of capital to the members depends on the financial goals of the
cooperative and the cooperative's loan and security agreements.
Power Supply Business
Oglethorpe provides wholesale electric service to the 39 Members completedfor a
corporate restructuring (the
"Corporate Restructuring") on March 11, 1997 (the "Closing")substantial portion of their requirements from a combination of owned and leased
1
generating plants and power purchased from other suppliers and power marketers.
This service is provided pursuant to termslong-term, take-or-pay Wholesale Power
Contracts described below. The Wholesale Power Contracts obligate the Members on
a joint and conditions set forth inseveral basis to pay rates sufficient to pay all the Second Amendedcosts of owning
and Restated Restructuring
Agreement, dated February 24, 1997, by and among Oglethorpe, Georgia
Transmission Corporation (An Electric Membership Corporation) ("GTC") and
Georgia System Operations Corporation ("GSOC"). Pursuant to the Corporate
Restructuring, Oglethorpe divided itself into three specialized operating companies to respond to increasing competition and regulatory changes in the
electric industry. As part of the Corporate Restructuring, the transmission
business is now owned and operated by GTC, a newly formed Georgia electric
membership corporation, and the system operations business is now owned and
operated by GSOC, a newly formed Georgia nonprofit corporation. Oglethorpe
continues to own and operate itsOglethorpe's power supply business. On October 1, 1996,The Members may satisfy all or
a portion of their requirements above their existing Oglethorpe transferred to GSOC its system
operations assets,purchase
obligations with purchases from Oglethorpe or other suppliers. The Members are
now purchasing varying portions of their requirements from other suppliers. (See
"OGLETHORPE'S POWER SUPPLY RESOURCES--Future Power Resources" and "THE MEMBERS
AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources" and "--Future
Power Resources.")
Oglethorpe owns or leases undivided interests in thirteen generating units.
These units provide Oglethorpe with a total of 3,335 megawatts ("MW") of
nameplate capacity, consisting of its system control center1,501 MW of coal-fired capacity, 1,185 MW of
nuclear-fueled capacity, 632 MW of pumped storage hydroelectric capacity, 15 MW
of oil-fired combustion turbine capacity and related energy
control and revenue metering systems equipment. The purchase price totaled
approximately $9.4 million and was paid by GSOC's assumption2 MW of Oglethorpe's
obligations under an existing note held by the Rural Utilities Service ("RUS"),
by delivery ofconventional hydroelectric
capacity. In addition, Oglethorpe purchases a purchase money note payable to Oglethorpe and by the assumption
of certain other liabilities of Oglethorpe. Since October 1, 1996, Oglethorpe
had been the sole member of GSOC. The Members and GTC became members of GSOC at
the Closing. GSOC now operates the system control center and provides system
operations services to the Members, Oglethorpe and GTC.
At the Closing, Oglethorpe transferred to GTC its transmission business
and assets. The purchase price for the transmission business was based on an
appraisal of the fair market value of such business, as determined by an
independent appraiser, and was approximately $708 million. The purchase price
was paid primarily by GTC's assumption of a portion (approximately 16.86%) of
Oglethorpe's long-term secured debt in an amount equal to approximately $686
million. Approximately $541 million of this debt (payable to RUS, the Federal
Financing Bank ("FFB") and CoBank, ACB ("CoBank")) became the sole obligation of
GTC, and Oglethorpe was released from all liability with regard to this debt.
The remaining debt assumed by GTC in connection with the Corporate
1
Restructuring, approximately $145 million, relates to Oglethorpe's pollution
control revenue bonds ("PCBs"). While GTC assumed and agreed to pay this $145
million of debt, Oglethorpe is not legally released from its obligation to pay
for this debt. The remainder of the purchase price was paid by GTC from cash
obtained through a borrowing from National Rural Utilities Cooperative Finance
Corporation ("CFC") and the assumptiontotal of approximately $1 million1,200 MW of
otherpower pursuant to long-term power purchase agreements. Oglethorpe liabilities. Oglethorpe also made a special patronage capital
distribution of approximately $49 million to the Members which was used by the
Members to establish equity inmeets its
supplemental power supply needs through short-term power purchase contracts and
to provide initial working capital to GTC.
Oglethorpe and the 39 Members are members of GTC.spot market purchases. GTC now provides transmission services to the Members and Oglethorpe. GTC has succeeded to allfor
delivery of Oglethorpe's
rights and obligations with respect to the Integrated Transmission System
("ITS").Members' power purchases. (See "Relationship with GTC" herein,
for further discussion of the ITS."OGLETHORPE'S POWER SUPPLY RESOURCES" and "PROPERTIES--Generating Facilities" in
Item 2.)
Oglethorpe continues to operate itshas entered into power supply business. Oglethorpe
retained allarrangements with two power
marketers to reduce the cost of its ownedcapacity and leased generation assets and has total assets of
approximately $4.7 billion and total long-term debt of approximately $3.9
billion. Oglethorpe also continues to administer its power purchase contracts
and provide marketing support functionsenergy delivered to the Members.
Effective with the Corporate Restructuring, Oglethorpe amended its
Bylaws to implement a new governance structure with an 11-member board(See "OGLETHORPE'S POWER SUPPLY RESOURCES--Power Marketer Arrangements.")
In 2000, Cobb EMC and Jackson EMC accounted for 11.9% and 11.8% of
directors consisting of six directors elected from the Members, four independent
outside directors and Oglethorpe's President and Chief Executive Officer. This
smaller board replaced Oglethorpe's former 39-member board comprised of
directors nominated from and by each Member. (See "DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT" in Item 10 for further information.)
Contemporaneously with the Corporate Restructuring, Oglethorpe replaced
its Consolidated Mortgage and Security Agreement, dated as of September 1, 1994
(the "RUS Mortgage"), by and among Oglethorpe, as mortgagor, the United States
of America, acting through the Administratortotal revenues, respectively. None of the RUS, CoBank, Credit Suisse
First Boston, acting by and through its New York Branch ("Credit Suisse"), and
SunTrust Bank, Atlanta ("SunTrust"),other Members accounted
for as trustee under certain pollution control
bond indentures identifiedmuch as 10% of Oglethorpe's total revenues in the RUS Mortgage, with an Indenture, dated as of
March 1, 1997, from Oglethorpe to SunTrust, as trustee (the "Master Indenture").
As did the RUS Mortgage, the Master Indenture provides for a lien on
substantially all of the owned tangible and certain intangible property of
Oglethorpe. (See "Electric Rates" herein and "General--Rates and Financial
Coverage Requirements" in Item 7 for further discussion of the revenue
requirements of the Master Indenture.)
New2000.
Wholesale Power Contracts
In connection with the Closing,1997, Oglethorpe and each of the Members entered into ana substantially similar Amended and
Restated Wholesale Power Contract dated August 1,
1996 (collectively, the "New Wholesale Power Contracts") which extendswith each Member extending through December
31, 2025. The NewUnder the Wholesale Power Contracts permitContract, each Member to take
future incremental power requirements either from Oglethorpe or other sources.
Under the New Wholesale Power Contracts, a Member is unconditionally
obligated on an express "take-or-pay" basis for a fixed allocation of
Oglethorpe's costs for its existing generation and purchased power resources, as
well as the costs with respect to any future resources in which such Member
elects to participate. The NewEach Wholesale Power ContractsContract specifically provideprovides that
the Member must make payments whether or not power is delivered and whether or
not a plant has been sold or is otherwise unavailable. Oglethorpe is obligated
to use its reasonable best efforts to operate, maintain and manage its resources
in accordance with prudent utility practices.
The New Wholesale Power Contracts provide that Oglethorpe will be
responsible for power supply planning, resource procurement and sales of
capacity and energy for a Member unless the Member notifies Oglethorpe that it
does not want Oglethorpe to provide these services.
Each Member's cost responsibility is allocated in the Newunder its Wholesale Power Contracts by assigning each Member anContract is
based on agreed-upon fixed percentage capacity responsibility ("PCR"). PCRsresponsibilities. Percentage
capacity responsibilities have been assigned for all of Oglethorpe's existing
generation and purchased power resources. PCRsPercentage capacity responsibilities
for any future resource will be assigned only to Members choosing to participate
in that resource. The New Wholesale Power Contracts provide that each Member will be
jointly and 2
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 of a defaulting Member are shared first among the participating Members, and if all participating
Members default, each non-participating Member is expressly obligated to pay a
proportionate share of such default.
The NewUnder the Wholesale Power Contracts, contain covenants by theeach Member (i)
tomust establish maintain and collect rates and charges for the service of its
electric system, and (ii) to
conduct its business in a manner that will produce
revenues and receipts at least sufficient to enable the Member to pay (i) to
2
Oglethorpe when due, all amounts payable by the Member under the Newits Wholesale Power
ContractsContract and to pay(ii) any and all other amounts payable from, or which might
constitute a charge or a lien upon, the revenues and receipts derived from itsthe
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.
In connection withUnder the implementation of long-term power marketer
arrangements with LG&E Power Marketing Inc. ("LPM"), Oglethorpe and each Member
entered into supplemental agreements to the New Wholesale Power Contracts, which
relateOglethorpe is not obligated to certain provisions of the New Wholesale Power Contracts and apply
during the term of the power marketer arrangements. The supplemental agreements
clarify the application of the New Wholesale Power Contract rate schedule to the
power marketer agreements. The 75% requirement described above has been met with
respect to the LPM agreements. The supplemental agreements assure thatprovide
all costs
incurred by Oglethorpe under the LPM agreement are recoverable under the New
Wholesale Power Contracts. As the expected additional power marketer
arrangements are finalized, additional supplemental agreements to the New
Wholesale Power Contracts will be entered into by Oglethorpe and the Members.
See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES" for a description of the Members' demandcapacity 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 the related power supply
resources."--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 New 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 suchits
rates, will be sufficient, but only sufficient,together with its revenues from all other sources, will be sufficient to
pay operating and maintenance costs, the cost of purchased
power, the cost of transmission services, and principal and interest on all
indebtedness (including capital lease obligations) of Oglethorpe, all costs associated with decommissioning or otherwise retiring any generating facility,
andof its system, to provide for reasonable reserves and to meet all
financial requirements.
Oglethorpe's principal financial requirements are contained in the
establishment and maintenanceIndenture, dated as of reasonable reserves.
Rates are also required to be established so as to enableMarch 1, 1997, from Oglethorpe to comply
with all financial requirements underSunTrust Bank
("SunTrust"), as trustee (as supplemented, the Master Indenture. (See "General--Rates
and Financial Coverage Requirements" in Item 7."Mortgage Indenture")
Oglethorpe had been required under the prior RUS Mortgage to implement
rates designed to maintain a Times Interest Earned Ratio ("TIER") of not less
than 1.05, a Debt Service Coverage Ratio ("DSC") of not less than 1.0 and an
Annual Debt Service Coverage Ratio ("ADSCR") of not less than 1.25. Oglethorpe
has always met or exceeded the TIER, DSC and ADSCR requirements of the RUS
Mortgage. Oglethorpe's policy for 1996 was to set rates to meet a TIER of 1.07.. Under the
MasterMortgage 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 ("MFI")Ratio for
each fiscal year equal to at least 1.10 times1.10. "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, during such fiscal yearwhether capitalized or expensed, on all indebtedness
secured under the MasterMortgage Indenture (oror by a lien equal or prior to the
lien of the Master Indenture),Mortgage Indenture, including amortization of debt discount
or premium on issuance, but excluding indebtedness assumed by GTC. MFI is determined
by adding (i) Oglethorpe's net margins (after certain defined adjustments), (ii) interest charges on indebtedness
secured under the Master Indenture (or by lien
equal to
3
or prior to the lien of the Master Indenture), excluding indebtedness assumed by GTC and (iii)("Interest Charges"), plus
o any amount included in net margins for accruals for federal or state
income taxes. The definitiontaxes imposed on income after deduction of MFIinterest 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.
(See "General--Rates and Financial Coverage Requirements" in Item
7.)
Under the3
The formulary rate established by Oglethorpe in the new rate schedule to the
New Wholesale Power Contracts the rates charged by Oglethorpe
are developed usingemploys 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 formulaalso implements the assignment of
responsibility for fixed costs (i.e.,assigned to each Member (that is, the PCR)Member's
percentage capacity responsibility). The monthly charges for capacity and other
non-energy charges are based on a rate formula using 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 passthroughpass-through of actual energy costs, including fuel costs,
variable operations and maintenance costs and purchased energy costs. However, under the supplemental agreements for the LPM agreements, each Member
pays a fixed rate for energy, plus certain adjustments, while LPM pays all
energy costs, within an agreed upon range of costs.(See
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--General--Rates and Regulation" in Item 7.)
The new rate schedule formula also includes a prior period adjustment ("PPA") mechanism. The PPA
servesmechanism
designed to facilitate the achievement ofensure that Oglethorpe achieves the minimum 1.10 MFI ratio, and it
providesMargins for
the retention of margins within a range from a 1.10 MFI ratio to a
1.20 MFI ratio.Interest Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum
1.10 MFI ratio would beMargins for Interest Ratio are accrued as of December 31 of the applicable
year and collected duringfrom the period April through December of the following year.
Amounts, if any, earned by Oglethorpe in excess of a 1.20 MFI ratio would be
charged against revenues as of December 31 of the applicable year and refundedMembers during the period April through December of
the following year. The new rate schedule formula is intended to permitprovide for the
collection of revenues which, together with revenues from all other sources, are
equal to all costs and expenses recorded by Oglethorpe, plus amounts necessary
to achieve at least the minimum 1.10 MFI ratio.Margins for Interest Ratio.
Under the terms of Oglethorpe's prior RUS Mortgage all rate revisions
by Oglethorpe were subject to the approval of RUS. Under the Master Indenture and related loan contract with RUS, however,the Rural
Utilities Service ("RUS"), adjustments to Oglethorpe's rates to reflect changes
in Oglethorpe's budgets are generally not subject to RUS approval,
except for reductions in rates in a fiscal year following a fiscal year in which
Oglethorpe has failed to meet the minimum 1.10 MFI ratio set forth in the Master
Indenture. Any changeapproval. Changes to
the underlying rate formula would beschedule under the Wholesale Power Contracts are generally subject to
RUS approval. Rate revisionsOglethorpe's rates are not subject to the approval of any other
federal or state agency or authority, including the Georgia Public Service
Commission (the "GPSC").
For information regarding future rates, see "General--Rates and
Financial Coverage Requirements" and "Results of Operations--Factors Affecting
Future Financial Performance" in Item 7.
Relationship with GTC
GTC purchased and is operating the transmission system as described in
"Corporate Restructuring" herein. Oglethorpe and allthe 39 Members are members of GTC. GTC is providingprovides transmission
services to the Members for delivery of the Members' power purchases from
Oglethorpe Southeastern Power Administration
("SEPA") and any other power suppliers. GTC also provides transmission services to
Oglethorpe and third parties. Oglethorpe has entered into a transmissionan 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
Project, a pumped storage hydroelectric facilityPumped Storage Hydroelectric Facility ("Rocky Mountain").
In connection with the Corporate Restructuring, GTC and the Members
entered into transmission agreements (the "Transmission Agreements") under which
GTC provides transmission service to the Members pursuant to a transmission
tariff. The Transmission Agreements have a minimum term of network service for
current load until December 31, 2025. After an initial ten-year term, load
growth above 1995 requirements may, with notice to GTC, be served by others. The
Transmission Agreements provide that if a Member elects to
4
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 Transmission Agreements, Members have the right to
design, construct and own new distribution substations.
The Transmission Agreements provide that the Members are responsible,
on a joint and several basis, for all of GTC's obligations relating to its
transmission business. The Transmission Agreements contain an express covenant
of the Members to set and collect retail rates sufficient to allow the Members
to meet their respective obligations under the Transmission Agreements. The rate
formula set forthhas rights in the Integrated Transmission System, which consists of
transmission tariff is intended to recover all costs
and expenses paid or incurredfacilities owned by GTC. The rate expressly includes in the
description of costs to be recovered all principal and interest on indebtedness
of GTC, (including any indebtedness of Oglethorpe assumed by GTC). The rate
further expressly provides for GTC to earn sufficient margins to satisfy the
requirements of its new indenture, which is substantially similar to
Oglethorpe's Master Indenture.
The GTC transmission tariff and associated Transmission Agreements have
been developed to implement the Corporate Restructuring and to be consistent
with federal transmission policy as expressed in Order 888 of the Federal Energy
Regulatory Commission ("FERC"). FERC's Order 888 mandates open access of
essentially all transmission systems in order to promote competition in the bulk
power markets and provides that non-regulated utilities (such as GTC) must
provide access to their transmission systems on reciprocal terms and conditions
in order to obtain transmission from FERC-regulated utilities. The transmission
tariff and Transmission Agreements have been designed to facilitate the
operation of GTC in the new regulatory environment and provide for GTC to serve
on a nondiscriminatory basis both member and non-member customers on terms
intended to meet FERC's reciprocity requirement.
Prior to the Closing, Oglethorpe, together with Georgia Power Company ("GPC"), the
Municipal Electric Authority of Georgia ("MEAG") and the City of Dalton
("Dalton"), owned transmission facilities which together form the ITS.
GTC succeeded to Oglethorpe's rights in the ITS at the Closing, and GTC now owns
approximately 2,267 miles of transmission line and 426 substations of various
voltages.. Through agreements, common access to the combined facilities that
compose the ITSIntegrated 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. GTC's rights and obligations with respect to the ITS are governed by
the Revised and RestatedThe Integrated Transmission System Agreement (the "ITSA"),
which was assigned to GTC in connection with the Corporate Restructuring. The
ITSA provides for the transmission and distribution of electric energy in the
State of Georgia, other than in certain counties, and for bulk power
transactions, through use of the ITS. The ITS was established in order to obtain
the benefits of a coordinated development of the parties' transmission
facilities and to make it unnecessary for any party to construct duplicative
facilities.
The ITS consists of all transmission facilities, including land,
owned by the parties on the date the ITSA became effective and those thereafter
acquired, which are located in the State of Georgia other than in the excluded
counties and which are used or usable to transmit power of a certain minimum
voltage and to transform power of a certain minimum voltage and a certain
minimum capacity (the "Transmission Facilities"). GPC has entered into
agreements with MEAG and Dalton that are substantially similar to the ITSA, and
GPC may enter into such agreements with other entities. The ITSA will remain in
effect through December 31, 2012 and, if not then terminated by five years'
prior written notice by either party, will continue until so terminated.
The ITSA is administered by a committee (the "Joint Committee")
composed of GTC, GPC, MEAG and Dalton. Each year, the Joint Committee determines
a four-year plan of additions to the Transmission Facilities that will reflect
the current and anticipated future transmission requirements of the parties.
Each ITS participant is generally required to maintain an original cost
investment in the Transmission Facilities in proportion to their respective Peak
Loads (as defined in the ITSA).
GTC and GPC are parties to a Transmission Facilities Operation and
Maintenance Contract (the "Transmission Operation Contract"), under which GPC
provides System Operator Services (as defined in the
5
Transmission Operation Contract) for GTC. In addition, GPC is required to
provide such supervision, operation and maintenance supplies, spare parts,
equipment and labor for the operation, maintenance and construction as may be
specified by GTC. GPC is also required to perform certain emergency work under
the Transmission Operation Contract. GTC is permitted, upon notice to GPC, to
perform, or contract with others for the performance of, certain services
performed by GPC. Absent termination or amendment of the Transmission Operation
Contract, however, GPC will continue to perform System Operator Services for
GTC. The term of the Transmission Operation Contract will continue from year to
year unless terminated by either party upon four years' notice. GTC is required
to pay its proportionate share of the cost for the services provided by GPC.
Relationship with GSOC
From October 1, 1996 untilOglethorpe, GTC and the Closing, Oglethorpe was the sole member39 Members are members of GSOC. The Members and GTC became members of GSOC upon the Closing. GSOC now operates the
system control center and currently provides system operations services to
the Members, Oglethorpe and GTC. Oglethorpe has also contracted with GSOC to operate an
electric capacity and energy pool for scheduling and dispatching Oglethorpe and
Member resources. (See "OGLETHORPE'S POWER SUPPLY RESOURCES--Capacity and Energy
Pool"). Since January 1, 2000, GSOC has been providing support services to
Oglethorpe in the areas of accounting, auditing, communications, human
resources, facility management, telecommunications and information technology at
cost-based rates.
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.
Relationship with Smarr EMC
In providing joint planning and resource management services under the
Wholesale Power Contracts, Oglethorpe identified Member needs that could best be
met by the construction and ownership of simple cycle combustion turbine
facilities. Oglethorpe and the Members determined that such facilities should be
owned, not by Oglethorpe, but by a separate Member-owned entity. Accordingly,
Smarr EMC was formed as a Georgia electric membership corporation in 1998 and is
now owned by 37 of Oglethorpe's 39 Members. Oglethorpe is providing operation
and financial management services for Smarr Energy Facility and Sewell Creek
Energy Facility, the gas-fired combustion turbine projects currently owned by
Smarr EMC.
Relationship with GPC
Oglethorpe's relationship with GPC is a significant factor in several
aspects of Oglethorpe's business. GPC is one of Oglethorpe's principal suppliers
of purchased power, and Oglethorpe is one of GPC's largest customers. All of Oglethorpe's co-owned generating
facilities, except Rocky Mountain, are operated by GPC on behalf of itself as a
co-owner and as agent for the other co-owners. GPC and Oglethorpe, through the
Members, are competitors in the State of Georgia for electric service to new
customers that have a choice of supplier under the Georgia Territorial Electric
Service Act, which was enacted in 1973 (the "Territorial Act"). GPC is also one
of Oglethorpe's suppliers of purchased power. For further information regarding
the various relationships and agreements with GPC, see "THE MEMBERS OF OGLETHORPE--ServiceAND THEIR POWER
SUPPLY RESOURCES--Service Area and Competition", "MEMBER REQUIREMENTS
AND and "OGLETHORPE'S POWER SUPPLY
RESOURCES--Power Purchase and Sale Arrangements--Power Purchases from GPC", "--Other Power System Arrangements" herein, and "GENERATING
FACILITIES--Fuel Supply", "CO-OWNERS OF THE PLANTS AND THE PLANT
AGREEMENTS--Co-OwnersGPC." 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 FFBthe Federal Financing Bank ("FFB") have been a major source of
funding for Oglethorpe. In
recent years, there have been legislative, administrative(See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--Financial Condition--Capital Requirements"
and budgetary
initiatives intended"--Liquidity and Sources of Capital" in Item 7.)
Oglethorpe entered into a loan contract with RUS in connection with the
Mortgage Indenture. Under the loan contract, RUS has approval rights over
certain significant actions and arrangements, including, without limitation,
o significant additions to reduce 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 some cases, eliminate federal funding for
electric cooperatives. However,limited circumstances, issuance of additional secured debt.
The extent of RUS's approval rights under the loan contract with Oglethorpe does not have any new generation
facilitiesis
substantially less than the supervision and control RUS has traditionally
exercised over borrowers under construction,its standard loan and management does not anticipate the need for
construction of any new capacity well into the future. (See "MEMBER REQUIREMENTS
AND POWER SUPPLY RESOURCES--Power Purchase and Sale Arrangements--Power Marketer
Arrangements" for a discussion of the long-term power marketer arrangements.)security documentation. In
addition, the MasterMortgage Indenture improves Oglethorpe's ability to borrow funds
in the public capital markets. Seemarkets 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 applications to RUS to provide permanent
financing for six new combustion turbines and a combined cycle facility being
constructed to meet future requirements of the Members. The facilities may
ultimately be owned by a subsidiary of Oglethorpe, by Smarr EMC or by a similar
separate entity. The loan applications were made on behalf of any entity that
may ultimately own these facilities. (See "OGLETHORPE'S POWER SUPPLY
RESOURCES--Future Power Resources" and "THE MEMBERS OF OGLETHORPE--Members'
RelationshipAND THEIR POWER SUPPLY
Resources--Future Power Resources.")
Seasonal Variations
The demand for energy by the Members is influenced by seasonal weather
conditions. Historically, Oglethorpe's peak demand has occurred during the
months of June through August. Energy revenues track energy costs as they are
incurred and also fluctuate month to month. Capacity revenues reflect the
recovery of Oglethorpe's fixed costs, which do not vary significantly from month
to month; therefore, capacity charges are billed and capacity revenues are
recognized in equal monthly amounts.
6
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 RUS"other power suppliers and power marketers. Oglethorpe has also
entered into power supply arrangements with power marketers to reduce the cost
of capacity and energy delivered to the Members. Oglethorpe meets its
supplemental power supply needs through short-term power purchase contracts and
spot-market purchases.
Generating Plants
Oglethorpe's thirteen generating units consist of 30% undivided interests
in the Edwin I. Hatch Plant ("Plant Hatch"), the Alvin W. Vogtle Plant ("Plant
Vogtle") and the Hal B. Wansley Plant ("Plant Wansley"), a 60% undivided
interest in the Robert W. Scherer Unit No. 1 ("Scherer Unit No. 1"), a 60%
undivided interest in the Robert W. Scherer Unit No. 2 ("Scherer Unit No. 2"), a
100% interest in the Tallassee Project at the Walter W. Harrison Dam
("Tallassee") and a 74.61% undivided interest in Rocky Mountain. Plant Hatch
consists of two nuclear-fueled units, with nameplate ratings of 810 MW and 820
MW, respectively. Plant Vogtle consists of two nuclear-fueled units, each with a
nameplate rating of 1,160 MW. Plant Wansley consists of two coal-fired units,
each with a nameplate rating of 865 MW. Plant Wansley also includes a 49.2 MW
oil-fired combustion turbine. Plant Scherer consists of four coal-fired units,
each with a nameplate rating of 818 MW. Oglethorpe has an interest only in
Scherer Unit No. 1 and Scherer Unit No. 2. Tallassee is a conventional
hydroelectric facility with a nameplate rating of 2.1 MW. Rocky Mountain is a
three-unit pumped storage hydroelectric facility with a nameplate rating of
847.8 MW.
Participants in Plants Hatch, Vogtle and Wansley and Scherer Units No. 1
and No. 2 also include MEAG, Dalton and GPC. GPC serves as operating agent for
these units. GPC is also a participant in Rocky Mountain, which is operated by
Oglethorpe.
See "PROPERTIES" in Item 2 for a description of Oglethorpe's generating
facilities, fuel supply and the co-ownership arrangements.
Power Marketer Arrangements
Oglethorpe utilizes power marketer arrangements to reduce the cost of power
to the Members. Oglethorpe has power marketer agreements with LG&E Energy
Marketing Inc. ("LEM") for approximately 50% of the load requirements of the 37
participating Members and with Morgan Stanley Capital Group Inc. ("Morgan
Stanley") with respect to 50% of the 39 Members' load requirements forecasted at
the time Oglethorpe entered into the agreement. The LEM agreement is based on
the actual requirements of the participating Members during the contract term,
whereas the Morgan Stanley agreement represents a fixed supply obligation.
Generally, these arrangements reduce the cost of supplying power to the
Members by limiting the risk of unit availability, by providing a guaranteed
benefit for the use of excess resources and by providing future power needs at a
fixed price. Under these power marketer agreements, Oglethorpe purchases energy
at fixed prices covering a portion of the costs of energy to its Members. LEM
and Morgan Stanley, in turn, have certain rights to market excess energy from
the Oglethorpe system. Most of Oglethorpe's generating facilities and power
purchase arrangements are available for use by LEM and Morgan Stanley under the
terms of the respective agreements. Oglethorpe continues to be responsible for
all of the costs of its system resources but receives revenue, as described
below, from LEM and Morgan Stanley for the use of the resources.
7
LEM Agreement
Effective January 1, 1997, Oglethorpe entered into a power marketer
agreement with LEM, an indirect, wholly owned subsidiary of LG&E Energy Corp.,
which is a diversified energy services company headquartered in Louisville,
Kentucky. In December 2000, LG&E Energy Corp. completed a merger with Powergen
plc, a British public limited company, under which LG&E Energy Corp. became an
indirect wholly owned subsidiary of Powergen plc.
Under the power marketer agreement, LEM is obligated to deliver, and
Oglethorpe is obligated to take, (i) 50% of the load requirements of the 37
participating Members, less (ii) the load requirements for certain customers who
have the right to choose electric suppliers, plus (iii) 50% of the 37 Members'
percentage capacity responsibility shares of the delivery obligations under
Oglethorpe's existing firm power off-system sale contracts. For certain smaller
customer choice loads, LEM is obligated to deliver, if Oglethorpe requests, 50%
of the associated load requirements. Oglethorpe has the option of purchasing the
energy requirements for any customer choice load from another supplier.
Oglethorpe is obligated to sell and LEM is obligated to buy 50% of the output of
each of the 37 Members' percentage capacity responsibility shares of the "must
run" units (primarily nuclear units). Oglethorpe is also obligated to make
available the same share of most of Oglethorpe's other resources, which LEM may
schedule. LEM does not have the right to the output of upgrades to these
resources. LEM pays Oglethorpe the costs associated with the energy taken,
subject to certain adjustments. Oglethorpe must pay LEM a contractually
specified price for each megawatt-hour ("MWh") purchased.
The LEM agreement has a term extending through 2011. With one year's
notice, Oglethorpe has the right to terminate the LEM agreement as of December
31, 2001 or any December 31 after that. With 18 months' notice, LEM has the
right to terminate the agreement as of December 31, 2004 or any December 31
after that. In February 2001, LEM initiated the contractually defined
arbitration process to resolve a number of issues relating to the administration
of the LEM agreement. (See "LEGAL PROCEEDINGS" in Item 3.)
Morgan Stanley Agreement
Effective May 1, 1997, Oglethorpe entered into a power marketer agreement
with Morgan Stanley with respect to 50% of the Members' then forecasted load
requirements. The agreement obligates Oglethorpe to purchase fixed quantities of
energy at fixed prices. Each Member selected a term for its obligation, as well
as the portion of its then forecasted requirements to be purchased as a fixed
quantity. Oglethorpe is obligated to sell and Morgan Stanley is obligated to buy
50% of the output, in contractually fixed amounts, of each Member's percentage
capacity responsibility share (for the term and portion selected) of the "must
run" units (primarily nuclear units). Oglethorpe is also obligated to make
available the same share of most of Oglethorpe's other resources, in
contractually fixed amounts, which Morgan Stanley may schedule for each 24-hour
day. This schedule is set the day prior based on availability limitations in the
contract. Morgan Stanley pays a contractually fixed amount each month and an
amount for the scheduled energy based on contractually fixed prices. The
agreement has a term extending to March 31, 2005, but the purchases for certain
Members decline to zero prior to that date. Oglethorpe manages the portion of
the system resources covered by the Morgan Stanley agreement on behalf of the
"pool" participants through scheduling and dispatching such resources.
Oglethorpe makes purchases and sales on behalf of the "pool" participants to
balance the fixed purchase obligation against the actual requirements and to
optimize the use of the resources after receiving the daily schedule from Morgan
Stanley.
Morgan Stanley is a subsidiary of Morgan Stanley, Dean Witter, Discover &
Co., a diversified investment banking and financial services company. Morgan
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
capacity and associated energy from GPC as follows: 750 MW through May 31, 2000,
500 MW from June 1, 2000 to August 31, 2000 and 375 MW from September 1, 2000 to
December 31, 2000. Oglethorpe will continue to purchase 375 MW of capacity and
associated energy under this agreement through August 31, 2001, and will
purchase 250 MW from September 1, 2001 to March 31, 2006.
Other Power Purchases
Oglethorpe purchases 100 MW of capacity from each of Entergy Power, Inc.
("Entergy Power") and Big Rivers Electric Corporation ("Big Rivers"), under
agreements extending through June and July 2002, respectively. The availability
of capacity under the Entergy Power contract is dependent on the availability of
two specific generating units available to Entergy Power. The Tennessee Valley
Authority ("TVA") provides the transmission service to deliver the power from
the Big Rivers electric system to the Integrated Transmission System. TVA and
Southern Company Services, as agent for Alabama Power Company and Mississippi
Power Company, provide the transmission service necessary to deliver the power
from Entergy Power to the Integrated Transmission System.
Oglethorpe has a contract through 2019 to purchase approximately 300 MW of
capacity from Hartwell Energy Limited Partnership, a joint venture between
Dynegy Inc. and American National Power, Inc., a subsidiary of National Power,
PLC. This capacity is provided by two 150 MW gas-fired combustion turbine
generating units on a site near Hartwell, Georgia. Oglethorpe has the right to
dispatch the units fully.
Oglethorpe has an agreement with Doyle I, LLC, a limited liability company
owned by an affiliate of Enron North America Corp. and one of Oglethorpe's
Members, to purchase the output of a 325 MW gas-fired combustion turbine
generating facility over a 15-year term. Delivery commenced May 15, 2000.
Oglethorpe has the right to dispatch the units fully.
See Note 9 of Notes to Financial Statements in Item 8 for a discussion of
Oglethorpe's commitments under these power purchase agreements.
In addition, Oglethorpe also purchases small amounts of capacity and energy
from "qualifying facilities" under the impactPublic Utility Regulatory Policies Act of
changes1978 ("PURPA"). Under a waiver order from the Federal Energy Regulatory
Commission ("FERC"), Oglethorpe historically made all purchases the Members
would have otherwise been required to make under PURPA and Oglethorpe was
relieved of its obligation to sell certain services to "qualifying facilities"
so long as the Members make those sales. Oglethorpe historically provided the
Members with the necessary services to fulfill these sale obligations. Purchases
by Oglethorpe from such qualifying facilities provided less than 0.1% of
Oglethorpe's energy requirements for the Members in 2000. Under their Wholesale
Power Contracts, the Members may make such purchases instead of Oglethorpe.
Long-Term Power Sales
Oglethorpe has an agreement to sell 100 MW of base capacity to Alabama
Electric Cooperative, Inc. through December 31, 2005. During the term of the
power marketer agreements, LEM and Morgan Stanley will be responsible for
supplying Oglethorpe with sufficient power to fulfill this power sale.
9
Other Power System Arrangements
Oglethorpe has interchange, transmission and/or short-term capacity and
energy purchase or sale agreements with over 80 utilities, power marketers and
other power suppliers. The agreements provide variously for the purchase and/or
sale of capacity and energy and/or for the purchase of transmission service. The
development of and access to the Integrated Transmission System and the
interconnections with other utilities are key elements in Oglethorpe's ability
to make off-system sales and purchases through its transmission contract with
GTC and to compete in an increasingly competitive market.
Future Power Resources
Although the existing long-term power marketer arrangements with LEM and
Morgan Stanley were designed to provide substantially all of the Members'
requirements during their contract terms, in fact the Members' requirements have
exceeded the amounts provided by these arrangements. Oglethorpe expects that the
Members' requirements will continue to exceed contracted purchases over the next
several years. The Members also have significant additional requirements beyond
the term of the power marketer arrangements.
Under the Wholesale Power Contracts, Members can elect on an annual basis
whether to have Oglethorpe provide joint planning and resource management
services. These services consist of bulk power supply planning, future resource
procurement, and bulk power sales for the Members. Some Members are currently
not participating in joint planning and resource management services.
Oglethorpe is in the RUS
lending program onprocess of arranging the Members.
Through provisionsnecessary power supply for
Members that currently participate in joint planning and resource management
services. In this regard, Oglethorpe has entered into agreements to acquire and
construct six gas-fired combustion turbines designed to provide 618 MW of
capacity and a gas-fired combined cycle facility designed to provide 468 MW of
capacity. Four of the prior RUS Mortgage, RUS exercised substantial
controlcombustion turbines are scheduled for completion in 2002,
with the other two to be completed in 2003. The combined cycle facility is
scheduled for completion in 2003. Oglethorpe also has an agreement to purchase
equipment for a possible 2005 gas-fired combined cycle project. Members have
subscribed for all of the capacity and supervision over Oglethorpe in such areas as accounting, the
issuance of secured indebtedness, rates and chargesenergy from these facilities except for
the salecapacity and associated energy of a 2003 combustion turbine and the capacity
and energy of the possible 2005 combined cycle project. Oglethorpe is evaluating
options with respect to the unsubscribed portions, which include seeking
additional subscriptions from Members, contracting to sell some of the output of
the facilities to non-Members, or selling the equipment.
Although Oglethorpe plans for and procures power constructionsupply resources for
electing Members, Oglethorpe will not necessarily own these resources. For a
number of reasons, these facilities may be owned by a subsidiary of Oglethorpe,
by Smarr EMC or by a similar separate entity owned by those Members who
participate in the facilities. Oglethorpe has submitted loan applications to RUS
for FFB loans to permanently finance the 2002 and acquisition of2003 combustion turbine
facilities and the purchase2003 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 sale"--Future
Power Resources" for a discussion of power.
Undercapacity purchased by the Master Indenture
6Members 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 new loan contact entered into with RUS in connection therewith, RUS has
significantly reduced these controls.
Relationship with Intellisource
In conjunction with the Corporate Restructuring and as a part of its
continuing efforts to reduce costs, effective February 1, 1997, Oglethorpe
implemented a business alliance with Intellisource, Inc., a national provider of
outsourcing services. Pursuant to an agreement with Intellisource, approximately
150 support services division employees in the areas of accounting, auditing,
communications, human resources, facility management, purchasing,
telecommunications and information technology became employees of the
Intellisource organization. Oglethorpe, GTC and GSOC are key customers of
Intellisource and are being served on-site by the managers and employees of
Oglethorpe's former support services division.
Certain Factors Affecting the Utility Industry in General
The electric utility industry in the United States is undergoing
fundamental change and is becoming increasingly competitive. This change is
promoted by the Energy Policy Act of 1992 (the "Energy Policy Act"), recently
adopted and proposed policies from FERC regarding transmission access and
pricing, increased consolidation and mergers of electric utilities, the
proliferation of self-generators and independent power producers, surplus
generation in certain regional markets and other factors. The Energy Policy Act
and FERC policies allow for increased competition among wholesale electric
suppliers and increased access to transmission services by such suppliers. The
new competitive
environment is subject to rapidly evolving regulatory policy at
both the federal and state levels, which is based on a shift to a market-driven
environment from a regulated one. Significant legislative developments at the
federal level and in various state legislative bodies, and regulatory
developments at FERC and in state commissions are expected to continue to
clarify the policy and regulatory framework for increased competition. The GPSC
staff has scheduled a series of workshops, the stated purpose of which is to
solicit views from the various parties impacted by electric industry
restructuring and to discuss potential resolutions to these issues. At the
conclusion of the workshops, the GPSC staff anticipates presenting a report to
the GPSC that will identify electric industry restructuring issues, potential
resolutions and the views of the parties who participated in the workshop. (See
"THE MEMBERS OF OGLETHORPE--Service Area and Competition".)
A number of other significant factors have affected the operations of
electric utilities. They include the cost of fuel for the generation of electric
energy, recovery of the cost of existing facilities, fluctuating rates of load
growth, the effects of conservation and energy management on the use of electric
energy and compliance with environmental and other governmental regulations.
All of the factors mentioned above present an increasing challenge to
companies in the electric utility industry, includingamong other reasons.
Oglethorpe's current power procurement efforts for these projected
requirements include initial discussions with a number of entities regarding
contractual power supply arrangements. These arrangements could take a form
similar to Oglethorpe's existing power marketer arrangements or a form more like
traditional power purchase arrangements. Oglethorpe may also evaluate other
alternatives for meeting future power supply requirements. (See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Miscellaneous--Competition" in Item 7).
Capacity and Energy Pool
In connection with scheduling rights granted to the Members in the
Wholesale Power Contracts adopted in 1997, Oglethorpe established an electric
capacity and energy pool for scheduling and dispatching Oglethorpe and Member
resources. Pursuant to the Wholesale Power Contracts and the policies and
procedures governing the pool, the Members may elect either to reduce costs, improveparticipate in
the managementpool or separately to schedule and dispatch the capacity represented by the
Member's percentage capacity responsibility under the Wholesale Power Contract.
The Members may also elect to include all or part of their other resources in
the pool. Some Members have elected to be self-scheduling Members. See "THE
MEMBERS AND THEIR POWER SUPPLY RESOURCES--Member Power Supply Resources."
Oglethorpe has contracted with GSOC to operate the pool. Oglethorpe and
respondGSOC maintain, and in conjunction with the Members are currently refining,
policies and procedures relating to the changing environment. (See "Corporate Restructuring" hereinpool and "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES--General", "--Power Purchase and Sale
Arrangements--Other Power Purchases", and "ENVIRONMENTAL AND OTHER REGULATIONS"
in Item 2.)
7self-scheduling Members.
11
THE MEMBERS OF OGLETHORPE
Service AreaAND THEIR POWER SUPPLY RESOURCES
Member Demand and CompetitionEnergy Requirements
The Members are listed below and include 39 of the 42 electric distribution
cooperatives in the State of Georgia.
Altamaha EMC Habersham EMC Planters EMC
Amicalola EMC Hart EMC Rayle EMC
Canoochee EMC Irwin EMC Satilla Rural EMC
Carroll EMC Jackson EMC Sawnee EMC
Central Georgia EMC Jefferson Energy Cooperative, an EMC Slash Pine EMC
Coastal EMC Lamar EMC Snapping Shoals EMC
Cobb EMC Little Ocmulgee EMC Sumter EMC
Colquitt EMC Middle Georgia EMC Three Notch EMC
Coweta-Fayette EMC Mitchell EMC Tri-County EMC
Excelsior EMC Ocmulgee EMC Troup EMC
Flint EMC Oconee EMC Upson County EMC
Grady EMC Okefenoke Rural EMC Walton EMC
GreyStone Power Corporation Pataula EMC Washington EMC
Corporation, an EMC
The Members serve approximately 1.21.4 million electric consumers (meters)
representing a total population of approximately 2.63.4 million people. The Members serve a region
covering approximately 40,000 square miles, which is approximately 70% of the
land area in the State of Georgia, served by the owners of the ITS, encompassing 150 of the State's 159 counties.
Sales by the Members in 19962000 amounted to approximately 19.627 million megawatt-hours ("MWh"),MWh, with
72%approximately 66% to residential consumers, 26%31% to commercial and industrial
consumers and 2%3% to other consumers. The Members are the principal suppliers for
the power needs of rural Georgia. While the Members do not serve any major
cities, portions of their service territories are in close proximity to urban
areas and are experiencing substantial growth due to the expansion of urban
areas, including metropolitan Atlanta, into suburban areas and the growth of
suburban areas into neighboring rural areas. The Members have experienced
average annual compound growth rates from 19941998 through 19962000 of 5% in number of
consumers, 9%7% in MWh sales and 7%5% in electric revenues.
The following table shows the aggregate peak demand and energy requirements
of the Members for the years 1998 through 2000, and also shows the amounts of
energy requirements supplied by Oglethorpe. From 1998 through 2000, demand and
energy requirements of the Members increased at an average annual compound
growth rate of 7.3% and 7.4%, respectively.
Member Member Energy
Demand (MW) Requirements (MWh)
----------------------------------------------------------------
Total(1) Total(2) Supplied by
------- ------- Oglethorpe(3)
------------
1998 5,816 24,494,807 23,315,950
1999 6,452 25,760,322 24,755,812
2000 6,703 28,210,327 27,232,641
(1) System peak demand of the Members measured at the Members' delivery points
(net of system losses), adjusted to include Members' resources behind the
delivery points.
(2) Retail requirements served by Members' resources, adjusted to include
resources behind the delivery points. (See "Member Power Supply Resources"
below.)
(3) Includes energy supplied to self-scheduling Members for resale at
wholesale. (See "OGLETHORPE'S POWER SUPPLY RESOURCES--Capacity and Energy
Pool.")
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 chiefprincipal 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 not reassign territory or transfer service except in
limited circumstances provided by the Territorial Act. 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:only if: (i) upon a determination by 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) upon a finding bythe 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
premisespremise and the electric utility is unwilling or unable to comply with an order
from GPSC regarding such service.
As discussed above,Since 1973, the Territorial Act allowshas 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 demandload 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 8
commercial and industrial
loads served by the Members continues to increase annually. Retail competition in the electric utility industry has historically
been rare. While the
competition for 900-kilowatt loads represents only limited competition in
Georgia, this competition has given Oglethorpe and the Members the opportunity
to develop resources and strategies to operate in an increasingly competitive
market.
The electric utility industry in the United States is undergoing
fundamental change and is becoming increasingly competitive. (See "FACTORS
AFFECTING THE ELECTRIC UTILITY INDUSTRY--General" and "MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Miscellaneous--Competition" in Item 7.)
From time to time, utilities are approached by other parties interested in
purchasing their systems. Some of the Members have been approached in the past
by third parties indicating an interest in purchasing their systems. The
New Wholesale Power Contracts provide that a Member may not dissolve, liquidate or
otherwise wind up its affairs without Oglethorpe's approval. TheA Member generally
must obtain approval from Oglethorpe before it may
not consolidate or merge with any
person or reorganize or change the form of its business organization from an
electric membership corporation or sell, transfer, lease or otherwise dispose of
all or substantially all of its assets to any person, whether in a single
transaction or series of transactions, unless either (i) thetransactions. The Member may enter such a transaction
is approved by Oglethorpe or (ii) otherwithout Oglethorpe`s approval if specified conditions are satisfied, including,
but not limited to, an assumption agreement by the transferee, satisfactory to Oglethorpe,
containing an assumption by the transferee ofto assume the performance and observance of every covenant and condition of the
Member under the New Wholesale Power Contract, and certifications of accountants as
to certain specified financial requirements of the transferee (taking into account
the transfer).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, after any such
distribution, the Member's total equity will equal at least 40% (30% in the case
of Members that have the new form of RUS loan documents, discussed below) of its
total assets, except that distributions may be made of up to 25% of the margins
and patronage capital received by the Member in the preceding year. As a general matter,year (provided
that equity is at least 20% in the case of Members that borrow fromhave the new form of RUS
distribute accumulated patronage capital from time to time
subject to their respective financial policies and in conformity with their
respective RUS mortgages.loan documents). (See "Members' Relationship with RUS" herein.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 New 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--New WholesaleCORPORATION--Wholesale Power Contracts".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 New Wholesale Power Contracts. Revenues of the Members that borrow
from RUS are, however, pledged
under their respective RUS mortgages.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 in
such areas as: (i) accounting; (ii) borrowings; (iii) rates and charges for the
sale of power; (iv) construction and acquisition of facilities; and (v) the
purchase and sale of power.it. The individual RUS mortgages of thesuch Members require them to
design rates with a view to maintaining an average TIER of not less than
1.50Times Interest Earned Ratio
and an average DSCDebt Service Coverage Ratio of not less than 1.25 for the two
highest out of every three successive years. AlthoughMembers that have the new form of
RUS loan documents are also required to maintain an Operating Times Interest
Earned Ratio and an Operating Debt Service Coverage Ratio of not less than 1.10
for the two highest out of every three successive years.
The Georgia Electric Membership Corporation Act, under which each of the
Members was formed, requires the Members to operate on a not-for-profit basis
and to set rates at levels that are sufficient to recover their costs and to
provide for reasonable reserves. The setting of the rates ofby the Members is not
subject to approval by any Federalfederal or state agency or authority other than RUS,
but the Territorial Act prohibits the Members from unreasonable discrimination
in the
9
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, Mitchell EMC, Troup
EMC and Walton EMC and Cobb EMC
have prepaidpaid their RUS indebtedness and are no longer RUS
borrowers. Each of these Members now have financial and other requirements under loan documentshas a rate covenant with their new lenders.its current
lender. Other Members may also pursue this option. To the extent that these five Members and others that in the future prepay theira Member
who is not an RUS indebtedness engageborrower engages in wholesale sales or transmission in
interstate commerce, they willit would be subject to regulation by FERC under the Federal
Power Act.
Members' Relationship with RUS
Through provisions in the loan documents securing loans to the Members, RUS
also exercises control and supervision over the Members that borrow from it in
such areas as accounting, borrowings, construction and acquisition of
facilities, and the purchase and sale of power. RUS has adopted new standard
forms of mortgages and loan contracts for distribution borrowers, the stated
purpose of which is to update and modernize the loan and security documentation
employed by RUS. Distribution borrowers are required to adopt these new forms as
a condition to receiving new loans from RUS.
Historically, federal loan programs providing direct loans from RUS to
electric cooperatives have been a major source of funding for the Members. In
recent years, there have been legislative, administrative and budgetary
initiatives intended to reduce or, in some cases, eliminate federal funding for
electric cooperatives. In addition,Under
the current RUS loan and guarantee programs have
been characterized by the imposition of increasingly problematic terms and
conditions and extended delays in access to necessary funding. RUS has adopted a
new standard form of mortgage and has published a proposed rule describing a new
standard form of loan contract for distribution borrowers.
Recent changes and proposals for further changes have made the direct
loan program, administered by RUS more costly. The Rural Electrification Loan
Restructuring Act of 1993 eliminated the long-standing 2% loan program and
substituted a new program, the interest rates for which 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 aspecial loans at 5% loan program. The. Distribution borrowers are also
eligible for loans made by FFB or other lenders and guaranteed by RUS.
Oglethorpe cannot predict the future cost, availability and amount of RUS direct
and guaranteed loans which may be available to the Members cannot be predicted.
Five Members have prepaid their RUS indebtedness and are no longer RUS
borrowers. Other Members may also pursue this option. (See "Rate Regulation of
Members" herein.)Members.
Members' RelationshipRelationships with GTC and GSOC
GTC provides transmission services to the Members for delivery of the
Members' power purchases from Oglethorpe and other power suppliers. GTC and the
Members have entered into Member Transmission Service Agreements under which GTC
provides transmission service to the Members pursuant to a transmission tariff.
The Member Transmission Service Agreements have a minimum term for network
service for current load until December 31, 2025. After an initial term ending
in 2006, load growth above 1995 requirements may, with notice to GTC, be served
by others. The Member Transmission Service Agreements provide that if a Member
elects to purchase a part of its network service elsewhere, it must pay
appropriate stranded costs to protect the other Members from any rate increase
that could otherwise occur. Under the Member Transmission Service Agreements,
Members have the right to design, construct and own new distribution
substations.
For information about the Members' relationshiprelationships with GTC and GSOC, see "OGLETHORPE
POWER Corporation--RelationshipCORPORATION--Relationship with GTC" and "--RelationshipGSOC."
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 GSOC".purchases from Oglethorpe or other suppliers. (See "OGLETHORPE
POWER CORPORATION--Wholesale Power Contracts.")
Contracts with SEPA
In addition to energy received from Oglethorpe under the New Wholesale
Power Contracts, theThe Members purchase hydroelectric power from the Southeastern Power
Administration ("SEPA") under contracts with
SEPA.that extend until 2016. In 1996,2000, the
aggregate SEPA allocation to the Members was 542 megawatts
("MW")543 MW plus associated energy, representing approximately 11% of totalenergy. Each
Member
peak demand and approximately 5% of total Member energy requirements. New
20-year contracts between each of the Members and SEPA have recently been
executed. The provisions of the new contracts are essentially the same as the
existing contracts with a few exceptions. The Members must schedule theirits energy allocation, and each Member has designated
Oglethorpe to perform this function. InPursuant to a separate agreement,
Oglethorpe will schedule, through GSOC, the Members' SEPA power deliveries.
Further, the Memberseach 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.
SEPASmarr EMC
The Members participating in the facilities owned by Smarr EMC purchase the
output of those facilities pursuant to long-term, take-or-pay power purchase
agreements. Smarr EMC owns Smarr Energy Facility, a two-unit, 217 MW gas-fired
combustion turbine facility (with 36 participating Members), and Sewell Creek
Energy Facility, a four-unit, 492 MW gas-fired combustion turbine facility (with
31 participating Members). Smarr Energy Facility began commercial operation in
June 1999, and Sewell Creek Energy Facility began commercial operation in June
2000.
Other Member Resources
Two Members formed an entity that has constructed and continues to
construct combustion turbine capacity. Oglethorpe anticipates that these two
Members will use a portion of this capacity to serve some or all of their load
growth.
15
In addition, a number of Members have installed and may continue to install
small diesel generators and gas-fired microturbines on their distribution
systems.
Future Power Resources
Oglethorpe has entered into agreements on behalf of participating Members
to acquire and construct six gas-fired combustion turbines designed to provide
618 MW of capacity and a gas-fired combined cycle facility designed to provide
468 MW of capacity. Four of the combustion turbines are targeted for completion
in 2002, with the other two to be completed in 2003. The combined cycle facility
is targeted for completion in 2003. Oglethorpe has an agreement to purchase
equipment for a possible 2005 gas-fired combined cycle project. Although
Oglethorpe plans for and procures generating resources for electing Members,
these generating resources may not necessarily be owned by Oglethorpe. For a
number of reasons, the facilities may be owned by a subsidiary of Oglethorpe, by
Smarr EMC or by a similar separate entity owned by those Members who participate
in the facilities. For information on financing for these facilities, see
"OGLETHORPE'S POWER SUPPLY RESOURCES--Future Power Resources.")
Several Members have entered into newlong-term contracts with a third party
for all of their future incremental power requirements. Other Members may do so
in the future.
16
FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY
General
The electric utility industry has been and in the future will continue to
be affected by a number of factors which could have an impact on an electric
utility such as Oglethorpe. These factors likely would affect individual
utilities in different ways. Such factors include, among others:
o the transition to increasing competition in the generation of
electricity and the corresponding increase in competition from other
suppliers of electricity,
o fluctuations in the market price for electricity,
o effects of compliance with changing environmental, licensing and
regulatory requirements,
o regulatory and other changes in national and state energy policy,
including open access transmission,
arrangements under whicho uncertain access to low cost capital for replacement of aging fixed
assets,
o increases in operating costs, including the cost of fuel for the
generation of electric energy,
o uncertain recovery of the cost of existing facilities,
o limitations on purchasing and selling energy from and to other
suppliers due to transmission constraints,
o limitations on supply of equipment and available sites for
construction of generation resources,
o fluctuations in demand, including rates of load growth and changes in
competitive market share,
o unbundling of services and corresponding corporate and functional
restructurings by electric utility companies, and
o the effects of conservation and energy management on the use of
electric energy.
These factors present an increasing challenge to companies in the electric
utility industry, including Oglethorpe would deliverand the Members' SEPA purchases. GTC, as assigneeMembers, to reduce costs, improve
the management of this
agreement, will
10
deliverresources and respond to the SEPA power under its network tariffchanging environment.
Competition
The electric utility industry in the United States is undergoing
fundamental change and contract with each Member.
The new contracts areis becoming increasingly competitive. (See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Miscellaneous--Competition" in Item 7.)
Environmental and Other Regulation
General
As is typical for electric utilities, Oglethorpe is subject to RUS approval.various
federal, state and local air and water quality requirements which, among other
things, regulate emissions of pollutants, such as particulate matter, sulfur
dioxide and nitrogen oxides into the air and discharges of other pollutants,
including heat, into waters of the United States. Oglethorpe is also subject to
federal, state and local waste disposal requirements that regulate the manner of
transportation, storage and disposal of various types of waste.
17
In general, environmental requirements are becoming increasingly stringent.
New requirements may substantially increase the cost of electric service, by
requiring changes in the design or operation of existing facilities or changes
or delays in the location, design, construction or operation of new facilities.
Failure to comply with these requirements could result in the imposition of
civil and criminal penalties as well as the complete shutdown of individual
generating units not in compliance. There is no assurance that Oglethorpe's
units will always remain subject to the regulations currently in effect or will
always be in compliance with future regulations.
Compliance with environmental standards will continue to be reflected in
Oglethorpe's capital expenditures and operating costs. Oglethorpe made
environmental-related capital expenditures of approximately $3 million in 2000,
and expects to spend $28 million in 2001 and $66 million in 2002 to achieve
compliance with current environmental requirements. (See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Financial Condition--Capital Requirements" in Item 7.) Based on the
current status of regulatory requirements, Oglethorpe does not anticipate that
these capital expenditures will have a material effect on its results of
operations or its financial condition. However, as discussed below, future
regulations could require Oglethorpe to make additional capital expenditures.
Clean Air Act
Environmental concerns of the public, the scientific community and Congress
have resulted in the enactment of legislation that has had and will continue to
have a significant impact on the electric utility industry. The amountmost significant
environmental legislation applicable to Oglethorpe is the Clean Air Act. One of
capacitythe purposes of the Clean Air Act is to improve air quality by reducing the
emissions of sulfur dioxide and energy
availablenitrogen oxides from SEPAaffected 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 not expectedtransferable 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 increaseimpose stringent reductions on all affected units. The aggregate
emissions of sulfur dioxide from all affected units are now capped at 8.9
million tons per year. Oglethorpe is now complying with this program by using
lower-sulfur fuel, coupled with the use of emission allowances (issued, banked
or purchased, if needed). Installation of flue gas desulfurization equipment
remains a possibility for compliance in the more distant future.
A number of recently finalized regulations, proposed regulations and other
actions could result in more stringent controls on all emissions, including
utility emissions. The most significant of these appear to be the following.
First, because nitrogen oxides are considered to be a precursor to ozone,
coupled with the fact that metropolitan Atlanta is classified as a "serious
nonattainment area" under the one hour ozone National Ambient Air Quality
Standards ("NAAQS"), EPA and the State of Georgia have imposed further limits on
such emissions. Recently, both Plants Wansley and Scherer were made subject to
stringent nitrogen oxides averaging plans, which will cause the co-owners of the
plants to install new control equipment at both plants no later than May 2003.
Oglethorpe expects to incur significant capital expenditures over the next three
years to install this equipment.
Second, EPA attempted to tighten the NAAQS for both ozone and particulate
matter, an amount sufficientaction that could affect any source that emits nitrogen oxides and
sulfur dioxide, including utility units. Court challenges to serveboth standards were
made. On appeal, the Supreme Court reversed a materialsuccessful challenge of these
revised NAAQS, and remanded the case back to the Court of Appeals for further
disposition. This decision may result in tightening of the standards for both
18
ozone and particulate matter. Other challenges to both NAAQS are still pending
at the Court of Appeals level. In addition, with respect to the ozone NAAQS, EPA
must harmonize provisions in the Clean Air Act imposing the old ozone NAAQS with
its proposed standard before the new standard can be implemented.
Third, in 1998, EPA issued a regulation calling for regional reductions in
nitrogen oxides emissions from 22 states, including Georgia, which imposes a
fixed cap on nitrogen oxides emissions from such states beginning in the year
2004. States remain free to choose the sources on which to impose reductions
needed to stay below the cap. The Georgia Environmental Protection Division has
indicated that if Georgia must adhere to the regulation, it will require large
fossil fuel-fired units, including those at Plants Wansley and Scherer, to
participate in achieving the required reductions. On appeal, EPA's regulation
was upheld in part, with that portion of the projected growthrule that would have applied to
Georgia sent back to EPA for further consideration. EPA recently indicated its
intention to finalize shortly a rule reinstating the cap for Georgia. As a
result, Georgia's implementation plan for this regulation will depend on this
new rulemaking. Therefore, it is not yet known what additional controls, if any,
would be needed at Plants Wansley and/or Scherer to comply with this regional
nitrogen oxides reduction program.
Fourth, EPA has promulgated a new regional haze rule, which affects any
source that emits nitrogen oxides or sulfur dioxide and that may contribute to
the degradation of visibility in mandatory federal Class I areas, including
utility units. Several industry groups have challenged the rule and some have
also petitioned EPA to reconsider the rule. Until such litigation is resolved,
Oglethorpe will not know what controls, if any, must be installed at Plants
Wansley and/or Scherer to comply with this rule.
Fifth, although EPA had decided not to impose a new NAAQS for sulfur
dioxide, that decision has been remanded to EPA for further rulemaking, so it is
still possible that a new short-term standard for sulfur dioxide could be
established.
Finally, several studies required by the Clean Air Act examined the health
effects of power plant emissions of certain hazardous air pollutants. In late
2000, EPA concluded that mercury emissions from coal and oil-fired electric
utility steam generating units should be regulated. Emissions of other hazardous
air pollutants, such as nickel and cadmium, may also become regulated. EPA
expects to follow a rulemaking schedule that would require compliance by
2007-2008. Depending on the outcome of such rulemaking, significant capital
expenditures might be incurred at Plants Wansley and/or Scherer.
On November 3, 1999, the United States Justice Department, on behalf of
EPA, filed lawsuits against GPC and some of its affiliates, as well as other
utilities. The lawsuits allege violations of the new source review provisions
and the new source performance standards of the Clean Air Act at, among other
facilities, Plant Scherer Unit Nos. 3 and 4. Oglethorpe is not currently named
in the Members' requirements.lawsuits and Oglethorpe does not have an ownership interest in the named
units of Plant Scherer. However, Oglethorpe can give no assurance that units in
which Oglethorpe has an ownership interest will not be named in this or a
related lawsuit in the future. The resolution of this matter is highly uncertain
at this time, as is any responsibility of Oglethorpe for a share of any
penalties and capital costs required to remedy any violations at facilities
co-owned by Oglethorpe.
Depending on the final outcome of these developments, and the
implementation approach selected by EPA and the State of Georgia, significant
capital expenditures and increased operation expenses could be incurred by
Oglethorpe for the continued operation of Plants Wansley and/or Scherer. The
power marketer arrangements generally do not provide for the recovery from the
power marketers of increased environmental costs. (See
"OGLETHORPE POWER Corporation--New Wholesale Power Contracts" and "MEMBER REQUIREMENTS AND
POWER SUPPLY RESOURCES--Member DemandRESOURCES--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 Energy Requirements"
andScherer.
19
Compliance with the table thereunder.)
During 1996, legislative proposals were made that would have resultedrequirements 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 privatizationcost of several of the federal power
marketing administrations,
in particular SEPA. Ultimately, no proposal for the privatization of the power
marketing administrations was passed by Congress. The President's Budget for
fiscal year 1998 does not include any proposals to privatize the federal power
marketing administrations. The ultimate outcome of this issue in Congress cannot
be predicted with certainty.
11
MEMBERpurchased from GPC. (See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES
General
Oglethorpe supplies the current capacity and energy requirements of the
Members from a combination of owned and leased generating plants and from power
purchased under long-term contracts with other power suppliers and power
marketers. Oglethorpe owns or leases 3,335.0 MW of nameplate capacity,
consisting of 1,500.6 MW of coal-fired capacity, 1,185 MW of nuclear-fueled
capacity, 632.5 MW of pumped storage hydroelectric capacity, 14.8 MW of
oil-fired combustion turbine capacity and 2.1 MW of conventional hydroelectric
capacity. (SEE "GENERATING FACILITIES--General" and "--Plant Performance" in
Item 2 for a description of Oglethorpe's generating facilities.) These resources
are generally scheduled and dispatched so as to minimize the operating cost of
Oglethorpe's system. However, Oglethorpe has entered into long-term arrangements
with power marketers to better utilize its resources to reduce the cost of
capacity and energy delivered to the Members, in part by giving certain dispatch
rights to the power marketers. (See "Power Purchase and Sale Arrangements--Power
Marketer Arrangements" herein.)
Member Demand and Energy Requirements
The following table shows the aggregate peak demand and energy
requirements of the Members for the years 1994 through 1996 and also shows the
amounts of such requirements supplied by Oglethorpe and SEPA. For the years 1994
through 1996, demand and energy requirements increased at an average annual
compound growth rate of 13.2% and 9.7%, respectively.
Demand (MW) Energy Requirements (MWh)
--------------------------------------- --------------------------------------------
Total Total
Require- Supplied by Supplied by Require- Supplied by Supplied by
ments(1) Oglethorpe(2) SEPA(3) ments Oglethorpe(2) SEPA(3)
-------- ------------- ------- ----- ------------- -------
1994 3,938 3,396 542 17,278,812 16,285,127 993,685
1995 4,850 4,308 542 19,403,703 18,442,153 961,550
1996 5,045 4,503 542 20,793,864 19,807,101 986,763
- ----------
(1) System peak demand of the Members measured at the Members' delivery points
(net of system losses). The significant increase in peak demand in 1995
was due in large part to a milder than normal summer in 1994.
(2) Includes purchased power. (See "PowerRESOURCES--Power
Purchase and Sale Arrangements--Power Purchases from GPC" and "--Other Power Purchases"
herein.GPC.")
(3) Supplied by SEPA through existing contracts with the Members. (See "THE
MEMBERS OF OGLETHORPE--Contracts with SEPA".)
In 1996, Cobb EMC and Jackson EMC accounted for approximately 12.5% and
11.2% of Oglethorpe's total revenues, respectively.
Seasonal Variations
The demand for energy by the Members is influenced by seasonal weather
conditions. Historically, Oglethorpe's peak demand occurs during the months of
June through September. (See "OGLETHORPE POWER Corporation--Electric Rates".)
Energy revenues track energy costs as they are incurred and also fluctuate month
to month. Capacity revenues reflect the recovery of Oglethorpe's fixed costs
which do not vary significantly from month to month; therefore, the capacity
revenues are billed and recognized in equal monthly amounts.
12
Demand ManagementNuclear Regulation
Oglethorpe and the Members have implemented various demand management
programs. The program goal, developed in conjunction with Oglethorpe's
integrated resource planning process, has been to modify demand patterns so that
current resources are used efficiently and the need for additional generating
resources is delayed. The programs that have been implemented include an energy
efficient home program (the "Good Cents Home" program), remote-controlled
switching of air conditioners, water heaters and irrigation pumps, residential
energy audits and public appeals to encourage consumers to use less energy
during periods of peak demand. The demand management programs have reduced the
growth of peak demand and have also resulted in an increase in off-peak sales.
(See "Power Purchase and Sale Arrangements--Other Power Purchases" herein.)
Power Purchase and Sale Arrangements
Power Marketer Arrangements
As a means of reducing the cost of power provided to the Members,
Oglethorpe utilized short-term power marketer arrangements during 1996 with two
different power marketers. Under both of the arrangements, the power marketer
was required to provide to Oglethorpe at a favorable fixed rate all of the
energy needed to meet the Members' requirements, and Oglethorpe was required to
provide upon request to the power marketers at cost (subject to certain
limitations) all energy available from Oglethorpe's total power resources. Under
these arrangements, Oglethorpe continued to operate the power supply system and
continued to dispatch the generating resources to ensure system reliability.
Oglethorpe is now utilizing power marketer arrangements on a long-term
basis to reduce the cost of power. It has entered into power marketer agreements
with LPM for 50% of the load requirements of the Members, and is working to
finalize an agreement with Morgan Stanley Capital Group ("Morgan Stanley") for
the remaining 50% of the Members' load requirements.
Effective January 1, 1997, Oglethorpe entered into power marketer
agreements with LPM for 50% of the load requirements of the Members. Under the
agreements, LPM is obligated to deliver, and Oglethorpe is obligated to take,
50% of the load requirements of the participating Members less the load
requirements for certain customer choice loads (900 kilowatt or greater), plus
50% of the delivery obligations under Oglethorpe's existing firm power
off-system sale contracts. For customer choice loads of three megawatts or less,
LPM is obligated to deliver, if Oglethorpe requests, 50% of the associated load
requirements. Oglethorpe has the option of purchasing the energy requirements
for customer choice loads from another supplier. Oglethorpe is obligated to sell
and LPM is obligated to buy 50% of the output of each participating Member's PCR
share of the "must run" units (primarily nuclear units). Oglethorpe is also
obligated to make available the same share of all other resources, which LPM may
schedule. LPM does not have the right to the output of upgrades to these
resources. LPM must pay Oglethorpe the cost of fuel associated with the energy
taken. There is a price adjustment if the plant performance does not meet
specified levels of availability and output. Oglethorpe must pay LPM a
contractually specified price for each MWh purchased.
Oglethorpe has contracted with GTC to provide available transmission
services to deliver to the border of the ITS any energy sold to LPM. Each Member
will use its Transmission Agreement for delivery of energy purchased from LPM
and others.
Effective with the Corporate Restructuring and the execution of
supplemental agreements to the New Wholesale Power Contracts, the LPM agreement
relating to 37 of the 39 Members has a term extending to 2011. With one years'
notice, Oglethorpe has the right to terminate the LPM agreement for any year
beginning with 2002. With one years' notice, LPM has the right to terminate the
LPM agreement for any year beginning with 2005. The LPM agreement relating to
the other two Members has a term extending through the end of 1999. The
13
supplemental agreements are the vehicle through which Oglethorpe and the Members
assure that the Members receive the benefits of and support the obligations for
the new power marketer arrangements under the New Wholesale Power Contracts.
LPM is an indirect wholly owned subsidiary of LG&E Energy Corp., a
Kentucky corporation, which is a diversified energy services holding company.
LG&E Energy Corp. is subject to the informational requirementsprovisions of the Securities
ExchangeAtomic Energy Act of 1934,1954,
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 accordance therewith, files reportsthe design, operation and other informationmaintenance of
existing nuclear reactors. Operating licenses issued by the NRC are subject to
revocation, suspension or modification, and the operation of a nuclear unit may
be suspended if the NRC determines that the public interest, health or safety so
requires. The operating licenses issued for each unit of Plants Hatch and Vogtle
expire in 2014 and 2018 and 2027 and 2029, respectively.
On February 29, 2000, Southern Nuclear Operating Company ("SONOPCO"), the
operator of Plant Hatch, filed an application with the SecuritiesNRC to extend the
operating licenses for each unit of Plant Hatch, until 2034 and Exchange Commission (the
"Commission"). Copies2038,
respectively. The NRC has published a timetable that indicates a decision will
be made by the end of this material can be obtainedMarch 2002.
Pursuant to the Nuclear Waste Policy Act of 1982, as amended, the Federal
government has the regulatory responsibility for the final disposition of
commercially produced high-level radioactive waste materials, including spent
nuclear fuel. This Act requires the owner of nuclear facilities to enter into
disposal contracts with the Department of Energy ("DOE") for such material.
These contracts require each such owner to pay a fee, which is currently one
dollar per MWh for the net electricity generated and sold by each of its
reactors.
Contracts with DOE have been executed to provide for the permanent disposal
of spent nuclear fuel produced at prescribed rates fromPlants Hatch and Vogtle. DOE failed to begin
disposing of spent fuel in 1998 as required by the Commission's Public Reference Section at 450 Fifth Street, N.W., Room 1024,
Washington, D.C. 20549. Certain securities of LG&E Energy Corp. are listed oncontracts, and GPC, as agent
for the New York Stock Exchange, and reports and other information concerning LG&E
Energy Corp. can be inspected at the office of such Exchange.
Oglethorpe is now working to finalize power marketer arrangements with
Morgan Stanley that would supply the remaining 50%co-owners of the Members' load
requirements. The agreementplants, is pursuing legal remedies against DOE for
breach of contract.
Plants Hatch and Vogtle currently have on-site spent fuel storage capacity.
Effective June 2000, an on-site dry storage facility for Plant Hatch became
operational. Based on normal operations and retention of all spent fuel in the
reactor, sufficient capacity is believed to be available to continue dry storage
operations at Plant Hatch for the life of the plant, and Plant Vogtle spent fuel
storage is expected to allow each Member to have Oglethorpe
elect a term from three to eight years. Each Member is currently deciding
whether to have Oglethorpe obtain its remaining load requirements from Morgan
Stanley. The proposed agreement would obligate Oglethorpe to purchase fixed
quantities of energy, averaging 50%be sufficient into 2014. In addition, SONOPCO, as agent
for the co-owners of the Members' forecasted requirements
during the termplant, is a member of the agreement. Initially, Oglethorpe would manage the system
through purchases or salesPrivate Fuel Storage, LLC, a
joint utility effort to balance this fixed requirement against the actual
requirements. Oglethorpe would have considerably more discretion in the
managementdevelop a private spent fuel storage facility for
temporary storage of the power supply system under the proposed Morgan Stanley contract
than under the LPM contract. In orderspent nuclear fuel. This facility is planned to complete the implementation of the
Morgan Stanley power marketer arrangements, Oglethorpe and each participating
Member will enter into supplemental agreements to the New Wholesale Power
Contract to conform the provisions of the New Wholesale Power Contracts to the
terms of the power marketing arrangements. Any Member that elects not to
participate in the Morgan Stanley agreement would have other options available,
including having Oglethorpe manage this portion of the Member's load
requirements and, beginningbegin
operation as early as January 1, 1998, contract with other
power marketers.
In the interim, Oglethorpe is supplying this portion of the Members'
requirements from its own resources and by off-system purchase and sales. In the
event Oglethorpe does not enter into power marketer agreements for the remainder
of its load, it can continue to operate effectively in this manner
Oglethorpe will continue to plan for each Member's requirements beyond
the term of the respective power marketer agreements, including decisions
regarding early termination.
Power Purchases from GPC
Oglethorpe currently purchases 1,000 MW of capacity and associated
energy from GPC on a take-or-pay basis under the Block Power Sale Agreement
("BPSA"), which extends through December 31,year 2003. The capacity purchases under
the BPSA are from five Component Blocks (as defined in the BPSA), composed of
three Component Blocks of 250 MW each (coal-fired units) and two Component
Blocks of 125 MW each (combustion turbine units). The capacity in one or more
Component Blocks may, however, be less than the MW stated above, as the result
of scheduled retirement of units or retirements due to force majeure events. All
units in the combustion turbine Component Blocks are scheduled to be retired by
2003. Although Oglethorpe may not increase its capacity purchases under the
BPSA, it may reduce or extend its purchases of one or more Component Blocks upon
proper notice to GPC. Oglethorpe has given notice of its intent to reduce its
purchases by two 250 MW Component Blocks (coal-fired units) effective September
1, 1997 and September 1, 1998. Also, pursuant to its long-term power marketer
agreements with LPM, Oglethorpe has committed to continue reducing its purchases
from GPC as permitted under the BPSA and thus will no longer purchase any energy
under the BPSA effective September 1, 2001. (See "Power Marketer Arrangements"
herein for a discussion of the LPM agreement.)
14
Other Power Purchases
Oglethorpe purchases 100 MW of capacity from each of Entergy Power,
Inc. ("EPI") and Big Rivers Electric Corporation ("Big Rivers"), under
agreements extending through June and July 2002, respectively. The availability
of capacity under the EPI contract is dependent on the availability of two
specific generating units available to EPI. The Tennessee Valley Authority
("TVA") provides the transmission service to deliver the power from the Big
Rivers electric system to the ITS. TVA and Southern Company Services, as agent
for Alabama Power Company and Mississippi Power Company, provide the
transmission service necessary to deliver the power from EPI to the ITS. (See Note 91 of Notes to Financial
Statements in Item 8.)
For information concerning nuclear insurance, see Note 8 of Notes to
Financial Statements in Item 8. For information regarding NRC's regulation
relating to decommissioning of nuclear facilities and regarding DOE's
assessments pursuant to the Energy Policy Act for decontamination and
decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to
Financial Statements in Item 8.
20
Other Environmental Regulation
In 1993, EPA issued a ruling confirming the non-hazardous status of coal
ash. That ruling may apply, however, only to situations where those wastes are
not co-managed, i.e., not mixed with other wastes. Pursuant to court order, EPA
had until the Spring of 1999 to classify co-managed utility wastes as either
hazardous or non-hazardous. Recently, EPA decided that although these wastes
should be considered non-hazardous, national regulations were warranted.
Depending on the outcome of such rulemaking, substantial additional costs for
the management of these wastes might be required of Oglethorpe, also hasalthough the
full impact would depend on the subsequent development of such rules.
Oglethorpe is subject to other environmental statutes including, but not
limited to, the Clean Water Act, the Georgia Water Quality Control Act, the
Georgia Hazardous Site Response Act, the Toxic Substances Control Act, the
Resource Conservation & Recovery Act, the Endangered Species Act, the
Comprehensive Environmental Response, Compensation and Liability Act, the
Emergency Planning and Community Right to Know Act, and to the regulations
implementing these statutes. Oglethorpe does not believe that compliance with
these statutes and regulations will have a contract through 2019material impact on its financial
condition or results of operations. Changes to purchase approximately
300 MWany of capacitythese laws, some of which
are being reviewed by Congress, could affect many areas of Oglethorpe's
operations. Although compliance with Hartwell Energy Limited Partnership ("Hartwell"),new environmental legislation could have a
partnership owned 50% by Destec Energy, Inc.significant impact on Oglethorpe, those impacts cannot be fully determined at
this time and 50% by American National Power,
Inc., a subsidiarywould depend in part on the final legislation and the development
of National Power, PLC.implementing regulations.
The scientific community, regulatory agencies and the electric utility
industry are continuing to examine the issues of global warming and the possible
health effects of electromagnetic fields. While no definitive scientific
conclusions have been reached, it is possible that new laws or regulations
pertaining to these matters could increase the capital and operating costs of
electric utilities, including Oglethorpe intends to use the units
for peaking capacity but has the right to dispatch the units fully.or entities from which Oglethorpe
purchases power. In addition, to the purchasespotential for liability exists from GPC, Big Rivers and EPI, Oglethorpe
also purchases small amounts of capacity and energylawsuits
that might be brought alleging damages from "qualifying facilities"
under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). Under a
waiver order from FERC, Oglethorpe has 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 has historically
provided the Members with the necessary services to fulfill these sale
obligations. Purchases by Oglethorpe from such qualifying facilities provided
0.2% of Oglethorpe's energy requirements for the Members in 1996. As a result of
the Corporate Restructuring, the Member may make such purchases in the future.
Oglethorpe has contracted with Florida Power Corporation to purchase 50
MW of peaking capacity during the summer of 1997 and 275 MW of peaking capacity
during the summer of 1998.
Under the New Wholesale Power Contracts, Oglethorpe will provide joint
planning services for all participating Members. A Member may elect not to have
Oglethorpe provide joint planning, procurement or bulk power marketing. Although
the long-term power marketer arrangements may provide substantially all of the
Members' requirements for the contract term, Oglethorpe will continue to supply
these planning services for requirements beyond the contract term as well as for
evaluation of contract options.
Long-Term Power Sales
Oglethorpe has an agreement to sell 100 MW of base capacity to Alabama
Electric Cooperative beginning June 1, 1998, and extending through December 31,
2005.
Other Power System Arrangements
Oglethorpe has interchange, transmission and/or short-term capacity and
energy purchase or sale agreements with over 20 utilities and other power
suppliers. The agreements provide variously for the purchase and/or sale of
capacity and energy and/or for the purchase of transmission service. The
development of and access to a statewide transmission network and the
interconnections with other utilities are key elements in Oglethorpe's ability
to make off-system sales and purchases through its contract with GTC and to
compete in an increasingly competitive market.
15electromagnetic fields.
21
OTHER INFORMATION
Information with respect to fuel supply for Oglethorpe's plants is set
forth under the caption "GENERATING FACILITIES--Fuel Supply" included in Item 2
and is incorporated herein by reference. Information with respect to
environmental and other regulations affecting Oglethorpe and its plants is set
forth under the caption "ENVIRONMENTAL AND OTHER REGULATIONS" included in Item 2
and is incorporated herein by reference.
16
ItemITEM 2. PROPERTIES
GENERATING FACILITIES
GeneralGenerating Facilities
The following table sets forth certain information with respect to the
generating facilities in which Oglethorpe currently has ownership or leasehold
interests, all of which are in commercial operation.
The Edwin I. Hatch Plant
("Plant Hatch"), the Hal B. Wansley Plant ("Plant Wansley"), the Alvin W. Vogtle
Plant ("Plant Vogtle") and the Robert W. Scherer Units No. 1 and No. 2 ("Scherer
Units No. 1 and No. 2") are co-owned by Oglethorpe, GPC, MEAG and Dalton. GPC is
the operating agent for each of these co-owned plants. Rocky Mountain is
co-owned by Oglethorpe and GPC, and Oglethorpe is the operating agent.
Oglethorpe is the sole owner of the Tallassee Project at the Walter W. Harrison
Dam ("Tallassee"). (See "CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--The
Plant Agreements".)
Oglethorpe's
Share of
Name-NamePlate Commercial License
Type of Percentage Plate Capacity Operation Expiration
Type ofFacilities Fuel Interest(1)Interest (MW) Date Date
------------ ----------- ---- ---- ----
FACILITIES IN SERVICE:- ----------------------------------------------------------------------------------------------------------------
Plant Hatch (near Baxley)Baxley, Ga.)
Unit No. 11........................ Nuclear 30 243.0 1975 20142014(1)
Unit No. 22........................ Nuclear 30 246.0 1979 20182018(1)
Plant Vogtle (near Waynesboro)Waynesboro, Ga.)
Unit No. 11........................ Nuclear 30 348.0 1987 2027
Unit No. 22........................ Nuclear 30 348.0 1989 2029
Plant Wansley (near Carrollton)Carrollton, Ga.)
Unit No. 11........................ Coal 30 259.5 1976 N/A(2)
Unit No. 22........................ Coal 30 259.5 1978 N/A(2)
Combustion TurbineTurbine................ Oil 30 14.8 1980 N/A(2)
Plant Scherer (near Forsyth)Forsyth, Ga.)
Unit No. 11........................ Coal 60 490.8 1982 N/A(2)
Unit No. 22........................ Coal 60 490.8 1984 N/A(2)
Tallassee (near Athens)Athens, Ga.)......... Hydro 100 2.1 1986 2023
Rocky Mountain (near Rome, Ga.)...... Pumped
Storage
(near Rome)
Hydro 74.61 632.5 1995 2027
-----------------
Total Ownership 3,335.0
================
- --------------------------
(1) Southern Nuclear Operating Company, the operator of Plant Hatch, has filed
an application with the NRC to extend the licenses with respect to Plant
Hatch by 20 years. (See "FACTORS AFFECTING THE ELECTRIC UTILITY
INDUSTRY--Environmental and Other Regulation--Nuclear Regulation" in Item
1.)
(2) Coal-fired units and combustion turbines do not operate under operating
licenses similar to those granted to nuclear units by the NRC and to
hydroelectric plants by FERC.
- ----------
(1) Oglethorpe has an ownership interest in all of the facilities except
Scherer Unit No. 2. The 60% interest in Scherer Unit No. 2 is leased under
leases that expire in 2013, subject to options to renew for a total of 8.5
years.
(2) Coal-fired units and combustion turbines do not operate under operating
licenses similar to those granted to nuclear units by the Nuclear
Regulatory Commission and to hydroelectric plants by FERC.
1722
Plant Performance
The following table sets forth certain operating performance information of
each of the major generating facilities in which Oglethorpe currently has
ownership or leasehold interests:
Equivalent Availability (1)Availability(1) Capacity Factor (2)
------------------------------ -------------------------Factor(2)
--------------------------- --------------------------
Unit 1996 1995 1994 1996 1995 1994
-2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ---- ----
Plant Hatch
Unit No. 1................... 83% 98%1........... 84% 83%81% 100% 85% 83% 99%
Unit No. 2................... 97 75 78 99 75 792........... 89 92 81 90 94 81
Plant Vogtle
Unit No. 1................... 80 981........... 86 80 98 8692 100 91 94 102
Unit No. 2...................2........... 100 88 82 102 89 91 89 90 9182
Plant Wansley
Unit No. 1................... 88 90 92 581........... 83 91 86 77 73 56 62
Unit No. 2................... 91 89 88 62 56 582........... 78 86 92 72 66 50
Plant Scherer
Unit No. 1................... 92 95 97 74 73 641........... 100 86 93 79 67 70
Unit No. 2................... 842........... 90 95 89 73 79 75
Rocky Mountain(3)
Unit No. 1........... 94 97 85 72 85 6090 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 (3)
Unit No. 1................... 94 83 N/A 15 16 N/A
Unit No. 2................... 95 92 N/A 13 15 N/A
Unit No. 3................... 95 92 N/A 10 16 N/Aprimarily operates as a peaking
plant, which results in a low capacity factor.
- ---------------------
(1) Equivalent Availability is a measure of the percentage of time that a unit
was available to generate if called upon, adjusted for periods when the
unit is partially derated from the "maximum dependable capacity" rating.
(2) Capacity Factor is a measure of the output of a unit as a percentage of
the maximum output, based on the "maximum dependable capacity" rating,
over the period of measure.
(3) Rocky Mountain Commercial Operation Dates: Unit 1 - July 24, 1995; Unit 2
- June 19, 1995; Unit 3 - June 1, 1995. This information was calculated
beginning from the commercial operation date for each unit. As a pumped
storage plant, Rocky Mountain primarily operates in peaking service.
The nuclear refueling cycle for Plants Hatch and Vogtle exceeds twelve
months. Therefore, in some calendar years the units at these plants are not
taken out of service for refueling, resulting in higher levels of equivalent
availability and capacity factor.
Fuel Supply
Coal. Coal for Plant Wansley is currently purchased under long-term
contracts which are
estimated to be sufficient to provide the majority of the coal requirements of
Plant Wansley through 1997, with the remainder being provided throughand in spot market transactions. As of February 28, 1997,2001, there was a
38-day26-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,
1997,2001, the coal stockpile at Plant Scherer contained a 37-day
18
50-day supply based on
nameplate rating. During 1994, Plant Scherer was converted to
burnburns both sub-bituminous and bituminous coals,
and a separate stockpile of sub-bituminous coal was builtis maintained in addition to the
stockpile of bituminous coal. Oglethorpe leases over 700 rail cars to transport
coal to Plants Scherer and Wansley.
The Plant Scherer and Wansley ownership and operating agreements were
amended in 1993 and 1996, respectively, to allow each
co-owner (i) to dispatch separately its respective ownership interest in
conjunction with contracting separately for long-term coal purchases procured by
GPC and (ii) to procure separately long-term coal purchases. Pursuant to the amendments, Oglethorpe
implemented separate dispatch ofseparately dispatches Plant Scherer in 1994. Oglethorpe expects to
implement separate dispatch atand Plant Wansley, by early to mid-summer 1997.
Oglethorpebut continues to use GPC
as its agent for fuel procurement.
To take advantage of these changes at Plants Scherer and Wansley,
Oglethorpe formed a wholly owned subsidiary to acquire rail cars designed for
hauling coal from the western coal mining regions. The subsidiary, Black Diamond
Energy, Inc., has purchased or leased 299 rail cars. Oglethorpe has entered into
an initial 15-year lease with the subsidiary which obligates Oglethorpe to pay
all of the ownership and operating expenses of the subsidiary relating to the
rail cars during the lease term.23
For information relating to the impact that the Clean Air Act will have on
Oglethorpe, see "ENVIRONMENTAL AND OTHER REGULATIONS--Clean"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 provide nuclear services,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.
Plants Hatch and Vogtle currently have on-site spent fuel storage
capacity. Based on normal operations and retention of all spent fuel in the
reactor, it is anticipated that existing on-site pool capacity would not be
sufficient in 2003 and 2008, respectively, to accept the number of spent fuel
assemblies that would normally be removed from the reactor during a refueling.
Contracts with the Department of Energy ("DOE") have been executed to provide
for the permanent disposal of spent nuclear fuel produced at Plants Hatch and
Vogtle. The services to be provided by DOE are scheduled to begin in 1998;
however, the DOE has stated that permanent nuclear waste storage facilities will
not be available by that date, and it is uncertain when they will be available.
If DOE does not begin receiving the spent fuel from Plant Hatch in 2003 or from
Plant Vogtle in 2008, alternative methods of spent fuel storage will be needed.
Activities for adding dry cast storage capacity at Plant Hatch by as early as
1999 are in progress. (See "ENVIRONMENTAL AND OTHER REGULATIONS--Nuclear
Regulation" for a discussion of the Nuclear Waste Policy Act and Note 1 of Notes
to Financial Statements in Item 8 regarding nuclear fuel cost.)
19
CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS
Co-ownersCo-Owners of the Plants
Plants Hatch, Vogtle, Wansley and Scherer Units No. 1 and No. 2 are
co-owned by Oglethorpe, GPC, MEAG and Dalton, and Rocky Mountain is co-owned by
Oglethorpe and GPC. Each such co-owner owns and Oglethorpe owns or leases undivided interests in the
amounts shown in the following table (which excludes the Plant Wansley
combustion turbine). Oglethorpe is the operating agent for Rocky Mountain. GPC
is the operating agent for each of these plants, except for Rocky Mountain for which Oglethorpe is the operating
agent. (See "The Plant Agreements" herein.)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.Oglethorpe... 30.0 489 30.0 696 30.0 519 60.0(2)60.0 982 74.61 633 3,319
GPC........GPC.......... 50.1 817 45.7 1,060 53.5 926 8.4 137 25.39 215 3,155
MEAG.......MEAG......... 17.7 288 22.7 527 15.1 261 30.2 494 -- -- 1,570
Dalton.....Dalton 2.2 36 1.6 37 1.4 24 1.4 23 -- -- 120
--------------------- ------- ------- ------- ------- ---------- ---- ---- ---- ----- ---- ------ ----- ------ ------
Total......---- ----
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.
- ----------
(1) Based on nameplate ratings.
(2) Oglethorpe leases its interest in Scherer Unit No. 2 pursuant to long-term
net leases.
Georgia Power Company
GPC is a wholly owned subsidiary of The Southern Company, a registered
holding company under the Public Utility Holding Company Act, and is engaged
primarily in the generation and purchase of electric energy and the
transmission, distribution and sale of such energy. 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 threetwo 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.
Copies of this material can be
obtained at prescribed rates from the Commission's Public Reference Section at
450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549. Certain securities of
GPC are listed on the New York Stock Exchange, and reports and other information
concerning GPC can be inspected at the office of such Exchange.
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, (who also markets under the name ofknown as MEAG Power)Power, has entered
into power sales contracts with each of 4847 cities and one county in the State of
Georgia. Such political subdivisions, located in 39 of the State's 159 counties,
collectively serve approximately 270,000283,000 electric customers.
20consumers (meters).
24
City of Dalton, Georgia
The City of Dalton, located in northwest Georgia, supplies electric
capacity and energy to consumers in Dalton, and presently serves more than
10,000 residential, commercial and industrial customers.
The Plant Agreements
Hatch, Wansley, Vogtle and Scherer
Oglethorpe's rights and obligations with respect to Plants Hatch, Wansley,
Vogtle and Scherer are contained in a number of contracts between Oglethorpe and
GPC and, in some instances, MEAG and Dalton. Oglethorpe is a party to four
Purchase and Ownership Participation Agreements ("Ownership Agreements") under
which it acquired from GPC a 30% undivided interest in each of Plants Hatch,
Wansley and Vogtle, a 60% undivided interest in Scherer Units No. 1 and No. 2
and a 30% undivided interest in those facilities at Plant Scherer intended to be
used in common by Scherer Units No. 1, No. 2, No. 3 and No. 4 (the "Scherer
Common Facilities"). Oglethorpe has also entered into four Operating Agreements
("Operating Agreements") relating to the operation and maintenance of Plants
Hatch, Wansley, Vogtle and Scherer, respectively. The OperatingOwnership Agreements and
OwnershipOperating Agreements relating to Plants Hatch and Wansley are two-party
agreements between Oglethorpe and GPC. The otherOwnership Agreements and Operating
Agreements relating to Plants Vogtle and Ownership AgreementsScherer are agreements among
Oglethorpe, GPC, MEAG and Dalton. The parties to each Ownership Agreement and
each Operating Agreement are referred to as "Participants""participants" with respect to each such
agreement.
In 1985, in four separate 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.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 Participantparticipant under
the Ownership and Operating Agreements relating to Scherer Unit No. 2 for the
term of the leases. Oglethorpe's leases expire in 2013, with options to renew
for a total of 8.5 years. (In the following discussion, references to
Participantsparticipants "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 subject to, in the case offor Scherer Units No. 1 and No. 2 subject to certain
limited rights of the Participantsparticipants to disapprove capital budgets proposed by GPC
and to substitute alternative capital budgets and in the case ofbudgets. 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.
Each Operating Agreement gives GPC, as agent, sole authority and
responsibility for the management, control, maintenance, operation, scheduling
and dispatching of the plant to which it relates. However, as provided in the
amendments to the Plant Scherer Ownership and Operating Agreements, Oglethorpe
is separately dispatching its ownership share of Scherer Units No. 1 and No. 2.
Similar amendments to the Plant Wansley Operating Agreement have recently been
entered into and Oglethorpe expects to begin dispatching separately its
ownership share in Plant Wansley in 1997. (See "GENERATING FACILITIES--Fuel
Supply".) In 1990,1993, the co-owners of Plants Hatch and Vogtle entered into the Nuclear Managing Board Agreement which amended the Plant Hatch and Plant Vogtle
Ownership and Operating agreements, primarily with respect to GPC's reporting
requirements, but did not alter GPC's role as agent with respect to the nuclear
plants. In 1993, the co-owners entered into the Amended
and Restated Nuclear Managing Board Agreement, (the "Amended and Restated NMBA") which provides for a managing
board (the "Nuclear Managing Board") to coordinate the implementation and administration of the Plant Hatch and
Plant Vogtle Ownership and Operating Agreements, and provides for increased rights
for the co-owners regarding certain decisions and allowedallows GPC to contract with a
2125
third party for the operation of the nuclear units. In March 1997, GPC
designated SONOPCO as the operator of Plants Hatch and Vogtle, pursuant to the
Nuclear Operating Agreement between GPC and SONOPCO, which the co-owners had
previously approved. In connection with the
recent amendments to the Plant Scherer
Ownership and Operating Agreements, the co-owners of Plant Scherer entered into
the Plant Scherer Managing Board Agreement which provides for a managing board (the "Plant Scherer Managing
Board")
to coordinate the implementation and administration of the Plant Scherer
Ownership and Operating Agreements and provides for increased rights for the
co-owners regarding certain decisions, but does not alter GPC's role as agent
with respect to Plant Scherer.
The Operating Agreements provide that Oglethorpe is entitled to a
percentage of the net capacity and net energy output of each plant or unit equal
to its percentage undivided interest owned or leased in such plant or unit,
subject to its obligation to sell capacity and energy tounit. GPC,
as described below.
Except as otherwise provided,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 partyparticipant 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, once Oglethorpe begins separate dispatch there, each party will beis responsible for its fuel costs and for
variable Operating Costs in proportion to the net energy output for its
ownership interest, while responsibilityand is responsible for a percentage of fixed Operating Costs will continue to be
equal to the percentage of its undivided ownership 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 subject
to, inplans. In the case of Scherer Units No. 1 and
No. 2, certainthe participants have limited rights of the
Participants to disapprove such budgets proposed
by GPC and to substitute alternative budgets. The Ownership Agreements and
Operating Agreements provide that, should a Participantparticipant fail to make any payment
when due, among other things, such nonpaying Participant'sparticipant's rights to output of
capacity and energy would be suspended.
The Operating Agreement for Plant Hatch will remain in effect with respect
to Hatch Units No. 1 and No. 2 until 2009 and 2012, respectively. Oglethorpe
anticipates that the Operating Agreement will be extended if the operating
license for Plant Hatch is extended. (See "FACTORS AFFECTING THE ELECTRIC
UTILITY Industry--Environmental and Other Regulation--Nuclear Regulation.") The
Operating Agreement for Plant Vogtle will remain in effect with respect to each
unit at Plant Vogtle until 2018. The Operating Agreement for Plant Wansley will
remain in effect with respect to Wansley Units No. 1 and No. 2 until 2016 and
2018, respectively. The Operating Agreement for Scherer Units No. 1 and No. 2
will remain in effect with respect to Scherer Units No. 1 and No. 2 until 2022
and 2024, respectively. Upon termination of each Operating Agreement, following
any extension agreed to by the parties, GPC will retain such powers as are
necessary in connection with the disposition of the property of the applicable
plant, and the rights and obligations of the parties shall continue with respect
to actions and expenses taken or incurred in connection with such disposition.
Proposed Changes to Nuclear Plant Operating Arrangements
In September 1992, GPC filed applications with the Nuclear Regulatory
Commission (the "NRC") to add SONOPCO to the operating license of each unit of
Plants Hatch and Vogtle and designate SONOPCO as the operator. The application
has been recently approved by the Atomic Safety and Licensing Board and became
effective in late March. SONOPCO, a subsidiary of The Southern Company
specializing in nuclear services, currently provides certain operating,
maintenance, and other services to GPC in accordance with the Amended and
Restated NMBA and the agreements referenced in the Amended and Restated NMBA.
The co-owners had previously agreed to a Nuclear Operating Agreement between GPC
and SONOPCO, which became operative on the effective date of the license
amendment.
Rocky Mountain
Oglethorpe's rights and obligations with respect toOglethorpe owns a 74.61% undivided interest in Rocky Mountain are
contained in several contracts between Oglethorpe and GPC owns
the co-owners of
Rocky Mountain. Pursuant toremaining 25.39% undivided interest.
The Rocky Mountain Pumped Storage Hydroelectric Ownership Participation
Agreement, by and between Oglethorpe and GPC (the "Ownership Participation Agreement"), Oglethorpe initially acquired a 3%
undivided interest in Rocky Mountain which interest increased as Oglethorpe
expended funds to complete construction of Rocky Mountain. The final ownership
percentages for Rocky Mountain are Oglethorpe 74.61% and GPC 25.39%. In
connection with this
22
acquisition, Oglethorpe and GPC also entered into the Rocky Mountain Pumped
Storage Hydroelectric Project Operating Agreement (the "Rocky Mountain OperatingOwnership
Agreement").
The Ownership Participation Agreement appoints Oglethorpe as agent with sole authority and responsibility
for, among other things, the planning, licensing, design, construction,
operation, maintenance and disposal of Rocky Mountain. The Rocky Mountain Pumped
Storage Hydroelectric Project Operating Agreement (the "Rocky Mountain Operating
Agreement") gives Oglethorpe, as agent, sole authority and responsibility for
the management, control, maintenance and operation of Rocky Mountain.
26
In general, each co-owner is responsible for payment of its respective
ownership share of all Operating Costs and Pumping Energy Costs (as defined in
the Rocky Mountain Operating Agreement) as well as costs incurred as the result
of any separate schedule or independent dispatch. A co-owner's share of net
available capacity and net energy is the same as its respective ownership
interest under the Rocky Mountain Ownership Participation Agreement. Oglethorpe and GPC have
each elected to schedule separately their respective ownership interests. The
Rocky Mountain Operating Agreement will terminate in 2035. Oglethorpe completed, in two separate closings on December 31,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 January 3,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 a termthe useful
life of 71 years,the facility, who in turn leased it back to Oglethorpe for a term of 30
years. The transactions are
characterized as a sale and lease-back for income tax purposes, but not for
financial reporting purposes. Oglethorpe will continue to control and operate the plantRocky Mountain during the
lease-back term, and it fullyleaseback term. Oglethorpe intends to repurchase tax
ownership andexercise its fixed price purchase option
at the end of the leaseback period so as to retain all other rights of ownership
with respect to the plant if it is advantageous for Oglethorpe to exercise such
option.
27
ITEM 3. LEGAL PROCEEDINGS
On June 17, 1997, PECO Energy Company-Power Team ("PECO") filed an
application with FERC pursuant to Section 211 of the Federal Power Act
requesting FERC to compel Oglethorpe and/or GTC to provide PECO with 250 MW of
firm point-to-point transmission service from the TVA-Integrated Transmission
System ("TVA-ITS") interface to the Florida-Integrated Transmission System
interface for an initial three-year period, with an automatic roll-over
provision. PECO also seeks $10,000 per day in penalties from Oglethorpe and/or
GTC, alleging bad faith and delays in negotiations. In their response to FERC,
GTC and Oglethorpe contend that they negotiated with PECO in good faith, and
thus there is no reasonable basis for imposing the penalties sought by PECO. GTC
also responded that it does not have firm "available transfer capability" at the
endTVA-ITS interface to fulfill PECO's request, after taking into account the need
to protect system reliability, existing firm commitments, and use of the lease-back period.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 resultconsequence of these transactions,any such order, power
purchased by Oglethorpe received net proceeds of approximately $96 million which is being
recorded as a deferred creditfor delivery through the TVA-ITS interface would
probably be curtailed (based on past operational experience at that interface),
and will be recognized in income over the term of
the lease-back. Approximately $91 million of the proceeds will be used for the
early retirement of FFB debt, with the remaining $5 million being used to pay
alternative minimum taxes on the transactions. The combination of the debt
prepayment and the amortized gain willcould result in an estimated $11 million in
annual savings. In connection with these transactions, Oglethorpehigher purchased power cost than would otherwise be the
case. Although FERC transmission pricing policy is obligateddesigned to maintain liquidity from various sources of approximately $50 million.
23
ENVIRONMENTAL AND OTHER REGULATIONS
General
Asensure that a
transmission provider is typical in the utility industry, Oglethorpe is subject to
Federal, State and local air and water quality requirements which, among other
things, regulate emissions of pollutants, such as particulate matter ("PM"),
sulfur oxides and nitrogen oxides ("NOx") 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 which regulate
the manner of transportation, storage and disposal of solid and other waste. In
general, environmental requirements are becoming increasingly stringent, and
further or new requirements may substantially increasefully compensated for the cost of electricproviding
transmission service, by requiring changes in the design or operation of existing facilities
as well as 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 ispotentially including opportunity cost, there can be no
assurance that rates ordered by FERC for service to PECO would fully compensate
GTC, Oglethorpe and the units in operation will always remain subject to the regulations currently in
effect or will always be in compliance with future regulations.
Compliance with environmental standards or deadlines will continue to
be reflected in Oglethorpe's capital and operating costs. Oglethorpe's direct
capital costs to achieve compliance with environmental requirements are expected
to be an aggregate of approximately $250,000Members for 1997, 1998 and 1999.
Clean Air Act
The Clean Air Act seeks to improve air quality throughout the United
States. The acid rain provisions of the Clean Air Act require the reduction of
sulfur dioxide ("SO2") and NOx emissions from affected units, including
coal-fired electric power facilities. The SO2 reductions required by the Clean
Air Act will be achieved in two phases. Phase I addresses specific generating
units named in the Clean Air Act. Both units of Plant Wansley are "affected
units" under Phase I. Scherer Units No. 1 and No. 2 are not "affected units"
under Phase I but are "affected units" under Phase II. Beginning in 1995, Phase
I affected units became subject to the SO2 emission allowance trading program.
Emission allowances are issued by the U.S. Environmental Protection Agency
("EPA"), based on statutory allocations in Phase I and on fossil fuel
consumption for affected units from 1985 through 1987 for Phase II. An
allowance, which gives the holder the authority to emit one ton of SO2 during a
calendar year, is transferable and can be bought, sold or banked for use in the
years following its issuance. Oglethorpe expects to comply with Phase I
requirements through the use of its allowances coupled with switching to lower
sulfur coal, a compliance strategy that has required some equipment upgrades at
Plant Wansleythe transmission system and may result in unused allowances that can be banked for
future
use or sold.
For Phase II, which begins in the year 2000, when total U.S. emissions
of SO2 will be capped at 8.9 million tons, Oglethorpe could use a variety of
options for SO2 compliance, including use of emission allowances (allocated,
banked or purchased, if needed), fuel-switching or installation of flue gas
desulfurization equipment. Achieving compliance with Phase II has already
resulted in some equipment upgrades at Scherer Units No. 1 and No. 2.
Although some NOx regulations implementing the requirements of the
Clean Air Act have been finalized for some time, others have recently been
promulgated and there remains the possibility that further regulation of NOx
emissions from utility sources could be imposed. EPA recently issued a final
rule lowering the NOx emission standard for boiler types such as those found at
Scherer Units No. 1 and No. 2. These rules have been challenged, however, and
whether the new NOx emission standards will ultimately be imposed at Plant
Scherer Units No. 1 and
24
No. 2 is not known. Depending on the form those NOx rules take after the
associated litigation has ended, additional expenditures for pollution control
equipment may be incurred.
In general, compliance with the Clean Air Act will continue to require
expenditures for monitoring and permitting, and in some instances may involve
increased operating or maintenance expenses. Capital expenditures of Oglethorpe
through 1996 for pollution control equipment needed to comply with the Clean Air
Act at Plant Wansley have been approximately $7,200,000 and at Scherer Units No.
1 and No. 2 have been approximately $720,000. Although the estimated cost of any additional improvements at Plant Wansley and Scherer Units No. 1 and No. 2
remains dependent upon the chosen compliance plan and may be affected by future
plan amendments and/or future regulation, Oglethorpe has budgeted approximately
$250,000 in capital expenditures for Clean Air Act and related projects over the
next three years. In addition, the final capital cost of improvements and anyresulting effect on operating costs will be determined by the compliance plan as finally
implemented and any applicable regulatory changes.
Metropolitan Atlanta is classified as a "serious nonattainment area"
with regard to the ozone ambient air quality standards. The Clean Air Act, under
which these standards are promulgated, requires the State of Georgia to conduct
specific studies and establish new rules regulating sources of NOx and volatile
organic compounds ("VOC"), to achieve attainment of the standards by 1999 and to
maintain compliance thereafter. These studies could result in new rules for
power plants in the State, including Plants Wansley and Scherer. Further, along
with 36 other states in the eastern half of the U.S., Georgia, as a member of
the Ozone Transport Assessment Group ("OTAG"), is performing extensive
photochemical grid modeling in an effort to reach a consensus among its member
states as to the strategies needed to reduce ozone and its precursors (including
NOx). Large, stationary sources of NOx have been a focus for OTAG. Originally,
each OTAG state was to have new emission reduction strategies in place by late
springreliability or early summer of 1997. However, EPA has stated its intention to specify
the overall amount of NOx and VOC emission reductions that must be achieved by
each OTAG state.
Plant Wansley is near the non-attainment area while Plant Scherer is
located further away. The results of these studies and new rules could require
NOx controls more stringent than those now required under the acid rain
provisions of the Clean Air Act for compliance. Portions of Subchapter I of the
Clean Air Act also require that several studies be conducted regarding the
health effects of power plant emissions of certain hazardous air pollutants. The
studies will be used in making decisions on whether additional controls of these
pollutants are necessary. The effect of any of these potential regulatory
changes under the Clean Air Act, including new rules under the amended
provisions, can not now be predicted.
The Clean Air Act also requires EPA to review all National Ambient Air
Quality Standards ("NAAQS") periodically, revising such standards as necessary.
Last year, EPA decided not to impose a new short-term standard for sulfur oxides
(measured as SO2). That decision has been appealed, however, so that it is still
possible that a new SO2 standard could be promulgated. If a new short-term NAAQS
for SO2 were imposed, it might require new emission controls at Plants Wansley
and Scherer, which could result in substantial costs to Oglethorpe.
EPA has also proposed to revise the NAAQS for both ozone and PM. Either
of these proposals, if finalized, could have a substantial effect on the types
of controls that might be needed at Plants Wansley or Scherer for compliance.
However, the final impacts (and any associated expenditures) at either plant can
not now be predicted with any certainty. In fact, the impact of any change in
these NAAQS can not now be determined, because the effect of any change would
depend in part on the final ambient standards developed.
Although Oglethorpe's management is currently unable to determine the
overall effect that compliance with requirements under the Clean Air Act will
have on its operations, it does not believe that any required increases in
capital or operating expenses would have a material effect on its results of
operations or its financial condition. Compliance with the requirements under
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
25
increase in the cost of power purchased from GPC. (See "MEMBER REQUIREMENTS
AND POWER SUPPLY RESOURCES--Power Purchasepower.
As previously reported, Oglethorpe and Sale Arrangements--Power
Purchases from GPC" in Item 1.)
Clean Water Act
For some time now, Congress hasLEM have been considering reauthorizationaddressing a number of
issues relating to administration of the Clean Water Act. If that occurs,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 operations could be affected.
However, the full impact of any reauthorization cannot now be determined and
will depend on the specific changes to the statute, as well as to any
implementing state or federal regulations that might be promulgated.
At the state level, EPA is under Federal court order to begin
development of Total Maximum Daily Loads ("TMDLs") for all of Georgia's stream
segments that do not yet meet established water quality standards. The order
calls for a strict schedule for the development of such TMDLs, beginning in the
summer of 1997. Oglethorpe cannot now predict what impact, if any, such
development will have on the operations of Plants Wansley, Scherer, Hatch or
Vogtle, because the effect will depend on the final TMDLs to be developed and
EPA's (and the state's) approach for revising National Pollutant Discharge
Elimination System permits to achieve the desired TMDLs and ultimately achieve
the required water quality standards.
Georgia Hazardous Site Response Act ("GHSRA")
GHSRA requires the compilation and listing of an inventory of all known
or suspected sites where "regulated substances" have been disposed of or
released in quantities deemed reportable by the state. In developing this list,
which includes hundreds of sites, one site co-owned by Oglethorpe was listed.
The site is located at Plant Wansley and consists of an ash pond. As the
operating agent of the plant, GPC will conduct the required remedial
investigation in late 1997 or early 1998, to determine if any clean-up
activities are required. At this time, it is uncertain whether any remediation
will be required and what the timing of any required remediation might be. If
remediation is required, Oglethorpe could incur up to an estimated $800,000 in
clean-up costs and $6 million in capital costs, associated with the
redevelopment of the ash pond. Additional sites may require investigation and
remediation expenses, a portion or all of which Oglethorpe may be liable for. At
this time, Oglethorpemanagement does not believe that any capital or operating costs
associated with GHSRA clean-ups would have a material effect on its resultsexpect the ultimate resolution
of operations or its financial condition.
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 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. (See
"CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--The Plant
Agreements--Proposed Changes to Nuclear Plant Operating Arrangements".)
Pursuant to the Nuclear Waste Policy Act of 1982, as amended, the
Federal government has the regulatory responsibility for the final disposition
of commercially produced high-level radioactive waste materials, including
26
spent nuclear fuel. Such Act requires the owner of nuclear facilities to enter
into disposal contracts with 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. (See "GENERATING
FACILITIES--Fuel Supply".)
For information concerning nuclear insurance, see Note 8 of Notes to
Financial Statements in Item 8. For information regarding NRC's regulation
relating to decommissioning of nuclear facilities and regarding DOE's
assessments pursuant to the Energy Policy Act for decontamination and
decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to
Financial Statements in Item 8.
Other Environmental Regulation
In 1993, EPA issued a ruling confirming the non-hazardous status of
coal ash. That ruling may apply, however, only to situations where those wastes
are not co-managed, i.e. not mixed with other wastes. Pursuant to court order,
EPA has until 1998 to classify co-managed utility wastes as either hazardous or
non-hazardous. If the wastes are classified as hazardous, substantial additional
costs for the management of such wastes might be required, although the full
impact would depend on the subsequent development of requirements pertaining to
these wastes.
Oglethorpe is subject to other environmental statutes including, but
not limited to, the Toxic Substances Control Act ("TSCA"), the Resource
Conservation & Recovery Act ("RCRA"), the Endangered Species Act ("ESA"), the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
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 regulationsissues will have a material impactadverse effect on its financial condition
or results of operations. Changes to anyFor a discussion of these laws, however, could affect many areas of Oglethorpe's
operations. Congress is considering amending the ESA and reauthorizing CERCLA,
TSCA and perhaps RCRA. Although compliance with new environmental legislation
could have a significant impact on Oglethorpe, those impacts cannot be fully
determined at this time and would depend in part on the final legislation and
the development of implementing regulations.
The scientific community, regulatory agencies and the electric utility
industry are continuing to examine the issues of global warming and the possible
health effects of electromagnetic fields. While no definitive scientific
conclusions have been reached regarding these issues, 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 alleging damages from electromagnetic fields.
Energy Policy Act
The Energy Policy Act allows for increased competition among wholesale
electric suppliers and increased access to transmission services by such
suppliers. It created a new class of utilities called Exempt Wholesale
Generators ("EWGs"), which are exempt from certain restrictions otherwise
imposed by the Public Utility Holding Company Act. The effect of this exemption
is to facilitate the development of independent third-party generators
potentially available to satisfy utilities' needs for increased power supplies.
Unlike purchases from qualifying facilities under PURPA (see "MEMBER
REQUIREMENTS ANDLEM agreement, see
"OGLETHORPE'S POWER SUPPLY RESOURCES--Power Purchase and Sales
Arrangements--Other Power Purchases"Marketer Arrangements--LEM
Agreement" in Item 1), utilities have no statutory
obligation to purchase power from EWGs. Furthermore, EWGs are precluded from
making direct sales to retail electricity customers.
The Energy Policy Act also broadened the authority of FERC to require a
utility to transmit power to or on behalf of other participants in the electric
utility industry, including EWGs and qualifying facilities, but FERC is
precluded from requiring a utility to transmit power from another entity
directly to a retail customer. In 1996,
27
FERC issued two final rules (Orders 888 and 889) and a notice of proposed
rulemaking regarding capacity reservation tariffs that would make significant
changes in the form of transmission services performed by public utilities
subject to FERC's jurisdiction. See "OGLETHORPE POWER CORPORATION--Relationship
with GTC" in Item 1 for information regarding GTC's transmission tariff.
28
Item 3. LEGAL PROCEEDINGS1.
Oglethorpe is a party to various other actions and proceedings incidentincidental
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.
ItemITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
2928
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERSMATTERS.
Not applicable.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected historical financial data of
Oglethorpe. The financial data presented as of the end of and for each year in
the five-year period ended December 31, 2000, have been derived from the audited
financial statements of Oglethorpe. Due to a corporate restructuring, the
results of operations and financial condition reflect operations as a combined
power supply, transmission and system operations company through March 31, 1997,
and operations solely as a power supply company thereafter. These data should be
read in conjunction with the financial statements of Oglethorpe and the notes
thereto included in Item 8 and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS" in Item 7.
(dollars in thousands)
2000 1999 1998 1997 1996
1995 1994 1993 1992-----------------------------------------------------------------------------------
Operating revenues:
Sales to Members .....................$ 1,146,064 $ 1,122,336 $ 1,095,904 $ 1,000,319 $ 1,023,094 $ 1,030,797 $ 930,875 $ 899,720 $ 816,000
Sales to non-Members .................53,333 53,896 48,263 47,533 78,343
118,764 125,207 200,940 268,763
------------ ------------ ------------ ------------ ------------- -----------------------------------------------------------------------------------------------------------------------------
Total operating revenues .............1,199,397 1,176,232 1,144,167 1,047,852 1,101,437
1,149,561 1,056,082 1,100,660 1,084,763
------------ ------------ ------------ ------------ ------------- -----------------------------------------------------------------------------------------------------------------------------
Operating expenses:
Fuel .................................216,952 196,182 191,399 206,315 206,524
219,062 203,444 176,342 167,288
Production .............................. 129,178 133,858 132,723 129,972 115,915215,834 215,517 198,378 181,923 173,497
Purchased power .........................403,574 401,719 387,662 266,875 229,089 264,844 227,477 271,970 230,510
Depreciation and amortization ............................142,082 130,883 124,074 126,730 163,130 139,024 131,056 128,060 126,047
Taxes ................................... 30,262 27,561 24,741 25,148 19,634
Other operating expenses ................ 60,505 56,535 49,234 44,876 50,578
------------ ------------ ------------ ------------ ------------- - - 6,334 46,448
- -----------------------------------------------------------------------------------------------------------------------------
Total operating expenses ................978,442 944,301 901,513 788,177 818,688
840,884 768,675 776,368 709,972
------------ ------------ ------------ ------------ ------------- -----------------------------------------------------------------------------------------------------------------------------
Operating margin ........................220,955 231,931 242,654 259,675 282,749 308,677 287,407 324,292 374,791
Other income, net .......................60,839 50,545 42,293 46,646 65,334 33,710 40,795 38,741 45,928
Net interest charges ....................(261,816) (262,538) (263,867) (283,916) (326,331)
(320,129) (305,120) (350,652) (393,247)
Margin before cumulative effect of change
in accounting principle ............. 21,752 22,258 23,082 12,381 27,472
Cumulative effect of change in accounting
for income taxes .................... -- -- -- 13,340 --
------------ ------------ ------------ ------------ ------------- -----------------------------------------------------------------------------------------------------------------------------
Net margin ..............................$ 19,978 $ 19,938 $ 21,080 $ 22,405 $ 21,752
$ 22,258 $ 23,082 $ 25,721 $ 27,472
============ ============ ============ ============ ============- -----------------------------------------------------------------------------------------------------------------------------
Electric plant, net:
In service ...........................$ 3,214,974 $ 3,312,669 $ 3,429,704 $ 3,588,204 $ 4,345,200 $ 4,436,009 $ 3,980,439 $ 4,054,956 $ 4,122,411
Construction work in progress ...........62,357 18,299 20,948 13,578 31,181
35,753 538,789 450,965 322,628
------------ ------------ ------------ ------------ ------------- -----------------------------------------------------------------------------------------------------------------------------
Total electric plant $ 3,277,331 $ 3,330,968 $ 3,450,652 $ 3,601,782 $ 4,376,381
$ 4,471,762 $ 4,519,228 $ 4,505,921 $ 4,445,039
============ ============ ============ ============ ============- -----------------------------------------------------------------------------------------------------------------------------
Total assets ............................$ 4,568,170 $ 4,564,622 $ 4,506,265 $ 4,509,857 $ 5,362,175
$ 5,438,496 $ 5,346,330 $ 5,323,890 $ 5,359,597
============ ============ ============ ============ ============- -----------------------------------------------------------------------------------------------------------------------------
Capitalization:
Long-term debt .......................$ 3,019,019 $ 3,103,590 $ 3,177,883 $ 3,258,046 $ 4,052,470 $ 4,207,320 $ 4,128,080 $ 4,058,251 $ 4,095,796
Obligation under capital leases .........267,449 275,224 282,299 288,638 293,682 296,478 303,749 303,458 302,061
Other obligations ....................63,665 59,579 55,755 52,176 41,685 -- -- -- --
Patronage capital and membership fees 392,682 370,025 352,701 330,509 356,229
338,891 309,496 289,982 264,261
------------ ------------ ------------ ------------ ------------- -----------------------------------------------------------------------------------------------------------------------------
Total capitalization $ 3,742,815 $ 3,808,418 $ 3,868,638 $ 3,929,369 $ 4,744,066
$ 4,842,689 $ 4,741,325 $ 4,651,691 $ 4,662,118
============ ============ ============ ============ ============- -----------------------------------------------------------------------------------------------------------------------------
Property additions ......................$ 108,254 $ 41,829 $ 43,904 $ 63,527 $ 93,704
$ 138,921 $ 206,345 $ 235,285 $ 232,283
============ ============ ============ ============ ============- -----------------------------------------------------------------------------------------------------------------------------
Energy supply (megawatt-hours):
Generated ............................19,565,925 18,295,514 17,781,896 17,722,059 17,866,143
18,402,839 16,924,038 14,575,920 13,805,683
Purchased ...............................11,401,071 7,971,583 8,544,714 6,377,643 6,606,931
5,738,634 4,381,087 7,620,815 6,233,262
------------ ------------ ------------ ------------ ------------- -----------------------------------------------------------------------------------------------------------------------------
Available for sale ......................30,966,996 26,267,097 26,326,610 24,099,702 24,473,074
24,141,473 21,305,125 22,196,735 20,038,945
============ ============ ============ ============ ============- -----------------------------------------------------------------------------------------------------------------------------
Member revenue per kWh sold ............. 5.11(cent) 5.53(cent) 5.65(cent) 5.47(cent) 5.55(cent)
============ ============ ============ ============ ============4.21 cents 4.53 cents 4.70 cents 4.83 cents 5.11 cents
- -----------------------------------------------------------------------------------------------------------------------------
29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
Corporate RestructuringGeneral
Margins and Patronage Capital
Oglethorpe and the Members completed a corporate restructuring (the
Corporate Restructuring) on March 11, 1997 (the Closing) pursuant to terms and
conditions set forth in the Second Amended and Restated Restructuring Agreement
(the Restructuring Agreement). Pursuant to the Corporate Restructuring,
Oglethorpe divided itself into three specialized operating companies to respond
to increasing competition and regulatory changes in the electric industry. As
part of the Corporate Restructuring, the transmission business is now owned and
operated by a newly formed Georgia electric membership corporation, Georgia
TransmissionPower Corporation (An Electric Membership Corporation)
(GTC), and the
system operations business is now owned and operated by a newly formed Georgia
nonprofit corporation, Georgia System Operations Corporation (GSOC). Oglethorpe
continues to own and operate the power supply business.
On October 1, 1996, Oglethorpe transferred to GSOC its system operations
assets, consisting of its system control center and related energy control and
revenue metering systems equipment. The purchase price of these assets totaled
approximately $9.4 million and was funded by GSOC's assumption of Oglethorpe's
obligations under an existing note held by the Rural Utilities Service (RUS), by
delivery of a purchase money note payable to Oglethorpe and by the assumption of
certain other liabilities of Oglethorpe. Since October 1, 1996, Oglethorpe has
been the sole member of GSOC. The Members and GTC became members of GSOC on the
Closing. GSOC will operate the system control center and provide system
operations services to the Members, Oglethorpe and GTC.
At the Closing, Oglethorpe transferred its transmission business and assets
to GTC. The purchase price for the transmission business was based on an
appraisal of the fair market value of such business, as determined by an
independent appraiser, and was approximately $708 million. The purchase price
was paid primarily by GTC's assumption of a portion (approximately 16.86%("Oglethorpe") of
Oglethorpe's long-term secured debt in an amount equal to approximately $686
million. Approximately $541 million of this debt (payable to RUS, Federal
Financing Bank (FFB) and CoBank, ACB (CoBank)) became the sole obligation of
GTC, and Oglethorpe was released from all liability with regard to this
indebtedness. The remaining debt assumed by GTC in connection with the Corporate
Restructuring, approximately $145 million, relates to Oglethorpe's pollution
control revenue bonds (PCBs). While GTC assumed and agreed to pay this $145
million of debt, Oglethorpe is not legally released from its liability for this
debt. The remainder of the purchase price was paid by GTC from cash obtained
through a borrowing from National Rural Utilities Cooperative Finance
Corporation (CFC) and the assumption of approximately $1 million of other
Oglethorpe liabilities. Oglethorpe also made a special patronage capital
distribution of approximately $49 million to the Members which was used by the
Members to establish equity in and to provide initial working capital to GTC.
Oglethorpe and the 39 Members are members of GTC. GTC now owns and operates the
transmission system and provides transmission services to the Members and
Oglethorpe. GTC has succeeded to all of Oglethorpe's rights and obligations with
respect to the Integrated Transmission System (ITS).
Oglethorpe continues to operate the power supply business. Oglethorpe
retained all of its owned and leased generation assets and has total assets of
approximately $4.7 billion and total long-term debt of approximately $3.9
billion. Oglethorpe also continues to administer its power purchase contracts
and provide marketing support functions to the Members.
In connection with the Corporate Restructuring, Oglethorpe, GTC, GSOC and
the Members entered into a Member Agreement (Member Agreement) which specifies
the form of the new wholesale power contracts (New Wholesale Power Contracts),
transmission agreements (Transmission Agreements) and system operations
contracts to be signed by the Members. The New Wholesale Power Contracts provide
that the Members are responsible, on a joint and several basis, for all of
Oglethorpe's obligations relatingelectric service to its existing generation business. The
Transmission Agreements provide that the Members are responsible, on a joint and
several basis, for all of GTC's obligations with respect to its transmission
business.
Pursuant to the Member Agreement, in connection with the Closing, Oglethorpe
and each of the Members entered into New Wholesale Power Contracts which extend
through December 31, 2025. Under the New Wholesale Power Contracts, each Member
is assigned an agreed-upon fixed percentage capacity responsibility (PCR) for
all of Oglethorpe's existing resources. PCR responsibility for any future
resource will be assigned only to Members choosing to participate in that
resource. The New Wholesale Power Contracts permit each Member to take future
incremental power requirements either from Oglethorpe or other sources. Under
the New Wholesale Power Contracts, a Member is unconditionally obligated on an
express "take-or-pay" basis for a fixed allocation of Oglethorpe's costs for its
31
existing resources, as well as the costs with respect to any future resources in
which such Member elects to participate. The New Wholesale Power Contracts
specifically provide that the Member must make payments whether or not power is
delivered and whether or not a plant has been sold. Oglethorpe is obligated to
use its reasonable best efforts to operate, maintain and manage its resources in
accordance with prudent utility practices. The New Wholesale Power Contracts
provide that Oglethorpe will be responsible for power supply planning, resource
procurement and sales of capacity and energy for a Member unless the Member
notifies Oglethorpe that it does not want Oglethorpe to provide these services.
The New Wholesale Power Contracts provide that each Member will be jointly
and severally responsible for all costs and expenses of all existing resources
and any future resources (whether or not such Member has elected to participate
in such future resource) that have been 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 of a defaulting Member 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.
In connection with the implementation of new power marketer arrangements
with LG&E Power Marketing Inc.39 retail electric
distribution cooperative members ("LPM"Members"), Oglethorpe and each Member have entered
into supplemental agreements to the New Wholesale Power Contracts which relate
to certain provisions of the New Wholesale Power Contracts and apply during the
term of the power marketer arrangements. The supplemental agreements clarify the
application of the New Wholesale Power Contract rate schedule to the power
marketer agreements. The 75% requirement described above has been met with
respect to the LPM agreements. The supplemental agreement assures that all costs
incurred by Oglethorpe under the LPM agreement are recoverable under the New
Wholesale Power Contracts. As the expected additional power marketer
arrangements are finalized, additional supplemental agreements to the New
Wholesale Power Contracts will be entered into by Oglethorpe and the Members.
See "Results of Operations-Factors Affecting Future Financial Performance" for a
description of the power supply arrangements.
The rate set forth in the New Wholesale Power Contracts is intended to
recover all costs and expenses paid or incurred by Oglethorpe. The rate
expressly includes in the description of costs to be recovered all principal and
interest on indebtedness of Oglethorpe and all costs associated with
decommissioning or otherwise retiring any generating facility. The rate further
expressly provides for Oglethorpe to earn sufficient margins to satisfy the
requirements of the Master Indenture (defined below). The New Wholesale Power
Contracts contain covenants by the Member (i) to establish, maintain and collect
rates and charges for the service of its electric system and (ii) to conduct its
business in a manner that will produce revenues and receipts at least sufficient
to enable the Member to pay to Oglethorpe, when due, all amounts payable by the
Member under the New Wholesale Power Contracts and to pay any and all other
amounts payable from, or which might constitute a charge and a lien upon, the
revenues and receipts derived from its electric system, including all operation
and maintenance expenses and the principal of, premium (if any) and interest on
all indebtedness related to the Member's electric system.
The New Wholesale Power Contracts provide that a Member will not dissolve,
liquidate or otherwise wind up its affairs without Oglethorpe's approval. The
Member will not consolidate or merge with any person or reorganize or change the
form of its business organization from an electric membership corporation or
sell, transfer, lease or otherwise dispose of all of its assets to any person,
whether in a single transaction or series of transactions, unless either (i) the
transaction is approved by Oglethorpe or (ii) other specified conditions are
satisfied including, but not limited to, an assumption agreement by the
transferee, satisfactory to Oglethorpe, containing an assumption by the
transferee of the performance and observance of every covenant and condition of
the Member under the New Wholesale Power Contract, and certifications of
accountants as to certain specified financial requirements of the transferee
(taking into account the transfer).
Effective with the Corporate Restructuring, Oglethorpe amended its Bylaws to
implement a new governance structure with an 11-member board of directors
consisting of six directors elected from the Members, four independent outside
directors and Oglethorpe's President and Chief Executive Officer. This smaller
board replaced Oglethorpe's former 39-member board comprised of directors
nominated from and by each Member. The new directors will be nominated by
representatives from each Member on a weighted-voting method, based on the
number of retail customers served by such Member. However, each director will
continue to be elected by a vote of the Member representatives on a one-Member,
one-vote basis. Except for two of the four outside directors, all of
Oglethorpe's new directors have been elected and began their terms at the
Closing. The remaining two outside directors are expected to be elected on March
27, 1997.
Contemporaneously with the Corporate Restructuring, Oglethorpe replaced its
existing Consolidated Mortgage and Security Agreement, dated as of September 1,
1994, by and among Oglethorpe, as Mortgagor, the United States of
32
America, acting through the Administrator of the RUS and certain other
mortgagees (the RUS Mortgage) with the Indenture, dated as of March 1, 1997,
from Oglethorpe to SunTrust Bank, Atlanta, as trustee, (the Master Indenture)
providing for a lien on substantially all of the owned tangible and certain
intangible property of Oglethorpe. See "Rates and Financial Coverage
Requirements" below for a further description of the Master Indenture.
In conjunction with the Corporate Restructuring and as a part of its
continuing efforts to reduce costs, effective February 1, 1997, Oglethorpe
implemented a business alliance with Intellisource, Inc., a national provider of
outsourcing services. Pursuant to an agreement with Intellisource, approximately
150 support services division employees in the areas of accounting, auditing,
communications, human resources, facility management, purchasing,
telecommunications and information technology became employees of the
Intellisource organization. Oglethorpe, GTC and GSOC are key customers of
Intellisource and are being served on-site by the managers and employees of
Oglethorpe's former support services division.
Margins and Patronage Capital Oglethorpe operates on a
not-for-profit basis and, accordingly, seeks only to generate revenues
sufficient to recover its cost of service and to generate margins sufficient to
establish reasonable reserves and meet certain financial coverage requirements.
Revenues in excess of current period costs in any year are designated as net
margin in Oglethorpe's statements of revenues and expenses and patronage
capital as net margin.capital. Retained net margins are designated on Oglethorpe's balance sheets as
patronage capital, which is allocated to each of the Members on the basis of its
electricity purchases from Oglethorpe. Since its formation in 1974, Oglethorpe
has generated a positive net margin in each year and had a balance of $356$393
million in patronage capital as of December 31, 1996.2000. Oglethorpe's equity ratio
(patronage capital and membership fees divided by total capitalization)
increased from 7.0%9.7% at December 31, 19951999 to 7.5%10.5% at December 31, 1996.2000.
Patronage capital constitutes the principal equity of Oglethorpe. Under
Oglethorpe's patronage capital retirement policy, margins are to be returned to
the Members 30 years after the year in which the margins are earned. Pursuant to
such policy, no patronage capital would be retired until 2010, at which time the
1979 patronage capital would be returned. Any
distributions of patronage capital are subject to the discretion of the Board of
Directors. See "Corporate
Restructuring" above regarding a special patronage capital distribution made in
connection withHowever, under the Corporate Restructuring.
Now that the Master Indenture, has been substituted for the prior RUS
dated as of March 1, 1997, from
Oglethorpe to SunTrust Bank, as trustee ("Mortgage distributions of patronage capital are no longer subject to the
approval of RUS, but are subject to certain restrictions set forth in the Master
Indenture. Under the Master Indenture,Indenture"), Oglethorpe is
prohibited from making any distribution of patronage capital to the Members if,
at the time thereofof or after giving effect thereto,to the distribution, (i) an event of
default exists under the MasterMortgage 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 ofto 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 Financial Coverage RequirementsRegulation
Pursuant to the NewAmended and Restated Wholesale Power Contract,Contracts, dated
August 1, 1996 ("Wholesale Power Contracts") entered into between Oglethorpe and
each of the Members, Oglethorpe is required to design capacity and energy rates
that generate sufficient revenues to recover all costs, as described in such contracts, to establish and
maintain reasonable margins and to meet its financial coverage requirements.
Oglethorpe reviews its capacity rates at least annually to ensure that its fixed costs are being
adequately recovered and, if necessary, adjusts its rates to meetit meets
its net margin goals.
Oglethorpe's energy rate is established to recover actual fuel and
variable operations and maintenance costs. Under the terms of Oglethorpe's prior
RUS Mortgage, rate revisions by Oglethorpe were subject to the approval of RUS.
Under the Master Indenture, Oglethorpe's rates are not subject to RUS approval
except in limited circumstances.
The capacity rate applied by Oglethorpe in 1994 utilized a proportional
allocation of fixed costs based on the previous year's billing demand for each
Member. Consequently, the 1994 rate produced capacity revenues which were
virtually unaffected by current year factors. In 1995, Oglethorpe implemented
two additional capacity rate options in an effort to provide greater flexibility
to the Members. These options allocated fixed costs using billing determinants
of the current year. These rates produced differing monthly amounts of capacity
revenues throughout the year and introduced some variability and uncertainty as
to the level of revenues and margins to be received. Due to extreme weather
conditions and other factors, the 1995 rates options produced $2.5 million of
revenues in excess of budgeted amounts. Such excess amounts were returned to the
Members in 1996.
Under a capacity rate mechanism effective throughout 1996, each Member was
responsible for
33
an assigned share of fixed costs based on an agreed-upon allocation. Under this
approach, capacity costs were collected in equal monthly amounts. This interim
rate mechanism has now been extended through March 31, 1997. A new rate schedule will become effective under the New Wholesale Power Contracts on April 1, 1997.
This new rate schedule 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. Such
capacity and other non-energy charges may be adjusted by theThe Board of Directors if necessary,may adjust
these charges during the year through an adjustment to the annual budget. Energy
charges are based on actual energy costs. However, under the supplemental
agreements for the LPM agreements, each Member pays a fixed rate forcosts, including fuel costs, variable
operations and maintenance costs, and purchased energy plus certain adjustments, while LPM pays all energy costs, within certain risk
bands. The new rate schedule also includes a prior period adjustment (PPA)
mechanism. The PPA serves to facilitate the achievement of the minimum 1.10 MFI
ratio, and it provides for the retention of margins within a range from a 1.10
MFI ratio to a 1.20 MFI ratio. Amounts, if any, by which Oglethorpe fails to
achieve a minimum 1.10 MFI ratio would be accrued as of December 31 of the
applicable year and collected during the period April through December of the
following year. Amounts, if any, earned by Oglethorpe in excess of a 1.20 MFI
ratio would be charged against revenues as of December 31 of the applicable year
and refunded during the period April through December of the following year.costs.
Under the prior RUS Mortgage Oglethorpe utilized a Times Interest Earned
Ratio (TIER) as the basis for establishing its annual net margin goal. TIER is
determined by dividing the sum of Oglethorpe's net margin plus interest on
long-term debt (including interest charged to construction) by Oglethorpe's
interest on long-term debt (including interest charged to construction). The RUS
Mortgage required Oglethorpe to implement rates that are designed to maintain an
annual TIER of not less than 1.05. Oglethorpe's Board of Directors set an annual
net margin goal to be the amount required to produce a TIER of 1.07 in 1994
through 1996.
In addition to the TIER requirement under the RUS Mortgage, Oglethorpe was
also required under the RUS Mortgage to implement rates designed to maintain a
Debt Service Coverage Ratio (DSC) of not less than 1.0 and an Annual Debt
Service Coverage Ratio (ADSCR) of not less than 1.25. DSC is determined by
dividing the sum of Oglethorpe's net margin plus interest on long-term debt
(including interest charged to construction) plus depreciation and amortization
(excluding amortization of nuclear fuel and debt discount and expense) by
Oglethorpe's interest and principal payable on long-term debt (including
interest charged to construction). ADSCR is determined by dividing the sum of
Oglethorpe's net margin plus interest on long-term debt (excluding interest
charged to construction) plus depreciation and amortization (excluding
amortization of nuclear fuel and debt discount and expense) by Oglethorpe's
interest and principal payable on long-term debt secured under the RUS Mortgage
(excluding interest charged to construction).
Oglethorpe always met or exceeded the TIER, DSC and ADSCR requirements of
the RUS Mortgage. TIER, DSC and ADSCR for the years 1994 through 1996 were as
follows:
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
TIER 1.07 1.07 1.07
DSC 1.25 1.21 1.19
ADSCR 1.32 1.27 1.25
- --------------------------------------------------------------------------------
Under the Master Indenture, Oglethorpe is required, subject to any
necessary regulatory approval, to establish and collect rates whichthat are
reasonably expected, together with other revenues of Oglethorpe, to yield a
Margins for Interest (MFI)Ratio for each fiscal year equal to at least 1.10 times total interest charges during such fiscal year on all indebtedness
secured under the Master Indenture (or by a lien equal or prior to the lien of
the Master Indenture), excluding indebtedness assumed by GTC. MFI1.10. The
Margins for Interest Ratio is determined by addingdividing 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 on indebtedness secured under the Master Indenture (or by lien
equal to or prior to the lien of the Master Indenture),Interest Charges and (iii) any
amount included in net margins for accruals for federal or state income taxes.
The definition of MFIMargins 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 MFI ratio requirement went into effect uponrate schedule also includes a prior period adjustment mechanism
designed to ensure that Oglethorpe achieves the substitutionminimum 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
Master Indentureapplicable 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 priorcollection of revenues which, together with revenues from all other
sources, are equal to all costs and expenses recorded by Oglethorpe, plus
amounts necessary to achieve at least the minimum 1.10 Margins for Interest
Ratio.
For 2000, 1999 and 1998, Oglethorpe achieved a Margins for Interest Ratio
of 1.10.
Under the Mortgage Indenture and related loan contract with the Rural
Utilities Service ("RUS"), adjustments to Oglethorpe's rates to reflect changes
in Oglethorpe's budgets are generally not subject to RUS Mortgage. For comparative purposes only,approval. Changes to
the pro-forma MFI ratio for 1996 would have been 1.09.
Miscellaneous
Currently, Oglethorpe israte schedule under the Wholesale Power Contracts are generally subject to
RUS approval. Oglethorpe's rates are not subject to the provisionsapproval of any other
federal or state agency or authority, including the Georgia Public Service
Commission (the "GPSC").
Results of Operations
Power Marketer Arrangements
Oglethorpe is utilizing power marketer arrangements to reduce the cost of
power to the Members. Oglethorpe has a power marketer agreement with LG&E Energy
Marketing Inc. ("LEM"), for approximately 50% of the load requirements of 37 of
the Members and an additional power marketer agreement with Morgan Stanley
Capital Group Inc. ("Morgan Stanley"), effective May 1, 1997, with respect to
50% of the 39 Members' then forecasted load requirements. The LEM agreement is
based on the actual requirements of the participating Members during the
contract term, whereas the Morgan Stanley agreement represents a fixed supply
obligation. Generally, these arrangements reduce the cost of supplying power to
the Members by limiting the risk of unit availability, by providing a guaranteed
benefit for the use of excess resources and by providing future power needs at a
fixed price. Most of Oglethorpe's generating facilities and power purchase
arrangements are available for use by LEM and Morgan Stanley. Oglethorpe
continues t be responsible for all of the costs of its system resources but
receives revenue from LEM and Morgan Stanley for the use of the resources.
In February 2001, LEM initiated the contractually defined arbitration
process to resolve a number of issues relating to administration of the
agreement.
Operating Revenues
Sales to Members. Revenues from Members are collected pursuant to the
Wholesale Power Contracts and are a function of the demand for power by the
Members' consumers and Oglethorpe's cost of service. Revenues from sales to
Members increased by 2.1% for 2000 compared to 1999 and increased by 2.4% for
1999 compared to 1998. Kilowatt-hours (kWh) sales to Members were 10.0% higher
in 2000 compared to 1999 and 6.2% higher in 1999 compared to 1998. The average
revenue per kWh from sales to Members decreased 7.1% for 2000 compared to 1999
and decreased 3.6% for 1999 compared to 1998. The components of Member revenues
were as follows:
- -----------------------------------------------------------------
(dollars in thousands)
2000 1999 1998
- -----------------------------------------------------------------
Capacity revenues $ 624,537 $ 613,974 $ 623,464
Energy revenues 521,527 508,362 472,440
- -----------------------------------------------------------------
Total $1,146,064 $1,122,336 $1,095,904
- -----------------------------------------------------------------
Capacity revenues from Members increased from 1999 to 2000 primarily due to
capacity charges incurred for new power purchase agreements and higher
depreciation and amortization offset in part by higher investment income. For
1999 compared to 1998, Member capacity revenues decreased due to lower interest
costs and higher investment income offset in part by higher production expenses.
Energy revenues from Members increased by 2.6% from 1999 to 2000 and by
7.6% from 1998 to 1999. The increases in Member energy revenues over the past
two years were primarily due to greater volumes of energy sold to Members.
31
The following table summarizes the amounts of kWh sold to Members and total
revenues per kWh during each of the past three years:
- ------------------------------------------------------------------------------
(in thousands)
Kilowatt-hours Cents per
Kilowatt-hour
- ------------------------------------------------------------------------------
2000 27,232,641 4.21
1999 24,755,812 4.53
1998 23,315,950 4.70
- ------------------------------------------------------------------------------
In 2000, a cold November and December combined with growth in the Members'
service territories resulted in a 10.0% increase in kWh sales to Members. The
6.2% increase in kWh sales to Members in 1999 compared to 1998 was due to
continued sales growth in the Members' service territories. In addition,
Oglethorpe provided the Members with additional energy in 1999 to offset lower
delivery of hydroelectric power from Southeastern Power Administration due to
lower than normal rainfall.
The energy portion of Member revenues per kWh decreased 6.8% in 2000
compared to 1999 and increased 1.4% in 1999 compared to 1998. Oglethorpe passes
through actual energy costs to the Members such that energy revenues equal
energy costs. The decrease in 2000 of energy revenues per kWh was primarily due
to the pass-through of lower purchased power costs. The increase in 1999 for the
cost of energy supplied to the Members resulted primarily from higher purchased
power costs. See "Operating Expenses" below.
Sales to non-Members. The following table summarizes non-Member revenues
for the past three years:
- -----------------------------------------------------------------
(dollars in thousands)
2000 1999 1998
- -----------------------------------------------------------------
Sales to other utilities $46,952 $46,186 $28,890
Sales to power marketers 6,381 7,710 19,373
- -----------------------------------------------------------------
Total $53,333 $53,896 $48,263
- -----------------------------------------------------------------
Sales to other utilities represent sales made directly by Oglethorpe.
Oglethorpe sells for its own account any energy available from the portion of
its resources dedicated to Morgan Stanley that is not scheduled by Morgan
Stanley pursuant to its power marketer arrangements. Sales to other utilities
were higher in 1999 compared to 1998 partly due to receiving a full year of
capacity revenues in 1999 under an agreement entered into with Alabama Electric
Cooperative to sell 100 megawatts ("MW") of capacity for the period June 1998
through December 2005 and partly due to higher energy prices experienced in the
wholesale electricity markets during 1999.
Sales to power marketers represent the net energy transmitted on behalf of
LEM and Morgan Stanley off-system on a daily basis from Oglethorpe's total
resources. Oglethorpe sold this energy to LEM at Oglethorpe's cost, subject to
certain limitations, and to Morgan Stanley at a contractually fixed price. The
volume of sales to power marketers depends primarily on the power marketers'
decisions for servicing their load requirements.
Operating Expenses
Oglethorpe's operating expenses increased 3.6% in 2000 compared to 1999 and
increased 4.7% in 1999 compared to 1998. Operating expenses increased in 2000
primarily as a result of higher fuel and depreciation and amortization costs.
The higher operating expenses in 1999 as compared to 1998 were primarily
attributable to increases in production expenses and purchased power costs.
For 2000 compared to 1999 total fuel costs increased 10.6% primarily as a
result of a 7.4% increase in MWhs of generation. For 2000 compared to 1999
output of nuclear generation was 4.3% higher and output of fossil generation was
9.9% higher. The larger portion of fossil generation, with its higher average
fuel cost compared to nuclear generation, yielded a 3.0% increase in average
fuel cost. Total fuel costs increased 2.5% in 1999 compared to 1998 primarily as
a result of a 2.4% increase in generation.
The increase in production expenses in 1999 as compared to 1998 was
primarily due to three factors: (1) write-off of $3.6 million of obsolete
inventory at Plants Vogtle, Hatch , Wansley and Scherer; (2) approximately $2
million in expenses resulting from a Georgia Power Company ("GPC") workforce
reduction at Plants Vogtle and Hatch; and (3) expenses incurred for the LEM
arbitration and other special projects totaling $4.9 million.
32
Purchased power costs increased 0.5% in 2000 compared to 1999 and increased
3.6% in 1999 compared to 1998 as follows:
- -------------------------------------------------------------------
(dollars in thousands)
2000 1999 1998
- -------------------------------------------------------------------
Capacity costs $105,763 $ 97,616 $115,599
Energy costs 297,811 304,103 272,063
- -------------------------------------------------------------------
Total $403,574 $401,719 $387,662
- -------------------------------------------------------------------
The increase in purchased power capacity costs for 2000 as compared to 1999
were primarily a result of capacity charges incurred for new power purchase
agreements, including an agreement with Doyle I, LLC. Purchased power capacity
costs were 15.6% lower in 1999 compared to 1998 primarily due to the elimination
on September 1 of 1998 of a 250 MW component block (coal-fired units) of power
under a power purchase agreement between Oglethorpe and GPC.
Purchased power energy costs decreased 2.1% in 2000 compared to 1999 and
increased by 11.8% in 1999 compared to 1998. The average cost of purchased power
energy per MWh decreased 31.5% in 2000 compared to 1999 and increased 19.8% in
1999 compared to 1998. The decrease in average cost in 2000 resulted from a
combination of lower prices in the wholesale electricity markets and from
purchases made under new power purchase agreements during 2000. The increase in
average cost in 1999 compared to 1998 resulted from slightly higher energy
prices.
The volumes of purchased power increased 43.0% in 2000 compared to 1999 and
decreased by 6.7% in 1999 compared to 1998. The higher volumes of purchased
power in 2000 were utilized to serve Member load that was not contractually
provided by the power marketers.
Purchased power expenses for the years 1998 through 2000 include the cost
of capacity and energy purchases under various long-term power purchase
agreements. These long-term agreements have, in some cases, take-or-pay minimum
energy requirements. For 1998 through 2000, Oglethorpe utilized its energy from
these power purchase agreements in excess of the take-or-pay requirements.
Oglethorpe's capacity and energy expenses under these agreements amounted to
approximately $176 million in 2000, $133 million in 1999 and $173 million in
1998. For a discussion of the power purchase agreements, see Note 9 of Notes to
Financial Statements.
The increase in depreciation and amortization in 2000 was primarily due to
$10.3 million of Board approved accelerated amortization of project costs for
the Vogtle radioactive waste facility. The increase in depreciation and
amortization for 1999 compared to 1998 resulted from the amortization of the
Vogtle radioactive waste facility. The amortization of these project costs
commenced January 1, 1999. For further discussion of the Vogtle radioactive
waste facility see Note 1 of Notes to Financial Statements.
Other Income (Expense)
The higher investment income for 2000 compared to 1999 was partly due to
higher cash and temporary cash investment balances and higher interest earnings
on those investments, partly due to higher earnings from the decommissioning
fund and partly due to interest earnings on the note receivable from Smarr EMC
relating to the Sewell Creek Energy Facility. Investment income was higher in
1999 compared to 1998 partly due to higher earnings from the decommissioning
fund and partly due to interest earnings on the notes and interim financing
receivable from Smarr EMC relating to the Smarr Energy Facility and the Sewell
Creek Energy Facility. For 1999, the increase in income under the caption
"Other" is due in part to a gain of $849,000 from the sale of rail cars and a
$1,005,000 increase in patronage allocation from GTC.
Interest Charges
Interest on long-term debt and capital leases decreased 5.2% in 1999
compared to 1998 primarily as a result of interest costs savings from
refinancing transactions. Other interest expense increased 18.5% in 2000
compared to 1999 and increased 53.3% in 1999 compared to 1998. The increase in
2000 was primarily as a result of interest charges incurred on commercial paper
33
issued as interim financing for the construction of combustion turbine
facilities owned by Smarr EMC. The increase for 1999 compared to 1998 was partly
due to interest charges incurred on commercial paper issued as interim financing
for Smarr EMC and partly due to an increase in interest expense for
decommissioning (which is recorded as an offset to interest earnings on the
decommissioning fund). The increase in amortization of debt discount and expense
for 1999 compared to 1998 was primarily due to the accelerated amortization of
$7 million in premiums paid to the Federal Financing Bank (FFB) for refinancing
$89 million in 1999. These cost are being amortized over a period of
approximately 3 years beginning in 1999.
Net Margin and Comprehensive Margin
Oglethorpe's net margin for 2000, 1999 and 1998 was $20.0 million, $19.9
million and $21.1 million, respectively. Oglethorpe's margin requirement is
based on a ratio applied to interest charges. For 1999 compared to 1998, the
reduction in interest charges reduced Oglethorpe's margin requirement.
Comprehensive margin for Oglethorpe is net margin adjusted for the net change in
unrealized gains and losses on investments in available-for-sale securities.
Financial Condition
General
The principal changes in Oglethorpe's financial condition in 2000 were due
to property additions, an increase in cash and temporary cash investments and an
increase in patronage capital.
Property additions, including nuclear fuel purchases, totaled $108 million,
and were financed with funds from operations and short-term borrowings.
Oglethorpe's cash and temporary cash investments increased by $108 million
from December 31, 1999 to December 31, 2000.
Oglethorpe achieved a net margin of $20 million in 2000; however,
Oglethorpe's equity (patronage capital) increased by $23 million due to a net
change in unrealized gain on available-for-sale securities.
Capital Requirements
As part of its ongoing capital planning, Oglethorpe forecasts expenditures
required for generation facilities and other capital projects. The table below
details these expenditure forecasts for 2001 through 2003. Actual construction
costs may vary from the estimates listed below because of factors such as
changes in business conditions, fluctuating rates of load growth, environmental
requirements, design changes and rework required by regulatory bodies, delays in
obtaining necessary federal and other regulatory approvals, construction delays,
cost of capital, equipment, material and labor, and decisions whether to
purchase or construct additional generation capacity.
- ----------------------------------------------------------------------
(dollars in thousands)
Capital Expenditures(1)
- ----------------------------------------------------------------------
Year Existing Future Nuclear General
Generation(2) Generation(3) Fuel Plant Total
2001 $ 43,114 $ 280,000 $ 47,247 $ 7,612 $377,973
2002 83,979 141,500 45,768 4,000 275,247
2003 44,413 23,200 48,660 4,120 120,393
- ----------------------------------------------------------------------
Total $ 171,506 $ 444,700 $141,675 $15,732 $773,613
- ----------------------------------------------------------------------
(1) Excludes allowance for funds used during construction.
(2) Consists of capital expenditures required for environmental compliance and
for replacements and additions to facilities in-service.
(3) Expenditures relate to new generation facilities that may ultimately be
owned by a subsidiary of Oglethorpe, by Smarr EMC or by a similar separate
entity.
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $3.3 billion as of December 31, 2000. Expenditures for property
additions during 2000 amounted to $108 million and were funded with a
combination of funds from operations and short-term borrowings. These
expenditures were primarily for additions and replacements to existing
generation facilities, construction of new generation facilities (as discussed
below) and for purchases of nuclear fuel.
Over the past several years, Oglethorpe has been providing interim funding
through its commercial paper program for two combustion turbine generation
facilities that were built to meet the growth of a majority of the Members.
These two facilities are now owned by Smarr EMC, a separate entity created
specifically for this purpose that is owned by 37 of Oglethorpe's 39 Members.
Smarr EMC secured permanent financing for these facilities, the proceeds of
which were used to reimburse Oglethorpe for the interim commercial paper
financings.
34
Oglethorpe continues to fund, on an interim basis, the construction of new
generation facilities on behalf of the participating Members. As of December 31,
2000, $78 million of commercial paper was outstanding for this purpose. The
projects currently being funded include six combustion turbines (totaling 618
MW) and a 468 MW combined cycle facility. Four of the six combustion turbines
are expected to be in-service in the summer of 2002, and the two remaining
combustion turbines and the combined cycle facility are expected to be
in-service in the summer of 2003. The costs associated with the combustion
turbines are reflected in construction work in progress and the costs associated
with the combined cycle facility are reflected in prepayments and other current
assets on Oglethorpe's balance sheet at December 31, 2000. It is anticipated
that these new facilities will ultimately be owned by a subsidiary of
Oglethorpe, Smarr EMC, or a similar separate entity.
Oglethorpe expects to issue the maximum amount of its commercial paper
($260 million) by the fall of 2001 in conjunction with the interim financing of
these new generation facilities. Oglethorpe has submitted loan applications to
RUS to provide financing for these projects and expects a response from RUS
later in 2001. If RUS funding is delayed or denied, Oglethorpe will continue to
finance these projects with funds from operations and will seek additional
construction financing until permanent financing is obtained.
Oglethorpe is also making payments under an agreement to purchase equipment
for a possible combined cycle facility for 2005. At December 31, 2000, $9
million of commercial paper was outstanding that was issued for this purpose,
and the payments are reflected in prepayments and other current assets on
Oglethorpe's balance sheet. If Oglethorpe and the Members elect to build this
project, Oglethorpe anticipates that it will continue to provide interim
construction funding until permanent financing is obtained. The estimated
capital expenditures related to this project, which are not included in the
capital expenditure table above, are approximately $215 million over the next
three years. If this project is not ultimately built, Oglethorpe will pursue a
sale of the equipment.
In addition to the funds needed for capital expenditures, approximately
$453 million will be required over the next three years (2001-2003) for current
sinking fund requirements and maturities of long-term debt. Of this amount, $294
million, or 65%, relates to the repayment of RUS and FFB debt. In addition,
Oglethorpe anticipates that it will refund $143 million of the $453 million due
over the next three years with proceeds from the issuance of new tax-exempt
pollution control bonds ("PCBs").
Liquidity and Sources of Capital
In the past, Oglethorpe has obtained the majority of its long-term
financing from RUS-guaranteed loans funded by FFB. Oglethorpe has also obtained
a substantial portion of its long-term financing requirements from the issuance
of PCBs.
In addition, Oglethorpe's operations have consistently provided a sizable
contribution to its funding of capital requirements, such that internally
generated funds have provided interim funding or long-term capital for nuclear
fuel reloads, general plant facilities, replacements and additions to existing
facilities, and retirement of long-term debt. Oglethorpe anticipates that it
will continue to meet these types of capital requirements through 2003 with
funds generated from operations. As discussed above, Oglethorpe is currently
providing interim financing for new generation facilities with a combination of
short-term borrowings and funds from operations until permanent financing is
obtained.
To meet short-term cash needs and liquidity requirements, Oglethorpe had,
as of December 31, 2000, (i) approximately $331 million in cash and temporary
cash investments, (ii) $82 million in other short-term investments and (iii) up
to $232 million available under the following credit facilities:
- ---------------------------------------------------------------------------
(dollars in thousands)
Authorized Available
Short-Term Credit Facilities Amount Amount
- ---------------------------------------------------------------------------
Committed line of credit:
Commercial paper $ 260,000 $ 182,000
Uncommitted line of credit:
National Rural Utilities
Cooperative Finance
Corporation 50,000 50,000
- ---------------------------------------------------------------------------
35
Under its commercial paper program, Oglethorpe may issue commercial paper
not to exceed $260 million outstanding at any one time. The commercial paper is
backed 100% by committed lines of credit provided by a group of banks that was
syndicated by Bank of America.
Oglethorpe has minimum liquidity requirements in conjunction with certain
financial agreements currently in place. These agreements include the commercial
paper line of credit, the interest rate swap arrangements relating to two PCB
transactions and the Rocky Mountain lease transactions. The maximum amount of
liquidity that could be required under these agreements is $80 million. As of
December 31, 2000, the required amount was $78 million.
Refinancing Transactions
Oglethorpe has a program under which it is refinancing, on a continued
tax-exempt basis, the annual principal maturities of serial bonds and the annual
sinking fund payments of term bonds originally issued on behalf of Oglethorpe by
the Development Authority of Burke County and the Development Authority of
Monroe County. The refinancing of these PCB principal maturities allows
Oglethorpe to preserve a low-cost source of financing. To date, Oglethorpe has
refinanced approximately $111 million under this program, including $22 million
of PCB principal which matured on January 1, 2001. Oglethorpe also has Board
approval to refinance Burke and Monroe principal of $23 million maturing on
January 1, 2002.
In connection with a corporate restructuring in 1997 in which Oglethorpe
sold its transmission assets to GTC, GTC assumed a portion of the indebtedness
associated with PCBs. Under an indemnity agreement executed in connection with
this assumption, GTC is entitled to participate in any refinancing of this PCB
debt by Oglethorpe by agreeing to assume a portion of the refinancing debt.
However, GTC agreed not to participate in Oglethorpe's refinancing of the Burke
and Monroe principal payments due January 1, 2000, 2001 and 2002. Pursuant to
this agreement, Oglethorpe provided a discount of approximately $1.1 million and
received cash of $2.6 million on the $3.7 million due from GTC in connection
with the Burke and Monroe principal payments due January 1, 2001.
The average interest rate on long-term debt was 6.21% at December 31, 2000.
Miscellaneous
Competition
The electric utility industry in the United States continues to undergo
fundamental changes and continues to become increasingly competitive. These
changes have been promoted by:
o the Energy Policy Act of 1992;
o Federal Energy Regulatory Commission ("FERC") policies regarding mergers,
transmission access and pricing and regional transmission organizations;
o federal and state deregulation initiatives;
o increased consolidation and mergers of electric utilities;
o the proliferation of power marketers and independent power producers;
o generation surpluses and deficits and transmission constraints in certain
regional markets;
o generation technology; and
o other factors.
Some states have implemented varying forms of retail competition among
power suppliers. Most other states are either in the process of implementing
retail competition or are studying options relating to retail competition.
Proposed federal legislation could mandate or encourage retail competition in
every state and otherwise deregulate the industry. No legislation related to
retail competition has yet been enacted in Georgia, and no bill is currently
pending in the Georgia legislature which would amend the Georgia Territorial
Electric Service Act (the "Territorial Act") or otherwise affect the exclusive
right of the Members to supply power to their current service territories. As a
36
result of the GPSC's order in the 1998 GPC rate case, the GPSC opened a docket
to address the mechanics of how stranded costs and stranded benefits should be
calculated, the estimated range of stranded costs and benefits, the proper level
of cost recovery, and the proper disposition of any stranded benefits. The GPSC
does not have the authority under Georgia law to order retail competition or
amend the Territorial Act. Oglethorpe and the Members have voluntarily provided
information and are participating in the GPSC proceedings. Oglethorpe and the
Members are also actively monitoring and studying legislative initiatives in
Congress and in other states to take advantage of the experiences of
cooperatives and other utilities in other states to protect their interests in
any future legislative activities in Georgia.
Under current Georgia law, the Members generally have the exclusive right
to provide retail electric service in their respective territories. Since 1973,
however, the Territorial Act has permitted limited competition among electric
utilities located in Georgia for sales of electricity to certain large
commercial or industrial customers. The owner of any new facility may receive
electric service from the power supplier of its choice if the facility is
located outside of municipal limits and has a connected load upon initial full
operation of 900 kilowatts or more. The Members, with Oglethorpe's support, are
actively engaged in competition with other retail electric suppliers for these
new commercial and industrial loads. While the competition for 900-kilowatt
loads represents only limited competition in Georgia, this competition has given
Oglethorpe and the Members the opportunity to develop resources and strategies
to prepare for an increasingly competitive market.
Oglethorpe cannot predict at this time the outcome of the various
developments that may lead to increased competition in the electric utility
industry or the effect of such developments on Oglethorpe or the Members.
Nonetheless, Oglethorpe has taken several steps to prepare for and adapt to the
fundamental changes that have occurred or appear likely to occur in the electric
utility industry and to reduce stranded costs. In 1997, Oglethorpe divided
itself into separate generation, transmission and system operations companies in
order to better serve its Members in a deregulated and competitive environment.
Oglethorpe also has pursued an interest cost reduction program, which has
included refinancings and prepayments of various debt issues, and that has
provided significant cost savings. Oglethorpe has also entered into arrangements
with power marketers to reduce power costs and to provide for future load
requirements without taking all the risk associated with traditional suppliers.
(See "Results of Operations--Power Marketer Arrangements.")
Oglethorpe and the Members continue to consider and evaluate a wide array
of other potential actions to meet future power supply needs, to reduce costs,
to reduce risks of the increasingly competitive generation business and to
respond more effectively to increasing competition. Among the alternatives
subject to such consideration are:
o additional power marketing arrangements or other alliance arrangements;
o whether potential load fluctuation risks in a competitive retail
environment can be shifted to other wholesale suppliers;
o whether power supply requirements will continue to be met by the current
mix of ownership and purchase arrangements;
o whether future power supply resources will be owned by Oglethorpe or by
other entities;
o whether disposition of existing assets or asset classes would be advisable;
o the effects of nuclear license extensions;
o ways to facilitate the prepayment of RUS-guaranteed indebtedness;
o the effects of proliferation of services offered by electric utilities; and
o other regulatory and business changes that may affect relative values of
generation classes or have impacts on the electric industry.
These activities are in various stages of study and consideration. Such
studies and consideration necessarily take account of and are subject to legal,
regulatory and contractual (including financing and plant co-ownership
arrangements) considerations.
Under the Wholesale Power Contracts, the Members may satisfy all or a
portion of their requirements above their existing Oglethorpe purchase
obligations with purchases from Oglethorpe or other suppliers. The Members are
now purchasing varying portions of their requirements from other suppliers.
37
Many Members are also providing or considering proposals to provide
non-traditional products and services such as telecommunications and other
services. Depending on the nature of future competition in Georgia, there could
be reasons for the Members to separate their physical distribution business from
their energy business, or otherwise restructure their current businesses to
operate more effectively under retail competition.
Oglethorpe's ongoing consideration of industry trends and developments in
general, and specifically its strategic alternatives with respect to existing
and future power supply arrangements and its efforts to explore debt prepayments
with RUS, may present opportunities for Oglethorpe to reduce costs, reduce risks
and otherwise to respond more effectively to increasing competition. However,
Oglethorpe cannot predict at this time the results of these matters or any
action Oglethorpe might take based thereon.
Oglethorpe has deferred recognition of certain costs of providing services
to the Members and certain income items pursuant to Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation". Oglethorpe has recordedRegulation." Note 1 of Notes to Financial Statements sets forth the
regulatory assets and liabilities relatedreflected on Oglethorpe's balance sheet as of
December 31, 2000. Regulatory assets represent certain costs that are assured to
its generationbe 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 transmission operations.that will be applied in the future to
reduce Member revenue requirements. (See "General--Rates and Regulation.") In
the event that competitive or other factors result in cost recovery practices
under which Oglethorpe iscan no longer subject toapply the provisions of StatementSFAS No. 71,
Oglethorpe would be required to write off relatedeliminate all regulatory assets and liabilities.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 ofto other assets, including utility plant, and 34
write down the plantwrite-down those assets, if
impaired, to their fair value.
See Note 1 of
Notes to Financial Statements for additional information.Decommissioning Costs
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry regarding
the recognition, measurement and classification of decommissioning costs for
nuclear generating facilities in financial statements of electric utilities. In
response to these questions, the Financial Accounting Standards Board has issued
an Exposure Draft of a proposed Statement on "Accounting for Certain Liabilities
Related to Closure or Removal of Long-Lived Assets".Assets." The proposed Statement
would require the recognition of the entire obligation for decommissioning at
its present value as a liability in the financial statements. Rate-regulated
utilities would also recognize an offsetting asset for differences in the timing
of recognition of the costs of decommissioning for financial reporting and
rate-makingratemaking 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.
Beginning in years 2014 through 2029,Assuming extensions of the respective licenses are not obtained, it is
expected that Plant Hatch and Plant Vogtle units will begin the decommissioning
process.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 whichthat have been set
asideplaced in reserves
for this purpose.
RESULTS OF OPERATIONS
Historical Factors Affecting Financial Performance
OverNew Accounting Pronouncement
As of January 1, 2001, Oglethorpe adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The standard establishes
accounting and reporting requirements for derivative instruments, including
certain derivative instruments embedded in other contracts, and hedging
activities. It requires the past three years,recognition of all derivative instruments as assets
or liabilities in Oglethorpe's Members have absorbed into rates
additional responsibility forbalance 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 costtype of its ownership interestshedge. Oglethorpe's interest rate swap arrangements in
Plant
Vogtle Unitsplace at December 31, 2000 are designated as cash flow hedges. Adoption of SFAS
No. 133 on January 1, and No. 2. These generating units were placed2001, resulted in commercial
operationrecording $33,515,000 of decline in 1987 and 1989, respectively. Oglethorpe has utilized both long-term
contractual arrangements with GPCfair
value to accumulated other comprehensive income and a rate mechanism to allow for a gradual
absorption of costs over several years. In addition, Oglethorpe utilized this
rate mechanism to mitigate the impact of absorbing the costs of the Rocky
Mountain Pumped Storage Hydroelectric Project (Rocky Mountain) which was placed
in service during June and July 1995.
Contractual arrangements with GPC provided that Oglethorpe sell to GPC a
declining percentage of Oglethorpe's entitlement to the capacity and energy of
certain co-owned generating plants during the initial seven to ten years of
operation of such units (GPC Sell-back). As of May 31, 1995, the GPC Sell-back
has expired for all units. The historical ability of Oglethorpe to sell power
from new units to GPC under the GPC Sell-back enabled Oglethorpe to moderate the
effects of the higher costs associated with new generating units on Oglethorpe's
cost of service and, therefore, on the rates charged to Members. Furthermore,
the GPC Sell-back enabled Oglethorpe to obtain the generating capacity needed to
serve anticipated increases in Member loads while minimizing the risks and costs
of excess generating capacity.
Prior to the completion of the first unit of Plant Vogtle in 1987,
Oglethorpe's Board of Directors implemented policies that resulted in the
gradual absorption of the costs of Plant Vogtle by the Members. In each of the
years 1985 through 1995, Oglethorpe exceeded its net margin goal. The Board
adopted resolutions in each of these years requiring that these excess margins
be retained and used to mitigate rate increases associated with Plant Vogtle
and, subsequently, with Rocky Mountain. In each year beginning with 1989, a
portion of these margins was returned to the Members through billing credits.
(See Note 1 of Notes to Financial Statements.) As of December 31, 1996, all
amounts previously retained have been returned to the Members and this rate
mechanism ended.
Operating Revenues
Oglethorpe's operating revenues are derived from sales of electric services
to the Members and non-Members. Revenues from Members are collected pursuant to
wholesale power contracts and are a function of the demand for power by the
Members' consumers and Oglethorpe's cost of service. Historically, most of
Oglethorpe's non-Member revenues resulted from various plant operating
agreements with GPC as discussed below. However, in recent years, an increasing
amount of non-Member revenues has been derived by off-system sales to other
utilities and power marketers.
For the period 1994 through 1996, although total revenues have varied
slightly, the scheduled reduction of the GPC Sell-back has resulted in the
planned decrease of non-Member revenues from GPC of about $45 million. As
expected, the capacity and energy no longer being sold to GPC have been used by
Oglethorpe to meet increased Member requirements. In addition to increasing
sales to Members, Oglethorpe achieved reductions in fixed and operating costs in
order to mitigate the need to recover from the Members costs which were
previously recovered through sales to GPC. The refinancing transactions
discussed under "Financial Condition-Refinancing Transactions" below have
resulted in a reduction in gross interest charges from $330 million in 1994 to
$308 million in 1996, or a 7% decrease in that fixed cost component of the
capacity rates.
As a means of further reducing the cost of power provided to the Members,
Oglethorpe utilized short-term power supply arrangements during 1996. The
35
initial agreement was with Enron Power Marketing, Inc. (EPMI) and was in place
January through August. From September through December 1996, another power
supply arrangement was utilized with Duke/Louis Dreyfus L.L.C. (DLD). Under both
of the agreements, the power marketer was required to provide to Oglethorpe at a
favorable fixed rate all the energy needed to meet the Members' requirements and
Oglethorpe was required to provide to the power marketer at cost, subject to
certain limitations, upon request, all energy available from Oglethorpe's total
power resources. Under both agreements, Oglethorpe continued to operate the
power supply system and continued to dispatch the generating resources to ensure
system reliability.
Sales to Members. Revenues from sales to Members decreased by 0.7% in 1996
compared to 1995 and increased 10.7% in 1995 compared to 1994. These changes
reflect both cost-related and volume-related factors. The 1996 revenues
decreased compared to 1995 due to the fact that the pass-through of savings in
energy costs (see the discussion of savings in purchased power under "Operating
Expenses" herein) more than offset higher capacity revenue requirements and the
effect of increased amounts of energy sold. Thecomparable increase in
revenues between
1995 and 1994 was due to the fact that higher capacity revenue requirements and
additional amounts of energy sold more than offset savings in energy costs (see
the discussion of savings in fuel and purchased power costs under "Operating
Expenses" herein).
As non-Member revenues from GPC have declined, Oglethorpe's Member capacity
revenues have increased to reflect the recovery of the fixed costs which had
previously been recovered from GPC through the GPC Sell-back. (See the
discussion of this type of revenues under "Sales to non-Members" herein.) Member
capacity revenues in 1996 and 1995 were also affected by additional fixed costs
related to the commercial operation of Rocky Mountain beginning in June 1995.
Member energy revenues per kilowatt-hour (kWh) declined 13.2% in 1996
compared to 1995 and declined 7.6% in 1995 compared to 1994. The decrease in
1996 resulted from savings of approximately $32 million in energy costs
(compared to budget) achieved under the power supply arrangements. In 1995, the
decrease reflected savings in fuel and production costs and lower average
purchased power costs. Actual energy costs are passed through to the Members
such that energy revenues equal energy costs.
The following table summarizes the amounts of kWh sold to Members during each of
the past three years:
- --------------------------------------------------------------------------------
Kilowatt-hours
(in thousands)
- --------------------------------------------------------------------------------
1996 19,807,101
1995 18,442,153
1994 16,285,127
- --------------------------------------------------------------------------------
Member sales have been significantly affected by abnormal weather conditions
during two of the past three years. In 1995 prolonged hot weather boosted sales,
while in 1994 record-breaking rainfall amounts statewide moderated Member sales.
Member sales increased 7.4% in 1996 despite a summer in which temperatures were
lower than 1995, due to continued growth in the Member systems' service
territories.
The net impact of the above capacity and energy rate factors, combined with
the spreading of fixed capacity costs over an increasing number of kWh sold each
year, have resulted in the following decreasing trend in average Member revenue
requirements:
- --------------------------------------------------------------------------------
Cents per Kilowatt-hour
- --------------------------------------------------------------------------------
1996 5.11(cent)
1995 5.53
1994 5.65
- --------------------------------------------------------------------------------
Sales to non-Members. Sales of electric services to non-Members are primarily
made pursuant to three different types of contractual arrangements with GPC and
from off-system sales to other non-Member utilities.
The following table summarizes the amounts of non-Member revenues from these
sources for the past three years:
- --------------------------------------------------------------------------------
1996 1995 1994
(dollars in thousands)
- --------------------------------------------------------------------------------
GPC-plant operating agreements $ -- $ 10,096 $ 45,392
GPC-power supply arrangements 13,703 43,226 26,280
ITS transmission agreements 9,789 12,614 10,974
Sales to power marketers 15,895 -- --
Sales to other utilities 38,956 52,828 42,561
------- -------- --------
Total $78,343 $118,764 $125,207
======= ======== ========
- --------------------------------------------------------------------------------
Revenues from sales to non-Members declined in 1996 compared to 1995 and in
1995 compared to 1994. The first two types of non-Member revenues were derived
from contractual agreements with GPC. First, the elimination of the revenues
from the plant operating agreements was due to the scheduled conclusion,
effective June 1, 1995, of the GPC Sell-back with respect to Plant Vogtle.
The second source of non-Member revenues is
36
power supply arrangements with GPC. These revenues are derived, for the most
part, from energy sales arising from dispatch situations whereby GPC causes
co-owned coal-fired generating resources to be operated when Oglethorpe's system
does not require all of its contractual entitlement to the generation. These
revenues essentially represent reimbursement of costs to Oglethorpe because,
under the operating agreements, Oglethorpe is responsible for its share of fuel
costs any time a unit operates. Revenues from sales of this type to GPC were
lower in 1996 compared to 1995 and were higher in 1995 compared to 1994. In
1996, the power marketers elected to retain more of the output from Plant
Wansley, whereas, in 1995, Oglethorpe retained less of its share of the output
from Plant Wansley units because the added cost associated with emission
allowances made those units less attractive than certain purchased resources.
The 1994 revenues reflect the fact that Oglethorpe retained much of its share of
the output from the Plant Scherer and Plant Wansley units because the lower
average fuel costs made those units more attractive than certain purchased
resources. Emission allowances for Plant Wansley were not required in 1994. See
the discussion under "Operating Expenses" herein of the lower average fuel costs
of the coal-fired generating units in 1996 and 1995. Pursuant to the amendments
to the Plant Scherer ownership and operating agreements, Oglethorpe elected to
separately dispatch its ownership interest in Plant Scherer beginning May 1,
1994. Thereafter, Plant Scherer ceased to be a source of this type of sales
transaction. Pursuant to similar amendments to the Plant Wansley operating
agreement, Oglethorpe expects to begin separately dispatching its ownership
interest in Plant Wansley this year.
The third source of non-Member revenues is primarily payments from GPC for
use of the ITS and related transmission interfaces. GPC compensates Oglethorpe
to the extent that Oglethorpe's percentage of investment in the ITS exceeds its
percentage use of the system. In such case, Oglethorpe is entitled to
compensation for the use of its investment by the other ITS participants. The
change in revenues for 1996 through 1994 resulted from normal variations of
Oglethorpe's investment percentages and its use of the system.
Under the EPMI and DLD power supply agreements, sales to the power marketers
represented the net energy transmitted off-system on behalf of EPMI and DLD on a
daily basis from Oglethorpe's total resources. Such energy was sold to EPMI and
DLD at Oglethorpe's cost, subject to certain limitations. Sales to other
non-Member utilities were initiated by EPMI and DLD in 1996 while in 1995 and
1994 these sales were made by Oglethorpe directly with the non-Member utilities.
While Oglethorpe maintains the contractual relationship with these other
utilities and administers the transactions, all profits in 1996 on these sales
to other utilities from Oglethorpe's total resources accrued to EPMI and DLD.
See "Factors Affecting Future Financial Performance" herein regarding
Oglethorpe's new long-term power supply arrangements.
Operating Expenses
Oglethorpe's operating expenses decreased 2.6% in 1996 compared to 1995 and
increased 9.4% in 1995 compared to 1994. The decrease in operating expenses in
1996 compared to 1995 was primarily attributable to energy cost savings achieved
under the short-term power supply arrangements offset somewhat by an increase in
depreciation and amortization. The increase in operating expenses in 1995
compared to 1994 was primarily attributable to a 13% increase in kWhs sold to
Members and non-Members. In addition, depreciation and amortization, sales, and
administrative and general expenses were also higher.
The decrease in total fuel costs in 1996 as compared to 1995 resulted partly
from unplanned outages at Plant Scherer and Plant Wansley Unit No. 1 and partly
from the power marketer electing to dispatch the fossil units less. These
factors resulted in 3.1% lower fossil generation in 1996 compared to 1995. The
increase in total fuel costs in 1995 versus 1994 resulted from 23% higher
generation at Plant Scherer. The continued use of lower-priced western coal
combined with a greater reliance on a favorable spot market for coal resulted in
a per unit fuel cost decrease for Plant Scherer of 5% in 1995 from 1994 levels.
Because of the decline in fuel cost per kWh at Plant Scherer, the usage of the
units increased significantly. Oglethorpe retained significantly less of its
output from Plant Wansley in 1995 compared to 1994 primarily as a result of
relatively higher costs compared to Plant Scherer due to its emission allowance
requirement and due to cost reductions at Plant Scherer discussed above.
Purchased power cost decreased by 14% in 1996 compared to 1995 and increased
by 16% in 1995 compared to 1994. Lower purchased power costs were achieved in
1996 despite the fact that energy purchases increased 15% in 1996 from 1995
levels. The 1996 cost reduction was due to (1) energy cost savings of $32
million realized from the short-term power supply arrangements and (2)
reductions in purchased power capacity costs due to (a) proceeds of $10.8
million from the settlement of a lawsuit with GPC and (b) savings resulting from
the elimination of a 250 MW Component Block (coal-fired units) of the Block
Power Sale Agreement (BPSA) effective September 1, 1996. In 1995, the 13% higher
kWh sales, including the increased Member sales and sales to GPC pursuant to
power supply arrangements (see the discussion under "Operating Revenues" herein)
37
resulted in higher utilization of purchased power resources. Energy purchases
increased 31% in 1995 compared to 1994.
Purchased power expense for 1994 through 1996 reflect 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 1994 through 1996, Oglethorpe utilized its energy from these
purchase power agreements in excess of the take-or-pay requirements.
Oglethorpe's power purchases from these agreements amounted to approximately
$196 million in 1996, $207 million in 1995 and $183 million in 1994. For a
discussion of the power purchase agreements, see Note 9 of Notes to Financial
Statements.
The increase in depreciation and amortization in 1996 is partly due to a
full year of depreciation on Rocky Mountain which began commercial operation in
June 1995 and due to $14 million of Board- approved accelerated amortization of
deferred charges of the discontinued Pickens County pumped storage hydroelectric
project. All remaining unamortized charges related to this project were expensed
in 1996.
Sales, administrative and general expenses increased in 1995 as compared to
1994 primarily resulting from increased marketing efforts in support of the
Members.
Other Income/Expense
Interest income increased in 1996 compared to 1995 and 1995 compared to
1994. In 1996, interest income was higher due to higher average investment
balances. In 1995, interest income increased partly due to higher short-term
interest rates and due to higher investment returns in the decommissioning trust
fund.
In 1996, Oglethorpe utilized all remaining amounts available ($32 million)
under its deferred margin rate mechanism, and, as scheduled, this mechanism
ended. Likewise, deferred margins of $16 million and $18 million were amortized
as credits against Member revenue requirements in 1995 and 1994, respectively,
to mitigate the rate impact of increased capacity costs related to Plant Vogtle
and Rocky Mountain. Also, in 1995 and 1994, Oglethorpe's Board of Directors
authorized the retention of approximately $14 million and $9 million,
respectively, in excess of the 1.07 TIER margin requirement as deferred margins
under the mechanism. (See Note 1 of Notes to Financial Statements for a
discussion of deferred margins and amortization of deferred margins.) The
decrease in amortization of deferred gains in 1996 and 1995 as compared to 1994
resulted from the completion of amortization in September 1994 of a gain on the
sale of Plant Scherer common facilities. (Also see Note 1 of Notes of Financial
Statements for a discussion of the sale.)
Interest Charges
Net interest charges increased in 1996 compared to 1995 and in 1995 compared
to 1994. The increases were due to the fact that the allowances for debt and
equity funds used during construction (AFUDC) decreased in 1996 compared to 1995
and 1995 compared to 1994 as a result of the three units of Rocky Mountain
becoming commercially operable in June and July 1995. The continued decrease in
gross interest on long-term debt and capital leases in 1996 and 1995 was due to
the refinancing efforts discussed under "Financial Condition(Refinancing
Transactions" below. The change in other interest expense in 1995 compared to
1994 was due to higher investment returns in the decommissioning trust fund.
(See Note 1 of Notes to Financial Statements for explanation of Oglethorpe's
accounting for decommissioning gains and losses.)
Factors Affecting Future Financial Performance
Effective January 1, 1997, Oglethorpe entered into power supply agreements
with LPM for 50% of the load requirements of the Members. Under the agreements,
LPM is obligated to deliver, and Oglethorpe is obligated to take, 50% of the
load requirements of the participating Members less the load requirements for
certain customer choice loads (900 kilowatt or greater), plus 50% of the
delivery obligations under Oglethorpe's existing firm power off-system sale
contracts. For customer choice loads of three megawatts or less, LPM is
obligated to deliver if Oglethorpe requests 50% of the associated load
requirements. Oglethorpe is obligated to sell and LPM is obligated to buy, 50%
of the output of each participating Member's PCR share of the "must run" units
(primarily nuclear units). Oglethorpe is also obligated to make available the
same share of all other resources, which LPM may schedule. LPM does not have the
right to the output of upgrades to these resources. LPM must pay Oglethorpe the
cost of fuel associated with the energy taken. There is a price adjustment if
the plant performance does not meet specified levels of availability and output.
Oglethorpe must pay LPM a contractually specified price for each MWh purchased.
Oglethorpe has the option of purchasing the energy requirements for customer
choice loads from another supplier.
Oglethorpe will cause GTC to provide available transmission to deliver to
the border of the ITS any energy sold to LPM. Each Member will use its
Transmission Agreement for delivery of energy purchased from LPM and others.
Effective with the Corporate Restructuring and the execution of supplemental
agreements to the New Wholesale Power Contracts, the LPM agreement relating to
37 of the 39 Members has a term extending to 2011. With one years' notice,
Oglethorpe has the right to terminate the contract for any year beginning with
38
2002. LPM has the right to terminate the contract for any year beginning with
2005. The LPM agreement relating to the other two Members has a term extending
through the end of 1999.
Oglethorpe is now working to finalize a power supply agreement with Morgan
Stanley Capital Group (Morgan Stanley) that would supply the remaining 50% of
the Members' load requirements. The contract is expected to have a term of up to
eight years. Each Member is currently deciding individually whether to have
Oglethorpe obtain its remaining load requirements from Morgan Stanley. Any
Member that elects not to participate in the Morgan Stanley agreement would have
other options available, including having Oglethorpe manage this portion of the
Member's load requirements. In the interim, Oglethorpe is supplying this portion
of its requirements from its own resources and by off-system purchase and sales.
In the event Oglethorpe does not enter into power marketer agreements for the
remainder of its load, it can continue to operate effectively in this manner.
In order to complete the implementation of power marketer arrangements,
Oglethorpe and each Member will enter into supplemental agreements to the New
Wholesale Power Contracts to implement the terms of each power marketing
arrangement under the New Wholesale Power Contracts.
The electric utility industry in the United States is undergoing fundamental
change and is becoming increasingly competitive. This change is promoted by the
Energy Policy Act of 1992 (the "Energy Policy Act"), recently adopted and
proposed policies from FERC regarding transmission access and pricing, increased
consolidation and mergers of electric utilities, the proliferation of
self-generators and independent power producers, surplus generation in certain
regional markets and other factors. The Energy Policy Act and FERC policies
allow for increased competition among wholesale electric suppliers and increased
access to transmission services by such suppliers. The new competitive
environment is subject to rapidly evolving regulatory policy at both the federal
and state levels which is based on a shift to a market-driven environment from a
regulated one. Significant legislative developments at the federal level and in
various state legislative bodies, and regulatory developments at the Federal
Energy Regulatory Commission (FERC) and in state commissions, are expected to
continue to clarify policy and the regulatory framework for increased
competition. All of these factors present an increasing challenge to Oglethorpe
and the Members to reduce costs, manage resources and respond to the changing
environment.liabilities.
Inflation
As with utilities generally, inflation has the effect of increasing the
cost of Oglethorpe's operations and construction program. Operating and
construction costs have been less affected by inflation over the last few years
because rates of inflation have been relatively low.
FINANCIAL CONDITION
General
The principalForward-Looking Statements and Associated Risks
This Annual Report on Form 10-K contains forward-looking statements,
including statements regarding, among other items, (i) anticipated trends in
Oglethorpe's business, (ii) Oglethorpe's future power supply requirements,
resources and arrangements and (iii) disclosures regarding market risk included
in Item 7A. Some forward-looking statements can be identified by use of terms
such as "may," "will," "expects," "anticipates," "believes," "intends,"
"projects" or similar terms. These forward-looking statements are based largely
on Oglethorpe's current expectations and are subject to a number of risks and
uncertainties, certain of which are beyond Oglethorpe's control. For certain
factors that could cause actual results to differ materially from those
anticipated by these forward-looking statements, see "Competition" herein and
"OGLETHORPE'S POWER SUPPLY RESOURCES--Future Power Resources", "THE MEMBERS AND
THEIR POWER SUPPLY RESOURCES--Future Power Resources" and "FACTORS AFFECTING THE
ELECTRIC UTILITY INDUSTR in Item 1. In light of these risks and uncertainties,
Oglethorpe can give no assurance that events anticipated by the forward-looking
statements contained in this Annual Report will in fact transpire.
39
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oglethorpe is exposed to market risk, including changes in Oglethorpe's financial condition in 1996 were
additions of $43 million to gross utility plant and a decreaseinterest rates,
in the costvalue of capital achieved through the refinancing of $106 million of long-term debt. The
average interest rate on long-term debt decreased from 6.76% at December 31,
1995 to 6.56% at December 31, 1996.
In addition, Oglethorpe completed a long-term lease transaction on its share
of Rocky Mountain which produced approximately $96 million of net proceeds. (For
a further discussion of this transaction, see "Rocky Mountain Transactions"
below.)
Capital Requirements
As part of its ongoing capital planning, Oglethorpe forecasts expenditures
required for generation facilitiesequity securities, and other capital projects. The table below
details these expenditures for 1997 through 1999. 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,
and cost of capital, equipment, material and labor.
- --------------------------------------------------------------------------------
Capital Expenditures(1)
(dollars in thousands)
- --------------------------------------------------------------------------------
Generating Nuclear General
Year Plant(2) Fuel Plant AFUDC(3) Total
1997 $14,753 $ 44,271 $ 3,715 $1,882 $ 64,621
1998 14,142 33,148 3,827 1,804 52,921
1999 11,250 35,549 3,941 1,435 52,175
------- -------- ------- ------ --------
Total $40,145 $112,968 $11,483 $5,121 $169,717
======= ======== ======= ====== ========
(1) Not included in the above amounts are capital expenditures which became the
responsibilitymarket price of GTC and GSOC as of the Closing of the Corporate Restructuring.
For the period 1997 through 1999, these expenditures total $135 million for GTC
and $1 million for GSOC.
(2) Consists of capital expenditures required for replacements and additions to
facilities in service and compliance with environmental regulations..
(3) Allowance for funds used during construction of generation and general plant
facilities.
- --------------------------------------------------------------------------------
Currently, Oglethorpe does not have any new generation facilities under
construction, and management does not anticipate the need for construction of
any new capacity well into the future. (See "Results of Operations-Factors
Affecting Future Financial Performance" for a discussion of the long-term power
supply arrangements.)
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $4.4 billion as of December 31, 1996. Expenditures for property
additions during 1996 amounted to $94 million, of which
39
$91 million was provided from operations. These expenditures were primarily for
additions and replacements to generation and transmission facilities.
In addition to the funds needed for capital expenditures, approximately $271
million will be required over the next three years for sinking fund requirements
and maturities of long-term debt. Of this amount, $216 million, or 80%, relates
to the repayment of RUS and FFB debt. Excluded from these amounts is the amount
of debt assumed by GTC and GSOC as part of the Corporate Restructuring. (See
"General-Corporate Restructuring" and Note 5 of Notes to Financial Statements
for further discussion regarding long-term debt maturities.)
Liquidity and Sources of Capital
In the past, Oglethorpe, like most other G&Ts, has obtained the majority of
its long-term financing from RUS-guaranteed loans funded by FFB. Oglethorpe has
also obtained a substantial portion of its long-term financing requirements from
tax-exempt PCBs.
In addition, Oglethorpe's operations have consistently provided a sizable
contribution to the funding of capital requirements, such that internally
generated funds have provided interim funding or long-term capital for nuclear
fuel reloads, new generation, transmission and general plant facilities,
replacements and additions to existing facilities, and retirement of long-term
debt. Oglethorpe anticipates that it will meet its future capital requirements
through 1999 primarily with funds generated from operations and, if necessary,
with short-term borrowings.
To meet short term cash needs and liquidity requirements, Oglethorpe had, as
of December 31, 1996, (i) approximately $133 million in cash and temporary cash
investments, (ii) $91 million in other short term investments and (iii)
available credit facilities as follows:
- --------------------------------------------------------------------------------
Short-Term Credit Facilities Authorized Amount
- --------------------------------------------------------------------------------
Commercial Paper ..............................................$250,000,000
Committed lines of credit:
SunTrust Bank, Atlanta .......................................30,000,000
Uncommitted lines of credit:
National Rural Utilities Cooperative
Finance Corporation (CFC) ...............................50,000,000
- --------------------------------------------------------------------------------
Under its commercial paper program, Oglethorpe may issue commercial paper
not to exceed $250 million outstanding at any one time. The commercial paper is
backed 100% by committed lines of credit provided by a group of banks for which
SunTrust Bank, Atlanta acts as agent. Proceeds from the issuance of commercial
paper may be used for working capital requirements and for general corporate
purposes.
The maximum amount that can be outstanding at any one time under the
commercial paper program and the lines of credit totals $250 million due to
certain restrictions contained in the SunTrust Bank and CFC line of credit
agreements. As of December 31, 1996, no commercial paper was outstanding and
there was no outstanding balance on any line of credit. In March 1997,
Oglethorpe issued approximately $92 million of commercial paper to fund the
defeasance of certain PCBs in conjunction with the Corporate Restructuring. (See
"Refinancing Transactions" below for a further discussion of this defeasance.)
Refinancing Transactions
Over the past few years, Oglethorpe has implemented a program to reduce its
interest costs by refinancing or prepaying a sizable portion of its
high-interest rate PCB and FFB debt. Since the first transaction was completed
in June 1992, Oglethorpe has refinanced $1.1 billion in PCB debt and $1.2
billion in FFB debt and has prepaid another $105 million in FFB debt. Included
in these amounts are a January 1996 refinancing of $89 million of FFB debt and
an October 1996 refinancing of $16 million of PCB debt. (See Note 5 of Notes to
Financial Statements.) The net result of the 1996 transactions was to reduce the
average interest rate on total long-term debt from 6.76% at December 31, 1995 to
6.56% at December 31, 1996. The refinancings completed since the program began
resulted in total annual savings in 1996 of more than $90 million in gross
interest expense and $80 million in net interest expense (net of prepayment
penalties and transaction costs).electricity.
Oglethorpe's use of derivative financial derivativesor commodity instruments is for the
purpose of mitigating business risks and is not used for speculativetrading purposes.
Derivatives have been
used onOglethorpe has established a very limited basis, as discussedRisk Management Committee to provide general
management oversight over all risk management activities, including commodity
trading, fuels management, debt management and investment portfolio management.
The committee consists of senior executive officers, including the Chief
Executive Officer and the Chief Operating Officer. The committee has implemented
a comprehensive risk management policy, which includes authority limits and
credit policies. The committee regularly meets, reviews risk management reports
and reports activities to the Audit Committee of the Board of Directors.
Interest Rate Risk
Oglethorpe is exposed to the risk of changes in interest rates due to the
significant amount of financing obligations it has entered into, including fixed
and variable rate debt and interest rate swap transactions. Oglethorpe's
objective in managing interest rate risk is to maintain a balance of fixed and
variable rate debt that will lower its overall borrowing costs within reasonable
risk parameters. As part of this debt management strategy, Oglethorpe has a
guideline of having between 15% and 30% variable rate debt to total debt. At
December 31, 2000, Oglethorpe had 14% of its debt in a variable rate mode.
The table below details Oglethorpe's debt instruments and provides the fair
value at December 31, 1996, any
credit risk for derivatives2000, the outstanding was not material.balance at the beginning and end of
each year and the annual principal maturities and associated average interest
rates.
(dollars in thousands)
Fair Value Cost
----------- ------------------------------------------------------------------------------
2000 2001 2002 2003 2004 2005 Thereafter
---- ---- ---- ---- ---- ---- ----------
Fixed Rate Debt
- ---------------
Beginning of year $2,438,663 $2,321,527 $2,219,056 $2,059,686 $1,939,763 $1,810,010
Maturities (117,136) (102,471) (159,370) (119,923) (129,753)
--------- --------- --------- --------- ---------
End of year $2,644,443 $2,321,527 $2,219,056 $2,059,686 $1,939,763 $1,810,010
========= ========= ========= ========= =========
Average interest rate 6.09% 6.07% 6.18% 6.08% 6.09% 6.48%
Variable Rate Debt
- ------------------
Beginning of year $ 447,031 $ 441,492 $ 436,911 $ 386,218 $ 381,545 $376,810
Maturities (5,539) (4,581) (50,693) (4,673) (4,735)
--------- --------- --------- --------- ---------
End of year $443,924 $ 441,492 $ 436,911 $ 386,218 $ 381,545 $ 376,810
========= ========= ========= ========= =========
Average interest rate(1) 5.37% 5.35% 5.46% 5.51% 5.46% 4.71%
Interest Rate Swaps(2)
- -------------------
Beginning of year $ 260,149 $ 256,001 $ 251,420 $ 246,536 $ 241,315 $238,343
Maturities (4,148) (4,581) (4,884) (5,221) (2,972)
--------- --------- --------- --------- ---------
End of year $260,149 $ 256,001 $ 251,420 $ 246,536 $ 241,315 $ 238,343
========= ========= ========= ========= =========
Average interest rate 5.82% 5.83% 5.83% 5.83% 5.67% 5.80%
Unrealized loss on swaps ($33,515)
(1) Future variable debt interest rates are adjusted based on a forward U.S.
Treasury yield curve.
(2) The interest rate swaps converted variable rate underlying debt to a fixed
rate.
40
Interest Rate Swap Transactions
To refinance high-interest rate PCBs, Oglethorpe entered into two interest
rate swap transactions with a swap counterparty, AIG Financial Products Corp.
(AIG-FP)("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 agreementsarrangements 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 agreements,arrangements, Oglethorpe is obligated to make periodic
payments to AIG-FP based on a notional principal amount equal to the aggregate
prin-
40
cipalprincipal amount of the bonds outstanding during the period and a contractual
fixed rate (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)("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 affectsaffect whether
Oglethorpe is obligated to make payments to AIG-FP or is entitled to receive
payments from AIG-FP, the effective interest rate Oglethorpe pays with respect
to the PCBs is not affected by changes in interest rates. The Fixed Rate for the
$200 million of variable rate bonds issued in 1993 is 5.67% and the Fixed Rate
for the $122 million of variable rate bonds issued in 1994 is 6.01%. At December
31, 2000, the bonds issued in 1993 carried a variable rate of interest of 4.90%
and the bonds issued in 1994 carried a variable rate of interest of 4.95%. For
the three years ended December 31, 1994, 19951998, 1999 and 1996,2000, Oglethorpe has made in
connection with both interest rate swap arrangements combined net swap payments
to AIG-FP (net of $6.0 million, $6.4amounts assumed by GTC) of $6.3 million, and $8.2$6.7 million, and
$4.3 million, respectively.
The swap arrangements extend for the life of these PCBs. If the swap
arrangements were to be terminated while the PCBs are still outstanding,
Oglethorpe or AIG-FP may owe the other party a termination payment depending on
a number of factors, including whether the fixed rate then being offered under
comparable swap arrangements is higher or lower than the Fixed Rate. Under the
terms of the swap agreements, AIG-FP has limited rights to terminate the swaps
only upon the occurrence of specified events of default or a reduction in
ratings on Oglethorpe's PCBs, without credit enhancement, to a level that is
below investment grade. Oglethorpe estimates that its maximum aggregate
liability (net of GTC's assumed percentage) for termination payments under both
swap arrangements had such payments been due on December 31, 19962000 would have
been approximately $34$33.5 million.
(For additional information aboutScherer Unit No. 2 Capital Lease
In December 1985, Oglethorpe sold and subsequently leased back from four
purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The
capital leases provide that Oglethorpe's rental payments vary to the swap arrangements, seeextent of
interest rate changes associated with the debt used by the lessors to finance
their purchase of undivided ownership shares in the unit. The debt currently
consists of $224,702,000 in serial facility bonds due June 30, 2011 with a 6.97%
fixed rate of interest.
41
Equity Price Risk
Oglethorpe maintains trust funds, as required by the NRC, to fund certain
costs of nuclear decommissioning. (See Note 21 of Notes to Financial Statements.Statements
in Item 8.) In connection withAs of December 31, 2000, these interest rate swap agreements,funds were invested primarily in
domestic equity securities, U.S. Government and corporate debt securities and
asset-backed securities. By maintaining a portfolio that includes long-term
equity investments, Oglethorpe is
obligatedintends to maintain minimum liquiditymaximize the returns to be utilized to
fund nuclear decommissioning, which in an amount equalthe long-term will better correlate to
25%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 principal amountfund's equity securities as of
December 31, 2000 would result in a loss of value to the fund of approximately
$9 million. Oglethorpe actively monitors its portfolio by benchmarking the
performance of its investments against certain indexes and by maintaining, and
periodically reviewing, established target allocation percentages of the variable rate refunding bonds outstanding. This minimum
liquidity requirement currently equals $81 millionassets
in its trusts to various investment options. Because realized and will decrease
proportionately as such bonds are retired as a result of scheduled sinking fund
payments.
In connection with the Corporate Restructuring, Oglethorpe defeased
approximately $92 million in principal amount of Series 1992 PCBs. Initially
these bonds have been defeased through the issuance of commercial paper.
Oglethorpe may refinance the commercial paper issuance with medium-term notes at
some pointunrealized
gains and losses from investment securities held in the future and expectsdecommissioning fund are
directly added to refinanceor deducted from the commercial paperdecommissioning reserve, fluctuations in
equity prices or such
medium-term notes in late 2002 with PCBs.
Also, in connection with the Corporate Restructuring, Oglethorpe refinanced
approximately $217 million in principal amount of Series 1992A PCBs through the
issuance of refunding bonds having a nine-month maturity (the Series 1997A
bonds). Payment of principal and interest on the Series 1997A bonds are insured
by a municipal bond insurance policy issued by AMBAC Indemnity Corporation. In
connection with the AMBAC insurance, Oglethorpe is obligated to maintain
liquidity in an amount at least equal to the principal amount of the Series
1997A bonds outstanding plus interest accrued thereon. The maximum amount of
this liquidity requirement during the nine-month period equals approximately
$223 million. Oglethorpe currently expects to refinance the Series 1997A bondsrates do not affect Oglethorpe's net margin in the
second halfshort-term.
Commodity Price Risk
The market price of 1997 with another series of PCBs.
Rocky Mountain Transactions
Oglethorpe completed, in two separate closings on December 31, 1996 and
January 3, 1997, lease transactions for its 74.61% undivided ownership interest
in Rocky Mountain. Under the terms of these transactions, Oglethorpe leased the
facility to three institutional investors for a term of 71 years, who in turn
leased it back to Oglethorpe for a term of 30 years. The transactions are
characterized as a sale and lease-back for income tax purposes, but not for
financial reporting purposes. Rocky Mountainelectricity 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 liensupply of energy to the
Members. To secure a firm supply of electricity and to limit price volatility
associated with electricity purchases, Oglethorpe has taken several actions.
Oglethorpe supplies substantially all of the Master Indenture. The leasehold interest transferredMembers' requirements from a
combination of owned and leased generating plants and power purchased under
long-term contracts with other power suppliers and power marketers. Therefore,
only a small percentage of Oglethorpe's requirements is purchased in the
short-term market, and further only a small portion of these requirements is
covered by derivative commodity instruments. Oglethorpe's market price risk
exposure on these instruments is not material.
Oglethorpe has entered into a service agreement with ACES Power Marketing
("APM") under which APM acts as Oglethorpe's agent in the purchase and sale of
short-term wholesale power. APM also provides related risk management services.
APM is subject to Oglethorpe's risk management policies, including trading
authority limits. APM is an organization owned by several generation and
subordinatetransmission cooperatives that provides energy trading services to such lien.rural
electric cooperatives.
Oglethorpe will continueis also exposed to controlrisks of changing prices for fuels, including
coal and operatenatural gas. Oglethorpe has interests in 1,501 MW of coal-fired
capacity. Oglethorpe purchases coal under long-term contracts and in spot-market
transactions. Oglethorpe's long-term coal contracts provide volume flexibility
and fixed prices.
Oglethorpe has several power purchase contracts under which approximately
805 MW of capacity and associated energy is supplied by gas-fired facilities,
including the plant duringpower purchase contracts with Doyle and Hartwell. Under these
contracts, Oglethorpe is exposed to variable energy charges, which incorporate
each facility's actual operation and maintenance and fuel costs. Oglethorpe has
the lease-back term,right to purchase natural gas for the Doyle and it fully intendsHartwell facilities and
exercises this right from time to repurchase tax ownershiptime to actively manage the cost of energy
supplied from these contracts and the underlying natural gas price and
operational risks.
In providing operation management services for Smarr EMC, Oglethorpe
negotiates natural gas supply and transportation contracts on behalf of Smarr
EMC, ensures that the Smarr facilities have fuel available for operations, and
42
assists Smarr EMC in managing its exposure to retain all other rights of ownershipnatural gas price and operational
risks. Oglethorpe expects to provide similar services for the gas-fired
combustion turbine and combined cycle projects currently under construction.
(See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES--Member Power Supply
Resources" in Item 1 and "PROPERTIES--Generating Facilities" and "--Fuel Supply"
in Item 2.)
Oglethorpe purchases natural gas for the above purposes under short-term
contracts that cannot be settled in cash. Oglethorpe currently has no derivative
commodity instruments with respect to coal or natural gas.
Changes in Risk Exposure
Oglethorpe's exposure to changes in interest rates, the plant atprice of equity
securities it holds, and electricity prices have not changed materially from the
end of the
lease-backprevious reporting period. As a result of these transactions, Oglethorpe received net
proceeds of approximately $96 million which is being recorded as a deferred
credit and will be recognized in income over the term of the lease-back.
Approximately $91 million of the proceeds will be used for the early retirement
of FFB debt, with the remaining $5 million being used to pay alternative minimum
taxes on the transactions. The combination of the debt prepayment and the
amortized gain will result in an estimated $11 million in annual savings. In
connection with these transactions, Oglethorpe is obligated to maintain
liquiditynot aware of approximately $50 million.
41any facts or circumstances
that would significantly impact such exposure in the near future.
43
ItemITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index To Financial Statements
Page
----
Statements of Revenues and Expenses,
For the Years Ended December 31, 1996, 19952000, 1999 and 1994...................................... 431998................... 45
Statements of Patronage Capital,
For the Years Ended December 31, 1996, 19952000, 1999 and 1994...................................... 431998................... 45
Balance Sheets, As of December 31, 19962000 and 1995......................... 441999.......................... 46
Statements of Capitalization, As of December 31, 19962000 and 1995........... 461999............ 48
Statements of Cash Flows,
For the Years Ended December 31, 1996,
19952000, 1999 and 1994......................................................... 471998 .................. 49
Notes to Financial Statements, including pro-forma financial
statements relating to the Corporate Restructuring.................... 48Statements............................................. 50
Report of Management..................................................... 60
ReportsManagement...................................................... 63
Report of Independent Public Accountants................................ 60
42Accountants......................................... 63
44
STATEMENTS OF REVENUES AND EXPENSES
For the years ended December 31, 1996, 1995 and 1994
- ------------------------------------------------------------------------------------------------------STATEMENTS OF REVENUES AND EXPENSES
For the years ended December 31, 2000, 1999 and 1998
(dollars in thousands)
1996 1995 19942000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
Operating revenues (Note 1):
Sales to Members $ 1,023,0941,146,064 $ 1,030,7971,122,336 $ 930,8751,095,904
Sales to non-Members 78,343 118,764 125,207
----------- ----------- -----------53,333 53,896 48,263
- -----------------------------------------------------------------------------------------------------------------------------
Total operating revenues 1,101,437 1,149,561 1,056,082
----------- ----------- -----------1,199,397 1,176,232 1,144,167
- -----------------------------------------------------------------------------------------------------------------------------
Operating expenses:
Fuel 206,524 219,062 203,444216,952 196,182 191,399
Production 129,178 133,858 132,723215,834 215,517 198,378
Purchased power (Note 9) 229,089 264,844 227,477
Power delivery 18,216 17,520 16,965
Sales, administrative and general 42,289 39,015 32,269403,574 401,719 387,662
Depreciation and amortization 163,130 139,024 131,056
Taxes other than income taxes 30,262 27,561 24,741142,082 130,883 124,074
Income taxes (Note 3) -- -- --
----------- ----------- ------------ - -
- -----------------------------------------------------------------------------------------------------------------------------
Total operating expenses 818,688 840,884 768,675
----------- ----------- -----------978,442 944,301 901,513
- -----------------------------------------------------------------------------------------------------------------------------
Operating margin 282,749 308,677 287,407
----------- ----------- -----------220,955 231,931 242,654
- -----------------------------------------------------------------------------------------------------------------------------
Other income (expense):
InterestInvestment income 23,485 18,031 10,51842,897 33,262 27,767
Amortization of deferred gains (Notes 1 and 4) 2,341 2,341 9,9852,475 2,475 2,486
Amortization of net benefit of sale of income
tax benefits (Note 1) 8,054 8,043 8,102
Amortization of deferred margins (Note 1) 32,047 15,959 18,072
Deferred margins (Note 1) -- (14,282) (9,287)11,195 11,195 11,195
Allowance for equity funds used during
construction (Note 1) 238 1,715 2,907204 180 158
Other (831) 1,903 498
----------- ----------- -----------4,068 3,433 687
- -----------------------------------------------------------------------------------------------------------------------------
Total other income 65,334 33,710 40,795
----------- ----------- -----------60,839 50,545 42,293
- -----------------------------------------------------------------------------------------------------------------------------
Interest charges:
Interest on long-term debt and capital leases 308,013 317,968 329,738221,893 224,489 236,692
Other interest 10,006 12,979 3,85621,954 18,531 12,086
Allowance for debt funds used during construction (Note 1) (2,576) (21,114) (36,113)(3,522) (1,570) (1,679)
Amortization of debt discount and expense 10,888 10,296 7,639
----------- ----------- -----------21,491 21,088 16,768
- -----------------------------------------------------------------------------------------------------------------------------
Net interest charges 326,331 320,129 305,120
----------- ----------- -----------261,816 262,538 263,867
- -----------------------------------------------------------------------------------------------------------------------------
Net margin 19,978 19,938 21,080
Net change in unrealized gain (loss) on
available-for-sale securities 2,679 (2,614) 1,112
- -----------------------------------------------------------------------------------------------------------------------------
Comprehensive margin $ 21,75222,657 $ 22,25817,324 $ 23,082
=========== =========== ===========
STATEMENTS OF PATRONAGE CAPITAL
For the years ended December 31, 1996, 1995 and 1994
22,192
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
STATEMENTS OF PATRONAGE CAPITAL
For the years ended December 31, 2000, 1999 and 1998
(dollars in thousands)
1996 1995 1994
2000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
Patronage capital and membership fees -
beginning of year (Note 1) $ 338,891370,025 $ 309,496352,701 $ 289,982
Net330,509
Comprehensive margin 21,752 22,258 23,082
Change in unrealized gain (loss) on available-for-sale
securities, net of income taxes (Note 2) (4,414) 7,137 (3,568)
----------- ----------- -----------22,657 17,324 22,192
- -----------------------------------------------------------------------------------------------------------------------------
Patronage capital and membership fees-endfees - end of year $ 356,229392,682 $ 338,891370,025 $ 309,496
=========== =========== ===========
352,701
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
43
45
BALANCE SHEETS
December 31, 1996 and 1995
- --------------------------------------------------------------------------------------------BALANCE SHEETS
December 31, 2000 and 1999
(dollars in thousands)
2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Assets 1996 1995
Electric plant (Notes 1, 4 and 6):
In service $ 5,742,5974,883,680 $ 5,699,2134,854,037
Less: Accumulated provision for depreciation (1,488,272) (1,362,431)
----------- -----------
4,254,325 4,336,782(1,752,176) (1,625,933)
- -----------------------------------------------------------------------------------------------------------------------------
3,131,504 3,228,104
Nuclear fuel, at amortized cost 86,722 94,013
Plant acquisition adjustments, at amortized cost 4,153 5,21483,470 84,565
Construction work in progress 31,181 35,753
----------- -----------
4,376,381 4,471,762
----------- -----------62,357 18,299
- -----------------------------------------------------------------------------------------------------------------------------
Total electric plant 3,277,331 3,330,968
- -----------------------------------------------------------------------------------------------------------------------------
Investments and funds (Notes 1 and 2):
Decommissioning fund, at market 148,300 135,703
Deposit on Rocky Mountain transactions, at cost 63,665 59,579
Bond, reserve and construction funds, at market 53,955 56,511
Decommissioning fund, at market 86,269 74,49229,167 31,158
Investment in associated organizations,companies, at cost 15,379 15,853
Deposit on Rocky Mountain transactions,19,997 17,919
Other, at cost 41,685 --
----------- -----------
197,288 146,856
----------- -----------1,513 2,535
- -----------------------------------------------------------------------------------------------------------------------------
Total investments and funds 262,642 246,894
- -----------------------------------------------------------------------------------------------------------------------------
Current assets:
Cash and temporary cash investments, at cost (Note 1) 132,783 201,151330,622 222,814
Other short-term investments, at market 91,499 79,16581,715 75,482
Receivables 113,289 99,559143,353 109,705
Inventories, at average cost (Note 1) 89,825 82,94975,389 89,766
Notes receivable (Note 5) 1,032 94,070
Prepayments and other current assets 14,625 14,325
----------- -----------
442,021 477,149
----------- -----------59,824 19,293
- -----------------------------------------------------------------------------------------------------------------------------
Total current assets 691,935 611,130
- -----------------------------------------------------------------------------------------------------------------------------
Deferred charges:
Premium and loss on reacquired debt, being amortized (Note 5) 201,007 200,794175,944 196,289
Deferred amortization of Scherer leasehold (Note 4) 90,717 87,134102,753 101,404
Discontinued projects, being amortized (Note 1) 9,490 28,020
Deferred debt expense, being amortized 21,703 21,13516,968 17,070
Other (Note 1) 33,058 33,666
----------- -----------
346,485 342,729
----------- -----------31,107 32,847
- -----------------------------------------------------------------------------------------------------------------------------
Total deferred charges 336,262 375,630
- -----------------------------------------------------------------------------------------------------------------------------
Total assets $ 5,362,1754,568,170 $ 5,438,496
=========== ===========
The accompanying notes are an integral part of these balance sheets.
444,564,622
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
46
- ------------------------------------------------------------------------------------------------
(dollars in thousands)
2000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Equity and Liabilities 1996 1995
Capitalization (see accompanying statements):
Patronage capital and membership fees (Note 1) $ 356,229392,682 $ 338,891370,025
Long-term debt 4,052,470 4,207,3203,019,019 3,103,590
Obligation under capital leases (Note 4) 293,682 296,478267,449 275,224
Obligation under Rocky Mountain transactions (Note 1) 41,685 --
---------- ----------
4,744,066 4,842,689
---------- ----------63,665 59,579
- -----------------------------------------------------------------------------------------------------------------------------
Total capitalization 3,742,815 3,808,418
- -----------------------------------------------------------------------------------------------------------------------------
Current liabilities:
Long-term debt and capital leases due within one year 159,622 89,675
Deferred margins to be refunded within one year (Note 1) -- 32,0475) 136,053 129,419
Accounts payable 42,891 48,855114,964 69,555
Notes payable (Note 5) 78,482 88,479
Accrued interest 15,931 91,096
Accrued and withheld taxes 4,940 1,78567,394 50,201
Other current liabilities 14,022 18,007
---------- ----------
237,406 281,465
---------- ----------23,691 9,344
- -----------------------------------------------------------------------------------------------------------------------------
Total current liabilities 420,584 346,998
- -----------------------------------------------------------------------------------------------------------------------------
Deferred credits and other liabilities:
Gain on sale of plant, being amortized (Note 4) 58,527 60,86853,332 55,807
Net benefit of sale of income tax benefits, being amortized (Note 1) 42,049 50,19410,012 18,021
Net benefit of Rocky Mountain transactions, being amortized (Note 1) 70,701 --82,819 86,004
Accumulated deferred income taxes (Note 3) 61,985 65,51063,485 63,203
Decommissioning reserve (Note 1) 124,468 114,049174,553 164,510
Other 22,973 23,721
---------- ----------
380,703 314,342
---------- ----------20,570 21,661
- -----------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 404,771 409,206
- -----------------------------------------------------------------------------------------------------------------------------
Total equity and liabilities $ 4,568,170 $ 4,564,622
- -----------------------------------------------------------------------------------------------------------------------------
Commitments and Contingencies (Notes 4 9 and 11)
$5,362,175 $5,438,496
========== ==========9)
- -----------------------------------------------------------------------------------------------------------------------------
4547
STATEMENTS OF CAPITALIZATION
December 31, 1996 and 1995
- ----------------------------------------------------------------------------------------------------------STATEMENTS OF CAPITALIZATION
December 31, 2000 and 1999
(dollars in thousands)
1996 19952000 1999
- -----------------------------------------------------------------------------------------------------------------------------
Long-term debt (Note 5):
Mortgage notes payable to the Federal Financing Bank (FFB) at interest rates
varying from 5.27%4.66% to 9.51%8.43% (average rate of 6.95%6.40% at December 31, 1996)2000)
due in quarterly installments through 2023 ............................................................. $ 3,172,851 $ 3,253,636$2,248,502 $2,326,730
Mortgage notes payable to the Rural Utilities Service (RUS) at an interest
rate of 5% due in monthly installments through 2021 .......... 22,475 22,98313,344 13,749
Mortgage notes issued in conjunction with the sale by public authorities of
pollution control revenue bonds:bonds (PCBs):
o Series 19821992A
Serial bonds, 10.60%, due serially through 1997 .......................... 6,675 6,675
o Series 1992
Term bonds, 7.50% to 8.00%, due 2003 to 2022 ............................. 92,130 92,130
oSeries 1992A
Adjustable tender bonds, 3.40% to 3.70%, due 2025 ........................ 216,925 216,925
Serial bonds, 5.35%5.95% to 6.80%, due serially from 19982001 through 2012 ........ 124,690 129,760107,820* 113,745*
o Series 1993
Serial bonds, 3.55%4.35% to 5.25%, due serially from 19972001 through 2013 ........ 37,255 38,11033,410* 34,544*
o Series 1993A
Adjustable tender bonds, 4.00%4.90%, due 2001 through 2016 ................................. 199,690 199,690192,420* 195,015*
o Series 1993B
Serial bonds, 3.75%4.35% to 5.05%, due serially from 19982001 through 2008 ........ 126,935 136,745105,980* 113,750*
o Series 1994
Serial bonds, 4.20%6.0% to 7.125%, due serially from 19972001 through 2015 ....... 10,365 10,6908,930* 9,315*
Term bonds, 7.15%, due 2016 to 2021 ............................................... 11,550 11,55011,550* 11,550*
o Series 1994A
Adjustable tender bonds, 4.00%4.95%, due 2001 to 2019 ................................. 122,740 122,740120,500* 122,740*
o Series 1994B
Serial bonds, 5.45%6.00% to 6.45%, due serially from 19982001 through 2005 ........ 11,140 12,4757,585* 9,125*
o Series 1998A
Adjustable tender bonds, 4.10% to 4.40%, due 2019 116,925* 116,925*
o Series 1998B
Adjustable tender bonds, 4.10% to 4.45%, due 2019 100,000* 100,000*
o Series 1999A
Adjustable tender bonds, 5.10%, due 2020 20,070 20,070
o Series 1999B
Adjustable tender bonds, 5.10%, due 2020 68,705 68,705
Unsecured notes issued in conjunction with the sale by public authorities of
pollution control revenue bonds:
o Series 19952000
Adjustable ratetender bonds, 3.70% to June 1996,5.10%, due in 2015 ................... -- 21,670
o Series 1996
Adjustable rate bonds, 3.88% to April 1997, due in 2017 .................. 37,885 --2021 21,950 -
CoBank, ACB notes payable:
o Headquarters mortgage note payable: fixed at 6.60%7.52% through April 1997,July 31, 2001,
due in quarterly installments through January 1, 2009 ................... 4,672 5,1593,212 3,602
o Transmission mortgage note payable: fixed at 6.50%8.13% through September 1997;February 28, 2001;
due in bimonthlybi-monthly installments through November 1, 2018 ... 2,237 2,2611,770 1,797
o Transmission mortgage note payable: fixed at 6.50%8.13% through October 1997;February 28, 2001;
due in bimonthlybi-monthly installments through September 1, 2019 ...................... 8,556 8,637
----------- -----------
4,208,771 4,291,836
Less:Unamortized debt discount ............................................. (766) (832)
----------- -----------6,815 6,906
o Medium-term loan, variable at 7.23% to 7.36%, due at various maturities
through October 2001, due March 31, 2003 46,065 46,065
National Rural Utilities Cooperative Finance Corporation mortgage note payable:
o Medium-term loan fixed at 6.575%, due March 31, 2003 46,065 46,065
- -----------------------------------------------------------------------------------------------------------------------------
3,281,618 3,360,398
*Less: Portion (16.86%) of PCBs assumed by Georgia Transmission Corporation (135,775) (135,775)
- -----------------------------------------------------------------------------------------------------------------------------
Total long-term debt, net .................................................. 4,208,005 4,291,0043,145,843 3,224,623
Less:Long-term debt due within one year .................................... (155,535) (83,684)
----------- -----------
Total long-term(126,824) (121,033)
- -----------------------------------------------------------------------------------------------------------------------------
Long-term debt, excluding amount due within one year .................... 4,052,470 4,207,3203,019,019 3,103,590
Obligation under capital leases, long-term (Note 4) ........................... 293,682 296,478267,449 275,224
Obligation under Rocky Mountain transactions, long-term (Note 1) .............. 41,685 --63,665 59,579
Patronage capital and membership fees (Note 1) ................................ 356,229 338,891
----------- -----------392,682 370,025
- -----------------------------------------------------------------------------------------------------------------------------
Total capitalization .......................................................... $ 4,744,066 $ 4,842,689
=========== ===========
$3,742,815 $3,808,418
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
46
48
STATEMENTS OF CASH FLOWS
For the years ended December 31, 1996, 1995 and 1994
STATEMENTS OF CASH FLOWS
For the years ended December 31, 2000, 1999 and 1998
(dollars in thousands)
1996 1995 19942000 1999 1998
- -----------------------------------------------------------------------------------------------------------------------------
Cash flows from operating activities:
Net margin ................................................... $ 21,75219,978 $ 22,25819,938 $ 23,082
--------- --------- ---------21,080
- -----------------------------------------------------------------------------------------------------------------------------
Adjustments to reconcile net margin to net cash provided by
operating activities:
Depreciation and amortization ............................ 196,593 196,920 193,351
Net benefit of Rocky Mountain transactions ............... 70,701 -- --188,870 177,065 170,466
Interest on decommissioning reserve ...................... 7,167 9,951 1,29111,007 12,266 9,716
Amortization of deferred gains ........................... (2,341) (2,341) (9,985)
Deferred margins and amortization of deferred margins .... (32,047) (1,677) (8,785)(2,475) (2,474) (2,486)
Amortization of net benefit of sale of income tax benefits (8,145) (8,043) (8,102)(11,195) (11,195) (11,195)
Allowance for equity funds used during construction ...... (238) (1,715) (2,907)(204) (180) (158)
Deferred income taxes .................................... (3,525) -- --
Option payment on power swap agreement ................... (3,750) -- --283 - 86
Other .................................................... (13) (13) (13)453 1,465 491
Change in net current assets, excluding long-term debt due
within one year and deferred margins and
Vogtle surcharge to be refunded within one year:
Receivables ............................................ (13,731) (10,686) (18,055)(33,649) 1,214 (5,025)
Inventories ............................................ (6,875) 12,127 (8,608)14,377 (12,983) (11,255)
Prepayments and other current assets ................... (299) 532 (94)2,398 2,102 (8,865)
Accounts payable ....................................... (5,964) (4,066) (10,569)45,409 22,879 (4,427)
Accrued interest ....................................... (75,165) (8,914) (8,692)17,192 40,128 (2,887)
Accrued and withheld taxes ............................. 3,155 219 (7,835)648 (188) (302)
Other current liabilities .............................. (3,985) (169) (24,124)
--------- --------- ---------13,698 (8,584) 9,472
- -----------------------------------------------------------------------------------------------------------------------------
Total adjustments ............................................ 121,538 182,125 86,873
--------- --------- ---------246,812 221,515 143,631
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities ....................... 143,290 204,383 109,955
--------- --------- ---------266,790 241,453 164,711
- -----------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Property additions ........................................... (93,704) (138,921) (206,345)(108,254) (41,829) (43,904)
Activity in decommissioning fund - Purchases ................. (327,233) (410,597) (297,492)(735,352) (608,471) (504,720)
- Proceeds ........................ 316,542 399,077 293,990722,620 591,851 490,450
Activity in bond, reserve and construction funds - Purchases . (107,890) (27,762) (498,052)(12,699) (23,325) -
- Proceeds ........... 109,230 39,566 540,712
Activity15,319 24,053 893
Decrease (increase) in other short-term investments - Purchases ......... (15,532) (76,180) --
Decrease(4,181) (3,718) 24,137
Increase in investment in associated organizations ........... 474 1,518 1,752
--------- --------- ---------(2,078) (1,688) (291)
Decrease (increase) in notes receivable (143) 97 60
Other - generation equipment deposits (42,929) - -
- -----------------------------------------------------------------------------------------------------------------------------
Net cash used in investing activities ........................... (118,113) (213,299) (165,435)
--------- --------- ---------(167,697) (63,030) (33,375)
- -----------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Debt proceeds, net .......................................... 2,243 132,874 523,51826,260 18,196 15,958
Debt payments ............................................... (95,367) (108,481) (517,530)
Return(100,729) (68,517) (86,889)
Premium paid on refinancing of Vogtle surcharge .................................. -- (3,320) (2,031)
Other ....................................................... (421) (1,648) (2,008)
--------- --------- ---------debt - - (24,041)
(Decrease) increase in notes payable (Note 5) (9,997) 37,493 50,986
Decrease (increase) in note receivable under interim financing
agreement (Note 5) 93,181 (49,016) (44,330)
- -----------------------------------------------------------------------------------------------------------------------------
Net cash provided by (used in) financing activities ............. (93,545) 19,425 1,949
--------- --------- ---------8,715 (61,844) (88,316)
- -----------------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and temporary cash investments .. (68,368) 10,509 (53,531)107,808 116,579 43,020
Cash and temporary cash investments at beginning of year ........ 201,151 190,642 244,173
--------- --------- ---------222,814 106,235 63,215
- -----------------------------------------------------------------------------------------------------------------------------
Cash and temporary cash investments at end of year ..............$330,622 $ 132,783222,814 $ 201,151 $ 190,642
========= ========= =========106,235
- -----------------------------------------------------------------------------------------------------------------------------
Cash paid for:
Interest (net of amounts capitalized) .......................$212,126 $ 383,440189,056 $ 308,797 $ 304,882240,270
Income taxes ................................................ -- -- --
- - -
- -----------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
47
49
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 1996, 19952000, 1999 and 19941998
1. Summary of significant accounting policies:
a. Business description
Oglethorpe Power Corporation (Oglethorpe) is an electric generation and
transmission (G&T) cooperativemembership
corporation incorporated in 1974 and headquartered in suburban Atlanta.
Oglethorpe provides wholesale electric service, on a not-for-profit basis, to 39
of Georgia's 42 Electric Membership Corporations (EMCs). These 39 electric
distribution cooperatives (Members) in turn distribute energy on a retail basis
to more than 2.6approximately 3.4 million people across two-thirds of the State. Oglethorpe
is the nation's largest G&Telectric cooperative in terms of operating revenues,
assets, kilowatt-hour sales and, through its Members, consumers served.
Oglethorpe supplies energy to the Members fromowns or leases undivided interests in thirteen generating units
totaling 3,335 megawatts (MW) of owned
or leased generating capacity and purchases the remainder from other power
suppliers.capacity. Oglethorpe also has accesspurchases a total of
1200 MW of capacity pursuant to over 16,000 miles of transmission line
through its ownership in the statewide Integrated Transmission System.
Oglethorpe and the Members completed on March 11, 1997, a corporate
restructuring. For a discussion of the corporate restructuring, see Note 11.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, 19962000 and 19951999
and the reported amounts of revenues and expenses for each of the three years
ending December 31, 1996.2000. Actual results could differ from those estimates.
c. Patronage capital and membership fees
Oglethorpe is organized and operates as a cooperative. The Members paid a
total of $195 in membership fees. Patronage capital is theincludes retained net margin
of Oglethorpe.Oglethorpe and the unrealized gain or loss on available-for-sale securities,
excluding securities held in the decommissioning fund. For 2000, 1999 and 1998
the unrealized gain or loss on available-for-sale securities were $1,070,000,
($1,609,000) and $1,005,000, respectively. As provided in the bylaws, any excess
of revenue over expenditures from operations is treated as advances of capital
by the Members and is allocated to each of them on the basis of their
electricity purchases from Oglethorpe.
Under Oglethorpe'sAny distributions of patronage capital retirements policy, margins are subject to be
returnedthe 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 30 yearsif, 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 year indate on which theOglethorpe's
equity first reaches 20% of Oglethorpe's total capitalization exceeds 35% of
Oglethorpe's aggregate net margins are earned.
Pursuantearned after such date. This last
restriction, however will not apply if, after giving effect to such
policy, no patronage capital would be returned to the Members
until 2010, at which time the 1979 patronage capital would be returned.
Since the RUS Mortgage was replaced with the Master Indenture in connection
withdistribution, Oglethorpe's corporate restructuring, patronage distributions also will be
restricted by the termsequity as of the Master Indenture.end of the immediately preceding
fiscal quarter is not less than 30% of Oglethorpe's total capitalization.
d. Margin policy
Under Oglethorpe's prior RUS mortgage, Oglethorpe's margin policy was based
onFor the provision of a Times Interest Earned Ratio (TIER) established annually byyears 1998 through 2000 under the Oglethorpe Board of Directors. Pursuant to this policy, the annual net
margin goal for 1996, 1995 and 1994 was the amount required to produce a TIER of
1.07. The RUS Mortgage was replaced with the Master Indenture in connection with
Oglethorpe's corporate restructuring. Under the Master Indenture, Oglethorpe
iswas required to produce a Margins for Interest (MFI) Ratio of at least 1.10.
The Oglethorpe Board of Directors adopted resolutions annually requiring that
Oglethorpe's net margins for the years 1985 through 1995 in excess of its annual
margin goals be deferred and used to mitigate rate increases associated with
Plant Vogtle and Rocky Mountain. In addition, during 1986 and 1987, Oglethorpe's
wholesale electric rate to its Members provided for a one mill per kilowatt-hour
charge (Vogtle Surcharge), also to be used to mitigate the effect of Plant
Vogtle on rates.
Pursuant to rate actions by Oglethorpe's Board of Directors, specified
amounts of deferred margins and Vogtle Surcharge were returned in 1989 through
1995 and all remaining amounts were returned in 1996. A summary of deferred
margins and Vogtle Surcharge as of December 31, 1996 and 1995 is as follows:
- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
- --------------------------------------------------------------------------------
Deferred margins
1985-92 $ 165,552 $ 165,552
1993 5,083 5,083
1994 9,287 9,287
1995 14,282 14,282
--------- ---------
194,204 194,204
Vogtle Surcharge
1986-87 36,613 36,613
--------- ---------
Subtotal 230,817 230,817
Less: Amounts returned in:
1989-93 (159,388) (159,388)
1994 (20,103) (20,103)
1995 (19,279) (19,279)
1996 (32,047) --
--------- ---------
-- 32,047
Less: Current portion -- (32,047)
--------- ---------
Long-term balance $ -- $ --
========= =========
- --------------------------------------------------------------------------------
48
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 CobbJackson EMC and JacksonCobb EMC, two of Oglethorpe's Members,
accounted for 12.5%11.8% and 11.2%11.9% in 1996, 11.3%2000, 11.8% and 10.4%11.7% in 1995,1999, and 11.0%11.4% and
10.5%12.8% in 1994,1998, 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 1996, 19952000, 1999 and 19941998 amounted to $49,298,000, $54,588,000$47,105,000, $46,226,000 and
$55,229,000,$46,751,000, respectively.
Contracts with the U.S. Department of Energy (DOE) have been executed to
provide for the permanent disposal of spent nuclear fuel. DOE failed to begin
disposing of spent fuel in January 1998 as required by the contracts, and
Georgia Power Company (GPC), as agent for the co-owners of the plants, is
pursuing legal remedies against DOE for breach of contract. Effective June 2000,
an on-site dry storage facility for Plant Hatch became operational. Sufficient
capacity is believed to be available to continue dry storage operations at Plant
Hatch through the life of Plant
Hatch and Plant Vogtle. The services to be provided by DOE were scheduled to
begin in 1998. However, the actual year that these services will begin is
uncertain. The Plant Hatch spent fuel storage is expected to be sufficient into
2003.plant. The Plant Vogtle spent fuel storage is
expected to be sufficient into 2008. Activities2014. In addition, GPC, as agent for adding dry castthe
co-owners of the plant, is a member of Private Fuel Storage, LLC, a joint
utility effort to develop a private spent fuel storage capacity at Plant Hatch byfacility for temporary
storage of spent nuclear fuel. This facility is planned to begin operation as
early as 1999 are in progress.the year 2003; however, the timing of availability is uncertain.
The Energy Policy Act of 1992 required that utilities with nuclear plants
be assessed over a 15-year period an amount which will be used by DOE for the
decon-taminationdecontamination 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
$14,900,000,$9,463,000, which is being amortized to nuclear fuel expense over the next 1110
years. Oglethorpe has also recorded an obligation to DOE which approximated
$11,800,000$7,085,000 at December 31, 1996.2000.
g. Nuclear decommissioning
Oglethorpe's portion of the costs of decommissioning co-owned nuclear
facilities is estimated as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
Hatch Hatch Vogtle Vogtle
Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2
- --------------------------------------------------------------------------------
Year of site study 1994 1994 1994 19942000 2000 2000 2000
Expected start date
of decommissioning 2014 2018 2027 2029
Decommissioning cost:
Discounted $ 92,000 $ 109,000 $ 82,000 $ 106,000$139,000 $175,000 $137,000 $171,000
Undiscounted 157,000 207,000 198,000 271,000265,000 400,000 475,000 650,000
- --------------------------------------------------------------------------------
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in regulatory requirements, changes in technology, and
changes in costs of labor, materials and equipment.
Based on the most recent Nuclear Regulatory Commission (NRC) funding
requirement, Oglethorpe has determined that its existing decommmissioning
reserve together with expected earnings on the external funds, should be
sufficient to meet the current projected required funding levels for Plant
Vogtle and Plant Hatch. Therefore, Oglethorpe did not record an annual provision
for decommissioning in 2000 and 1999. Based on current assumptions, Oglethorpe's
management does not expect to record an annual provision for decommissioning in
future years. The annual provision for decommissioning for 1996, 1995 and 19941998 was $2,597,000
$4,156,000 and $5,948,000, respectively. In developing the amount of
the annual provisionwas accounted for 1996 and 1997, the escalation rate was assumed to be
2.72% and return on trust assets was assumed to be 8%. Oglethorpe accounts for
this provision for decommissioning as depreciation expense with an offsetting credit to a
decommissioning reserve. In developing the amount of the annual provision for
1999 and 2000, the escalation rate was assumed to be 3.6% and return on trust
assets was assumed to be 8%, respectively. Oglethorpe's management is of the
opinion that any changes in cost estimates of decommissioning willcan be fully recovered
in future rates.
51
In compliance with a Nuclear Regulatory Commission (NRC)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.
Oglethorpe's decommissioning reserve
reflects its obligation to decommission both the radioactive and most of the
non-radioactive portions of its nuclear facilities.
Realized investment earnings from the external trust fund, while increasing
the fund and interest income, also are applied to the decommissioning reserve
and charged to interest expense. Interest income earned from the external trust
fund is offset by the recognition of interest expense such that there is no
effect on Oglethorpe's net margin.
49
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 1996,
19952000,
1999 and 19941998 were as follows:
2000 1999 1998
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------------------------------------------------------------------
Steam production 2.13% 2.13% 2.47%1.98% 2.15% 2.14%
Nuclear production 2.73% 2.78% 2.84%2.48% 2.69% 2.77%
Hydro production 2.00% 2.00% 2.00%
Other production 3.75% 3.75% 2.42%3.75%
Transmission 2.75% 2.75% 2.75%
Distribution 2.88% 2.88% 2.88%
General 2.00-20.00% 2.00-20.00%2.00-33.33% 2.00-33.33% 2.00-20.00%
- --------------------------------------------------------------------------------------------------------------------------------------------
i. Electric plant
Electric plant is stated at original cost, which is the cost of the plant
when first dedicated to public service, plus the cost of any subsequent
additions. Cost includes an allowance for the cost of equity and debt funds used
during construction. The cost of equity and debt funds is calculated at the
embedded cost of all such funds. The plant acquisition adjustments represent the
excess of the cost of the plant to Oglethorpe over the original cost, less
accumulated depreciation at the time of acquisition, and are being amortized
over a ten-year period.
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: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, 19962000 and 1995,1999, substantially all of the funds were invested in U.S.
Government securities.
k. Cash and temporary cash investments
Oglethorpe considers all temporary cash investments purchased with a
maturity of three months or less to be cash equivalents. Temporary cash
investments with maturities of more than three months are classified as other
short-term investments.
Of the amount reported as cash and temporary cash investments atAt December 31, 1996, approximately $65,600,000 is2000 and 1999, $22,241,000 and $20,155,000 were restricted
by RUSPCBs trust indentures and were utilized in January 2001 and 2000 for the purposepayment
of prepayingprincipal on certain Federal Financing Bank (FFB) long-term debt on or before March
31, 1997.PCBs, respectively.
l. Inventories
Oglethorpe maintains inventories of fossil fuels for its generation plant and spare parts for certain of its
generation and transmission plant.plants. These inventories are stated at weighted average cost on the
accompanying balance sheets.
At December 31, 19962000 and 1995,1999, fossil fuels inventories were $23,062,000$15,565,000
and $12,296,000,$31,787,000, respectively. Inventories for spare parts at December 31, 19962000
and 19951999 were $66,763,000$59,824,000 and $70,653,000,$57,979,000, respectively.
m. Deferred charges
Prior to 1996, Oglethorpe expensedaccounts for nuclear refueling outage costs as
incurred. In 1996, Oglethorpe began accounting for these 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, 19962000 and 1999 were
$12,961,000.$19,897,000 and $18,483,000, respectively.
As a result of the availability of long-term capacity purchases at similar
costs but with reduced risks to Oglethorpe and its Members, Oglethorpe
determineddetermination that the Smarr Combustion Turbine Project was not needed withinPlant Vogtle radioactive waste
facility has no usefulness as a radioactive waste storage facility, the
present planning horizon. Therefore, Oglethorpe is amortizing the accumulated
project costs in excess of the current value of the land purchased. The
remaining project costs of $6,445,000$5,076,000 are reflected as deferred charges on the
accompanying balance sheets. In 1995,1998, Oglethorpe's Board of Directors authorized
that these project costs be amortized and fully recovered through future rates over a
period of 15four years beginning in that year.1999.
52
n. Deferred credits
In October 1989, Oglethorpe sold to Georgia Power Company (GPC) a 24.45%
ownership interest in the Plant Scherer common facilities as required under the
Plant Scherer Purchase and Ownership Agreement to adjust its ownership in the
Scherer units. Oglethorpe realized a gain on the sale of $50,600,000. RUS and
Oglethorpe's Board of Directors approved a plan whereby this gain was deferred
and was amortized over 60 months ending in September 1994.
In April 1982, Oglethorpe sold to three purchasers certain of the income
tax benefits associated with Scherer Unit No.1 and related common facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act of
1981. Oglethorpe received a total of approximately $110,000,000 from the safe
harbor lease transactions. Oglethorpe accounts for the net benefits as a
deferred credit and 50
is amortizing the amount over the 20-year term of the
leases.
In December 1996 and January 1997, Oglethorpe entered into long-term lease
transactions for a
portion of its 74.6% undivided ownership interest in the Rocky Mountain,
Pumped
Storage Hydroelectric Project (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 $70,701,000$95,560,000 which
was deferred and will beis being amortized to income over the 30-year lease-back
period. The lease transactions increased
Oglethorpe's Capitalization and Investments and funds by $41,685,000,
respectively (see Note 2 where discussed further).
In January 1997, Oglethorpe completed long-term lease transactions for the
remainder of its interest in Rocky Mountain resulting in a net benefit of
$24,859,000. The net benefit will be deferred and amortized to income over the
30-year term of the leases. Oglethorpe will increase Capitalization and
Investments and funds by $15,810,000, respectively.
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 probable future revenues to Oglethorpe associated
with certain costs which willthat are assured to be
recoveredrecoverable by Oglethorpe from the Members in the future through the rate-makingratemaking
process. Regulatory liabilities represent probable future reduction in revenues
associated with amountscertain items of income that are being
retained by Oglethorpe and that will be applied in the future to be credited to Members through the
rate-making process.reduce Member
revenue requirements. The following regulatory assets and liabilities were
reflected on the accompanying balance sheets as of December 31, 19962000 and 1995:1999:
- --------------------------------------------------------------------------------
(dollars in thousands)
1996 19952000 1999
- --------------------------------------------------------------------------------
Premium and loss on reacquired debt $ 201,007175,944 $ 200,794196,289
Deferred amortization of Scherer leasehold 90,717 87,134102,753 101,404
Discontinued projects 9,490 28,020
Other regulatory assets 29,308 33,66628,141 29,017
Net benefit of sale of income tax benefits (42,049) (50,194)(10,012) (18,021)
Net benefit of Rocky Mountain transactions (70,701) --
Deferred margins -- (32,047)
Energy costs -- 4,237
--------- ---------(82,819) (86,004)
- --------------------------------------------------------------------------------
$ 208,282223,497 $ 243,590
========= =========250,705
- --------------------------------------------------------------------------------
In the event that competitive or other factors result in cost recovery
practices under which Oglethorpe iscan no longer subject toapply the provisions of StatementSFAS No.
71, Oglethorpe would be required to write off relatedeliminate all regulatory assets and
liabilities.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 thewrite-down those assets, if
impaired, to their fair value.
p. Presentation
Certain prior year amounts have been reclassified to conform with current
year presentation.
q. New accounting pronouncement
As of January 1, 2001, Oglethorpe adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The standard establishes
accounting and reporting requirements for derivative instruments, including
certain derivative instruments embedded in other contracts, and hedging
activities. It requires the recognition of all derivative instruments as assets
or liabilities in Oglethorpe's balance sheet and measurement of those
instruments at fair value. The accounting treatment of changes in fair value is
dependent upon whether or not a derivative instrument is designated as a hedge
and if so, the type of hedge. Oglethorpe's interest rate swap arrangements in
place at December 31, 2000 are designated as cash flow hedges. Adoption of SFAS
No. 133 on January 1, 2001, resulted in recording $33,515,000 of decline in fair
value to accumulated other comprehensive income and a comparable increase in
other liabilities. For information regarding the interest rate swap
arrangements, see Note 2.
53
2. Fair value of financial instruments:
A detail of the estimated fair values of Oglethorpe's financial instruments
as of December 31, 19962000 and 19951999 is as follows:
- ------------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
Fair Fair
Cost Value Cost Value
- ------------------------------------------------------------------------------------------------------------------------------------
Cash and temporary cash investments:
Commercial paper $ 52,700 $ 52,700 $ 179,055 $ 179,055
Certificates of deposit 10,000 10,000 20,000 20,000
Cash and money market
securities 70,083 70,083 2,096 2,096
---------- ---------- ---------- ----------
Total $ 132,783 $ 132,783 $ 201,151 $ 201,151
========== ========== ========== ==========
Other short term
investments:
Commingled
investment fund $ 91,712 $ 91,499 $ 76,180 $ 79,165
---------- ---------- ---------- ----------
Total $ 91,712 $ 91,499 $ 76,180 $ 79,165
========== ========== ========== ==========
Bond, reserve and construction funds:
U. S. Government
securities $ 36,505 $ 35,873 $ 49,348 $ 49,932
Repurchase agreements 18,082 18,082 6,579 6,579
---------- ---------- ---------- ----------
Total $ 54,587 $ 53,955 $ 55,927 $ 56,511
========== ========== ========== ==========
Decommissioning fund:
U. S. Government
securities $ 24,034 $ 23,950 $ 23,087 $ 23,568
Foriegn government
securities 1,228 1,278 -- --
Commercial paper -- -- 4,036 4,036
Corporate bonds 11,953 11,868 5,875 6,073
Equity securities 30,339 34,073 19,514 21,271
Asset-backed securities 3,103 3,125 12,484 12,614
Other bonds 5,445 5,453 -- --
Cash and money market
securities 6,522 6,522 6,937 6,930
---------- ---------- ---------- ----------
Total $ 82,624 $ 86,269 $ 71,933 $ 74,492
========== ========== ========== ==========
Long-term debt $4,118,117 $4,228,317 $4,207,320 $4,506,925
========== ========== ========== ==========
Interest rate swap $ -- $ 33,938 $ -- $ 52,089
========== ========== ========== ==========
- ------------------------------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
(dollars in thousands)
2000 1999
Fair Fair
Cost Value Cost Value
- --------------------------------------------------------------------------------
Cash and temporary
cash investments:
Commercial paper $ 330,052 $ 330,052 $ 220,941 $ 220,941
Cash and money
market securities 570 570 1,873 1,873
- --------------------------------------------------------------------------------
Total $ 330,622 $ 330,622 $ 222,814 $ 222,814
- --------------------------------------------------------------------------------
Other short term
investments $ 80,854 $ 81,715 $ 76,673 $ 75,482
- --------------------------------------------------------------------------------
Bond, reserve and
construction funds:
U. S. Government
securities $ 25,397 $ 25,608 $ 25,443 $ 25,025
Repurchase
agreements 3,559 3,559 6,133 6,133
- --------------------------------------------------------------------------------
Total $ 28,956 $ 29,167 $ 31,576 $ 31,158
- --------------------------------------------------------------------------------
Decommissioning
fund:
U. S. Government
securities $ 29,674 $ 31,049 $ 23,858 $ 23,574
Foreign government
securities 1,173 1,161 732 656
Commercial paper 6,183 6,180 2,387 2,388
Corporate bonds 6,784 6,929 11,215 10,891
Equity securities 80,795 85,225 69,944 77,148
Asset-backed
securities 12,156 12,406 9,954 9,751
Other bonds - - - -
Cash and money
market securities 5,350 5,350 11,293 11,295
- --------------------------------------------------------------------------------
Total $142,115 $148,300 $129,383 $135,703
- --------------------------------------------------------------------------------
Long-term debt $3,019,019 $ 3,221,692 $3,103,590 $3,007,048
- --------------------------------------------------------------------------------
Interest rate swap
(unrealized loss) $ - $ (33,515) $ - $ (18,935)
- --------------------------------------------------------------------------------
The contractual maturities of debt securities available for sale at
December 31, 19962000 and 1995,1999, regardless of their balance sheet classification,
are as follows:
- -------------------------------------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
1996 19952000 1999
Fair Fair
Cost Value Cost Value
- -------------------------------------------------------------------------------------------------------------------------------------------------------------
Due within one year $33,944 $33,819 $21,050 $21,300$ 3,559 $ 3,559 $ 6,818 $ 6,866
Due after one year
through five years 17,439 17,266 37,172 37,45239,583 40,022 36,017 35,509
Due after five years
through ten years 27,912 27,302 27,628 27,96612,499 12,904 11,597 11,262
Due after ten years 15,610 15,789 11,523 12,049
------- ------- ------- -------
$94,905 $94,176 $97,373 $98,767
======= ======= ======= =======23,102 24,227 22,902 22,393
- -------------------------------------------------------------------------------------------------------------------------------------------------------------
$ 78,743 $ 80,712 $ 77,334 $76,030
- -----------------------------------------------------------------------------
Oglethorpe uses the methods and assumptions described below to estimate the
fair value of each class of financial instruments. For cash and temporary cash
investments, the carrying amount approximates fair value because of the
short-term maturity of those 51
instruments. The fair value of Oglethorpe's
long-term debt and the swap arrangements is estimated based on the quoted market
prices for the same or similar issues or on the current rates offered to
Oglethorpe for debt of similar maturities.
A portion (16.86%) of the interest rate swap arrangements was assumed by
Georgia Transmission Corporation (GTC) in connection with a corporate
restructuring. Under the interest rate swap arrangements, Oglethorpe makes
payments to the counterparty based on the notional principal at a contractually
fixed rate and the counterparty makes payments to Oglethorpe based on the
notional principal at the existing variable rate of the refunding bonds. The
differential to be paid or received is accrued as interest rates change and is
recognized as an adjustment to interest expense. Oglethorpe entered into the
swap arrangements for the purpose of securing a fixed rate lower than otherwise
would have been available to Oglethorpe had it issued fixed rate bonds. For the
Series 1993A notes, the notional principal at December 31, 2000 was $199,690,000$192,420,000
(includes the portion assumed by GTC) and the fixed swap rate is 5.67% (the
variable rate at December 31, 19962000 and 19951999 was 4.00%4.90% and 5.15%5.40%, respectively).
With respect to the Series 1994A notes, the notional principal at December 31,
2000 was $122,740,000$120,500,000 (includes the portion assumed by GTC) and the fixed swap
rate is 6.01% (the variable rate at December 31, 19962000 and 19951999 was 4.00%4.95% and
5.05%54
5.65%, respectively). The notional principal amount is used to measure the
amount of the swap payments and does not represent additional principal due to
the counterparty. The swap arrangements extend for the life of the refunding
bonds, with reductions in the outstanding principal amounts of the refunding
bonds causing corresponding reductions in the notional amounts of the swap
payments. TheOglethorpe's portion of the estimated fair value of Oglethorpe's liability
under the swap
arrangements at December 31, 19962000 and 19951999 was $33,938,000an unrealized loss of $33,515,000
and $52,089,000, respectively. This amount represents$18,935,000, respectively, representing the estimated payment Oglethorpe
would pay if the swap arrangements were terminated. Oglethorpe may be exposed to
losses in the event of nonperformance of the counterparty, but does not
anticipate such nonperformance.
Oglethorpe adopted Statement of Financial Accounting StandardsUnder SFAS No. 115, "Accounting for Certain Investments in Debt and Equity
Securities," as of
January 1, 1994. Under this Statement, 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, 19962000
were $7,785,000$15,937,000 and $4,985,000,$8,681,000, respectively. Gross unrealized gains and losses
at December 31, 19951999 were $6,497,000$11,451,000 and $368,000,$6,740,000, respectively. Gross
unrealized gains and losses at December 31, 1998 were $12,182,000 and
$1,845,000, respectively. For 19962000, 1999 and 1995,1998 proceeds from sales of
available-for-sale securities totaled $425,772,000$725,240,000, $592,579,000 and
$438,643,000,$491,343,000, respectively. Gross realized gains and losses from the 19962000 sales
were $6,410,000$19,556,000 and $3,671,000,$16,086,000, respectively. Gross realized gains and losses
from the 19951999 sales were $5,098,000$29,429,000 and $1,308,000,$22,167,000, respectively. Gross
realized gains and losses from 1998 sales were $12,892,000 and $6,602,000,
respectively.
Investments in associated organizationscompanies were as follows at December 31, 19962000
and 1995:1999:
- --------------------------------------------------------------------------------
(dollars in thousands)
1996 19952000 1999
- --------------------------------------------------------------------------------
National Rural Utilities
Cooperative Finance Corp. (CFC) $13,476 $13,476$ 13,476 $ 13,603
CoBank, ACB 1,664 2,1322,407 1,577
Georgia Transmission
Corporation (GTC) 3,815 2,615
Other 239 245
------- -------299 124
- --------------------------------------------------------------------------------
Total $15,379 $15,853
======= =======$ 19,997 $ 17,919
- --------------------------------------------------------------------------------
The CFC investments are in these associated organizations are similar to compensating
bank balances in that theythe form of capital term certificates and are
required in order to maintain current financing
arrangements.conjunction with Oglethorpe's membership in CFC. Accordingly, there
is no market for these investments. The $41,685,000investments in CoBank and GTC represent
capital credits. Any distributions of capital credits are subject to the
discretion of the Board of Directors of CoBank and GTC.
The deposit, which is carried at cost, on the Rocky Mountain transactions
(see Note 1 where discussed) as of December 31, 1996 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 fully intends to use the deposit to repurchase tax ownership and to retain all other
rights of ownership with respect to the plant.plant if it is advantageous to do so.
The deposit is carried at cost.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 $460,769,000$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 taxestaxes:
Oglethorpe is a not-for-profit membership corporation subject to Federalfederal
and state income taxes. As a taxable electric cooperative, Oglethorpe has
annually allocated its income and deductions between Member and non-Member
activities. Any Member taxable income has been offset with a patronage exclusion
and member loss carryforwards.
Oglethorpe accounts for its income taxes pursuant to Statement of Financial
Accounting Standards (SFAS)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.
52
A detail of the provision for income taxes in 1996, 19952000, 1999 and 19941998 is shown
as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
1996 1995 19942000 1999 1998
- --------------------------------------------------------------------------------
Current
Federal $ 3,525(283) $ --- $ --(86)
State -- -- --
------- ------- -------
3,525 -- --
------- ------- -------- - -
- --------------------------------------------------------------------------------
(283) - (86)
- --------------------------------------------------------------------------------
Deferred
Federal (3,525) -- --283 - 86
State -- -- --
------- ------- -------
(3,525) -- --
------- ------- -------- - -
- --------------------------------------------------------------------------------
283 - 86
- --------------------------------------------------------------------------------
Income taxes charged
to operations $ --- $ --- $ --
======= ======= =======-
- --------------------------------------------------------------------------------
The difference between the statutory federal income tax rate on income
before income taxes and Oglethorpe's effective income tax rate is summarized as
follows:
- --------------------------------------------------------------------------------
1996 1995 19942000 1999 1998
- --------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Patronage exclusion (35.7%(35.8%) (35.6%) (35.4%(35.7%)
Other 0.8% 0.6% 0.7%
0.6% 0.4%
------ ------ ------- --------------------------------------------------------------------------------
Effective income tax rate 0.0% 0.0% 0.0%
====== ====== ======
- --------------------------------------------------------------------------------
The components of the net deferred tax liabilities as of December 31, 19962000
and 19951999 were as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
1996 19952000 1999
- --------------------------------------------------------------------------------
Deferred tax assets
Net operating losses $ 473,114478,497 $ 538,067477,817
Member loss carryforwards 328,912 342,37044,341 78,231
Tax credits (alternative minimum tax
and other) 256,205 252,680196,452 199,650
Accounting for Rocky Mountain
transactions 233,045 --312,441 309,474
Accounting for sale of income tax benefits 77,429 86,59916,702 27,909
Accrued nuclear decommissioning expense 49,127 45,04264,545 60,264
Accounting for asset dispositions 32,545 33,49620,010 28,185
Other 3,318 18,277
----------- -----------
1,453,695 1,316,5313,000 3,540
- --------------------------------------------------------------------------------
1,135,988 1,185,070
Less: Valuation allowance (252,680) (252,680)
----------- -----------
1,201,015 1,063,851
----------- -----------(194,145) (197,343)
- --------------------------------------------------------------------------------
941,843 987,727
- --------------------------------------------------------------------------------
Deferred tax liabilities
Depreciation (1,008,714) (1,034,153)(738,313) (771,577)
Accounting for Rocky Mountain
transactions (156,557) --(195,376) (199,675)
Accounting for debt extinguishment (64,841) (64,006)(57,042) (64,362)
Other (32,888) (31,202)
----------- -----------
(1,263,000) (1,129,361)
----------- -----------(14,597) (15,316)
- --------------------------------------------------------------------------------
(1,005,328) (1,050,930)
- --------------------------------------------------------------------------------
Net deferred tax liabilities $ (61,985)(63,485) $ (65,510)
=========== ===========(63,203)
- --------------------------------------------------------------------------------
56
As of December 31, 1996,2000, Oglethorpe has federal tax net operating loss
carryforwards (NOLs), alternative minimum tax credits (AMT) and unused general
business credits (consisting primarily of investment tax credits) as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
- --------------------------------------------------------------------------------
Alternative
Minimum
Expiration Date Tax Credits Tax Credits NOLs
19972001 $ --- $ 11,1977,264 $ --
1998 -- 6,934 --
1999 -- 37,206 --
2000 -- 3,198 --
2001 -- 7,264 ---
2002 --- 130,377 --7,102
2003 --- 652 242,187253,665
2004 --- 55,663 114,285
2005 --- 189 213,080
2006 -- --- - 209,009
2007 -- --- - 86,779
2008 -- --- - 94,927
2009 -- --- - 96,394
2010 -- --- - 77,970
2018 - - 61,533
2019 - - 10,516
2020 - - 4,809
None 3,525 -- --
-------- ---------- ----------
$ 3,525 $ 252,680 $1,134,631
======== ========== ==========2,307 - -
- --------------------------------------------------------------------------------
Based on Oglethorpe's historical taxable transactions, the timing of the
reversal of existing temporary differences, future income, and$ 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 is more likely than not that Oglethorpe's future taxable income
will be sufficienthas available options to realizeoffset the benefiteffect, if any, of NOLs
before their respective
expiration dates.expiring. The NOLsNOL expiration dates start in the year 20032002 and end in the year
2010.2020. However, as reflected in the above valuation allowance, it is more likely
than not that the tax credits will not be utilized before expiration. The change
in the valuation allowance from 1999 to 2000 was the result of the expiration of
$3,198,000 of tax credits in 2000. It is more likely than not that the AMT
credit will be utilized.
53
4. Capital leases:
In December 1985, Oglethorpe sold and subsequently leased back from four
purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The gain
from the sale is being amortized over the 36-year term of the leases. The
minimum lease payments under the capital leases together with the present value
of net minimum lease payments as of December 31, 19962000 are as follows:
- --------------------------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
19972001 $ 36,531
1998 37,302
1999 37,890
2000 37,755
2001 37,629
2002-2021 569,179
---------2002 37,491
2003 37,333
2004 37,156
2005 36,961
2006-2021 420,239
- --------------------------------------------------------------------------------
Total minimum lease payments 756,286606,809
Less: Amount representing interest
(458,517)
---------at an assumed rate of 11.05% (330,131)
- --------------------------------------------------------------------------------
Present value of net minimum lease payments 297,769276,678
Less: Current portion (4,087)
---------(9,229)
- --------------------------------------------------------------------------------
Long-term balance $ 293,682
=========267,449
- --------------------------------------------------------------------------------
The capital leases provide that Oglethorpe's rental payments vary to the
extent of interest rate changes associated with the debt used by the lessors to
finance their purchase of undivided ownership shares in Scherer Unit No. 2. In
December 1997, Oglethorpe refinanced the debt supporting the Scherer Unit No. 2
lease. The refunded debt consisted of $143,200,000 in serial facility bonds with
a 9.70% fixed interest rate (pertaining to three of the lessors is financed at fixed interest rates averaging
9.70%. As of December 31, 1996, thelessors) and $81,500,000
in bank debt with variable interest rates of the debt of the
remaining lessor rangedranging from 6.40% to 8.05% for an average rate6.90%
(pertaining to the remaining lessor). The debt was refinanced through a
$224,700,000 issue of 6.83%.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 fixed and variable rate debt of the lessors varyvaries from the 11.05%
debt rate assumed in the table.
The Scherer Unit No. 2 lease meets the definitional criteria to be reported
on Oglethorpe's balance sheets as a capital lease. For rate-making purposes,
however, Oglethorpe treats this lease as an operating lease; that is, Oglethorpe
considers the actual rental payment on the leased asset in its cost of service.
Oglethorpe's accounting treatment for this capital lease has been modified,
therefore, to reflect its rate-making treatment. Interest expense is applied to
57
the obligation under the capital lease; then, amortization of the leasehold is
recognized, such that interest and amortization equal the actual rental payment.
Through 1994, the level of actual rental payments was such that amortization of
the Scherer Unit No. 2 leasehold calculated in this manner was less than zero.
Thereafter, the scheduled cash rental payments increase such that positive
amortization of the leasehold occurs and the entire cost of the leased asset is
recovered through the rate-making process. The difference in the amortization
recognized in this manner on the statements of revenues and expenses and the
straight-line amortization of the leasehold is reflected on Oglethorpe's balance
sheets as a deferred charge.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 NoNo. 2. In 1994, the IRS issued a revised Notice of
Proposed Adjustments to one of the lessors which reduced the proposed
adjustments. During 1995, this lessor advised Oglethorpe that it had settled
this issue on the basis of the revised Notice of Proposed Adjustments.
Oglethorpe subsequently made a lump sum indemnity payment of $362,000 to the
lessor in order to compensate for the reduction in the lessor's tax benefits
resulting from the sale and leaseback transaction. The IRS has indicated that it
will take consistent positions with the other three lessors. If the IRS's
current positions regarding the sale and leaseback transactions were ultimately
upheld, Oglethorpe would be required to indemnify the other three lessors.
Oglethorpe's indemnification liability to the three lessors is estimated to be
approximately $1,290,000$1,454,000 as of December 31, 1996.2000. This liability has been
reflected on the accompanying balance sheet.
5. Long-term debt:
Long-term debt consists of mortgage notes payable to the United States of
America acting through the FFBFederal Financing Bank (FFB) and the RUS, mortgage
notes and unsecured notes issued in conjunction with the sale by public
authorities of pollution control revenue bonds,PCBs, mortgage notes and unsecured notes payable to CoBank.CoBank, and
mortgage notes payable to National Rural Utilities Cooperative Finance
Corporation (CFC). Oglethorpe's headquarters facility is pledged as collateral
for the CoBank headquarters note; substantially all of the owned tangible and
certain of the intangible assets of Oglethorpe are pledged as collateral for the
FFB and RUS notes, the remaining CoBank mortgage notes, the CFC notes, and the mortgage
notes issued in conjunction with the sale of pollution control revenue bonds.PCBs. The detail of the two
medium-term notes is included in the statements of capitalization.
Oglethorpe currently has ten RUS-guaranteed FFB notes of which $3,172,851,000
and $3,253,636,000 were outstanding at December 31, 1996 and 1995, respectively,
with rates ranging from 5.27% to 9.51%. In January 1996, Oglethorpe completed
note modifications pursuant to which it repriced $89,447,000 of FFB advances. In connection with a corporate restructuring effective April 1, 1997,
16.86% of the then outstanding secured PCBs was assumed by GTC. Because
Oglethorpe was not legally released from its obligation to pay this debt, the
entire debt is shown in the Statement of Capitalization as a liability of
Oglethorpe with an offsetting amount reflecting the portion assumed by GTC.
In connection with a corporate restructuring, Oglethorpe defeased
approximately $92,000,000 in principal amount of Series 1992 PCBs. Initially
these bonds were defeased with the proceeds from the issuance of approximately
$92,000,000 in commercial paper. In March and April 1998, Oglethorpe refinanced
the commercial paper issuance with two medium-term loans; one from CoBank and
one from CFC, of approximately $46,100,000 each. Oglethorpe ultimately expects
to refinance the two medium-term loans with an issuance of PCBs in the fall of
2002.
In October 2000, Oglethorpe completed a current refunding transaction
whereby $21,950,000 of PCBs were issued. The proceeds were used to make
principal payments due January 1, 2001.
GTC agreed with Oglethorpe not to participate in this $21,950,000
refinancing to the extent of their assumed obligation in the PCBs. Pursuant to
this agreement, Oglethorpe will provide a discount to GTC of approximately
$1,110,000 on the $3,701,000 of principal payments due from GTC in connection
with such modification, Oglethorpe paidrefinancings. This $1,110,000 loss will be reported, together with the
unamortized transaction costs, as a premium of $9,332,000.
These amounts are reported as deferred chargescharge on the balance sheet and
will be amortized over 22 years, the longest remaining life of the subject advances.
54
In October 1996, Oglethorpe completed a current refunding transaction whereby
$37,885,000 of fixed rate pollution control revenue bonds were issued. The
proceeds of this transaction were used to retire $37,885,000 of existing bonds.
The unamortized transaction costs related to this transaction have been reported
as a deferred charge on the balance sheet and are being amortized over the life
of the related bonds.four years.
The annual interest requirement for 19972001 is estimated to be $294,000,000.$219,000,000.
58
Maturities for the long-term debt and amortization of the capital lease
obligations through 20012005 are as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
1997 1998 1999 2000 2001 2002 2003 2004 2005
- --------------------------------------------------------------------------------
FFB and RUS $147,279$106,623 $ 86,89490,830 $ 91,123 $ 98,867 $105,94196,424 $101,383 $108,711
CoBank 376 502 516 532 550
PCB Bonds 7,880 17,970 19,730 23,995 26,260523 540 46,623 580 603
PCBs* 19,678 20,264 25,835 27,855 28,146
CFC - - 46,065 - -
Capital Leases 4,087 5,143 6,240 7,075 7,775
-------- -------- -------- -------- --------
Total $159,622 $110,509 $117,609 $130,469 $140,526
======== ======== ======== ======== ========9,229 8,544 9,455 10,387 11,474
- --------------------------------------------------------------------------------
Total $136,053 $120,178 $224,402 $140,205 $148,934
- --------------------------------------------------------------------------------
*Does not contain portion assumed by GTC
The estimated annualweighted average interest expense and therate for 2000 for long-term debt maturities
described above do not take into account Oglethorpe's proposed corporate
restructuring, discussed in Note 11.and capital
leases due within one year and notes payable is 6.21%.
Oglethorpe has a commercial paper program under which it may issue
commercial paper not to exceed a $250,000,000$260,000,000 balance outstanding at any time.
The commercial paper may be used for working capital requirements and for
general corporate purposes. Oglethorpe's commercial paper is backed 100% by
committed lines of credit provided by a group of banks.credit.
As of December 31, 19962000 and 1995, no1999, approximately $78,000,000 and
$88,000,000, respectively, of commercial paper was outstanding. The majority of
the amount outstanding at year-end 1999 relates to commercial paper issued to
fund, on an interim basis, the construction of a combustion turbine (CT) project
completed in Summer 2000. This project is owned by a cooperative, Smarr EMC,
which is owned by 37 of Oglethorpe's 39 Members. The commercial paper was
retired in October 2000 with proceeds from permanent financing secured by Smarr
EMC on a non-recourse basis to Oglethorpe. A majority of the commercial paper
outstanding at year-end 2000 was issued to fund, on an interim basis,
construction of additional generation facilities expected to be completed in
Summer 2002 and 2003. It is expected that by the time these projects are
completed, permanent financing will have been secured and the proceeds used to
retire the commercial paper. It is anticipated these new generating facilities
will be owned either by a subsidiary of Oglethorpe, Smarr EMC, or by a similar
separate entity.
Oglethorpe has a $50,000,000 uncommitted short-term line of credit with
CFC
and a $30,000,000 committed line of credit with SunTrust Bank, Atlanta
(SunTrust). The maximum combined amount that can be outstanding under these
lines of credit and the commercial paper program at any one time totals
$250,000,000 due to certain restrictions contained in the CFC and SunTrust line
of credit agreements.CFC. No balance was outstanding on either of these two linesthis line of credit at either December 31,
19962000 or 1995.1999.
6. Electric plant and related agreements:
Oglethorpe and GPC have entered into agreements providing for the purchase
and subsequent joint operation of certain of GPC's electric generating plants
and transmission facilities.plants. A
summary of Oglethorpe's plant investments and related accumulated depreciation
as of December 31, 19962000 is as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
Accumulated
Plant Investment Depreciation
- --------------------------------------------------------------------------------
In-service
Owned property
Vogtle Units No. 1 & No. 2
(Nuclear - 30% ownership) $2,781,446$2,734,776 $ 665,953931,580
Hatch Units No. 1 & No. 2
(Nuclear - 30% ownership) 523,163 208,687531,655 249,097
Wansley Units No. 1 & No. 2
(Fossil - 30% ownership) 173,192 84,388173,119 95,067
Scherer Unit No. 1
(Fossil - 60% ownership) 429,299 193,129426,891 225,371
Rocky Mountain Units No. 1,
No. 2 & No. 3
(Hydro - 74.6% ownership) 556,470 17,401556,875 61,860
Tallassee (Harrison Dam)
(Hydro - 100% ownership) 9,270 1,7972,508
Wansley (Combustion Turbine -
30% ownership) 3,718 1,3193,629 1,600
Generation step-up substations 55,877 19,173
Transmission and distribution plant 815,929 179,96060,470 26,387
Other 94,002 25,06085,667 33,617
Property under capital lease
Scherer Unit No. 2
(Fossil - 60% leasehold) 300,231 91,405
---------- ----------301,328 125,089
- --------------------------------------------------------------------------------
Total in-service $5,742,597 $1,488,272
========== ==========$4,883,680 $1,752,176
- --------------------------------------------------------------------------------
Construction work in progress
Generation improvements $ 11,963
Transmission and distribution plant 18,71524,033
New generation facilities 37,868
Other 503
----------456
- --------------------------------------------------------------------------------
Total construction work in progress $ 31,181
==========62,357
- --------------------------------------------------------------------------------
In 1988, Oglethorpe, acquired from GPC an undivided ownership interest in
Rocky Mountain. Under the Rocky Mountain agreements, Oglethorpe assumed
responsibility for construction of the facility, which was commenced by GPC.
Under the agreements, GPC retained its current investment in Rocky Mountain with
the ultimate ownership interests of Oglethorpe and GPC in the facility based on
the ratio of each party's direct construction costs to total project direct
construction costs with certain adjustments.
On June 1, 1995, Unit 3 and the completed Unit Common facilities were
declared to be in commercial operation by Oglethorpe. Unit 2 and Unit 1 were
declared to be in commercial operation on June 19, 1995 and July 24, 1995,
respectively. In accordance with the Rocky Mountain agreements, the final
ownership interests of Oglethorpe and GPC in Rocky Mountain is 74.6% and 25.4%,
respectively. The final ownership interests in the project will be applied to
all future capital costs.
55
Oglethorpe is engaged in a continuous construction program and, as of December 31, 1996,2000, estimates property additions
(including(excluding capitalized interest)interest and nuclear fuel) to be approximately
$108,000,000$331,000,000 in 1997, $98,000,0002001, $229,000,000 in 19982002 and $100,000,000$72,000,000 in 1999,2003, primarily
for replacements and additions to generation and transmission
facilities.
59
Oglethorpe's proportionate share of direct expenses of joint operation of
the above plants is included in the corresponding operating expense captions
(e.g., fuel, production or depreciation) on the accompanying statements of
revenues and expenses.
7. Employee benefit plans:
Oglethorpe has aEffective December 31, 1998, Oglethorpe's Board of Directors approved
termination of the noncontributory defined benefit pension plan coveringthat covered
substantially all employees. Oglethorpe's pension cost was approximately
$1,388,000employees, resulting in 1996, $1,954,000 in 1995 and $1,262,000 in 1994.a net gain of $1,645,000. For 1995, pension
cost increased by $912,000 related to termination benefits. The termination
benefits resulted from an early retirement program undertaken in1998,
the fourth
quarter of 1995. Plan benefits are based on years of service and the employee's
compensation during the last ten years of employment. Oglethorpe's funding
policy is to contribute annually an amount not less than the minimum required by
the Internal Revenue Code and not more than the maximum tax deductible amount.
The plan's pension cost recognized was a credit of $163,000.
The defined benefit pension plan was replaced with a new money purchase
pension plan which became effective January 1, 1999. Under this new plan
Oglethorpe contributes 5%, subject to IRS limitations, of each employee's annual
compensation. Oglethorpe's contributions to the plan were approximately $444,000
in 1996, 19952000 and 1994 was shown as
follows:
- --------------------------------------------------------------------------------
(dollars$365,000 in thousands) 1996 1995 1994
- --------------------------------------------------------------------------------
Pension cost was comprised of the
following
Service cost - benefits earned
during the year $ 1,149 $ 913 $ 1,084
Interest cost on projected benefit
obligation 872 742 714
Actual return on plan assets (984) (1,889) 387
Net amortization and deferral 351 1,288 (911)
Net gain from a plan curtailment -- (12) (12)
------- ------- -------
Net pension cost $ 1,388 $ 1,042 $ 1,262
======= ======= =======
- --------------------------------------------------------------------------------
The plan's funded status in Oglethorpe's financial statements as of December
31, 1996 and 1995 were as follows:
- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
- --------------------------------------------------------------------------------
Actuarial present value of accumulated
plan benefits
Vested $ 7,554 $ 6,868
Nonvested 540 591
-------- --------
$ 8,094 $ 7,459
======== ========
Projected benefit obligation $(13,211) $(12,326)
Plan assets at fair value 9,218 7,760
-------- --------
Projected benefit obligation in excess of
plan assets (3,993) (4,566)
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions (880) 223
Prior service cost not yet recognized in net
periodic pension cost 498 548
Unrecognized net asset at transition date
being recognized over 19 years (109) (121)
-------- --------
Pension accrual $ (4,484) $ (3,916)
======== ========
- --------------------------------------------------------------------------------
The discount rate and rate of increase in future compensation levels used in
determining the actuarial present value of the projected benefit obligations
shown above were 7.50% and 5.0% in 1996, and 7.25% and 5.0% in 1995,
respectively. The expected long-term rate of return on plan assets was 8.5% in
1996 and 1995, and 8% in 1994, and the discount rate used in determining the
pension expense was 7.25% in 1996, 8.5% in 1995 and 7.5% in 1994.1999.
Oglethorpe has a contributory employee retirement savings plan covering
substantially all employees. Employee contributions to the plan may be invested
in one or more of nine funds. The employee may contribute, subject to
IRSlimitations, up to 16% of his annual compensation. Oglethorpe will match the
employee's contribution up to one-half of the first 6% of the employee's annual
compensation, as long as there is sufficient net margin to do so. The
match, which is calculated each pay period, can be as much as one-half of the
first 6% of the employee's annual compensation depending upon the amount and
timing of the employee's contribution. Effective January 1, 2001, Oglethorpe
will match three-quarters of the first 6% of the employees contribution
depending on the amount and timing of the employee's contribution. Oglethorpe's
contributions to the plan were approximately $561,000$261,000 in 1996, $589,0002000, $226,000 in 19951999
and $565,000$214,000 in 1994.1998.
8. Nuclear insurance:
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member
of Nuclear Mutual Limited (NML)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 participation in the mutual insurer)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 $6,351,000$3,421,000 for each nuclear incident.
56
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is also a
member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer, and
Oglethorpe 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 NMLprimary coverage described above. Under the NEIL
policies, members are subject to retroactive assessments in proportion to their
participationpremiums 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 $12,960,000.$4,000,000.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
annually renewed on or after April 2, 1991 shall be dedicated first for the sole
purpose of placing the reactor in a safe and stable condition after an accident.
Any remaining proceeds are next to be applied toward the costs of
decontamination and debris removal operations ordered by the NRC, and any
further remaining proceeds are to be paid either to the company or to its bond
trustees as may be appropriate under the policies and applicable trust
indentures.
The Price-Anderson Act, as amended in 1988, limits public liability claims
that could arise from a single nuclear incident to $8,900,000,000,$9,500,000,000, which amount
is to be covered by private insurance and agreementsa mandatory program of indemnity with the NRC.deferred
premiums that could be assessed against all owners of nuclear power reactors.
Such private insurance (in the amount of $200,000,000 for each plant, the
maximum amount currently available) is carried by GPC for the benefit of all the
co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered
60
into by and between each of the co-owners and the NRC. In the event of a nuclear
incident involving any commercial nuclear facility in the country involving
total public liability in excess of $200,000,000, a licensee of a nuclear power
plant could be assessed a deferred premium of up to $79,275,000$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 $95,130,000$105,714,000 per incident, but not more than $12,000,000
in any one year.
Oglethorpe participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, Oglethorpe could be subject to a total
maximum assessment of $3,365,000.
All retrospective assessments, whether generated for liability or property,
may be subject to applicable state premium taxes.
9. Commitments:
a. Power purchase and sale agreements:agreements
Oglethorpe is utilizing power marketer arrangements to reduce the cost of
power to the Members. Oglethorpe has a power marketer agreement with LG&E Energy
Marketing Inc. ("LEM"), for approximately 50% of the load requirements of 37 of
the Members and an additional power marketer agreement with Morgan Stanley
Capital Group Inc. ("Morgan Stanley"), effective May 1, 1997, with respect to
50% of the 39 Members' then forecasted load requirements. The LEM agreement is
based on the actual requirements of the participating Members during the
contract term, whereas the Morgan Stanley agreement represents a fixed supply
obligation. Generally, these arrangements reduce the cost of supplying power to
the Members by limiting the risk of unit availability, by providing a guaranteed
benefit for the use of excess resources and by providing future power needs at a
fixed price. Most of Oglethorpe's generating facilities and power purchase
arrangements are available for use by LEM and Morgan Stanley. Oglethorpe
continues to be responsible for all of the costs of its system resources but
receives revenue from LEM and Morgan Stanley for the use of the resources.
In February 2001, LEM initiated the contractually defined arbitration
process to resolve a number of issues relating to administration of the
agreement.
In addition, Oglethorpe has entered into various long-term power purchase
agreements with GPC, Big
Rivers Electric Corporation (Big Rivers), and Entergy Power, Inc. (EPI). Under
the agreement with GPC, Oglethorpe purchased on a take-or-pay basis 1,250
megawatts (MW) of capacity through the period ending August 31, 1996. Effective
September 1, 1996, Oglethorpe will purchase 1,000 MW of capacity through the
period ending August 31, 1997. Effective September 1, 1997, Oglethorpe will
purchase 750 MW of capacity through the period ending August 31, 1998. Effective
September 1,1998, Oglethorpe will purchase 500 MW of capacity through the period
ending December 31,2004, subject to reductions or extension with proper notice.
The Big Rivers agreement commenced in August 1992 and is effective through July
2002. Oglethorpe is obligated under this agreement to purchase on a take-or-pay
basis 100 MW of firm capacity and certain minimum energy amounts associated with
that capacity. The EPI agreement commenced in July 1992, has a term of ten years
and represents a take-or-pay commitment by Oglethorpe to purchase 100 MW of
capacity.
Oglethorpe has a contract with Hartwell Energy Limited Partnership for the
purchase of approximately 300 MW of capacity for a 25-year period commencing in
April 1994.
Oglethorpe has entered into a short-term seasonal power purchase agreement
with Florida Power Corporation. Under the agreement, Oglethorpe will purchase 50
MW of capacity on a take-or-pay basis for the period June 1, 1997 through
September 30, 1997 and 275 MW for the period June 1, 1998 through September 30,
1998.agreements. As of December 31, 1996,2000, Oglethorpe's minimum purchase commitments
under the
abovethese agreements, without regard to capacity reductions or adjustments for
changes in costs, for the next five years are as follows:
- --------------------------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
1997 $ 130,457
1998 111,539
1999 92,873
2000 94,917
2001 97,116$95,400
2002 76,446
2003 63,423
2004 64,866
2005 66,329
- --------------------------------------------------------------------------------
Oglethorpe's power purchases from these agreements amounted to
approximately $190,760,000$175,623,000 in 1996, $206,641,0002000, $132,721,000 in 19951999 and $182,965,000$172,897,000 in
1994.1998.
Oglethorpe has entered into an agreement with Alabama Electric Cooperative
to sell 100 MW of 57
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 a means of reducing the cost of power provided to the Members, in 1996,
Oglethorpe utilized short-term power supply agreements. The initial agreement
was with Enron Power Marketing, Inc. and was in place from January 4, 1996
through August 31, 1996. From September 1, 1996 through December 31, 1996,
Oglethorpe utilized a short-term power supply transaction with Duke/Louis
Dreyfus L.L.C. Under both of2000,
Oglethorpe's estimated minimum rental commitments for these operating leases
over the agreements, the power marketer was required to
provide to Oglethorpe at a favorable fixed rate all the energy necessary to meet
the Members' requirementsnext five years are as follows:
- --------------------------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
2001 $ 2,877
2002 2,877
2003 2,877
2004 2,877
2005 2,877
2006 and Oglethorpe was required to provide to the power
marketer at cost, subject to certain limitations, upon request all energy
available from Oglethorpe's total power resources. Under both agreements,
Oglethorpe continued to operate the power supply system and continued to
dispatch the generating resources to ensure system reliability.beyond 40,489
- --------------------------------------------------------------------------------
61
10. Quarterly financial data (unaudited):
Summarized quarterly financial information for 19962000 and 19951999 is as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)
First Second Third Fourth
(dollars in thousands)
Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
19962000
Operating revenues $270,689 $275,228 $286,648 $ 268,872274,882 $ 285,026 $ 314,433 $ 325,056
Operating margin 73,568 72,514 75,009 61,65861,527 60,986 49,396 49,046
Net margin 8,988 4,732 12,508 (4,476)
19959,188 9,624 (323) 1,489
1999
Operating revenues $257,547 $281,228 $317,536 $ 293,250250,764 $ 273,917 $ 393,636 $ 257,915
Operating margin 68,682 82,048 82,949 74,99862,293 58,342 59,961 51,335
Net margin 8,462 20,292 10,656 (17,152)8,099 4,483 6,241 1,115
- --------------------------------------------------------------------------------
Oglethorpe's business is influenced by seasonal weather conditions. SecondThird quarter 19962000 net margin was lower than the same period of 19951999
primarily as a result of unbudgeted savingsa $10,500,000 reduction in 1995 from the continued capitalizationrevenue requirement approved
by Oglethorpe's Board of costs
of Rocky Mountain dueDirectors. Such reduction in revenues was recorded as a
reduction in sales to delay in commercial operation of the initial unit from
April 1995 to June 1995.
The negative net marginMembers for the fourththird quarter of 1996 is consistent with
expectations and reflects incurrence of certain nonrecurring expenses.
The negative net margin for the fourth quarter of 1995 was primarily
attributable to the deferral of excess margin. For a discussion of the amount of
excess margin deferred, see Note 1.
11. Subsequent events:
a. Power supply arrangements
Oglethorpe has entered into power supply agreements for approximately 50% of
its Members' load requirements with LG&E Power Marketing Inc. These agreements
commenced on January 1, 1997, initially on a short-term basis. These agreements
converted to a long-term arrangement upon the closing of the Corporate
Restructuring discussed below. Oglethorpe is now working to complete a long-term
contract for the remaining approximately 50% of its load.
b. Corporate restructuring
Oglethorpe and the Members completed on March 11, 1997, a corporate
restructuring (the Corporate Restructuring). Pursuant to the Corporate
Restructuring, Oglethorpe divided itself into three specialized companies to
respond to increasing competition and deregulation in the electric industry. As
part of the Corporate Restructuring, Oglethorpe transferred its transmission
business and assets to a newly formed Georgia electric membership corporation,
Georgia Transmission Corporation (An Electric Membership Corporation) (GTC), and
transferred its system operations business to a newly formed Georgia nonprofit
corporation, Georgia System Operations Corporation (GSOC). Oglethorpe retained
its generation business and owned and leased generation assets.
The following unaudited pro-forma balance sheet as of December 31, 1996
reflects the financial position of Oglethorpe as reported and as restated
reflecting the exclusion of the transmission business as though the Corporate
Restructuring had occurred at December 31, 1996.
The following unaudited pro-forma statement of revenues and expenses for the
year ended December 31, 1996 reflects the operations of Oglethorpe as reported
and as restated, reflecting the exclusion of the transmission business as though
the Corporate Restructuring had occurred at the beginning of 1996.
These unaudited pro-forma financial statements have been prepared based on
assumptions and estimates deemed appropriate and are presented for illustrative
purposes only and are not necessarily indicative of the financial position or
results of operations which would have actually been reported had the
transactions occurred in the period reported.
The columns titled Oglethorpe post-restructuring in the following unaudited
pro-forma financial statements have been restated reflecting the exclusion of
the system operations business as though the Corporate Restructuring had
occurred in the period reported. The system operations business is not shown
separately due to immateriality.
58
Pro-Forma Balance Sheet
(Unaudited)
As of December 31,1996
(dollars in thousands)
- ------------------------------------------------------------------------------------------------------------------------------------
Oglethorpe Transmission
Oglethorpe Pro-Forma Pro-Forma
(Pre- (Post- (Post-
Restructuring) Restructuring) Restructuring)
- ------------------------------------------------------------------------------------------------------------------------------------
Assets
Electric plant, at original cost:
In service $ 5,742,597 $ 4,908,752 $ 815,929
Less: Accumulated provision for depreciation (1,488,272) (1,299,328) (179,960)
----------- ----------- -----------
4,254,325 3,609,424 635,969
Nuclear Fuel, at amortized cost 86,722 86,722 --
Plant acquisition adjustments, at amortized cost 4,153 -- 8,780
Construction work in progress 31,181 12,466 18,715
----------- ----------- -----------
4,376,381 3,708,612 663,464
----------- ----------- -----------
Investments and funds 197,288 200,812 --
----------- ----------- -----------
Current assets:
Cash and temporary cash investments, at cost 224,282 245,424 --
Receivables 113,289 113,289 --
Inventories, at average cost 89,825 84,018 5,807
Prepayments and other current assets 14,625 14,264 361
----------- ----------- -----------
442,021 456,995 6,168
----------- ----------- -----------
Deferred charges:
Premium and loss on reacquired debt,
being amortized 201,007 169,081 31,926
Deferred debt expense, being amortized 21,703 18,256 3,447
Other 123,775 123,775 --
----------- ----------- -----------
346,485 311,112 35,373
----------- ----------- -----------
$ 5,362,175 $ 4,677,531 $ 705,005
=========== =========== ===========
Equities and Liabilities
Capitalization:
Patronage capital and membership fees $ 356,229 $ 356,229 $ --
Long-term debt 4,052,470 3,380,581 688,878
Obligations under capital leases 293,682 293,682 --
Obligations under Rocky Mountain
transactions 41,685 41,685 --
----------- ----------- -----------
4,744,066 4,072,177 688,878
----------- ----------- -----------
Current liabilities:
Long-term debt and capital leases due
within one year 159,622 144,565 15,057
Accounts payable 42,891 41,788 --
Accrued interest 15,931 15,931 --
Accrued and witheld taxes 4,940 4,940 --
Other current liabilities 14,022 12,799 1,070
----------- ----------- -----------
237,406 220,023 16,127
----------- ----------- -----------
Deferred credits and other liabilities 380,703 385,331 --
----------- ----------- -----------
$ 5,362,175 $ 4,677,531 $ 705,005
=========== =========== ===========
- ------------------------------------------------------------------------------------------------------------------------------------
Pro-Forma Statement of Revenues and Expenses
(Unaudited)
For the year ended December 31,1996
(dollars in thousands)
- ------------------------------------------------------------------------------------------------------------------------------------
Oglethorpe Transmission
Oglethorpe Pro-Forma Pro-Forma
(Pre- (Post- (Post-
Restructuring) Restructuring) Restructuring)
- ------------------------------------------------------------------------------------------------------------------------------------
Operating revenues:
Sales to Members $ 1,023,094 $ 927,156 $ 95,938
Sales to non-Members 78,343 68,554 9,789
----------- ----------- -----------
Total operating revenues 1,101,437 995,710 105,727
----------- ----------- -----------
Operating expenses:
Fuel 206,524 206,524 --
Production 129,178 129,178 --
Purchased power 229,089 229,089 --
Power delivery 18,216 -- 18,216
Depreciation and amortization 163,130 138,008 25,122
Taxes other than income taxes 30,262 22,728 7,534
Other operating expenses 42,289 33,307 8,982
----------- ----------- -----------
Total operating expenses 818,688 758,834 59,854
----------- ----------- -----------
Operating margin 282,749 236,876 45,873
----------- ----------- -----------
Other income (expense):
Interest income 23,485 20,129 3,356
Amortization of deferred margins 32,047 29,336 2,711
Allowance for equity funds used during
construction 238 114 124
Other 9,564 10,270 (706)
----------- ----------- -----------
Total other income 65,334 59,849 5,485
----------- ----------- -----------
Interest charges:
Interest on long-term debt and other obligations 328,907 279,542 49,365
Allowance for debt funds used during
construction (2,576) (1,231) (1,345)
----------- ----------- -----------
Net interest charges 326,331 278,311 48,020
----------- ----------- -----------
Net margin $ 21,752 $ 18,414 $ 3,338
=========== =========== ===========
- ------------------------------------------------------------------------------------------------------------------------------------
The above pro-forma balance sheet reflects the transfer of the transmission
and system operations businesses, and the related financing activities related
to the transfer based on the purchase price formula. In connection with the
Corporate Restructuring, Oglethorpe also made a special patronage capital
distribution to the Members totaling $48,863,000 which was used by the Members
to establish equity in and to provide initial working capital to GTC.
592000.
62
REPORT OF MANAGEMENT
The management of Oglethorpe Power Corporation has prepared this report and
is responsible for the financial statements and related information. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
Oglethorpe maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions. Limitations exist in any system of
internal control based upon the recognition that the cost of the system should
not exceed its benefits. Oglethorpe believes that its system of internal
accounting control, together with the internal auditing function, maintains
appropriate cost/benefit relations.
Oglethorpe's system of internal controls is evaluated on an ongoing basis
by itsa qualified internal audit staff. The Corporation's independent public
accountants (Coopers & Lybrand L.L.P.)(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.
Coopers & Lybrand L.L.P.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 Power Corporation.
T. D. KilgoreOglethorpe.
Thomas A. Smith
President and Chief Executive Officer
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Oglethorpe
Power Corporation:
We have auditedIn our opinion, the accompanying balance sheets and statements of
capitalization of Oglethorpe Power Corporation (a Georgia corporation) as of
December 31, 1996 and 1995 and the related statements of revenues and expenses, patronage
capital and of cash flows present fairly, in all material respects, the
financial position of Oglethorpe Power Corporation at December 31, 2000 and
1999, and the results of its operations and its cash flows for each of the three
years then ended.in the period ended December 31, 2000 in conformity with generally
accepted accounting principles in the United States of America. These financial
statements are the responsibility of Oglethorpe's management. Ourthe Company's management; our
responsibility is to express an opinion on these financial statements based on
our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards. Those 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. An audit also includesstatements, assessing the accounting principles
used and significant estimates made by management, as well asand evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Oglethorpe Power Corporation as
of December 31, 1996 and 1995 and the results of its operations and its cash
flows for the years then ended in conformity with generally accepted accounting
principles.
Coopers & Lybrand L.L.P.
Atlanta, Georgia,
February 21, 1997, except for Note 11, as to which the date is March 11,
1997.
60
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Oglethorpe Power Corporation:
We have audited the statement of revenues and expenses, patronage capital,
and cash flows of Oglethorpe Power Corporation (a Georgia corporation) for the
year ended December 31, 1994. These financial statements are the responsibility
of Oglethorpe's management. Our responsibility is to express an opinion on these
financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards 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. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the results of operations, changes in patronage capital,
and cash flows of Oglethorpe Power Corporation for the year ended December 31,
1994 in conformity with generally accepted accounting principles.
As explained in Note 2 of notes to financial statements, effective January 1,
1994, Oglethorpe Power Corporation changed its method of accounting for certain
investments in debt and equity securities.
Arthur AndersenPricewaterhouseCoopers LLP
Atlanta, Georgia,
February 24, 1995.
6123, 2001
63
ItemITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ItemITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(a) Identification of Directors:
As part of the Corporate Restructuring, Oglethorpe amended its Bylaws
to provide for an eleven memberhas 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") and Oglethorpe's President and Chief
Executive Officer. The. Each Member DirectorsDirector must be a director or
general manager of an Oglethorpe Member. Five of the six Member Directors must
be located in oneeach of five geographical regions of the State of Georgia. The
sixth Member Director is elected statewide. TheNone of the four Outside Directors
must notmay be a director, officer or employee of OglethorpeGTC, GSOC or any Member. All eleventen
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.
All of the new directors have been elected with terms beginning on
March 11, 1997, except for two of the four Outside Directors which are expected
to be elected at the annual meeting of Members on March 27, 1997. The Bylaws provide for staggering thestaggered three-year terms of the directors by
dividing the number of directors into three groups. As noted below, someThe terms of approximately
one-third of the directors were elected
to an initial termexpire each year
Oglethorpe is managed and operated under the direction of 1 year, some 2 yearsa President and
some 3 years. As these initial
terms expire, directors will thereafter be elected for a termChief Executive Officer, who is appointed by the Board of three years.Directors. The Senior
Officers and Directors of Oglethorpe are as follows:
Larry N. Chadwick, age 56, is the Member Director from the Northwest
Region. He is the owner of Chadwick's Hardware in Woodstock, Georgia. He has
served on the Board of Directors of Oglethorpe since July 1989. His present term
will expire in March 1999. Mr. Chadwick is an engineer, with experience in the
design of hydrogen gas plants. He isName Age Position
J. Calvin Earwood............ 59 Chairman of the Board of Cobb EMC.Directors,
Member Director, Statewide
Thomas A. Smith.............. 46 President and Chief Executive Officer
Michael W. Price............. 40 Chief Operating Officer
W. Clayton Robbins........... 54 Senior Vice President, Finance and
Administration
Elizabeth B. Higgins......... 32 Vice President, Corporate Strategy and
Member Services
Larry N. Chadwick............ 60 Member Director, Northwest Region
Benny W. Denham, age 66, is theDenham.............. 70 Member Director, Southwest Region
Sammy M. Jenkins............. 74 Member Director, Southeast Region
Mac F. Oglesby............... 68 Member Director, Northeast Region and
Treasurer
J. Sam L. Rabun.............. 69 Member Director, Central Region and
Vice Chairman
of the Board and is the
MemberAshley C. Brown.............. 55 Outside Director
from the Southwest Region. Mr. Denham has served as an executive
officer of Oglethorpe since March 1993. He has served on the Board of Directors
of Oglethorpe since December 1988. His present term will expire in March 1998.
He was previously the Vice-Chairman of the Executive Committee and a member of
the Power Planning and Technical Advisory Committee. Mr. Denham is co-owner of
Denham Farms in Turner County, Georgia. He served on the Turner County
Commission from 1980 to 1990, and was Chairman for six of those years. Mr.
Denham is aWm. Ronald Duffey............ 59 Outside Director
of Community National Bank in Ashburn, Georgia and aJohn S. Ranson............... 71 Outside Director
of Irwin EMC.Jeffrey D. Tranen............ 54 Outside Director
J. Calvin Earwood age 55, 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 as a
Directoron the Board of Directors of
Oglethorpe since March 1981. His present term will expire in March 2000.2003. He was previously a memberis
64
the Chairman of the Operations ReviewCompensation Committee. From 1965 through
62
1982, Mr. Earwood
was a salesman and part owner of Builders Equipment Company. Since January 1983,
he has been the owner and President of Sunbelt Fasteners, Inc., which sells
specialty tools and fasteners to the commercial construction trade. He is also
Vice Chairman of the Board of Directors of both Community Trust Financial
Services and Community Trust Bank in Hiram, Georgia and a Director of GreyStone
Power Corporation.
Thomas A. Smith is the President and Chief Executive Officer of Oglethorpe
and has served in that capacity since September 1999. He previously served as
Senior Vice President and Chief Financial Officer of Oglethorpe from September
1998 to August 1999, Senior Financial Officer from 1997 to August 1998, Vice
President, Finance from 1986 to 1990, Manager of Finance from 1983 to 1986 and
Manager, Financial Services from 1979 to 1983. From 1990 to 1997, Mr. Smith was
Senior Vice President of the Rural Utility Banking Group of CoBank, where he
managed the bank's eastern division, rural utilities. Mr. Smith is a Certified
Public Accountant, has a Master of Science degree in Industrial
Management-Finance from the Georgia Institute of Technology, a Master of Science
degree in Analytical Chemistry from Purdue University and a Bachelor of Arts
degree in Mathematics and Chemistry from Catawba College. Mr. Smith is a
Director of GSOC and a Director of the Georgia Chamber of Commerce. Mr. Smith is
also a member of the Advisory Board of Mid-South Telecommunications, Inc. in
Houston, Texas.
Michael W. Price is the Chief Operating Officer of Oglethorpe and has
served in that office since February 1, 2000. Mr. Price served GSOC from January
1999 to January 2000, first as Senior Vice President and then as Chief Operating
Officer. He served as Vice President of System Planning and Construction of GTC
from May 1997 to December 1998. He served as a manager of system control of GSOC
from January to May 1997. From 1986 to 1997, Mr. Price served Oglethorpe in the
areas of control room operations, system planning, construction and engineering,
and energy management systems. Prior to joining Oglethorpe, he was a field test
engineer with the TVA from 1983 to 1986. Mr. Price has a Bachelor of Science
degree in Electrical Engineering from Auburn University.
W. Clayton Robbins is the Senior Vice President, Finance and Administration
of Oglethorpe and has served in that office since November 1999. Mr. Robbins
served as Senior Vice President and General Manager of Intellisource, Inc. from
February 1997 to November 1999. Prior to that, Mr. Robbins held several
positions at Oglethorpe since 1986, including Senior Vice President, Support
Services from December 1991 to January 1997 and Vice President, Market Research
and Analysis from December 1989 to December 1991. Before coming to Oglethorpe,
Mr. Robbins spent 18 years with Stearns-Catalytic World Corporation, a major
engineering and construction firm, including 13 years in management positions
responsible for human resources, information systems, contracts, insurance,
accounting and project controls. Mr. Robbins has a Bachelor of Arts degree in
Business Administration from the University of North Carolina in Charlotte.
Elizabeth B. Higgins is the Vice President, Corporate Strategy and Member
Services of Oglethorpe and has served in this office since July 2000. Ms.
Higgins served as the Vice President and Assistant to the Chief Executive
Officer from October 1999 to July 2000 and served in other capacities for
Oglethorpe from April 1997 to September 1999. Prior to that, Ms. Higgins served
as Project Manager at Southern Engineering from October 1995 to April 1997, as
Senior Consultant at Deloitte & Touche, LLP from April 1995 to October 1995, and
as Senior Consultant at Energy Management Associates from June 1991 to April
1995. In these positions, Ms. Higgins was responsible for competitive bidding
analyses, rate designs, integrated resource planning studies,
operational/dispatch studies, bulk power market analysis, merger analyses and
litigation support. Ms. Higgins has a Bachelor of Industrial Engineering from
the Georgia Institute of Technology.
Larry N. Chadwick is the Member Director from the Northwest Region. He has
been the owner of Chadwick's Hardware in Woodstock, Georgia since 1983. He has
65
served on the Board of Directors of Oglethorpe since July 1989. His present term
will expire in March 2002. Mr. Chadwick is an engineer, with experience in the
design of hydrogen gas plants. He is Chairman of the Board of Cobb EMC.
Benny W. Denham is the Member Director from the Southwest Region. He has
served on the Board of Directors of Oglethorpe since December 1988. His present
term will expire in March 2001. Mr. Denham has been co-owner of Denham Farms in
Turner County, Georgia since 1980. He serves as the Chairman of the Turner
County Chamber of Commerce. Mr. Denham is a Director of Community National Bank
Holding Co., Cumberland National Bank, Georgia Electric Membership Corporation
and Irwin EMC.
Sammy M. Jenkins age 70, is the Member Director from the Southeast Region. He is in the farm machinery business and has
beenretired from farming after 25 years. In addition, from 1973 to 1995, he was
President of Jenkins Ford Tractor Co., Inc. since 1973., 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 1999. He was
Vice Chairman of the Board of Oglethorpe from March 1989 to March 1990.2002.
Mac F. Oglesby age 64, is the Member Director from the Northeast Region.Region and the
Treasurer of Oglethorpe. He served as Assistant Secretary-Treasureris a member of Hart EMC from July 1986
through December 1987, when he was appointed President.the Audit Committee. He has served as
a Directormember of the Board of Directors of Hart EMC since 1980 and now serves as its
Chairman of the Board. He has served on the Board of Directors of Oglethorpe
since February 1987. His present term will expire in March 2000.2003. Mr. Oglesby was
a U.S. Postal Service Rural Carrier for 30 years.years until he retired in 1991.
J. Sam L. Rabun age 65,is the Vice-Chairman of the Board and is the Member
Director from the Central Region. He is also a member of the Compensation
Committee. He has been the owner and operator of a farm in Jefferson County,
Ga.Georgia since 1979. He is also a 50% owner of R&R Livestock Farms, Inc. He has
served as a Directoron the Board of Directors of Oglethorpe since March 1993, with his1993. His present
term towill expire in March 1998.2001. Mr. Rabun served as the President of the Board
of Jefferson EMC from 1993 to 1996.1996, was employed as General Manager from 1974 to
1979 and as Office Manager and Accountant from 1970 to 1974. Mr. Rabun is the
President of the Georgia EMC Directors' Association.
Ashley C. Brown age 51, 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 1999.2002. He ishas been Executive
Director of the Harvard Electricity Policy Group at Harvard University's John F.
Kennedy School of Government. HeGovernment since 1993. In addition, he is Of Counsel to the
law firm of Verner, Liipfert, Bernhard, McPhersonLeBoeuf, Lamb, Greene and Hand of
Washington, D.C. In addition, he is a Principal Consultant with the firm of
Hagler Bailly Consulting, Inc.MacRae. From April 1983 through April
1993, Mr. Brown served as Commissioner of the Public Utilities Commission of
Ohio. Prior to his appointment to the Ohio Commission, he was Coordinator and
Counsel of the Montgomery County, Ohio, Fair Housing Center. From 1979 to 1981,
he was Managing Attorney for the Legal Aid Society of Dayton (Ohio), Inc. From
1977 to 1979, he was Legal Advisor of the Miami Valley Regional Planning
Commission in Dayton, Ohio. While practicing law, he specialized in litigation in federal and state
courts, as well as before administrative bodies. 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 AdministrationArts degree from the University of Cincinnati,
and a Bachelor of Science degree from Bowling Green State University.
Newton A. Campbell, age 68,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 2000. He retired in January 1994 as Chairman and Chief Executive
Officer of Burns & McDonnell Engineering Company after serving 41 years with the
firm.2001. Mr. Campbell directed the overall operations of Burns & McDonnell from
1982 until his retirement. From 1976 through 1982, he served as Vice President
and General Manager of the Power Division, and was responsible for directing the
company's work in the planning and design of fossil fueled power generation
facilities, high voltage transmission systems, and other power related
facilities. Mr. Campbell has been involved in feasibility, planning and
financial studies for numerous new and existing public and privately owned
electric utilities during various phases of their organization and development.
He also has considerable experience in conceptual studies, design, and project
management for large electric utility generation, transmission, substation and
distribution facilities throughout the United States. Mr. Campbell received a
Master of Business Administration degree from the University of Missouri at
Kansas City with a concentration in finance. He also holds a Bachelor of Science
degree in Electrical Engineering from the University of Illinois.
T. D. Kilgore, age 49,Duffey is the President and Chief
Executive Officer and a director of OglethorpePeachtree 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 as an executiveon the Board of
Directors of Oglethorpe since July 1984 (from
July 1984March 1997. His term will expire in March 2002. He
is also a member of the Compensation Committee. He has been the President of
Ranson Municipal Consultants, L.L.C., a financial advisor in Wichita, Kansas,
since 1994. From 1990 to July 1986, as Division Manager, Power Supply; July 1986 to July
1991,1994, Mr. Ranson was Chairman of Ranson Capital Corp.
an investment banking firm. Mr. Ranson has approximately 48 years experience in
the investment banking business. His public finance clients have included the
Kansas Turnpike Authority, the Kansas Municipal Energy Agency, the Kansas
Municipal Gas Agency, and the Kansas City (Kansas) Board of Public Utilities.
Mr. Ranson received his Bachelor of Science in Business Administration from the
University of Kansas (Lawrence, Kansas) and attended the Navy Supply Corps
School in Bayonne, New Jersey.
Jeffrey D. Tranen is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 2000. His present term will expire in March
2003. Since May 2000, he has served as Senior Vice President Power Supply;of Lexecon, an
economic, regulatory and since July 1991,business strategy consulting firm. Prior to that, he
served as President and Chief Executive Officer). He also currently servesOperating Officer of Sithe Northeast, a merchant
generation company. Mr. Tranen served as the President and Chief Executive
Officer and as a director of both GTC and GSOC. Mr. Kilgore has
over 20 years of experience, including five years in senior management positions
with
63
Arkansas Power & Light Co. and seven years as a civilian employee with the
Department of the ArmyCalifornia Independent System Operator from 1997 to 1999. From
1970 to 1997, Mr. Tranen worked in several positions ranging from reliability engineering to
construction management. Mr. Kilgore has served on various industry committees
includingfor the New England
Electric Power Research Institute's Board of Directors and its
Advanced Power Systems Division and Coal System, Division Advisory Committees. He
has also served on the Boards of Directorsmost recently as Senior Vice President of the U.S. Committee for Energy
Awareness, the Advanced Reactor Corporation, on the EdisonNew England
Electric Institute's
Power Plant Availability Improvement Task Force and the Nuclear Power Oversight
Committee. Mr. KilgoreSystem. He is currently serves ona member of the Board of Directors of the Georgia
Chamber of Commerce and on the National Rural Electric Cooperative Association's
Power and Generation Committee.Doble
Engineering. Mr. KilgoreTranen has a Bachelor of Science degree in MechanicalElectrical Engineering from the University of Alabama, where he has been
recognized as a Distinguished Engineering Fellow, and an Masters of Engineering
degree in industrial engineering from Texas A&M.
(b) Identification of Senior Executives:
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 executives assisting Mr. Kilgore, their areas of responsibility and
a brief summaryMaster of their experience are as follows:
Clarence D. Mitchell, Senior Vice President, Power Supply, age 43, has
served as an executive of Oglethorpe since January 1995. Prior to that time, Mr.
Mitchell served as Assistant to the Senior Vice President for Generation from
February 1994 to December 1994; Manager of Corporate Planning from September
1992 to January 1994; Manager of Construction from January 1992 to August 1992;
Program Director of Technical Services (environmental, survey and mapping, land
acquisition and R&D) from January 1989 to December 1991; and from April 1981 to
December 1988 held various positions in the generation area, including
supervisor, project engineer and generation engineer. Before coming to
Oglethorpe, Mr. Mitchell spent four years as a field engineer with General
Electric Company and worked various installation and maintenance projects
related to coal, nuclear, gas and oil-fired generation. Mr. Mitchell has an MS
degree in Management from Georgia State University, a Bachelor of Science degree
in Mechanical Engineering from Georgia Institute of Technology and a Bachelor of
Science degree in Interdisciplinary Science from Morehouse College. Mr. Mitchell
is presently the Oglethorpe representative on both the Nuclear Managing Board
and the Plant Scherer Managing Board. For information about the Managing Boards
see "CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--The Plant Agreements" in
Item 2. Mr. Mitchell also serves as a Trustee of the Foundation of the Southern
Polytechnic State University.
Nelson G. Hawk, Senior Vice President and Group Executive, Marketing,
age 47, has served as an executive at Oglethorpe since February 1994,
responsible for Market Planning, Economic Development, Commercial/Industrial
Marketing and Pricing, Commercial/Industrial Services, and Residential
Marketing. Prior to coming to Oglethorpe, Mr. Hawk spent almost 24 years with
the Florida Power & Light Company and related subsidiaries, serving as Director
of Regulatory Affairs from October 1993 to January 1994, Director of Market
Planning from July 1991 to September 1993, and as Director of Strategic Business
and President of FPL Enersys Services, Inc. (A utility subsidiary providing
energy services to commercial/industrial customers) from April 1989 to June
1991. Mr. Hawk has a wide range of utility management experience in energy
management, finance, strategic planning, marketing, system planning, quality
assurance, and distribution engineering. Mr. Hawk is a board member of the
Georgia Electrification Council, Inc. and the Georgia Partnership for Excellence
in Education, and served on the board of directors as well as President of the
National Association of Energy Services Companies (NAESCO), a national trade
association, during the late 1980s. Mr. Hawk is a registered Professional
Engineer in Florida and has a Bachelor of Science degree in Electrical Engineering from the GeorgiaMassachusetts Institute
of Technology and a Master of Business
Administration degree from Florida International University.
64Technology.
67
ItemITEM 11. EXECUTIVE COMPENSATION
Summary Compensation Table
The following table sets forth, for Oglethorpe's President and Chief
Executive Officer and for the five most highly compensated senior executives,three other executive officers, all compensation
paid or accrued for services rendered in all capacities during the years ended
December 31, 1996, 19952000, 1999 and 1994. Amounts included in the table
under "Bonus" represent payments based on an incentive compensation policy. All
amounts paid under this policy are fully at risk each year and are earned based
upon the achievement of corporate goals and each individual's contribution to
achieving those goals. In conjunction with this policy, base salaries are
targeted below the market valuations for similar positions and remain fairly
stable unless the job content changes.1998.
Annual Compensation
Name and Compensation------------------- All Other
Principal Position Year Salary Bonus (2) Compensation
- ------------------ ---- --------- ---------------- ----- ------------
T. D. Kilgore 1996 $265,627 $0 $6,246 (1)Thomas A. Smith(1)................................... 2000 $ 275,000 $ 82,800 $ 14,005(2)
President and Chief Executive Officer 1995 235,000 10,000 6,012
1994 224,997 0 6,7581999 202,008 65,283 14,237
1998 183,935 12,180 1,247
W. Clayton Robbins (3) 1996 144,460 17,112 5,425 (1)
Sr.Robbins(3)................................ 2000 163,000 42,476 11,335(2)
Senior Vice President 1995 142,310 10,631 4,716
Support Services 1994 140,366 11,946 4,986
Nelson G. Hawk 1996 142,535 16,530 5,246 (1)
Sr.and Finance Administration 1999 23,341 35,945 1,259
1998 0 0 0
Michael W. Price(4).................................. 2000 157,667 50,912 23,583(2)(5)
Chief Operating Officer 1999 0 0 0
1998 0 0 0
Elizabeth B. Higgins................................. 2000 126,125 24,975 11,846(2)
Vice President, 1995 140,000 10,899 4,589
Marketing 1994 116,005 9,620 32,821
Clarence D. Mitchell 1996 133,369 17,112 3,887Corporate Strategy and 1999 88,431 22,233 9,457
Member Services 1998 55,355 13,365 1,845
- -----------------
(1) Sr. Vice President, 1995 110,058 7,776 4,251
Power Supply 1994 91,705 5,765 3,354
Wiley H. SandersPrior to September 1, 1998, Mr. Smith provided services to Oglethorpe under
a contractual arrangement and the amounts reflected for 1998 include those
contract payments.
(2) Includes contributions made in 2000 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Mr. Smith, Mr. Robbins, Mr. Price and
Ms. Higgins of $5,100, $2,073, $4,768 and $4,239, respectively;
contributions under the Money Purchase Pension Plan on behalf of Mr. Smith,
Mr. Robbins, Mr. Price and Ms. Higgins of $8,500, $8,500, $8,500 and
$7,418, respectively; and insurance premiums paid on term life insurance on
behalf of Mr. Smith, Mr. Robbins, Mr. Price and Ms. Higgins of $405, $762,
$315 and $189, respectively.
(3) Mr. Robbins became an Oglethorpe employee on November 16, 1999.
(4) 1996 123,750 9,340 82,715 (1) (4)
Vice President, Transmission 1995 135,000 9,295 5,703
1994 119,785 12,737 25,178
Eugen HecklMr. Price became an Oglethorpe employee on February 1, 2000.
(5) 1996 99,480 16,734 117,245 (1) (5)
Sr. Vice President, Finance 1995 142,114 13,174 7,651
1994 142,114 13,919 7,600Includes a signing bonus of $10,000 paid in 2000.
- ----------
(1) Includes contributions made in 1996 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. Kilgore, Robbins, Hawk, Mitchell,
Sanders and Heckl of $4,750, $4,072, $4,446, $2,969, $3,654 and $2,958,
respectively; and insurance premiums paid on term life insurance on behalf of
Messrs. Kilgore, Robbins, Hawk, Mitchell, Sanders and Heckl of $1,496, $1,353,
$800, $918, $2,831 and $2,200, respectively.
(2) All executives listed above, except Mr. Kilgore, participate in an incentive
compensation program. Mr. Kilgore's compensation is governed solely by the Board
of Directors.
(3) In conjunction with the Corporate Restructuring, Mr. Robbins ceased to be a
senior executive of Oglethorpe as of January 31, 1997. Mr. Robbins now serves as
Vice President of Intellisource's Southeast operations, including support
services to Oglethorpe, GTC and GSOC. See "OGLETHORPE POWER
CORPORATION--Relationship with Intellisource" in Item 1 for further discussion.
(4) Mr. Sanders retired from Oglethorpe as of November 30, 1996. Mr. Sanders'
1996 compensation includes accrued severance benefits of $59,114, payment of
accrued vacation and sick benefits of $4,998 and relocation costs of $12,118.
65
(5) Mr. Heckl elected to retire from Oglethorpe under the provisions of an early
retirement program as of September 11, 1996. Mr. Heckl's 1996 compensation
includes severance benefits of $65,258, retirement-related contributions to his
deferred compensation account of $34,938 and payment of accrued vacation and
sick benefits of $11,891.
Pension Plan Table
Years of Credited Service
-----------------------------------------------
Average Compensation 15 20 25
- -------------------- ---------- --------- ---------
$ 50,000.................................................. $12,684 $16,911 $21,139
75,000.................................................. 20,184 26,911 33,639
100,000.................................................. 27,684 36,911 46,139
125,000.................................................. 35,184 46,911 58,639
150,000.................................................. 42,684 56,911 71,139
175,000.................................................. 50,184 66,911 83,639
200,000.................................................. 57,684 76,911 96,139
225,000.................................................. 65,184 86,911 108,639
250,000.................................................. 72,684 96,911 121,139
275,000.................................................. 80,184 106,911 133,639
The preceding table shows estimated annual straight life annuity
benefits payable upon retirement to persons in specified compensation and
years-of-service classifications assuming such persons had attained age 65 and
retired during 1996. For purposes of calculating pension benefits, compensation
is defined as total salary and bonus, as shown in the above Summary Compensation
Table. Because covered compensation changes each year, the estimated pension
benefits for the classifications above will also change in future years. The
above pension benefits are not subject to any deduction for Social Security or
other offset amounts.
As of December 31, 1996, the years of credited service under the Pension
Plan for the individuals listed in the Summary Compensation Table are as
follows:
Years of
Name Credited Service
---- ----------------
Mr. Kilgore.......................................... 11
Mr. Robbins.......................................... 10
Mr. Hawk ............................................ 1
Mr. Mitchell......................................... 15
Mr. Sanders.......................................... 1
Mr. Heckl............................................ 20
Compensation of Directors
Under a proposed policy which is scheduled for approval at the March 27,
1997 Board meeting, Oglethorpe will paypays its Outside Directors a per diem fee of $5,500 per Board meeting for
the first four meetings in a year; a per diemfee of $1,000 per Board meeting will be paid for the
fifth and subsequentremaining other Board meetings in a year. Outside Directors willare also be paid $1,000
per day for attending committee meetings, annual meetings of the Members or
other official meetings of Oglethorpe. Under the proposed policy, Member Directors will beare paid a per diem fee of $1,000
per Board meeting and a per diem of $300$600 per day for attending committee meetings, annual
meetings of the Members or other official meetingsbusiness of Oglethorpe. In addition,
Oglethorpe will reimbursereimburses all Directors for
66
out-of-pocket expenses incurred in
attending a meeting. All Directors will beare paid a per diem fee of $50 per day when participating in
meetings conducted by conference call. The Chairman of the Board will beis paid an additional 20%
of the
per diemhis Director's fee per Board meeting for time involved in preparing for the
meetings.
Employment Contracts
Effective January 1, 1996, Oglethorpe entered into an employment
agreementEmployment Agreement with itsThomas A. Smith,
Oglethorpe's President and Chief Executive Officer.Officer, effective September 15,
1999. The term of the agreement extends tountil December 31, 1998, with certain automatic annual extension
provisions beyond that date2002, and automatically renews
for successive one-year periods unless either party gives notice of termination
60
days prior to an extension. PursuantDecember 31, 2000 or 25 months prior to the agreement,expiration of any extension
68
of the agreement. Mr. Kilgore'sSmith's minimum base salary is $250,000 per year, and bonus will be determinedis
annually adjusted by the Board of Directors of Oglethorpe. In addition, Mr.
Smith has opportunities for variable pay for accomplishing goals set by
Oglethorpe's Board with annual base salary
being at least $240,000. Underof Directors each year.
Upon the agreement, if Oglethorpe terminatesoccurrence of any of the following events, Mr. Kilgore's employment without cause, heSmith 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 benefits he would have received betweena maximum of two years' pay) plus the datecost of termination toproviding all health and
dental insurance for the endlonger of one year or the remaining term of the
agreement. In addition, ifthe case of (3) above, Oglethorpe terminatesalso agrees to hire Mr. Kilgore's employment
without causeSmith as
a consultant for one year at a rate equal to his then-applicable base salary.
Oglethorpe has also entered into Employment Agreements with Michael W.
Price, W. Clayton Robbins and Elizabeth B. Higgins, Oglethorpe's Chief Operating
Officer, Senior Vice President of Finance and Administration and Vice President,
Corporate Strategy and Member Services, respectively. Mr. Price's agreement was
effective February 1, 2000, and Mr. Robbins' and Ms. Higgins' agreements were
effective August 1, 2000. Each agreement extends until December 31, 2001, and
automatically renews for a successive one-year period unless either party gives
notice of termination prior to November 30, 2000 or meaningfully reduces his stated duties or prerogatives within
three13 months prior to or 24 months subsequent to a Change in Controlthe
expiration of Oglethorpe (as defined inany extension of the agreement), a severance payment will be paid in an
amount not less than two times Mr. Kilgore'sAgreement. Minimum annual base salary onsalaries are
$172,000 for Mr. Price, $164,000 for Mr. Robbins and $135,000 for Ms. Higgins.
Salaries are annually adjusted by the dateBoard of termination orDirectors of Oglethorpe. Each
executive has opportunities for variable pay for accomplishing goals set by
Oglethorpe's Board of Directors each year.
Under each Employment Agreement, the date on which his duties or prerogatives are reduced,
whichever is applicable. If such reduction in duties occurs, Mr. Kilgoreexecutive will be entitled to a
lump-sum severance regardless whether he is terminatedpayment if Oglethorpe terminates the executive without cause
or resigns. If Mr.
Kilgore voluntarily separates himself from Oglethorpe, heif 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 be prohibited
from working with a competitor of Oglethorpeequal the
executive's base salary for a period of one year, thereafter
and will be paid an amount equal to his then current salary, bonus and benefits
for such period.plus the equivalent of six months' medical
allowance.
Compensation Committee Interlocks and Insider Participation
E. J. Martin, Jr., J. Calvin Earwood, John B. Floyd, Jr.,S. Ranson and J. G.
McCalmonSam L. Rabun served as members of
the Oglethorpe Human Resources ManagementPower Corporation Compensation Committee which functioned as Oglethorpe's compensation committee for 1996. J.
Calvinin 2000. Mr. Earwood has
served as an executive officer of Oglethorpe since 1984 and has served as the
Chairman of the Board since 1989.
6769
ItemITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ItemITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
T. D. Kilgore is the President and Chief Executive Officer and a
Director of Oglethorpe, GTC and GSOC. Oglethorpe plans to make payments to GSOC
for system operations services in 1997 of approximately $6.8 million, which is
55% of GSOC's budgeted revenues. (See "OGLETHORPE POWER CORPORATION--Corporate
Restructuring" in Item 1.)
68None.
70
PART IV
ItemITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Page
----(a) List of Documents Filed as a Part of This Report.
(1) Financial Statements (Included under "Item 8. Financial Statements
and Supplementary Data")
Statements of Revenues and Expenses, For the Years Ended
December 31, 1996, 19952000, 1999 and 1994.............................. 431998...............................45
Statements of Patronage Capital, For the Years Ended
December 31, 1996, 19952000, 1999 and 1994.................................... 431998...............................45
Balance Sheets, As of December 31, 19962000 and 1995...................... 441999.................46
Statements of Capitalization, As of December 31, 19962000 and 1995............................................................ 461999...48
Statements of Cash Flows, For the Years Ended
December 31, 1996, 19952000, 1999 and 1994................................................. 471998...............................49
Notes to Financial Statements, including pro-forma financial
statements relating to the Corporate Restructuring.................. 48Statements....................................50
Report of Management.................................................. 60
ReportsManagement.............................................63
Report of Independent Public Accountants............................. 60Accountants................................63
(2) Financial Statement Schedules
None applicable.
(3) Exhibits
Exhibits marked with an asterisk (*) are hereby incorporated by
reference to exhibits previously filed by the Registrant as indicated in
parentheses following the description of the exhibit.
Number Description
2.1(1)*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. 2.2(1)(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. *3(i)(a)(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(i)(b)*3.1(b) -- Amendment to Articles of Incorporation of Oglethorpe, dated as
of March 11, 1997. 69
3(ii) -- Bylaws of Oglethorpe, as amended on February 24, 1997,
and effective as of March 11, 1997.
*4.1 -- Serial Facility Bond (included in Collateral Trust
Indenture listed as Exhibit 4.2).
*4.2 -- Collateral Trust Indenture, dated as of October 15,
1986, between OPC Scherer Funding Corporation,
Oglethorpe and Trust Company Bank, a banking
corporation, as Trustee. (Filed as Exhibit 4.2 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.3 -- Refunding Lessor Notes. (Filed as Exhibit 4.3.1 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.4(a) -- Nonrecourse Promissory Secured Note, due June 30, 2011,
from Wilmington Trust Company and William J. Wade, as
Owner Trustees, to Columbia Bank for Cooperatives.
(Filed as Exhibit 4.3.4 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*4.4(b) -- First Amendment to Nonrecourse Promissory Secured Note,
dated as of June 30, 1987, by Wilmington Trust Company
and The Citizens and Southern National Bank, as Owner
Trustee under Trust Agreement No. 1 with IBM Credit
Financing Corporation, to Columbia Bank for
Cooperatives. (Filed as Exhibit 4.3.4(a)3(i)(b) to the Registrant's
Form 10-K for the fiscal year ended December 31, 1987,1996, File No.
33-7591.)
*4.5(a)*3.2 -- Bylaws of Oglethorpe, as amended on January 10, 2000. (Filed as
Exhibit 3.2 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1999, File No. 33-7591.)
71
*4.1 -- Form of Serial Facility Bond Due June 30, 2011 (included in
Collateral Trust Indenture filed as Exhibit 4.2.)
*4.2 -- Collateral Trust Indenture, dated as of December 1, 1997, between
OPC Scherer 1997 Funding Corporation A, Oglethorpe and SunTrust
Bank, Atlanta, as Trustee. (Filed as Exhibit 4.2 to the
Registrant's Form S-4 Registration Statement, File No.
333-42759.)
*4.3 -- Nonrecourse Promissory Lessor Note No. 2, with a Schedule
identifying three other substantially identical Nonrecourse
Promissory Lessor Notes and any material differences. (Filed as
Exhibit 4.3 to the Registrant's Form S-4 Registration Statement,
File No. 333-42759.)
*4.4 -- Amended and Restated Indenture of Trust, Deed to Secure Debt and
Security Agreement No. 2, dated December 30, 1985,1, 1997, between
Wilmington Trust Company and William J. Wade,NationsBank, N.A. collectively as
Owner TrusteesTrustee, under Trust Agreement No. 2, dated December 30,
1985, with DFO Partnership, as assignee of Ford Motor Credit
Company, and The First
National Bank of Atlanta,New York Trust Company of Florida, N.A.
as Indenture Trustee, together with a Schedule identifying three other
substantially identical Amended and Restated Indentures of Trust,
Deeds to Secure Debt and Security Agreements.Agreements and any material
differences. (Filed as Exhibit 4.4(b)4.4 to the Registrant's Form S-1S-4
Registration Statement, File No. 33-7591, filed on October 9, 1986.333-42759.)
*4.5(b) -- First Supplemental Indenture of Trust, Deed to Secure
Debt and Security Agreement No. 2 (included as Exhibit A
to the Supplemental Participation Agreement No. 2 listed
as 10.1.1(b)).
*4.5(c) -- First Supplemental Indenture of Trust, Deed to Secure
Debt and Security Agreement No. 1, dated as of June 30,
1987, between Wilmington Trust Company and The Citizens
and Southern National Bank, collectively as Owner
Trustee under Trust Agreement No. 1 with IBM Credit
Financing Corporation, and The First National Bank of
Atlanta, as Indenture Trustee. (Filed as Exhibit 4.4(c)
to the Registrant's Form 10-K for the fiscal year ended
December 31, 1987, File No. 33-7591.)
*4.6(a)*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, filed on
October 9, 1986.33-7591.)
70
*4.6(b)*4.5(b) -- First Supplement Toto Lease Agreement No. 2 (included as Exhibit B
to the Supplemental Participation Agreement No. 2 listed as
10.1.1(b)).
*4.6(c)*4.5(c) -- First Supplement to Lease Agreement No. 1, dated as of June 30,
1987, between The Citizens and Southern National Bank as Owner
Trustee under Trust Agreement No. 1 with IBM Credit Financing
Corporation, as Lessor, and Oglethorpe, as Lessee. (Filed as
Exhibit 4.5(c) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1987, File No. 33-7591.)
4.7*4.5(d) -- Second Supplement to Lease Agreement No. 2, dated as of December
17, 1997, between NationsBank, N.A., acting through its agent,
The Bank of New York, as an Owner Trustee under the Trust
Agreement No. 2, dated December 30, 1985, among DFO Partnership,
as assignee of Ford Motor Credit Company, as the Owner
Participant, and the Original Trustee, as Lessor, and Oglethorpe,
as Lessee, with a Schedule identifying three other substantially
identical Second Supplements to Lease Agreements and any material
differences. (Filed as Exhibit 4.5(d) to the Registrant's Form
S-4 Registration Statement, File No. 333-42759.)
*4.6 -- Amended and Consolidated Loan Contract, dated as of March 1,
1997, between Oglethorpe and the United States of America,
together with four notes executed and delivered pursuant thereto.
4.8.1(Filed as Exhibit 4.7 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*4.7.1(a) -- Indenture, dated as of March 1, 1997, made by Oglethorpe to
SunTrust Bank, Atlanta, as trustee. 4.8.2(Filed as Exhibit 4.8.1 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
72
*4.7.1(b) -- First Supplemental Indenture, dated as of October 1, 1997, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1997B (Burke) Note. (Filed as Exhibit 4.8.1(b) to the
Registrant's Form 10-Q for the quarterly period ended September
30, 1997, File No. 33-7591.)
*4.7.1(c) -- Second Supplemental Indenture, dated as of January 1, 1998, made
by Oglethorpe to SunTrust Bank, as trustee, relating to the
Series 1997C (Burke) Note. (Filed as Exhibit 4.7.1(c) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1997, File No. 33-7591.)
*4.7.1(d) -- Third Supplemental Indenture, dated as of January 1, 1998, made
by Oglethorpe to SunTrust Bank, as trustee, relating to the
Series 1997A (Monroe) Note. (Filed as Exhibit 4.7.1(d) to the
Registrant's Form 10-K for the fiscal year December 31, 1997,
File No. 33-7591.)
*4.7.1(e) -- Fourth Supplemental Indenture, dated as of March 1, 1998, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1998A (Burke) and 1998B (Burke) Notes. (Filed as Exhibit
4.7.1(e) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1998, File No. 33-7591.)
*4.7.1(f) -- Fifth Supplemental Indenture, dated as of April 1, 1998, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the
Series 1998 CFC Note. (Filed as Exhibit 4.7.1(f) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1998, File No. 33-7591.)
*4.7.1(g) -- Sixth Supplemental Indenture, dated as of January 1, 1999, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1998C (Burke) Note. (Filed as Exhibit 4.7.1(g) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1998, File No. 33-7591.)
*4.7.1(h) -- Seventh Supplemental Indenture, dated as of January 1, 1999, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1998A (Monroe) Note. (Filed as Exhibit 4.7.1(h) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1998, File No. 33-7591.)
*4.7.1(i) -- Eighth Supplemental Indenture, dated as of November 1, 1999, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1999B (Burke) Note. (Filed as Exhibit 4.7.1(i) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
*4.7.1(j) -- Ninth Supplemental Indenture, dated as of November 1, 1999, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1999B (Monroe) Note. (Filed as Exhibit 4.7.1(j) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
*4.7.1(k) -- Tenth Supplemental Indenture, dated as of December 1, 1999, made
by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to
the Series 1999 Lease Notes. (Filed as Exhibit 4.7.1(k) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
*4.7.1(l) -- Eleventh Supplemental Indenture, dated as of January 1, 2000,
made by Oglethorpe to SunTrust Bank as trustee, relating to the
Series 1999A (Burke) Note. (Filed as Exhibit 4.7.1(l) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
*4.7.1(m) -- Twelfth Supplemental Indenture, dated as of January 1, 2000, made
by Oglethorpe to SunTrust Bank as trustee, relating to the Series
1999A (Monroe) Note. (Filed as Exhibit 4.7.1(m) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
73
4.7.1(n) -- Thirteenth Supplemental Indenture, dated as of January 1, 2001,
made by Oglethorpe to SunTrust Bank, as trustee, relating to the
Series 2000 (Burke) Note.
4.7.1(o) -- Fourteenth Supplemental Indenture, dated as of January 1, 2001,
made by Oglethorpe to SunTrust Bank, as trustee, relating to the
Series 2000 (Monroe) Note.
*4.7.2 -- Security Agreement, dated as of March 1, 1997, made by Oglethorpe
to SunTrust Bank, Atlanta, as trustee. 4.9.1(3)(Filed as Exhibit 4.8.2 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
4.8.1(1) -- Loan Agreement, dated as of October 1, 1992, between Development
Authority of Monroe County and Oglethorpe relating to Development
Authority of Monroe County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Scherer Project), Series 1992A.
4.9.2(3)1992A, and
five other substantially identical loan agreements.
4.8.2(1) -- Note, dated October 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated as
of October 1, 1992, between Development Authority of Monroe
County and Trust Company Bank.
4.9.3(3)Bank, and five other substantially
identical notes.
4.8.3(1) -- Trust Indenture, dated as of October 1, 1992, between Development
Authority of Monroe County and Trust Company Bank, Trustee,
relating to Development Authority of Monroe County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Scherer
Project), Series 1992A.
4.10.1(4)1992A, and five other substantially identical
trust indentures.
4.9.1(1) -- Loan Agreement, dated as of December 1, 1992, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Adjustable Tender Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A.
4.10.2(4)1993A, and one other substantially identical loan
agreement.
4.9.2(1) -- Note, dated December 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated as
of December 1, 1992, between Development Authority of Burke
County and Trust Company Bank.
4.10.3(4)Bank, and one other substantially
identical note.
4.9.3(1) -- Trust Indenture, dated as of December 1, 1992, from Development
Authority of Burke County to Trust Company Bank, as trustee,
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1993A.
4.10.4(4)1993A, and one other
substantially identical trust indenture.
4.9.4(1) -- Interest Rate Swap Agreement, dated as of December 1, 1992, by
and between Oglethorpe and AIG Financial Products Corp. relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A.
71
4.10.5(4)1993A, and one other substantially
identical agreement.
4.9.5(1) -- Liquidity Guaranty Agreement, dated as of December 1, 1992, by
and between Oglethorpe and AIG Financial Products Corp. relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A.
4.10.6(2)1993A, and one other substantially
identical agreement.
74
4.9.6(1) -- Standby Bond Purchase Agreement, dated as of December 14, 1995,1, 1998,
between Oglethorpe and Canadian Imperial Bank
of Commerce, New York Agency,Bayerische Landesbank Girozentrale,
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1993A.
4.10.7(2)4.9.7(1) -- Standby Bond Purchase Agreement, dated as of November 30, 1994,
between Oglethorpe and Credit Local de France, Acting through its
New York Agency, relating to the
Development Authority of Burke
County Adjustable Tender Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1994A.
4.11.1(4)4.10.1(1) -- Loan Agreement, dated as of October 1, 1996, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1996.
4.11.2(4)1996, and
one other substantially identical loan agreements.
4.10.2(1) -- Note, dated October 1, 1996, from Oglethorpe to SunTrust Bank,
Atlanta, as trustee pursuant to an Indenture of Trust, dated as
of October 1, 1996, between Development Authority of Burke County
and SunTrust Bank, Atlanta.
4.11.3(4)Atlanta, and one other substantially identical
note.
4.10.3(1) -- Indenture of Trust, dated as of October 1, 1996, between
Development Authority of Burke County and SunTrust Bank, Atlanta,
as trustee, relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1996.
4.12.1(2)1996, and one other substantially
identical indenture.
4.11.1(1) -- Loan Agreement, dated as of April 2, 1992,December 1, 1997, between the Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project) Series 1997C, and
three other substantially identical loan agreements.
4.11.2(1) -- Note, dated January 14, 1998, from Oglethorpe to SunTrust Bank,
Atlanta, as amended and supplemented by First Amendatory and
Supplemental Loan Agreement,trustee pursuant to an Indenture of Trust, dated as
of MarchDecember 1, 1997, between Development Authority of Burke
County and SunTrust Bank, Atlanta, and three other substantially
identical notes.
4.11.3(1) -- Indenture of Trust, dated as of December 1, 1997, between
Development Authority of Burke County and SunTrust Bank, Atlanta,
as trustee, relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1997A.
4.12.2(2)1997C, and three other substantially
identical indentures.
4.12.1(1) -- Note, dated March 1, 1997, from Oglethorpe to SunTrust
Bank, Atlanta, as trustee acting pursuant to a Trust
Indenture,Loan Agreement, dated as of AprilMarch 1, 1992,1998, between Development
Authority of Burke County and SunTrust Bank,
Atlanta, as supplemented by First Supplemental Trust
Indenture, dated as of March 1, 1997.
4.12.3(2) -- Trust Indenture, dated as of April 2, 1992, between
Development Authority of Burke County and SunTrust Bank,
Atlanta, as trustee, as supplemented by a First
Supplemental Trust Indenture, dated as of March 1, 1997,Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1997A.
4.13.11998A, and
one other substantially identical loan agreement.
4.12.2(1) -- Note, dated March 17, 1998, from Oglethorpe to SunTrust Bank,
Atlanta, as trustee pursuant to a Trust Indenture, dated as of
March 1, 1998, between Development Authority of Burke County and
SunTrust Bank, Atlanta, and one other substantially identical
note.
4.12.3(1) -- Trust Indenture, dated as of March 1, 1998, between Development
Authority of Burke County and SunTrust Bank, Atlanta, as trustee,
relating to Development Authority of Burke County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1998A, and one other substantially identical
indenture.
75
4.12.4(1) -- Standby Bond Purchase Agreement, dated March 17, 1998, between
Oglethorpe and Cooperatieve Centrale Raiffeisen-Boerenleenbank
B.A., "Rabobank Nederland", acting through its New York Branch,
relating to Development Authority of Burke County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1998A, and one other substantially identical
agreement.
*4.13.1 -- Indemnity Agreement, dated as of March 1, 1997, by and between
Oglethorpe and Georgia Transmission Corporation (An Electric
Membership Corporation). 4.13.2(Filed as Exhibit 4.13.1 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*4.13.2 -- Indemnification Agreement, dated as of March 11, 1997, by
Oglethorpe and Georgia Transmission Corporation (An Electric
Membership Corporation) for the benefit of the United States of
America. 72
4.14.1(2)(Filed as Exhibit 4.13.2 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
4.14.1(1) -- Master Loan Agreement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, MLA No. 0459.
4.14.2(2)4.14.2(1) -- Consolidating Supplement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T1.
4.14.3(2)4.14.3(1) -- Promissory Note, dated March 1, 1997, in the original principal
amount of $7,102,740.26, from Oglethorpe to CoBank, ACB, relating
to Loan No. ML0459T1.
4.14.4(2)4.14.4(1) -- Consolidating Supplement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T2.
4.14.5(2)4.14.5(1) -- Promissory Note, dated March 1, 1997, in the original principal
amount of $1,856,475.12, made by Oglethorpe to CoBank, ACB,
relating to Loan No. ML0459T2.
4.14.6(1) -- Single Advance Term Loan Supplement, dated as of March 31, 1998,
between Oglethorpe and CoBank, ACB, relating to Loan No.
ML0459T3.
4.14.7(1) -- Promissory Note, dated March 31, 1998, in the original principal
amount of $46,065,000.00, made by Oglethorpe to CoBank, ACB,
relating to Loan No. ML0459T3.
*4.15.1 -- Loan Agreement, Loan No. T-830404, between Oglethorpe and
Columbia Bank for Cooperatives, dated as of April 29, 1983.
(Filed as Exhibit 4.18.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed
on October 9, 1986.33-7591.)
*4.15.2 -- Promissory Note, Loan No. T-830404-1, in the original principal
amount of $9,935,000, from Oglethorpe to Columbia Bank for
Cooperatives, dated as of April 29, 1983. (Filed as Exhibit
4.18.2 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on
October 9, 1986.33-7591.)
*4.15.3 -- Security Deed and Security Agreement, dated April 29, 1983,
between Oglethorpe and Columbia Bank for Cooperatives. (Filed as
Exhibit 4.18.3 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*4.16 -- Exchange and Registration Rights Agreement, dated December 17,
1997, by and among Oglethorpe, OPC Scherer 1997 Funding
Corporation A, and Goldman, Sachs & Co. as representative of the
purchasers identified therein. (Filed as Exhibit 4.15 to the
Registrant's Form S-4 Registration Statement, File No.
333-42759.)
76
4.17.1 (1) -- Loan Agreement, dated as of April 1, 1998, between Oglethorpe and
the National Rural Utilities Cooperative Finance Corporation,
relating to Loan No. GA 109-1-9001.
4.17.2 (1) -- Series 1998 CFC Note, dated April 9, 1998, in the original
principal amount of $46,065,000.00, from Oglethorpe to the
National Rural Utilities Cooperative Finance Corporation,
relating to Loan No. GA 109-1-9001.
*10.1.1(a) -- Participation Agreement No. 2 among Oglethorpe as Lessee,
Wilmington Trust Company as Owner Trustee, The First National
Bank of Atlanta as Indenture Trustee, Columbia Bank for
Cooperatives as Loan Participant and Ford Motor Credit Company as
Owner Participant, dated December 30, 1985, together with a
Schedule identifying three other substantially identical
Participation Agreements. (Filed as Exhibit 10.1.1(b) to the
Registrant's Form S-1 Registration Statement, File No. 33-7591, filed on October 9, 1986.33-7591.)
*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, filed on
October 9, 1986.33-7591.)
*10.1.1(c) -- Supplemental Participation Agreement No. 1, dated as of June 30,
1987, among Oglethorpe as Lessee, IBM Credit Financing
Corporation as Owner Participant, Wilmington Trust Company and
The Citizens and Southern National Bank as Owner Trustee, The
First National Bank of Atlanta, as Indenture Trustee, and
Columbia Bank for Cooperatives, as Loan Participant. (Filed as
Exhibit 10.1.1(c) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1987, File No. 33-7591.)
*10.1.1(d) -- Second Supplemental Participation Agreement No. 2, dated as of
December 17, 1997, among Oglethorpe as Lessee, DFO Partnership,
as assignee of Ford Motor Credit Company, as Owner Participant,
Wilmington Trust Company and NationsBank, N.A. as Owner Trustee,
The Bank of New York Trust Company of Florida, N.A. as Indenture
Trustee, CoBank, ACB as Loan Participant, OPC Scherer Funding
Corporation, as Original Funding Corporation, OPC Scherer 1997
Funding Corporation A, as Funding Corporation, and SunTrust Bank,
Atlanta, as Original Collateral Trust Trustee and Collateral
Trust Trustee, with a Schedule identifying three substantially
identical Second Supplemental Participation Agreements and any
material differences. (Filed as Exhibit 10.1.1(d) to Registrant's
Form S-4 Registration Statement, File No. 333-4275.)
*10.1.2 -- General Warranty Deed and Bill of Sale No. 2 between Oglethorpe,
Grantor, and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Grantee, together with a
Schedule identifying three substantially identical General
Warranty Deeds 73
and Bills of Sale. (Filed as Exhibit 10.1.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591, filed on October 9, 1986.33-7591.)
*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, filed on October 9, 1986.33-7591.)
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, filed on October 9, 1986.33-7591.)
*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.)
*10.1.5*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, filed on October 9, 1986.33-7591.)
*10.1.5(b) -- Amendment No. 1 to the Tax Indemnification Agreement No. 2, dated
December 17, 1997, between DFO Partnership, as assignee of Ford
Motor Credit Company, as Owner Participant, and Oglethorpe, as
Lessee, with a Schedule identifying three substantially identical
Amendments No. 1 to the Tax Indemnification Agreements and any
material differences. (Filed as Exhibit 10.1.5(b) to the
Registrant's Form S-4 Registration Statement, File No.
333-42759.)
*10.1.6 -- Assignment of Interest in Ownership Agreement and Operating
Agreement No. 2, dated December 30, 1985, between Oglethorpe,
Assignor, and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Assignee, together with
Schedule identifying three substantially identical Assignments of
Interest in Ownership Agreement and Operating Agreement. (Filed
as Exhibit 10.1.6 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.33-7591.)
78
*10.1.7 -- Consent, Amendment and Assumption No. 2 dated December 30, 1985,
among Georgia Power Company and Oglethorpe and Municipal Electric
Authority of Georgia and City of Dalton, Georgia and Gulf Power
Company and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, together with a Schedule
identifying three substantially identical Consents, Amendments
and Assumptions. (Filed as Exhibit 10.1.9 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed on October 9, 1986.33-7591.)
*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
74
Georgia, City of Dalton, Georgia,
Gulf Power Company, Jacksonville Electric Authority, Florida
Power & Light Company and Wilmington Trust Company and
NationsBank of Georgia, N.A., as Owner Trustees under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, together with a Schedule identifying three substantially
identical Amendments to Consents, Amendments and Assumptions.
(Filed as Exhibit 10.1.9(a) to the Registrant's Form 10-Q for the
quarterly period ended September 30, 1993, File No. 33-7591.)
*10.2.1 -- Section 168 Agreement and Election dated as of April 7, 1982,
between Continental Telephone Corporation and Oglethorpe. (Filed
as Exhibit 10.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed
on October 9, 1986.33-7591.)
*10.2.2 -- Section 168 Agreement and Election dated as of April 9,
1982, between National Service Industries, Inc. and
Oglethorpe. (Filed as Exhibit 10.3 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed
on October 9, 1986.)
*10.2.3 -- 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, filed on October 9, 1986.)
*10.2.4 -- Section 168 Agreement and Election dated as of December
13, 1982, between Selig Enterprises, Inc. and
Oglethorpe. (Filed as Exhibit 10.5 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed
on October 9, 1986.33-7591.)
*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, filed on October 9, 1986.33-7591.)
*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, filed on October 9, 1986.33-7591.)
*10.3.1(c) -- Amendment Number Two to the Plant Robert W. Scherer Units Numbers
One and Two Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia, dated as of July 1, 1986.
(Filed as Exhibit 10.6.1(a) to the Registrant's Form 10-K for the
fiscal year ended December 31, 1987, File No. 33-7591.)
*10.3.1(d) -- Amendment Number Three to the Plant Robert W. Scherer Units
Numbers One and Two Purchase and Ownership Participation
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 1, 1988. (Filed as Exhibit 10.6.1(b) to the
Registrant's Form 10-Q for the quarterly period ended September
30, 1993, File No. 33-7591.)
79
*10.3.1(e) -- Amendment Number Four to the Plant Robert W. Scherer Units Number
One and Two Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia, dated
75
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, filed on
October 9, 1986.33-7591.)
*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, filed on
October 9, 1986.33-7591.)
*10.3.2(c) -- Amendment Number Two to the Plant Robert W. Scherer Units Numbers
One and Two Operating Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of December 31, 1990. (Filed as Exhibit
10.6.2(a) to the Registrant's Form 10-Q for the quarterly period
ended September 30, 1993, File No. 33-7591.)
*10.3.3 -- Plant Scherer Managing Board Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia,
City of Dalton, Georgia, Gulf Power Company, Florida Power &
Light Company and Jacksonville Electric Authority, dated as of
December 31, 1990. (Filed as Exhibit 10.6.3 to the Registrant's
Form 10-Q for the quarterly period ended September 30, 1993, File
No. 33-7591.)
*10.4.1(a) -- Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit
10.7.1 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.33-7591.)
*10.4.1(b) -- Amendment Number One, dated January 18, 1977, to the Alvin W.
Vogtle Nuclear Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia. (Filed as Exhibit 10.7.3 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.1(c) -- Amendment Number Two, dated February 24, 1977, to the Alvin W.
Vogtle Nuclear Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia. (Filed as Exhibit 10.7.4 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.2 -- Alvin W. Vogtle Nuclear Units Numbers One and Two Operating
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 27, 1976. (Filed as Exhibit 10.7.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591, filed on
October 9, 1986.33-7591.)
80
*10.5.1 -- Plant Hal Wansley Purchase and Ownership Participation Agreement
between Georgia Power Company and Oglethorpe, dated as of March
26, 1976. (Filed as Exhibit 10.8.1 to 76
the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9, 1986.33-7591.)
*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, filed on
October 9, 1986.33-7591.)
*10.5.2(b) -- Amendment, dated as of January 15, 1995, to the Plant Hal Wansley
Operating Agreements by and among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia. (Filed as Exhibit 10.5.2(a) to the Registrant's
Form 10-Q for the quarterly period ended September 30, 1996, File
No. 33-7591.)
*10.5.3 -- Plant Hal Wansley Combustion Turbine Agreement between Georgia
Power Company and Oglethorpe, dated as of August 2, 1982 and
Amendment No. 1, dated October 20, 1982. (Filed as Exhibit 10.18
to the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on
October 9, 1986.33-7591.)
*10.6.1 -- Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation
Agreement between Georgia Power Company and Oglethorpe, dated as
of January 6, 1975. (Filed as Exhibit 10.9.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed on October 9, 1986.33-7591.)
*10.6.2 -- Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia
Power Company and Oglethorpe, dated as of January 6, 1975. (Filed
as Exhibit 10.9.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.33-7591.)
*10.7.1 -- Rocky Mountain Pumped Storage Hydroelectric Project Ownership
Participation Agreement, dated as of November 18, 1988, by and
between Oglethorpe and Georgia Power Company. (Filed as Exhibit
10.22.1 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1988, File No. 33-7591.)
*10.7.2 -- Rocky Mountain Pumped Storage Hydroelectric Project Operating
Agreement, dated as of November 18, 1988, by and between
Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.2
to the Registrant's Form 10-K for the fiscal year ended December
31, 1988, File No. 33-7591.)
10.8.1*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.
10.8.2(Filed as Exhibit 10.8.1 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.2 -- Amended and Restated Supplemental Agreement, dated as of August
1, 1996, by and between Oglethorpe, Altamaha Electric Membership
Corporation and the United States of America, together with a
Schedule identifying 38 other substantially identical Amended and
Restated Supplemental Agreements. 10.8.3(Filed as Exhibit 10.8.2 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
81
*10.8.3 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of January 1, 1997, by and among Georgia
Power Company, Oglethorpe and Altamaha Electric Membership
Corporation, together with a Schedule identifying 38 other
substantially identical Supplemental Agreements. 77
10.8.4(Filed as
Exhibit 10.8.3 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
*10.8.4 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of March 1, 1997, by and between
Oglethorpe and Altamaha Electric Membership Corporation, together
with a Schedule identifying 36 other substantially identical
Supplemental Agreements, and an additional Supplemental Agreement
that is not substantially identical. 10.8.5(Filed as Exhibit 10.8.4 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.8.5 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of March 1, 1997, by and between
Oglethorpe and Coweta-Fayette Electric Membership Corporation,
together with a Schedule identifying 1 other substantially
identical Supplemental Agreement. *10.9 -- Transmission Facilities Operation and Maintenance
Contract between Georgia Power Company and Oglethorpe
dated as of June 9, 1986. (Filed as Exhibit 10.1310.8.5 to the
Registrant's Form S-1 Registration Statement,10-K for the fiscal year ended December 31,
1996, File No. 33-7591, filed on October 9, 1986.33-7591.)
*10.10(a)*10.8.6 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of May 1, 1997 by and between Oglethorpe
and Altamaha Electric Membership Corporation, together with a
Schedule identifying 38 other substantially identical
Supplemental Agreements. (Filed as Exhibit 10.8.6 to the
Registrant's Form 10-Q for the quarterly period ended June 30,
1997, File No. 33-7591.)
*10.9(a) -- Joint Committee Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and the City
of Dalton, Georgia, dated as of August 27, 1976. (Filed as
Exhibit 10.14(b) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed
on October 9, 1986.33-7591.)
*10.10(b)*10.9(b) -- First Amendment to Joint Committee Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia and
the City of Dalton, Georgia, dated as of June 19, 1978. (Filed as
Exhibit 10.14(a) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.11 -- Interconnection Agreement between Oglethorpe and Alabama
Electric Cooperative, Inc., dated as of November 12,
1990. (Filed as Exhibit 10.16(a) to the Registrant's
Form 10-K for the fiscal year ended December 31, 1990,
File No. 33-7591.)
*10.11(a) -- Amendment No. 1 to Interconnection Agreement between
Alabama Electric Cooperative, Inc. and Oglethorpe, dated
as of April 22, 1994. (Filed as Exhibit 10.11(a) to the
Registrant's Form 10-Q for the quarter ended June 30,
1994, File No. 33-7591.)
*10.11(b)*10.10 -- Letter of Commitment (Firm Power Sale) Under Service Schedule
J - NegotiatedJ--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.)
*10.12 -- Oglethorpe Deferred Compensation Plan for Key Employees,
as Amended and Restated January, 1987. (Filed as Exhibit
10.19 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1986, File No. 33-7591.)
*10.13.1*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, filed on October 9, 1986.33-7591.)
*10.13.2*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 78
Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9, 1986.33-7591.)
*10.13.382
*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, filed on October 9, 1986.)
*10.14 -- Distribution Facilities Joint Use Agreement between
Oglethorpe and Georgia Power Company, dated as of May
12, 1986. (Filed as Exhibit 10.21 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1986,
File No. 33-7591.)
*10.15.1*10.12 -- Long Term Firm Power Purchase Agreement, dated as of
July 19, 1989, by and between Oglethorpe and Big Rivers
Electric Corporation. (Filed as Exhibit 10.24.1 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1989, File No. 33-7591.)
*10.15.2 -- Coordination Services Agreement, dated as of August 21,
1989, by and between Oglethorpe and Georgia Power
Company. (Filed as Exhibit 10.24.2 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1989,
File No. 33-7591.)
*10.15.3 -- Long TermLong-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.)
*10.15.4*10.13 -- InterchangeRevised and Restated Coordination Services Agreement between and
among Georgia Power Company, Oglethorpe and Big Rivers
ElectricGeorgia System
Operations Corporation, dated as of November 12, 1990.September 10, 1997. (Filed as
Exhibit 10.24.410.14 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1990,1997, File No. 33-7591.)
*10.16 -- Block Power Sale Agreement between Georgia Power Company
and Oglethorpe, dated as of November 12, 1990. (Filed as
Exhibit 10.25 to the Registrant's Form 8-K, filed
January 4, 1991, File No. 33-7591.)
*10.17 -- Coordination Services Agreement between Georgia Power
Company and Oglethorpe, dated as of November 12, 1990.
(Filed as Exhibit 10.26 to the Registrant's Form 8-K,
filed January 4, 1991, File No. 33-7591.)
*10.18 -- Revised and Restated Integrated Transmission System
Agreement between Oglethorpe and Georgia Power Company,
dated as of November 12, 1990. (Filed as Exhibit 10.27
to the Registrant's Form 8-K, filed January 4, 1991,
File No. 33-7591.)
*10.19*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.)
*10.20*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.)
*10.21*10.16 -- Supplemental Agreement by and among Oglethorpe, Tri-County
Electric Membership CooperationCorporation and Georgia Power Company, dated
as of November 12, 1990, together with
79
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.)
*10.22*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.)
*10.23 -- Interchange Agreement between Oglethorpe and Arkansas
Power & Light Company, Louisiana Power & Light Company,
Mississippi Power & Light Company, New Orleans Public
Service, Inc., Energy Services, Inc., dated as of
November 12, 1990. (Filed as Exhibit 10.32 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*10.24 -- Interchange Agreement between Oglethorpe and Seminole
Electric Cooperative, Inc., dated as of November 12,
1990. (Filed as Exhibit 10.33 to the Registrant's Form
10-K for the fiscal year ended December 31, 1990, File
No. 33-7591.)
*10.25.1 -- Excess Energy and Short-term Power Agreement between
Oglethorpe and Tennessee Valley Authority, effective as
of January 23, 1991. (Filed as Exhibit 10.34.1 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*10.25.2 -- Transmission Service Agreement between Oglethorpe and
Tennessee Valley Authority, effective as of January 23,
1991. (Filed as Exhibit 10.34.2 to the Registrant's Form
10-K for the fiscal year ended December 31, 1990, File
No. 33-7591.)
*10.26*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).
*10.27(5) -- Master Power Purchase and Sale Agreement between Enron
Power Marketing, Inc. and Oglethorpe, dated as of
January 3, 1996. (Filed as Exhibit 10.27 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1995, File No. 33-7591.)
*10.27(a) (5) -- Extension and Modification Agreement between Enron Power
Marketing, Inc. and Oglethorpe, dated as of April 30,
1996. (Filed as Exhibit 10.27(a) to the Registrant's
Form 10-Q for the quarterly period ended March 31, 1996,
File No. 33-7591.)
*10.28(6) -- Employment Agreement between Oglethorpe and T. D.
Kilgore, dated as of December 20, 1995. (Filed as
Exhibit 10.28 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1995, File No. 33-7591.)
*10.29(5) -- Master Power Purchase and Sale Agreement between
Duke/Louis Dreyfus L.L.C. and Oglethorpe, dated as of
August 31, 1996. (Filed as Exhibit 10.29 to the
Registrant's Form 10-Q for the quarterly period ended
September 30, 1996, File No. 33-7591.)
10.30(5)*10.19(2) -- Power Purchase and Sale Agreement among LG&E Power Marketing
Inc., LG&E Energy Corp. and Oglethorpe, dated as of November 19,
1996. 10.31(5)(Filed as Exhibit 10.30 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.20(2) -- Power Purchase and Sale Agreement among LG&E Power Marketing
Inc., LG&E Power Inc. and Oglethorpe, dated as of January 1,
1997. 80(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
10.32.1*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. 10.32.2(Filed as Exhibit 10.32.1 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.2 -- Rocky Mountain Head Lease Agreement (P1), dated as of December
30, 1996, between Oglethorpe and SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other
substantially identical Rocky Mountain Head Lease Agreements.
10.32.3(Filed as Exhibit 10.32.2 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.21.3 -- Ground Lease Agreement (P1), dated as of December 30, 1996,
between Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other substantially
identical Ground Lease Agreements. 10.32.4(Filed as Exhibit 10.32.3 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.21.4 -- Rocky Mountain Agreements Assignment and Assumption Agreement
(P1), dated as of December 30, 1996, between Oglethorpe and
SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Rocky Mountain
Agreements Assignment and Assumption Agreements. 10.32.5(Filed as
Exhibit 10.32.4 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
*10.21.5 -- Facility Lease Agreement (P1), dated as of December 30, 1996,
between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain
Leasing Corporation, together with a Schedule identifying five
other substantially identical Facility Lease Agreements. 10.32.6(Filed
as Exhibit 10.32.5 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.21.6 -- Ground Sublease Agreement (P1), dated as of December 30, 1996,
between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain
Leasing Corporation, together with a Schedule identifying five
other substantially identical Ground Sublease Agreements. 10.32.7(Filed
as Exhibit 10.32.6 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.21.7 -- Rocky Mountain Agreements Re-assignment and Assumption Agreement
(P1), dated as of December 30, 1996, between SunTrust Bank,
Atlanta, as Co-Trustee and Rocky Mountain Leasing Corporation,
together with a Schedule identifying five other substantially
identical Rocky Mountain Agreements Re-assignment and Assumption
Agreements. 10.32.8(Filed as Exhibit 10.32.7 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.8 -- Facility Sublease Agreement (P1), dated as of December 30, 1996,
between Oglethorpe and Rocky Mountain Leasing Corporation,
together with a Schedule identifying five other substantially
identical Facility Sublease Agreements. 10.32.9(Filed as Exhibit 10.32.8
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
84
*10.21.9 -- Ground Sub-sublease Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation and Oglethorpe,
together with a Schedule identifying five other substantially
identical Ground Sub-sublease Agreements. 10.32.10(Filed as Exhibit
10.32.9 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.21.10 -- Rocky Mountain Agreements Second Re-assignment and Assumption
Agreement (P1), dated as of December 30, 1996, between Rocky
Mountain Leasing Corporation and Oglethorpe, together with a
Schedule identifying five other substantially identical Rocky
Mountain Agreements Second Re-assignment and Assumption
Agreements. 10.32.11(Filed as Exhibit 10.32.10 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.11 -- Payment Undertaking Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation and Cooperatieve
Centrale Raiffeisen-Boerenleenbank B.A., New York Branch, as the
Bank, together with a Schedule identifying five other
substantially identical Payment Undertaking Agreements. 10.32.12(Filed as
Exhibit 10.32.11 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.21.12 -- Payment Undertaking Pledge Agreement (P1), dated as of December
30, 1996, between Rocky Mountain Leasing Corporation, Fleet
National Bank, as Owner Trustee, and 81
SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other
substantially identical Payment Undertaking Pledge Agreements.
10.32.13(Filed as Exhibit 10.32.12 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.21.13 -- Equity Funding Agreement (P1), dated as of December 30, 1996,
between Rocky Mountain Leasing Corporation, AIG Match Funding
Corp., the Owner Participant named therein, Fleet National Bank,
as Owner Trustee, and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other substantially
identical Equity Funding Agreements. 10.32.14(Filed as Exhibit 10.32.13
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*10.21.14 -- Equity Funding Pledge Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation and SunTrust
Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Equity Funding
Pledge Agreements. 10.32.15(Filed as Exhibit 10.32.14 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.21.15 -- Deed to Secure Debt, Assignment of Surety Bond and Security
Agreement (P1), dated as of December 30, 1996, between Rocky
Mountain Leasing Corporation, SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other
substantially identical Collateral Assignment, Assignment of
Surety Bond and Security Agreements. 10.32.16(Filed as Exhibit 10.32.15
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*10.21.16 -- Subordinated Deed to Secure Debt and Security Agreement (P1),
dated as of December 30, 1996, among Oglethorpe, AMBAC Indemnity
Corporation and SunTrust Bank, Atlanta, as Co-Trustee, together
with a Schedule identifying five other substantially identical
Subordinated Deed to Secure Debt and Security Agreements. 10.32.17(Filed
as Exhibit 10.32.16 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
85
*10.21.17 -- Tax Indemnification Agreement (P1), dated as of December 30,
1996, between Oglethorpe and the Owner Participant named therein,
together with a Schedule identifying five other substantially
identical Tax Indemnification Agreements. 10.32.18(Filed as Exhibit
10.32.17 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.21.18 -- Consent No. 1, dated as of December 30, 1996, among Georgia Power
Company, Oglethorpe, SunTrust Bank, Atlanta, as Co-Trustee, and
Fleet National Bank, as Owner Trustee, together with a Schedule
identifying five other substantially identical Consents. 10.32.19 (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. 10.33.1(Filed as Exhibit 10.32.19 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.21.19(b)-- Supplement to OPC Intercreditor and Security Agreement No. 1,
dated as of March 1, 1997, among the United States of America,
acting through the Administrator of the Rural Utilities Service,
SunTrust Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing
Corporation, SunTrust Bank, Atlanta, as Co-Trustee, Fleet
National Bank, as Owner Trustee, Utrecht-America Finance Co., as
Lender and AMBAC Indemnity Corporation, together with a Schedule
identifying five other substantially identical Supplements to OPC
Intercreditor and Security Agreements. (Filed as Exhibit
10.32.19(b) to the Registrant's Form S-4 Registration Statement,
File No. 333-42759.)
*10.22.1 -- Member Transmission Service Agreement, dated as of March 1, 1997,
by and between Oglethorpe and Georgia Transmission Corporation
(An Electric Membership Corporation). 10.33.2(Filed as Exhibit 10.33.1
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*10.22.2 -- Generation Services Agreement, dated as of March 1, 1997, by and
between Oglethorpe and Georgia System Operations Corporation.
10.33.3(Filed as Exhibit 10.33.2 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.22.3 -- Operation Services Agreement, dated as of March 1, 1997, by and
between Oglethorpe and Georgia System Operations Corporation.
(Filed as Exhibit 10.33.3 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.23(2) -- Power Purchase and Sale Agreement between Morgan Stanley Capital
Group Inc. and Oglethorpe, dated as of April 7, 1997. (Filed as
Exhibit 10.34 to the Registrant's Form 10-Q for the quarterly
period ended March 31, 1997, File No. 33-7591.)
86
*10.24 -- Long Term Transaction Service Agreement Under Southern Companies'
Federal Energy Regulatory Commission Electric Tariff Volume No. 4
Market-Based Rate Tariff, between Georgia Power Company and
Oglethorpe, dated as of February 26, 1999. (Filed as Exhibit
10.27 to the Registrant's Form 10-Q for the quarterly period
ended March 31, 1999, File No. 33-7591.)
*10.25(3) -- Employment Agreement, dated as of September 15, 1999, between
Oglethorpe and Thomas A. Smith. (Filed as Exhibit 10.26 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1999, File No. 33-7591.)
10.26(3) -- Employment Agreement, dated July 25, 2000, between Oglethorpe and
Michael W. Price.
*10.27(3) -- Employment Agreement, dated August 7, 2000, between Oglethorpe
and W. Clayton Robbins. (Filed as Exhibit 10.28 to the
Registrant's Form 10-Q for the quarterly period ended June 30,
2000, File No. 33-7591.)
*10.28(3) -- Employment Agreement, dated August 7, 2000, between Oglethorpe
and Elizabeth Higgins. (Filed as Exhibit 10.29 to the
Registrant's Form 10-Q for the quarterly period ended June 30,
2000, File No. 33-7591.)
21.1 -- Rocky Mountain Leasing Corporation, a Delaware corporation.
82
27.1 -- Financial Data Schedule (for SEC use only)
- -------------------------------
(1) Pursuant to 17 C.F.R. 229.601(b)(2), the schedules and exhibits to this
document are identified on a list of schedules and exhibits included
within this document and are not filed herewith; however the registrant
hereby agrees that such schedules and exhibits will be provided to the
Commission upon request.
(2) Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this documentdocument(s) is not filed
herewith; however the registrant hereby agrees that such documentdocument(s) will
be provided to the Commission upon request.
(3) For the reason stated in footnote (2), this document and five other
substantially identical documents are not filed as exhibits to this
Registration Statement.
(4) For the reason stated in footnote (2), this document and another
substantially identical document are not filed as exhibits to this
Registration Statement.
(5) Certain portions of this document have been omitted as confidential and
filed separately with the Commission.
(6)(3) Indicates a management contract or compensatory plan or arrangement required to be
filed as an exhibit to this form pursuant to Item 14(c) of
this report.
All other schedules and exhibits are omitted because of the absence of the
conditions under which they are required or because the required information is
included in the financial statements and related notes to financial statements.Report.
(b) Reports on Form 8-K.
NoOglethorpe filed no reports on Form 8-K were filed by Oglethorpe forduring the fourth quarter ended
December 31, 1996.
83of
2000.
87
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 26th16th day of
March, 1997.2001.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
By: /s/ J. CALVIN EARWOOD
-------------------------------------------------------------------------------
J. CalvinCALVIN EARWOOD
CHAIRMAN OF THE BOARDChairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ J. CALVIN EARWOOD Chairman of the Board, March 26, 1997
- ------------------------------------- Director (Principal Executive
J. CALVIN EARWOOD Officer)
/s/ T. D. KILGORE President and Chief Executive March 26, 1997
- ------------------------------------- Officer (Principal Executive
T. D. KILGORE Officer)
/s/ VACANT (Principal Financial Officer) March 26, 1997
- -------------------------------------
VACANT
/s/ ROBERT D. STEELE Controller March 26, 1997
- ------------------------------------- (Principal Accounting Officer)
ROBERT D. STEELE
/s/ ASHLEY C. BROWN Director March 26, 1997
- -------------------------------------
ASHLEY C. BROWN
/s/ NEWTON A. CAMPBELL Director March 26, 1997
- -------------------------------------
NEWTON A. CAMPBELL
/s/ LARRY N. CHADWICK Director March 26, 1997
- -------------------------------------
LARRY N. CHADWICK
/s/ BENNY W. DENHAM Director March 26, 1997
- -------------------------------------
BENNY W. DENHAM
/s/ SAMMY M. JENKINS Director March 26, 1997
- -------------------------------------Signature Title Date
/s/ J. CALVIN EARWOOD Chairman of the Board, Director March 16, 2001
- ----------------------- (Principal Executive Officer)
J. CALVIN EARWOOD
/s/ THOMAS A. SMITH President and Chief Executive Officer March 16, 2001
- ----------------------- (Principal Executive Officer)
THOMAS A. SMITH
/s/ MAC F. OGLESBY Treasurer, Director (Principal March 16, 2001
- ----------------------- Financial Officer)
MAC F. OGLESBY
/s/W. CLAYTON ROBBINS Senior Vice President, Finance and March 16, 2001
- ----------------------- Administration (Principal Financial
W. CLAYTON ROBBINS Officer)
/s/ WILLIE B. COLLINS Controller and Chief Risk Officer March 16, 2001
- -----------------------
WILLIE B. COLLINS
/s/ ASHLEY C. BROWN Director March 16, 2001
- -----------------------
ASHLEY C. BROWN
/s/ LARRY N. CHADWICK Director March 16, 2001
- -----------------------
LARRY N. CHADWICK
/s/ BENNY W. DENHAM Director March 16, 2001
- -----------------------
BENNY W. DENHAM
88
Signature Title Date
/s/ WM. RONALD DUFFEY Director March 16, 2001
- ---------------------------------------
WM. RONALD DUFFEY
/s/ SAMMY M. JENKINS Director March 16, 2001
- ---------------------------------------
SAMMY M. JENKINS
/s/ MAC F. OGLESBY Director March 26, 1997
- -------------------------------------
MAC F. OGLESBY
/s/ J. SAM L. RABUN Director March 26, 1997
- ------------------------------------- J. SAM L. RABUN
84Director March 16, 2001
- ---------------------------------------
J. SAM L. RABUN
/s/ JOHN S. RANSON Director March 16, 2001
- ---------------------------------------
JOHN S. RANSON
/s/ JEFFREY D. TRANEN Director March 16, 2001
- ---------------------------------------
JEFFREY D. TRANEN
89
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT.
The registrant is a membership corporation and has no authorized or outstanding
equity securities. Proxies are not solicited from the holders of Oglethorpe's
public bonds. No annual report or proxy material has been sent to such
bondholders.
8590