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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
(MARK ONE)
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1999
OR
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___________ TO _____________
COMMISSION FILE NO. 33-7591
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
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(Exact name of registrant as specified in its charter)
GEORGIA 58-1211925
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
POST OFFICE BOX 1349
2100 EAST EXCHANGE PLACE
TUCKER, GEORGIA 30085-1349
- --------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (770) 270-7600
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES /X/ NO / /
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/
State the aggregate market value of the voting and non-voting common
equity held by non-affiliates of the registrant. NONE
Indicate the number of shares outstanding of each of the registrant's
classes of common stock, as of the latest practicable date. THE REGISTRANT IS A
MEMBERSHIP CORPORATION AND HAS NO AUTHORIZED OR OUTSTANDING EQUITY SECURITIES.
Documents Incorporated by Reference: NONE
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OGLETHORPE POWER CORPORATION
1999 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
ITEM PAGE
- ---- ----
PART I
1 Business ............................................................................... 1
Oglethorpe Power Corporation.......................................................... 1
The Members........................................................................... 7
Member Requirements and Power Supply Resources........................................ 11
Certain Factors Affecting the Electric Utility Industry............................... 16
Other Information..................................................................... 20
2 Properties.............................................................................. 21
Generating Facilities................................................................. 21
Co-Owners of the Plants and the Plant Agreements...................................... 24
3 Legal Proceedings....................................................................... 27
4 Submission of Matters to a Vote of Security Holders..................................... 27
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters................... 29
6 Selected Financial Data................................................................. 29
7 Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................................... 30
7A Quantitative and Qualitative Disclosures About Market Risk.............................. 40
8 Financial Statements and Supplementary Data............................................. 43
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure................................................................ 64
PART III
10 Directors and Executive Officers of the Registrant...................................... 64
11 Executive Compensation.................................................................. 67
12 Security Ownership of Certain Beneficial Owners and Management.......................... 68
13 Certain Relationships and Related Transactions.......................................... 68
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................ 69
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SELECTED DEFINITIONS
When used herein the following terms will have the meanings indicated below:
TERM MEANING
- ---- -------
CFC National Rural Utilities Cooperative Finance Corporation
EMC Electric Membership Corporation
FERC Federal Energy Regulatory Commission
GPC Georgia Power Company
GPSC Georgia Public Service Commission
GSOC Georgia System Operations Corporation
GTC Georgia Transmission Corporation (An Electric Membership Corporation)
LEM LG&E Energy Marketing Inc.
MEAG Municipal Electric Authority of Georgia
NRC Nuclear Regulatory Commission
RUS Rural Utilities Service
SEPA Southeastern Power Administration
SONOPCO Southern Nuclear Operating Company
TVA Tennessee Valley Authority
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PART I
ITEM 1. BUSINESS
OGLETHORPE POWER CORPORATION
GENERAL
Oglethorpe Power Corporation (An Electric Membership Corporation)
("Oglethorpe") is a Georgia electric membership corporation incorporated in 1974
and headquartered in metropolitan Atlanta. Oglethorpe is owned by 39 retail
electric distribution cooperative members (the "Members"), who, in turn, are
owned by their retail consumers. Oglethorpe is the largest electric cooperative
in the United States in terms of operating revenues, assets, kilowatt-hour
("kWh") sales and, through the Members, consumers served. Oglethorpe has
approximately 144 employees.
As with cooperatives generally, Oglethorpe operates on a not-for-profit
basis. Oglethorpe's principal business is providing wholesale electric power to
the Members. (See "Power Supply Business" herein.) The Members are local
consumer-owned distribution cooperatives providing retail electric service on a
not-for-profit basis. In general, the customer base of the Members consists of
residential, commercial and industrial consumers within specific geographic
areas. The Members serve approximately 1.3 million electric consumers (meters)
representing approximately 3.1 million people. For information on the Members,
see "THE MEMBERS."
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.
CORPORATE STRUCTURE
Oglethorpe and the Members completed a corporate restructuring (the
"Corporate Restructuring") in 1997, in which Oglethorpe was divided into three
separate operating companies. Oglethorpe's transmission business was sold to and
is now owned and operated by Georgia Transmission Corporation (An Electric
Membership Corporation) ("GTC"), a Georgia electric membership corporation
formed for that purpose. Oglethorpe's system operations business was sold to and
is now owned and operated by Georgia System Operations Corporation ("GSOC"), a
Georgia nonprofit corporation formed for that purpose. Oglethorpe retained all
of its owned and leased generation assets. (See "Power Supply Business,"
"Relationship with GTC," and "Relationship with GSOC" herein and "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES.")
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POWER SUPPLY BUSINESS
Oglethorpe provides wholesale electric service to the 39 Members pursuant
to long-term, take-or-pay Wholesale Power Contracts described herein. The
Wholesale Power Contracts obligate the Members on a joint and several basis to
pay rates sufficient to pay all the costs of owning and operating Oglethorpe's
power supply business. (See "Wholesale Power Contracts" herein.) Oglethorpe
supplies capacity and energy to the Members from a combination of owned and
leased generating plants and power purchased from other power suppliers and
power marketers. GTC provides transmission services to the Members for delivery
of the Members' power purchases.
Oglethorpe owns or leases undivided interests in thirteen generating units.
These units provide Oglethorpe with a total of 3,335 megawatts ("MW") of
nameplate capacity, consisting of 1,500.6 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. Oglethorpe's 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 the Rocky Mountain Pumped
Storage Hydroelectric Facility ("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. (See "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES--General" and "GENERATING
FACILITIES--General" in Item 2.)
Participants in Plants Hatch, Vogtle and Wansley and Scherer Units No. 1
and No. 2 also include the Municipal Electric Authority of Georgia ("MEAG"), the
City of Dalton ("Dalton") and Georgia Power Company ("GPC"). GPC serves as
operating agent for these units. GPC is also a participant in Rocky Mountain,
which is operated by Oglethorpe.
Oglethorpe utilizes long-term power marketer arrangements to reduce the
cost of power to the Members. Oglethorpe has power marketer agreements with LG&E
Energy Marketing Inc. ("LEM") and Morgan Stanley Capital Group Inc. ("Morgan
Stanley"). 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 the
costs of its system resources but receives revenue from LEM and Morgan Stanley
for the use of the resources. (See "MEMBER REQUIREMENTS AND POWER SUPPLY
RESOURCES--General" and "--Power Marketer Arrangements".)
Oglethorpe purchases a total of approximately 1,250 MW of power pursuant to
power purchase agreements with GPC, Big Rivers Electric Corporation ("Big
Rivers"), Entergy Power, Inc. ("Entergy Power"), and Hartwell Energy Limited
Partnership ("Hartwell"). (See "MEMBER REQUIREMENTS AND POWER SUPPLY
RESOURCES--Power Purchase and Sale Arrangements".) Oglethorpe meets its
supplemental power supply needs through short-term power purchase contracts and
spot market purchases.
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WHOLESALE POWER CONTRACTS
Oglethorpe has entered into a substantially similar Amended and Restated
Wholesale Power Contract with each Member extending through December 31, 2025.
Each Wholesale Power Contract permits a Member to take future incremental power
requirements either from Oglethorpe or other sources. (See "THE MEMBERS--Other
Power Resources.") Under its Wholesale Power Contract, 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. Each Wholesale Power Contract specifically
provides that the Member must make payments whether or not power is delivered
and whether or not a plant has been sold or is otherwise unavailable. Oglethorpe
is obligated to use its reasonable best efforts to operate, maintain and manage
its resources in accordance with prudent utility practices.
Under the Wholesale Power Contracts, Oglethorpe provides joint planning and
resource management services. A Member may separately elect not to have
Oglethorpe provide joint power supply planning, resource procurement or bulk
power marketing services. Currently, all Members are participating in all joint
planning and resource management services. The Contracts also provide for the
establishment of a "pool" to operate Oglethorpe and Member resources in a single
system dispatch. Members may also choose to satisfy all or a portion of their
future requirements with purchases from suppliers other than Oglethorpe.
Each Member's cost responsibility under its Wholesale Power Contract is
based on agreed-upon fixed percentage capacity responsibilities. Percentage
capacity responsibilities have been assigned for all of Oglethorpe's existing
generation and purchased power resources. Percentage capacity responsibilities
for any future resource will be assigned only to Members choosing to participate
in that resource. The Wholesale Power Contracts provide that each Member will be
jointly and severally responsible for all costs and expenses of all existing
generation and purchased power resources, as well as for any future resources
(whether or not such Member has elected to participate in such future resource)
that are approved by 75% of Oglethorpe's Board of Directors and 75% of the
Members. For resources so approved in which less than all Members participate,
costs are shared first among the participating Members, and if all participating
Members default, each non-participating Member is expressly obligated to pay a
proportionate share of such default.
Under the Wholesale Power Contracts, each Member must establish, maintain
and collect rates and charges for the service of its electric system. Each
Member must also conduct its business in a manner that will enable the Member to
pay to Oglethorpe (i) when due, all amounts payable by the Member under its
Wholesale Power Contract and (ii) any and all other amounts payable from, or
which might constitute a charge or a lien upon, the revenues and receipts
derived from the Member's electric system, including all operation and
maintenance expenses and the principal of, premium, if any, and interest on all
indebtedness related to the Member's electric system.
See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES" for a description of
the Members' demand and energy requirements and the related power supply
resources. See also "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--Power
Marketer Arrangements--RELATED AGREEMENTS" regarding supplemental agreements to
the Wholesale Power Contracts relating to the power marketer agreements.
ELECTRIC RATES
Each Member is required to pay Oglethorpe for capacity and energy furnished
under its Wholesale Power Contract in accordance with rates established by
Oglethorpe. Oglethorpe reviews its rates at such intervals as it deems
appropriate but is required to do so at least once every year. Oglethorpe is
required to
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revise its rates as necessary so that the revenues derived from its rates,
together with its revenues from all other sources, will be sufficient, but only
sufficient to pay all costs of its system. These costs include
o operating and maintenance costs,
o the cost of purchased power,
o the cost of transmission services,
o principal and interest on all indebtedness and capital lease
obligations of Oglethorpe,
o all costs associated with decommissioning or otherwise retiring any
generating facility,
o amounts to provide for the establishment and maintenance of reasonable
reserves, and
o amounts to enable Oglethorpe to comply with all financial requirements
under the Indenture, dated as of March 1, 1997, from Oglethorpe to
SunTrust Bank ("SunTrust"), as trustee (as supplemented, the "Mortgage
Indenture").
Under the Mortgage Indenture, Oglethorpe is required, subject to any
necessary regulatory approval, to establish and collect rates which are
reasonably expected, together with other revenues of Oglethorpe, to yield a
Margins for Interest Ratio described herein for each fiscal year equal to at
least 1.10. Margins for Interest is defined in the Mortgage Indenture to be 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),
o plus interest charges, whether capitalized or expensed, on all
indebtedness secured under the Mortgage Indenture or by a lien equal
or prior to the lien of the Mortgage Indenture, including amortization
of debt discount or premium on issuance, but excluding interest
charges on indebtedness assumed by GTC ("Interest Charges"),
o plus any amount included in net margins for accruals for federal or
state income taxes imposed on income after deduction of interest
expense.
Margins for Interest takes into account any item of net margin, loss, gain
or expenditure of any affiliate or subsidiary of Oglethorpe only if Oglethorpe
has received such net margins or gains as a dividend or other distribution from
such affiliate or subsidiary or if Oglethorpe has made a payment with respect to
such losses or expenditures. "Margins for Interest Ratio" is the ratio of
Margins for Interest to total Interest Charges for a given period. (See
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--General--RATES AND REGULATION" in Item 7.)
The formulary rate established by Oglethorpe in the rate schedule to the
Wholesale Power Contracts employs a rate methodology under which all categories
of costs are specifically separated as components of the formula to determine
Oglethorpe's revenue requirements. The rate schedule also implements the
responsibility for fixed costs assigned to each Member (that is, the Member's
percentage capacity responsibility). The monthly charges for capacity and other
non-energy charges are based on Oglethorpe's annual budget. Such capacity and
other non-energy charges may be adjusted by the Board of Directors, if
necessary, during the year through an adjustment to the annual budget. Energy
charges reflect the pass-through of actual energy costs whether incurred from
generation or purchased power resources or under the power marketing
arrangements.
The rate schedule formula also includes a prior period adjustment mechanism
designed to ensure that Oglethorpe achieves the minimum 1.10 Margins for
Interest Ratio. Amounts, if any, by which Oglethorpe
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fails to achieve a minimum 1.10 Margins for Interest Ratio are accrued as of
December 31 of the applicable year and collected from the Members during the
period April through December of the following year. Amounts within a range from
a 1.10 Margins for Interest Ratio to a 1.20 Margins for Interest Ratio are
retained as margins. Amounts, if any, by which Oglethorpe exceeds the maximum
1.20 Margins for Interest Ratio are charged against revenues as of December 31
of the applicable year and refunded to the Members during the period April
through December of the following year. The rate schedule formula is intended to
provide for the collection of revenues which, together with revenues from all
other sources, are equal to all costs and expenses recorded by Oglethorpe, plus
amounts necessary to achieve at least the minimum 1.10 Margins for Interest
Ratio.
Under the Mortgage Indenture and related loan contract with the Rural
Utilities Service ("RUS"), adjustments to Oglethorpe's rates to reflect changes
in Oglethorpe's budgets are not subject to RUS approval, except for any
reduction in rates in a fiscal year following a fiscal year in which Oglethorpe
has failed to meet the minimum 1.10 Margins for Interest Ratio set forth in the
Mortgage Indenture. Changes to the rate schedule under the Wholesale Power
Contracts are subject to RUS approval. Oglethorpe's rates are not subject to the
approval of any other federal or state agency or authority, including the
Georgia Public Service Commission (the "GPSC").
RELATIONSHIP WITH GTC
Oglethorpe and the 39 Members are members of GTC. GTC provides transmission
services to the Members for delivery of the Members' power purchases from
Oglethorpe, Southeastern Power Administration ("SEPA") and any other power
suppliers. GTC also provides transmission services to Oglethorpe and third
parties. Oglethorpe has entered into a transmission agreement with GTC to
provide transmission services for third party transactions and for service to
Oglethorpe's headquarters and the administration building at Rocky Mountain.
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.
GTC has rights in the Integrated Transmission System, which consists of
transmission facilities owned by GTC, GPC, MEAG and Dalton. Through agreements,
common access to the combined facilities that compose the Integrated
Transmission System enables the owners to use their combined resources to make
deliveries to or for their respective consumers, to provide transmission service
to third parties and to make off-system purchases and sales. The Integrated
Transmission System was established in order to obtain the benefits of a
coordinated development of the parties' transmission facilities and to make it
unnecessary for any party to construct duplicative facilities.
RELATIONSHIP WITH GSOC
Oglethorpe, the 39 Members and GTC are members of GSOC. GSOC operates the
system control center and provides system operations services to the Members,
Oglethorpe and GTC. 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.
Since 1997, Oglethorpe had been receiving its support services in the areas
of accounting, auditing, communications, human resources, facility management,
purchasing, telecommunications, and information
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technology through an agreement with Intellisource, Inc., a provider of
outsourcing services. Oglethorpe and Intellisource mutually agreed to dissolve
their business relationship as of December 31, 1999. GSOC has assumed all of the
functions listed above, except for purchasing. GTC has assumed the purchasing
function because GTC is the primary user of purchasing services. Going forward,
GSOC and GTC will provide these services to Oglethorpe under cost-based
contracts.
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"). For further information regarding the relationships and
agreements with GPC, see "THE MEMBERS--Service Area and Competition" and "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES--Power Purchase and Sale
Arrangements--POWER PURCHASES FROM GPC." Also see "GENERATING FACILITIES--Fuel
Supply," "CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--Co-Owners of the
Plants--GEORGIA POWER COMPANY" and "--The Plant Agreements" in Item 2.
RELATIONSHIP WITH RUS
Historically, federal loan programs administered by RUS have provided the
principal source of financing for electric cooperatives. Loans guaranteed by RUS
and made by the Federal Financing Bank have been a major source of funding for
Oglethorpe. However, 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 any event, Oglethorpe's
management does not anticipate the need for loans guaranteed by RUS well into
the future. (See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS--Financial Condition--CAPITAL REQUIREMENTS" and
"--LIQUIDITY AND SOURCES OF CAPITAL" in Item 7.)
Oglethorpe entered into a loan contract with RUS in connection with the
Mortgage Indenture. Under the loan contract, RUS has approval rights over
certain significant actions and arrangements, including, without limitation,
o significant additions to or dispositions of system assets,
o significant power purchase and sale contracts,
o changes to the Wholesale Power Contracts, including the rate schedule
contained therein,
o changes to plant ownership and operating agreements and
o in limited circumstances, issuance of additional secured debt.
The extent of RUS's approval rights under the loan contract with Oglethorpe is
substantially less than the supervision and control RUS has traditionally
exercised over borrowers under its standard loan and security documentation. In
addition, the Mortgage Indenture improves Oglethorpe's ability to borrow funds
in the public capital markets relative to RUS's standard mortgage. The Mortgage
Indenture constitutes a lien on substantially all of the owned tangible and
certain intangible property of Oglethorpe.
See "THE MEMBERS--Members' Relationship with RUS" for a discussion of the
impact of the current RUS lending program on the Members.
6
THE MEMBERS
SERVICE AREA AND COMPETITION
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
an EMC
The Members serve approximately 1.3 million electric consumers (meters)
representing approximately 3.1 million people. The Members serve a region
covering approximately 40,000 square miles, which is approximately 70% of the
land area in the State of Georgia, encompassing 150 of the State's 159 counties.
Sales by the Members in 1999 amounted to approximately 25 million megawatt-hours
("MWh"), with approximately 67% to residential consumers, 30% to commercial and
industrial consumers and 3% to other consumers. The Members are the principal
suppliers for the power needs of rural Georgia. While the Members do not serve
any major cities, portions of their service territories are in close proximity
to urban areas and are experiencing substantial growth due to the expansion of
urban areas, including metropolitan Atlanta, into suburban areas and the growth
of suburban areas into neighboring rural areas. The Members have experienced
average annual compound growth rates from 1997 through 1999 of 5% in number of
consumers, 9% in MWh sales and 8% in electric revenues.
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 chief exception to this rule of exclusivity is that
electric suppliers may compete for most new retail loads of 900 kilowatts or
greater. The GPSC may reassign territory only if it determines that an electric
supplier has breached the tenets of public convenience and necessity. The GPSC
may transfer service for specific premises only if: (i) the GPSC determines,
after joint application of electric suppliers and proper notice and hearing,
that the public convenience and necessity require a transfer of service from one
electric supplier to another; or (ii) the GPSC finds, after proper notice and
hearing, that an electric supplier's service to a premise is not adequate or
dependable or that its rates, charges, service rules and regulations
unreasonably discriminate in favor of or against the consumer utilizing such
premises and the electric utility is unwilling or unable to comply with an order
from GPSC regarding such service.
7
Since 1973, the Territorial Act has allowed limited competition among
electric utilities in Georgia by allowing the owner of any new facility located
outside of municipal limits and having a connected demand upon initial full
operation of 900 kilowatts or greater to receive electric service from the
retail supplier of its choice. The Members, with Oglethorpe's support, are
actively engaged in competition with other retail electric suppliers for these
new commercial and industrial loads. The number of commercial and industrial
loads served by the Members continues to increase annually. While the
competition for 900-kilowatt loads represents only limited competition in
Georgia, this competition has given Oglethorpe and the Members the opportunity
to develop resources and strategies to operate in an increasingly competitive
market.
The electric utility industry in the United States is undergoing
fundamental change and is becoming increasingly competitive. (See "CERTAIN
FACTORS AFFECTING THE ELECTRIC UTILITY INDUSTRY--General" and "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Miscellaneous--COMPETITION" in Item 7.)
From time to time, utilities are approached by other parties interested in
purchasing their systems. Some of the Members have been approached in the past
by third parties indicating an interest in purchasing their systems. The
Wholesale Power Contracts provide that a Member may not dissolve, liquidate or
otherwise wind up its affairs without Oglethorpe's approval. A Member generally
must obtain approval from Oglethorpe before it may consolidate or merge with any
person or reorganize or change the form of its business organization from an
electric membership corporation or sell, transfer, lease or otherwise dispose of
all or substantially all of its assets to any person, whether in a single
transaction or series of transactions. The Member may enter such a transaction
without Oglethorpe`s approval if specified conditions are satisfied, including,
but not limited to, an agreement by the transferee, satisfactory to Oglethorpe,
to assume the performance and observance of every covenant and condition of the
Member under the Wholesale Power Contract, and certifications of accountants as
to certain specified financial requirements of the transferee.
COOPERATIVE STRUCTURE
The Members are cooperatives that operate their systems on a not-for-profit
basis. Accumulated margins derived after payment of operating expenses and
provision for depreciation constitute patronage capital of the consumers of the
Members. Refunds of accumulated patronage capital to the individual consumers
may be made from time to time subject to limitations contained in mortgages
between the Members and RUS or loan documents with other lenders. The RUS
mortgages generally prohibit such distributions unless, after any such
distribution, the Member's total equity will equal at least 40% (30% in the case
of Members, if any, that have the new form of RUS loan documents, discussed
below) of its total assets, except that distributions may be made of up to 25%
of the margins and patronage capital received by the Member in the preceding
year (provided that equity is at least 20% in the case of Members, if any, that
have the new form of RUS loan documents). (See "Members' Relationship with RUS"
herein.)
Oglethorpe is a membership corporation, and the Members are not
subsidiaries of Oglethorpe. Except with respect to the obligations of the
Members under each Member's Wholesale Power Contract with Oglethorpe and
Oglethorpe's rights under such contracts to receive payment for power and energy
supplied, Oglethorpe has no legal interest in, or obligations in respect of, any
of the assets, liabilities, equity, revenues or margins of the Members. (See
"OGLETHORPE POWER CORPORATION--Wholesale Power Contracts.") The revenues of the
Members are not pledged as security to Oglethorpe but are the source from which
moneys are derived by the Members to pay for power supplied by Oglethorpe under
the Wholesale Power Contracts. Revenues of the Members are, however, pledged
under their respective RUS mortgages or loan documents with other lenders.
8
RATE REGULATION OF MEMBERS
Through provisions in the loan documents securing loans to the Members, RUS
exercises control and supervision over the rates for the sale of power of the
Members that borrow from it. The RUS mortgages of such Members require them to
design rates with a view to maintaining an average Times Interest Earned Ratio
of not less than 1.50 and an average Debt Service Coverage Ratio of not less
than 1.25 for the two highest out of every three successive years.
Although the setting of the rates of the Members is not subject to approval
by any federal or state agency or authority other than RUS, the Territorial Act
prohibits the Members from unreasonable discrimination in the setting of rates,
charges, service rules or regulations and requires the Members to obtain GPSC
approval of long-term borrowings.
Snapping Shoals EMC, Mitchell EMC, Troup EMC, Walton EMC, Cobb EMC and
Flint EMC have prepaid their RUS indebtedness and are no longer RUS borrowers.
Each of these Members now has a rate covenant with its current lender. Other
Members may also pursue this option. To the extent that a Member who is not an
RUS borrower engages in wholesale sales or transmission in interstate commerce,
it would be subject to regulation by the Federal Energy Regulatory Commission
("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.
Historically, federal loan programs providing direct loans from RUS to
electric cooperatives have been a major source of funding for the Members.
However, 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, the 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 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.
Under the current RUS loan program, interest rates are based on rates being
paid on municipal bonds with comparable maturities. Certain borrowers with
either low consumer density or higher-than-average rates and lower-than-average
consumer income are eligible for special loans at 5%. Oglethorpe cannot predict
the future cost, availability and amount of RUS direct and guaranteed loans
which may be available to the Members.
MEMBERS' RELATIONSHIPS WITH GTC AND GSOC
For information about the Members' relationships with GTC and GSOC, see
"OGLETHORPE POWER CORPORATION--Relationship with GTC" and "--Relationship with
GSOC."
CONTRACTS WITH SEPA
In addition to energy received from Oglethorpe under the Wholesale Power
Contracts, the Members purchase hydroelectric power under contracts with SEPA
that extend until 2016. In 1999, the aggregate SEPA allocation to the Members
was 523 MW plus associated energy, representing approximately 8% of total Member
peak demand and approximately 3% of total Member energy requirements. Each
Member must schedule its energy allocation, and each Member has designated
Oglethorpe to perform this function. Pursuant to a separate agreement,
Oglethorpe will schedule, through GSOC, the Members' SEPA power
9
deliveries. Further, each Member may be required, if certain conditions are met,
to contribute funds for capital improvements for Corps of Engineers projects
from which its allocation is derived in order to retain the allocation. GTC
delivers the Members' SEPA purchases under its network tariff and contract with
each Member. The amount of capacity and energy available from SEPA is not
expected to increase in an amount sufficient to serve a material portion of the
projected growth in the Members' requirements. (See "OGLETHORPE POWER
CORPORATION--Wholesale Power Contracts" and "MEMBER REQUIREMENTS AND POWER
SUPPLY RESOURCES--Member Demand and Energy Requirements" and the table
thereunder.)
SMARR EMC
Under the Wholesale Power Contracts, a Member may choose to satisfy all or
a portion of its future requirements with purchases from suppliers other than
Oglethorpe. Smarr EMC was formed in 1998 by 36 of the Members to construct and
own a two-unit, 217 MW combustion turbine facility, Smarr Energy Facility. Smarr
Energy Facility was declared in commercial operation in June 1999. Oglethorpe is
providing operation management services for this facility.
Smarr EMC is currently constructing Sewell Creek Energy Facility, a
four-unit, 492 MW combustion turbine facility scheduled for commercial operation
by the summer of 2000. 31 Members are participating in Sewell Creek Energy
Facility, including one Member that did not participate in Smarr Energy
Facility. Oglethorpe is providing construction management services and interim
financing for this facility and anticipates that it will provide operation
management services as well.
Smarr Energy Facility and Sewell Creek Energy Facility are being or are
currently anticipated to be dispatched in the Oglethorpe pool of generation
resources.
Smarr EMC, or similar entities, may also own future generation facilities
on behalf of Members who may decide to participate in such projects.
OTHER POWER 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.
In addition, a number of Members have installed and may continue to install
small diesel generators and microturbines on their distribution systems.
10
MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES
GENERAL
Oglethorpe supplies capacity and energy to the Members from a combination
of owned and leased generating plants and from power purchased under long-term
contracts with other power suppliers and power marketers. Oglethorpe owns or
leases 3,335 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
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 1997 through 1999, and also shows
the amounts of such requirements supplied by Oglethorpe, SEPA and other
Member resources. From 1997 through 1999, demand and energy requirements
increased at an average annual compound growth rate of 9.6% and 8.3%,
respectively.
DEMAND (MW) ENERGY REQUIREMENTS (MWH)
----------------------------------------------- -----------------------------------------------------------
SUPPLIED BY SUPPLIED BY
----------------------------- ----------------------------------------------
TOTAL TOTAL
REQUIREMENTS(1) OGLETHORPE (2) SEPA (3) REQUIREMENTS OGLETHORPE (4) SEPA (3) OTHER (5)
--------------- -------------- -------- ------------ -------------- -------- ------------
1997...... 5,252 4,729 523 21,648,366 20,664,786 983,580 --
1998...... 5,812 5,289 523 24,500,536 23,315,950 1,184,586 --
1999...... 6,315 5,792 523 25,665,305 24,755,812 652,349 257,144
- ---------------
(1) System peak demand of the Members measured at the Members' delivery points
(net of system losses).
(2) Includes purchased power. (See "Power Marketer Arrangements," "Power
Purchase and Sale Arrangements--POWER PURCHASES FROM GPC" and "--OTHER
POWER PURCHASES" herein.) Includes Members' resources, excluding SEPA
and Members' resources behind the delivery points. (See "THE MEMBERS--
Smarr EMC" and "--Other Power Resources.")
(3) Firm Member resource supplied by SEPA. (See "THE MEMBERS--Contracts with
SEPA.")
(4) Includes purchased power.
(5) Consists of Members' resources, excluding SEPA and Members' resources
behind the delivery points.
In 1999, Jackson EMC and Cobb EMC accounted for approximately 11.8% and
11.7% of Oglethorpe's total revenues, respectively. None of the other Members
accounted for as much as 10% of Oglethorpe's total revenues in 1999. Due to
greater than average growth rates, certain of Oglethorpe's customers, including
its larger customers such as Jackson EMC and Cobb EMC, have historically
accounted for an increasing percentage of Oglethorpe's total revenues. However,
under the Wholesale Power Contracts, a Member may choose to supply all or a
portion of its future requirements with purchases from other suppliers. (See
"OGLETHORPE POWER CORPORATION--Wholesale Power Contracts.") Although the Members
have contracted for significant portions of their anticipated future needs by
participating in Oglethorpe's power marketer agreements, certain of the Members'
future needs during the terms of the power marketer agreements could still be
purchased from other suppliers. (See "Power Marketer Arrangements" and "Future
Power Resources" herein and "THE MEMBERS--Smarr EMC" and "--Other Power
Resources.")
11
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. (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, capacity charges are billed and capacity revenues are recognized in
equal monthly amounts.
POWER MARKETER ARRANGEMENTS
During 1997, Oglethorpe entered into long-term power marketer agreements
with LEM for approximately 50% of the load requirements of the Members and with
Morgan Stanley with respect to 50% of the Members' then forecasted load
requirements. The LEM agreements are based on the actual requirements of the
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 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.
LEM AGREEMENTS
Effective January 1, 1997, Oglethorpe entered into two power marketer
agreements with LEM, an indirect, wholly owned subsidiary of LG&E Power Inc., a
Delaware corporation, and of LG&E Energy Corp., which is a diversified energy
services company headquartered in Louisville, Kentucky. One of the two
agreements was for 50% of the load requirements of two of the 39 Members and
expired on December 31, 1999. Under the agreement relating to 37 of the 39
Members, LEM is obligated to deliver, and Oglethorpe is obligated to take, (i)
50% of the load requirements of the 37 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 MWh purchased.
The LEM agreement relating to the 37 Members has a term extending through
2011. With one year's notice, Oglethorpe has the right to terminate the LEM
agreement beginning in 2002. With 18 months' notice, LEM has the right to
terminate the LEM agreement beginning in 2005. In October 1998, LEM submitted a
dispute to arbitration seeking to terminate this agreement. On December 21,
1999, the arbitration panel ruled that the agreement is valid and must continue
to be honored. Oglethorpe and LEM, however, are addressing a number of issues
relating to administration of the agreement.
LG&E Energy Corp. 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.
12
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 plans to manage the portion of the system resources
covered by the Morgan Stanley agreement through scheduling and dispatching
such resources. Oglethorpe will also make purchases and sales 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
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.
RELATED AGREEMENTS
Oglethorpe has contracted with GTC to provide available transmission
services to deliver to the border of the Integrated Transmission System any
energy sold to LEM or Morgan Stanley, as well as any other wholesale power
purchase. Each Member will use its Member Transmission Service Agreement for
delivery of energy purchased by Oglethorpe from LEM, Morgan Stanley and others.
In connection with the LEM and Morgan Stanley arrangements, each Member has
entered into supplemental agreements to its Wholesale Power Contract. The
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 power marketer arrangements under the Wholesale Power Contracts.
Each Member has approved the agreements with LEM and Morgan Stanley as
"future resources" under the Wholesale Power Contracts. Accordingly, each Member
has a percentage capacity responsibility for each of the LEM and Morgan Stanley
agreements and all costs incurred by Oglethorpe under such agreements are
recovered from the Members under the Wholesale Power Contracts on a joint and
several basis. To this extent, the Members have elected, under the Wholesale
Power Contracts, to purchase a substantial portion of their future requirements
from Oglethorpe. (See "Future Power Resources" herein and "OGLETHORPE POWER
CORPORATION--Wholesale Power Contracts.")
POWER PURCHASE AND SALE ARRANGEMENTS
POWER PURCHASES FROM GPC
Oglethorpe entered into an agreement with GPC effective April 1, 1999 to
purchase capacity and associated energy on a take-or-pay basis. Under this
agreement, Oglethorpe will purchase capacity and associated energy from GPC as
follows: 750 MW through May 31, 2000, 500 MW from June 1, 2000 to August 31,
2000, 375 MW from September 1, 2000 to August 31, 2001, and 250 MW from
September 1, 2001 to March 31, 2006. This agreement replaced the Block Power
Sale Agreement between Oglethorpe
13
and GPC, pursuant to which Oglethorpe had been purchasing 500 MW of capacity
and associated energy at the time it was terminated.
OTHER POWER PURCHASES
Oglethorpe purchases 100 MW of capacity from each of Entergy Power and
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
Entergy Power. The Tennessee Valley Authority ("TVA") provides the
transmission service to deliver the power from the Big Rivers electric system
to the Integrated Transmission System. TVA and Southern Company Services, as
agent for Alabama Power Company and Mississippi Power Company, provide the
transmission service necessary to deliver the power from Entergy Power to the
Integrated Transmission System. (See Note 9 of Notes to Financial Statements
in Item 8.)
Oglethorpe also has a contract through 2019 to purchase approximately 300
MW of capacity from Hartwell, a partnership owned 50% by NGC Corporation and 50%
by American National Power, Inc., a subsidiary of National Power, PLC. This
capacity is provided by two 150 MW gas-fired turbine generating units on a site
near Hartwell, Georgia. Oglethorpe is using the units for peaking capacity but
has the right to dispatch the units fully.
Oglethorpe entered into an agreement with Doyle I, LLC, a limited liability
company owned by an affiliate of Enron Capital & Trade Resources Corp. and one
Member, to purchase approximately 325 MW of peaking capacity over a 15-year
term. Delivery is anticipated to commence by June 1, 2000 subject to the
generating units underlying the purchase being ready for commercial operation.
Under this agreement, all of the plant output is to be purchased by Oglethorpe,
and Oglethorpe has the contractual right to purchase the facility at the end of
the 15-year contract for a fixed price.
In addition, Oglethorpe also purchases small amounts of capacity and energy
from "qualifying facilities" under the Public Utility Regulatory Policies Act of
1978 ("PURPA"). Under a waiver order from 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 0.1% of Oglethorpe's energy requirements for the Members in 1999. Under
their Wholesale Power Contracts, the Members may make such purchases in the
future 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.
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, Oglethorpe
14
continues to offer planning services for the Members' requirements beyond the
contract terms as well as for evaluation of contract options and balancing of
actual requirements against fixed purchase obligations. Peak requirements for
the Members have exceeded contracted purchases, and Oglethorpe expects they
will continue to exceed contracted purchases over the next several years.
Some of the Members have arranged to meet some of these requirements by
forming Smarr EMC, which supplies power to the Members from combustion turbine
facilities. Oglethorpe also expects to enter into an agreement giving it the
option to construct six new combustion turbine facilities that could supply up
to 660 MW of capacity. The Members would then consider participation in these
turbines, either through Smarr EMC or a similar entity. If sufficient Members
participate, Oglethorpe would arrange for construction of one or more of the
facilities. See "THE MEMBERS--Smarr EMC" and "--Other Power Resources" for a
discussion of capacity purchased by the Members from sources other than
Oglethorpe.
In anticipation of additional requirements of the Members, Oglethorpe has
issued a request for proposals to supply 150 MW to 250 MW of summer peaking
capacity. Oglethorpe has received numerous proposals to supply this power for
terms of up to five years. Oglethorpe is considering these proposals and expects
to sign short-term contracts for peaking power in the near future. Oglethorpe
may also contract for or otherwise acquire additional capacity.
In addition, Oglethorpe and the Members continue to consider and
evaluate a wide array of alternatives for meeting future power requirements
in the increasingly competitive generation business. (See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--
Miscellaneous--Competition" in Item 7).
15
CERTAIN 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 the financial
condition of an electric utility such as Oglethorpe. These factors likely would
affect individual utilities in different ways. Such factors include, among
others:
o the transition to increasing competition in the generation of
electricity and the corresponding increase in competition from other
suppliers of electricity,
o fluctuations in the market price for electricity,
o effects of compliance with changing environmental, licensing and
regulatory requirements,
o regulatory and other changes in national and state energy policy,
including open access transmission,
o uncertain access to low cost capital for replacement of aging fixed
assets,
o increases in operating costs, including the cost of fuel for the
generation of electric energy,
o uncertain recovery of the cost of existing facilities,
o fluctuations in demand, including rates of load growth and changes in
competitive market share,
o unbundling of services and corresponding corporate and functional
restructurings by electric utility companies, and
o the effects of conservation and energy management on the use of
electric energy.
These factors present an increasing challenge to companies in the electric
utility industry, including Oglethorpe and the Members, to reduce costs, improve
the management of resources and respond to the changing environment. (See
"Environmental and Other Regulation" herein, "OGLETHORPE POWER
CORPORATION--Corporate Structure," "MEMBER REQUIREMENTS AND POWER SUPPLY
RESOURCES--General" and "--Power Purchase and Sale Arrangements--OTHER POWER
PURCHASES" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS--Miscellaneous--COMPETITION" in Item 7.)
COMPETITION
The electric utility industry in the United States is undergoing
fundamental change and is becoming increasingly competitive. (See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Miscellaneous--COMPETITION" in Item 7.)
ENVIRONMENTAL AND OTHER REGULATION
GENERAL
As is typical for electric utilities, Oglethorpe is subject to various
federal, state and local air and water quality requirements which, among other
things, regulate emissions of pollutants, such as particulate matter, sulfur
dioxide and nitrogen oxides into the air and discharges of other pollutants,
including heat, into waters of the United States. Oglethorpe is also subject to
federal, state and local waste disposal requirements that regulate the manner of
transportation, storage and disposal of various types of waste.
In general, environmental requirements are becoming increasingly stringent.
New requirements may
16
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's direct
capital costs to achieve compliance with current environmental requirements are
expected to be significant in 2001 through 2003, as further discussed below.
(See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Financial Condition--CAPITAL REQUIREMENTS" in Item 7.) Based on the
current status of regulatory requirements, Oglethorpe does not anticipate that
these capital expenditures will have a material effect on its results of
operations or its financial condition. However, as discussed below, future
regulations could require Oglethorpe to make additional capital expenditures.
CLEAN AIR ACT
Environmental concerns of the public, the scientific community and Congress
have resulted in the enactment of legislation that has had and will continue to
have a significant impact on the electric utility industry. The most significant
environmental legislation applicable to Oglethorpe is the Clean Air Act. One of
the purposes of the Clean Air Act is to improve air quality by reducing the
emissions of sulfur dioxide and nitrogen oxides from affected utility units,
which include the coal-fired units at Plants Wansley and Scherer.
Sulfur dioxide reductions are being imposed through a sulfur dioxide
emission allowance trading program. An emission allowance, which gives the
holder the authority to emit one ton of sulfur dioxide during a calendar year,
is transferable and can be bought, sold or banked for use in the years following
its issuance. Allowances are issued by the U.S. Environmental Protection Agency
("EPA") to impose stringent reductions on all affected units. The aggregate
emissions of sulfur dioxide from all affected units are now capped at 8.9
million tons per year. Oglethorpe is now complying with this program by using
lower-sulfur fuel, coupled with the use of emission allowances (issued, banked
or purchased, if needed). Installation of flue gas desulfurization equipment
remains a possibility for compliance in the more distant future.
A number of recently finalized regulations, proposed regulations and other
actions could result in more stringent controls on all emissions, including
utility emissions. The most significant of these appear to be the following.
First, because nitrogen oxides are considered to be a precursor to ozone,
coupled with the fact that metropolitan Atlanta is classified as a "serious
nonattainment area" under the one hour ozone National Ambient Air Quality
Standards ("NAAQS"), EPA and the State of Georgia have imposed further limits on
such emissions. Recently, both Plants Wansley and Scherer were made subject to
stringent nitrogen oxides averaging plans, which will cause the co-owners of the
plants to install new control equipment at both plants no later than May 2003.
Oglethorpe expects to incur significant capital expenditures over the next three
years to install this equipment.
Second, EPA attempted to tighten the NAAQS for both ozone and particulate
matter, an action that could affect any source that emits nitrogen oxides and
sulfur dioxide, including utility units. Court challenges to both standards were
made. The Court of Appeals remanded both standards back to EPA for further
consideration. EPA has appealed this decision to the Supreme Court, which has
not yet decided whether it will consider the appeal.
17
Third, in 1977, 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
2003. 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 will have to 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 recently upheld in part, with that portion of the rule that would have
applied to Georgia sent back to EPA for further consideration. That ruling may
undergo further appeal, however. As a result, Georgia's implementation plan for
this regulation has been delayed, pending the outcome of that litigation and
further 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, EPA had proposed that certain nitrogen oxides reductions be made in
upwind states, in response to petitions filed by various Northeastern states
under the Clean Air Act, asking for more stringent nitrogen oxides limits on
sources in such upwind states. Although Georgia was named in one of these
petitions, EPA's final determination was that Georgia was not significantly
contributing to nonattainment in any of the petitioning states.
Sixth, 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. These
studies indicate that further research is needed before decisions can be made on
whether additional controls of utility emissions of these pollutants are
necessary.
On November 3, 1999, the United States Justice Department, on behalf of
EPA, filed lawsuits against GPC and some of its affiliates, as well as other
utilities. The lawsuits allege violations of the new source review provisions
and the new source performance standards of the Clean Air Act at, among other
facilities, Plant Scherer Unit Nos. 3 and 4. Oglethorpe is not currently named
in the lawsuits and Oglethorpe does not have an ownership interest in the named
units of Plant Scherer. However, Oglethorpe can give no assurance that units in
which Oglethorpe has an ownership interest will not be named in this or a
related lawsuit in the future. The resolution of this matter is highly uncertain
at this time, as is any responsibility of Oglethorpe for a share of any
penalties and capital costs required to remedy any violations at facilities
co-owned by Oglethorpe.
Depending on the final outcome of these developments, and the
implementation approach selected by EPA and the State of Georgia, significant
capital expenditures and increased operation expenses could be incurred by
Oglethorpe for the continued operation of Plants Wansley and/or Scherer. The
power marketer arrangements generally do not provide for the recovery from the
power marketers of increased environmental costs. (See "MEMBER REQUIREMENTS AND
POWER SUPPLY RESOURCES--Power Marketer Arrangements.") Because of the
uncertainty associated with these various developments, Oglethorpe cannot now
predict the effect that any of these potential requirements may have on the
operations of Plants Wansley and Scherer.
Compliance with the requirements of the Clean Air Act may also require
increased capital or operating
18
expenses on the part of GPC. Any increases in GPC's capital or operating
expenses may cause an increase in the cost of power purchased from GPC. (See
"MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--Power Purchase and Sale
Arrangements--POWER PURCHASES FROM GPC.")
NUCLEAR REGULATION
Oglethorpe is subject to the provisions of the Atomic Energy Act of 1954,
as amended (the "Atomic Energy Act"), which vests jurisdiction in the Nuclear
Regulatory Commission ("NRC") over the construction and operation of nuclear
reactors, particularly with regard to certain public health, safety and
antitrust matters. The National Environmental Policy Act has been construed to
expand the jurisdiction of the NRC to consider the environmental impact of a
facility licensed under the Atomic Energy Act. Plants Hatch and Vogtle are being
operated under licenses issued by the NRC. All aspects of the operation and
maintenance of nuclear power plants are regulated by the NRC. From time to time,
new NRC regulations require changes in the design, operation and maintenance of
existing nuclear reactors. Operating licenses issued by the NRC are subject to
revocation, suspension or modification, and the operation of a nuclear unit may
be suspended if the NRC determines that the public interest, health or safety so
requires. The operating licenses issued for each unit of Plants Hatch and Vogtle
expire in 2014 and 2018 and 2027 and 2029, respectively.
On February 29, 2000, Southern Nuclear Operating Company ("SONOPCO"), the
operator of Plant Hatch, filed an application with the NRC to extend the
operating licenses for each unit of Plant Hatch, until 2034 and 2038,
respectively. Oglethorpe can give no indication as to the timing or ultimate
approval of the application.
Pursuant to the Nuclear Waste Policy Act of 1982, as amended, the Federal
government has the regulatory responsibility for the final disposition of
commercially produced high-level radioactive waste materials, including spent
nuclear fuel. This Act requires the owner of nuclear facilities to enter into
disposal contracts with the Department of Energy ("DOE") for such material.
These contracts require each such owner to pay a fee, which is currently one
dollar per MWh for the net electricity generated and sold by each of its
reactors.
Contracts with DOE have been executed to provide for the permanent disposal
of spent nuclear fuel produced at Plants Hatch and Vogtle. DOE failed to begin
disposing of spent fuel in 1998 as required by the contracts, and GPC, as agent
for the co-owners of the plants, is pursuing legal remedies against DOE for
breach of contract.
Plants Hatch and Vogtle currently have on-site spent fuel storage capacity.
Based on normal operations and retention of all spent fuel in the reactor, it is
anticipated that existing on-site pool capacity would be sufficient until 2003
and 2017, respectively, to accept the number of spent fuel assemblies that would
normally be removed from the reactor during a refueling. Activities for adding
dry cask storage capacity and potentially additional spent fuel pool rack
capacity at Plant Hatch during 2000 are in progress. In addition, Georgia Power,
as agent for the co-owners of the plant, is a member of Private Fuel Storage,
LLC, a joint utility effort to develop a private spent fuel storage facility for
temporary storage of spent nuclear fuel. This facility is planned to begin
operation as early as the year 2003. (See Note 1 of Notes to Financial
Statements regarding nuclear fuel cost 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.
19
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 the Spring of 1999 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
of Oglethorpe, 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 Clean Water Act, the Georgia Water Quality Control Act, the
Georgia Hazardous Site Response Act, the Toxic Substances Control Act, the
Resource Conservation & Recovery Act, the Endangered Species Act, the
Comprehensive Environmental Response, Compensation and Liability Act, the
Emergency Planning and Community Right to Know Act, and to the regulations
implementing these statutes. Oglethorpe does not believe that compliance with
these statutes and regulations will have a material impact on its financial
condition or results of operations. Changes to any of these laws, some of which
are being reviewed by Congress, could affect many areas of Oglethorpe's
operations. Although compliance with new environmental legislation could have a
significant impact on Oglethorpe, those impacts cannot be fully determined at
this time and would depend in part on the final legislation and the development
of implementing regulations.
The scientific community, regulatory agencies and the electric utility
industry are continuing to examine the issues of global warming and the possible
health effects of electromagnetic fields. While no definitive scientific
conclusions have been reached, it is possible that new laws or regulations
pertaining to these matters could increase the capital and operating costs of
electric utilities, including Oglethorpe or entities from which Oglethorpe
purchases power. In addition, the potential for liability exists from lawsuits
that might be brought alleging damages from electromagnetic fields.
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.
20
ITEM 2. PROPERTIES
GENERATING FACILITIES
GENERAL
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. Plant Hatch, Plant Vogtle,
Plant Wansley and Scherer Unit No. 1 and Scherer Unit 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 Tallassee.
(See "CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--The Plant Agreements.")
OGLETHORPE'S
SHARE OF
NAMEPLATE COMMERCIAL LICENSE
TYPE OF PERCENTAGE CAPACITY OPERATION EXPIRATION
FACILITIES FUEL INTEREST (MW) DATE DATE
- ---------- ------- ---------- ------------ ---------- ----------
Plant Hatch (near Baxley, Ga.)
Unit No. 1........................ Nuclear 30 243.0 1975 2014(1)
Unit No. 2........................ Nuclear 30 246.0 1979 2018(1)
Plant Vogtle (near Waynesboro, Ga.)
Unit No. 1........................ Nuclear 30 348.0 1987 2027
Unit No. 2........................ Nuclear 30 348.0 1989 2029
Plant Wansley (near Carrollton, Ga.)
Unit No. 1........................ Coal 30 259.5 1976 N/A(2)
Unit No. 2........................ Coal 30 259.5 1978 N/A(2)
Combustion Turbine................ Oil 30 14.8 1980 N/A(2)
Plant Scherer (near Forsyth, Ga.)
Unit No. 1........................ Coal 60 490.8 1982 N/A(2)
Unit No. 2........................ Coal 60 490.8 1984 N/A(2)
Tallassee (near Athens, Ga.)......... Hydro 100 2.1 1986 2023
Rocky Mountain (near Rome, Ga.)...... Pumped
Storage
Hydro 74.61 632.5 1995 2027
-------
Total Ownership 3,335.0
=======
- ---------------
(1) Southern Nuclear Operating Company, the operator of Plant Hatch, has filed
an application with the NRC to extend the licenses with respect to Plant
Hatch by 20 years. (See "CERTAIN 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 Nuclear
Regulatory Commission and to hydroelectric plants by FERC.
21
PLANT PERFORMANCE
The following table sets forth certain operating performance information of
each of the major generating facilities in which Oglethorpe currently has
ownership or leasehold interests:
EQUIVALENT AVAILABILITY(1) CAPACITY FACTOR
--------------------------- -----------------------
UNIT 1999 1998 1997 1999 1998 1997
---- ---- ---- ---- ---- ---- ----
Plant Hatch
Unit No. 1........... 81% 100% 86% 83% 99% 86%
Unit No. 2........... 92 81 85 94 81 84
Plant Vogtle
Unit No. 1........... 92 100 81 94 102 81
Unit No. 2........... 88 82 100 89 82 101
Plant Wansley
Unit No. 1........... 91 86 91 73 56 62
Unit No. 2........... 86 92 92 66 50 59
Plant Scherer
Unit No. 1........... 86 93 76 67 70 57
Unit No. 2........... 95 89 99 79 75 84
Rocky Mountain(3)
Unit No. 1........... 97 90 96 23 24 20
Unit No. 2........... 96 95 96 16 13 13
Unit No. 3........... 91 94 97 19 22 19
- ---------------
(1) Equivalent Availability is a measure of the percentage of time that a unit
was available to generate if called upon, adjusted for periods when the
unit is partially derated from the "maximum dependable capacity" rating.
(2) Capacity Factor is a measure of the output of a unit as a percentage of the
maximum output, based on the "maximum dependable capacity" rating, over the
period of measure.
(3) As a pumped storage plant, Rocky Mountain primarily operates as a peaking
plant, which results in a low capacity factor.
The nuclear refueling cycle for Plants Hatch and Vogtle exceeds twelve
months. Therefore, in some calendar years the units at these plants are not
taken out of service for refueling, resulting in higher levels of equivalent
availability and capacity factor.
FUEL SUPPLY
COAL. Coal for Plant Wansley is currently purchased under long-term
contracts and in spot market transactions. As of February 29, 2000, there was a
40-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 29,
2000, the coal stockpile at Plant Scherer contained a 56-day supply based on
nameplate rating. Plant Scherer burns both sub-bituminous and bituminous coals,
and a separate stockpile of sub-bituminous coal is maintained in addition to the
stockpile of bituminous coal. Oglethorpe leases over 700 rail cars to transport
coal to Plants Scherer and Wansley.
The Plant Scherer and Wansley ownership and operating agreements allow each
co-owner (i) to dispatch separately its respective ownership interest in
conjunction with contracting separately for long-term coal purchases procured by
GPC and (ii) to procure separately long-term coal purchases. Oglethorpe
separately dispatches Plant Scherer and Plant Wansley, but continues to use GPC
as its agent for fuel procurement.
22
For information relating to the impact that the Clean Air Act will have on
Oglethorpe, see "CERTAIN FACTORS AFFECTING THE ELECTRIC UTILITY
INDUSTRY--Environmental and Other Regulations--CLEAN AIR ACT" in Item 1.
NUCLEAR FUEL. GPC, as operating agent, has the responsibility to procure
nuclear fuel for Plants Hatch and Vogtle. GPC has contracted with Southern
Nuclear Operating Company ("SONOPCO"), a subsidiary of The Southern Company
specializing in nuclear services, to operate these plants, including nuclear
fuel procurement. (See "CO-OWNERS OF THE PLANTS AND PLANT AGREEMENTS--The Plant
Agreements.") 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.
23
CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS
CO-OWNERS OF THE PLANTS
Plants Hatch, Vogtle, Wansley and Scherer Units No. 1 and No. 2 are
co-owned by Oglethorpe, GPC, MEAG and Dalton, and Rocky Mountain is co-owned by
Oglethorpe and GPC. Each such co-owner owns, 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 the other plants. (See
"The Plant Agreements" herein.)
NUCLEAR COAL-FIRED PUMPED STORAGE
---------------------------- --------------------------------- ---------------
PLANT PLANT PLANT SCHERER UNITS ROCKY
HATCH VOGTLE WANSLEY NO. 1 & NO. 2 MOUNTAIN TOTAL
----------- ------------- -------------- ---------------- --------------- -----
% MW(1) % MW(1) % MW(1) % MW(1) % MW(1) MW(1)
----- ----- ----- ----- ----- ----- ----- ----- ----- ----- -----
Oglethorpe... 30.0 489 30.0 696 30.0 519 60.0 982 74.61 633 3,319
GPC.......... 50.1 817 45.7 1,060 53.5 926 8.4 137 25.39 215 3,155
MEAG......... 17.7 288 22.7 527 15.1 261 30.2 494 -- -- 1,570
Dalton 2.2 36 1.6 37 1.4 24 1.4 23 -- -- 120
--- ---- ---- ---- ----- ---- ------ ----- ------ --- ----
Total..... 100.0 1,630 100.0 2,320 100.0 1,730 100.0 1,636 100.00 848 8,164
===== ===== ===== ===== ===== ===== ===== ===== ====== === =====
- ---------------
(1) Based on nameplate ratings.
GEORGIA POWER COMPANY
GPC is a wholly owned subsidiary of The Southern Company, a registered
holding company under the Public Utility Holding Company Act, and is engaged
primarily in the generation and purchase of electric energy and the
transmission, distribution and sale of such energy. GPC distributes and sells
energy within the State of Georgia at retail in over 600 communities (including
Athens, Atlanta, Augusta, Columbus, Macon, Rome and Valdosta), as well as in
rural areas, and at wholesale to Oglethorpe, MEAG and two municipalities. GPC is
the largest supplier of electric energy in the State of Georgia. (See
"OGLETHORPE POWER CORPORATION--Relationship with GPC" in Item 1.) GPC is subject
to the informational requirements of the Securities Exchange Act of 1934, as
amended, and, in accordance therewith, files reports and other information with
the Commission.
MUNICIPAL ELECTRIC AUTHORITY OF GEORGIA
MEAG, an instrumentality of the State of Georgia, was created for the
purpose of providing electric capacity and energy to those political
subdivisions of the State of Georgia that owned and operated electric
distribution systems at that time. MEAG, also known as MEAG Power, has entered
into power sales contracts with each of 48 cities and one county in the State of
Georgia. Such political subdivisions, located in 39 of the State's 159 counties,
collectively serve approximately 276,000 electric customers.
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,
24
No. 3 and No. 4 (the "Scherer Common Facilities"). Oglethorpe has also entered
into four Operating Agreements ("Operating Agreements") relating to the
operation and maintenance of Plants Hatch, Wansley, Vogtle and Scherer,
respectively. The Ownership Agreements and Operating Agreements relating to
Plants Hatch and Wansley are two-party agreements between Oglethorpe and GPC.
The Ownership Agreements and Operating Agreements relating to Plants Vogtle and
Scherer are agreements among Oglethorpe, GPC, MEAG and Dalton. The parties to
each Ownership Agreement and Operating Agreement are referred to as
"participants" with respect to each such agreement.
In 1985, in four transactions, Oglethorpe sold its entire 60% undivided
ownership interest in Scherer Unit No. 2 to four separate owner trusts (the
"Lessors") established by four different institutional investors (the "Sale and
Leaseback Transaction"). (See Note 4 of Notes to Financial Statements in Item
8.) Oglethorpe retained all of its rights and obligations as a participant under
the Ownership and Operating Agreements relating to Scherer Unit No. 2 for the
term of the leases. Oglethorpe's leases expire in 2013, with options to renew
for a total of 8.5 years. (In the following discussion, references to
participants "owning" a specified percentage of interests include Oglethorpe's
rights as a deemed owner with respect to its leased interests in Scherer Unit
No. 2.)
The Ownership Agreements appoint GPC as agent with sole authority and
responsibility for, among other things, the planning, licensing, design,
construction, renewal, addition, modification and disposal of Plants Hatch,
Vogtle, Wansley and Scherer Units No. 1 and No. 2 and the Scherer Common
Facilities. Each Operating Agreement gives GPC, as agent, sole authority and
responsibility for the management, control, maintenance and operation of the
plant to which it relates. Each Operating Agreement also provides for the use of
power and energy from the plant and the sharing of the costs of the plant by the
participants in accordance with their respective interests in the plant. In
performing its responsibilities under the Ownership and Operating Agreements,
GPC is required to comply with prudent utility practices. GPC's liabilities with
respect to its duties under the Ownership and Operating Agreements are limited
by the terms thereof.
Under the Ownership Agreements, Oglethorpe is obligated to pay a percentage
of capital costs of the respective plants, as incurred, equal to the percentage
interest which it owns or leases at each plant. GPC has responsibility for
budgeting capital expenditures for Scherer Units No. 1 and 2 subject to certain
limited rights of the participants to disapprove capital budgets proposed by GPC
and to substitute alternative capital budgets. GPC has responsibility for
budgeting capital expenditures for Plants Hatch and Vogtle, subject to the right
of any co-owner to disapprove large discretionary capital improvements.
In 1993, the co-owners of Plants Hatch and Vogtle entered into the Amended
and Restated Nuclear Managing Board Agreement, which provides for a managing
board to coordinate the implementation and administration of the Plant Hatch and
Plant Vogtle Ownership and Operating Agreements, provides for increased rights
for the co-owners regarding certain decisions and allows GPC to contract with a
third party for the operation of the nuclear units. In March 1997, GPC
designated SONOPCO as the operator of Plants Hatch and Vogtle, pursuant to the
Nuclear Operating Agreement between GPC and SONOPCO, which the co-owners had
previously approved. In connection with the amendments to the Plant Scherer
Ownership and Operating Agreements, the co-owners of Plant Scherer entered into
the Plant Scherer Managing Board Agreement which provides for a managing board
to coordinate the implementation and administration of the Plant Scherer
Ownership and Operating Agreements and provides for increased rights for the
co-owners regarding certain decisions, but does not alter GPC's role as agent
with respect to Plant Scherer.
The Operating Agreements provide that Oglethorpe is entitled to a
percentage of the net capacity and net energy output of each plant or unit equal
to its percentage undivided interest owned or leased in such plant or unit. GPC,
as agent, schedules and dispatches Plants Hatch and Vogtle. Oglethorpe
separately
25
dispatches its ownership share of Scherer Units No. 1 and No. 2 and of Plant
Wansley. (See "GENERATING FACILITIES--Fuel Supply.")
For Plants Hatch and Vogtle, each participant is responsible for a
percentage of Operating Costs (as defined in the Operating Agreements) and fuel
costs of each plant or unit equal to the percentage of its undivided interest
which is owned or leased in such plant or unit. For Scherer Units No. 1 and No.
2 and for Plant Wansley, each party is responsible for its fuel costs and for
variable Operating Costs in proportion to the net energy output for its
ownership interest, and is responsible for a percentage of fixed Operating Costs
equal to the percentage of its undivided interest which is owned or leased in
such plant or unit. GPC is required to furnish budgets for Operating Costs, fuel
plans and scheduled maintenance plans. In the case of Scherer Units No. 1 and
No. 2, the participants have limited rights to disapprove such budgets proposed
by GPC and to substitute alternative budgets. The Ownership Agreements and
Operating Agreements provide that, should a participant fail to make any payment
when due, among other things, such nonpaying participant's rights to output of
capacity and energy would be suspended.
The Operating Agreement for Plant Hatch will remain in effect with respect
to Hatch Units No. 1 and No. 2 until 2009 and 2012, respectively. The Operating
Agreement for Plant Vogtle will remain in effect with respect to each unit at
Plant Vogtle until 2018. The Operating Agreement for Plant Wansley will remain
in effect with respect to Wansley Units No. 1 and No. 2 until 2016 and 2018,
respectively. The Operating Agreement for Scherer Units No. 1 and No. 2 will
remain in effect with respect to Scherer Units No. 1 and No. 2 until 2022 and
2024, respectively. Upon termination of each Operating Agreement, following any
extension agreed to by the parties, GPC will retain such powers as are necessary
in connection with the disposition of the property of the applicable plant, and
the rights and obligations of the parties shall continue with respect to actions
and expenses taken or incurred in connection with such disposition.
ROCKY MOUNTAIN
Oglethorpe owns a 74.61% undivided interest in Rocky Mountain and GPC owns
the remaining 25.39% undivided interest.
The Rocky Mountain Pumped Storage Hydroelectric Ownership Participation
Agreement, by and between Oglethorpe and GPC (the "Rocky Mountain Ownership
Agreement") appoints Oglethorpe as agent with sole authority and responsibility
for, among other things, the planning, licensing, design, construction,
operation, maintenance and disposal of Rocky Mountain. The Rocky Mountain Pumped
Storage Hydroelectric Project Operating Agreement (the "Rocky Mountain Operating
Agreement") gives Oglethorpe, as agent, sole authority and responsibility for
the management, control, maintenance and operation of Rocky Mountain.
In general, each co-owner is responsible for payment of its respective
ownership share of all Operating Costs and Pumping Energy Costs (as defined in
the Rocky Mountain Operating Agreement) as well as costs incurred as the result
of any separate schedule or independent dispatch. A co-owner's share of net
available capacity and net energy is the same as its respective ownership
interest under the Rocky Mountain Ownership Agreement. Oglethorpe and GPC have
each elected to schedule separately their respective ownership interests. The
Rocky Mountain Operating Agreement will terminate in 2035. The Rocky Mountain
Ownership and Operating Agreements provide that, should a co-owner fail to make
any payment when due, among other things, such non-paying co-owner's rights to
output of capacity and energy or to exercise any other right of a co-owner would
be suspended until all amounts due, with interest, had been paid. The capacity
and energy of a non-paying Co-Owner may be purchased by a paying co-owner or
sold to a third party.
26
In late 1996 and early 1997, Oglethorpe completed lease transactions for
its 74.61% undivided ownership interest in Rocky Mountain. The lease
transactions are characterized as a sale and leaseback for income tax purposes,
but not for financial reporting purposes. Under the terms of these transactions,
Oglethorpe leased the facility to three institutional investors for the useful
life of the facility, who in turn leased it back to Oglethorpe for a term of 30
years. Oglethorpe will continue to control and operate Rocky Mountain during the
leaseback term. Oglethorpe intends to exercise its fixed price purchase option
at the end of the leaseback period so as to retain all other rights of ownership
with respect to the plant if it is advantageous for Oglethorpe to exercise such
option.
ITEM 3. LEGAL PROCEEDINGS
On June 17, 1997, PECO Energy Company-Power Team ("PECO") filed an
application with FERC pursuant to Section 211 of the Federal Power Act
requesting FERC to compel Oglethorpe and/or GTC to provide PECO with 250 MW of
firm point-to-point transmission service from the TVA-Integrated Transmission
System ("TVA-ITS") interface to the Florida-Integrated Transmission System
interface for an initial three-year period, with an automatic roll-over
provision. PECO also seeks $10,000 per day in penalties from Oglethorpe and/or
GTC, alleging bad faith and delays in negotiations. In their response to FERC,
GTC and Oglethorpe contend that they negotiated with PECO in good faith, and
thus there is no reasonable basis for imposing the penalties sought by PECO. GTC
also responded that it does not have firm "available transfer capability" at the
TVA-ITS interface to fulfill PECO's request, after taking into account the need
to protect system reliability, existing firm commitments, and use of the TVA-ITS
interface to serve "native load," in accordance with North American Electric
Reliability Council guidelines. In the event GTC is ordered by FERC to provide
the requested service, PECO would be required to compensate GTC at rates set by
FERC in the order. As a consequence of any such order, power purchased by
Oglethorpe for delivery through the TVA-ITS interface would probably be
curtailed (based on past operational experience at that interface), and could
result in higher purchased power cost than would otherwise be the case. Although
FERC transmission pricing policy is designed to ensure that a transmission
provider is fully compensated for the cost of providing transmission service,
potentially including opportunity cost, there can be no assurance that rates
ordered by FERC for service to PECO would fully compensate GTC, Oglethorpe and
the Members for the use of the transmission system and for any resulting effect
on reliability or increase in the cost of power.
Oglethorpe is a party to various other actions and proceedings incident to
its normal business. Liability in the event of final adverse determinations in
any of these matters is either covered by insurance or, in the opinion of
Oglethorpe's management, after consultation with counsel, should not in the
aggregate have a material adverse effect on the financial position or results of
operations of Oglethorpe.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
27
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28
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Not Applicable.
ITEM 6. SELECTED FINANCIAL DATA
The following table presents selected historical financial data of
Oglethorpe. The financial data presented as of the end of and for each year in
the five-year period ended December 31, 1999, have been derived from the audited
financial statements of Oglethorpe. Due to the 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, "OGLETHORPE POWER CORPORATION--Corporate
Restructuring" in Item 1 and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS" in Item 7.
(dollars in thousands)
1999 1998 1997 1996 1995
---- ---- ---- ---- ----
Operating revenues:
Sales to Members .................. $ 1,122,336 $ 1,095,904 $ 1,000,319 $ 1,023,094 $ 1,030,797
Sales to non-Members .............. 53,896 48,263 47,533 78,343 118,764
--------- --------- --------- --------- ---------
Total operating revenues ............ 1,176,232 1,144,167 1,047,852 1,101,437 1,149,561
--------- --------- --------- --------- ---------
Operating expenses:
Fuel .............................. 196,182 191,399 206,315 206,524 219,062
Production ........................ 215,517 198,378 181,923 173,497 175,777
Purchased power ................... 401,719 387,662 266,875 229,089 264,844
Depreciation and amortization ..... 130,883 124,074 126,730 163,130 139,024
Other operating expenses .......... -- -- 6,334 46,448 42,177
--------- --------- --------- --------- ---------
Total operating expenses ............ 944,301 901,513 788,177 818,688 840,884
--------- --------- --------- --------- ---------
Operating margin .................... 231,931 242,654 259,675 282,749 308,677
Other income, net ................... 50,545 42,293 46,646 65,334 33,710
Net interest charges ................ (262,538) (263,867) (283,916) (326,331) (320,129)
--------- --------- --------- --------- ---------
Net margin .......................... $ 19,938 $ 21,080 $ 22,405 $ 21,752 $ 22,258
============ ============ ============ ============ ============
Electric plant, net:
In service ........................ $ 3,312,669 $ 3,429,704 $ 3,588,204 $ 4,345,200 $ 4,436,009
Construction work in progress ..... 18,299 20,948 13,578 31,181 35,753
--------- --------- --------- --------- ---------
$ 3,330,968 $ 3,450,652 $ 3,601,782 $ 4,376,381 $ 4,471,762
============ ============ ============ ============ ============
Total assets ........................ $ 4,564,622 $ 4,506,265 $ 4,509,857 $ 5,362,175 $ 5,438,496
============ ============ ============ ============ ============
Capitalization:
Long-term debt .................... $ 3,103,590 $ 3,177,883 $ 3,258,046 $ 4,052,470 $ 4,207,320
Obligation under capital leases ... 275,224 282,299 288,638 293,682 296,478
Other obligations ................. 59,579 55,755 52,176 41,685 --
Patronage capital and membership fees 370,025 352,701 330,509 356,229 338,891
--------- --------- --------- --------- ---------
$ 3,808,418 $ 3,868,638 $ 3,929,369 $ 4,744,066 $ 4,842,689
============ ============ ============ ============ ============
Property additions .................. $ 49,516 $ 43,904 $ 63,527 $ 93,704 $ 138,921
============ ============ ============ ============ ============
Energy supply (megawatt-hours):
Generated ......................... 18,295,514 17,781,896 17,722,059 17,866,143 18,402,839
Purchased ......................... 7,971,583 8,544,714 6,377,643 6,606,931 5,738,634
--------- --------- --------- --------- ---------
Available for sale ................ 26,267,097 26,326,610 24,099,702 24,473,074 24,141,473
========== ========== ========== ========== ==========
Member revenue per kWh sold ......... 4.53CENTS 4.70CENTS 4.83CENTS 5.11CENTS 5.53CENTS
========== ========== ========== ========== ==========
29
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
CORPORATE RESTRUCTURING
Oglethorpe Power Corporation (Oglethorpe) provides wholesale electric
service to its 39 retail electric distribution cooperative members (Members).
Oglethorpe and the Members completed a corporate restructuring (the Corporate
Restructuring) in 1997 in which Oglethorpe was divided into three separate
operating companies. Oglethorpe's transmission business was sold to, and is now
owned and operated by, Georgia Transmission Corporation (GTC). Oglethorpe's
system operations business was sold to, and is now owned and operated by,
Georgia System Operations Corporation (GSOC). (See Note 11 of Notes to Financial
Statements.) Oglethorpe retained all of its owned and leased generation assets.
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. 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 $370 million in patronage capital as of December 31, 1999.
Oglethorpe's equity ratio (patronage capital and membership fees divided by
total capitalization) increased from 9.1% at December 31, 1998 to 9.7% at
December 31, 1999.
Patronage capital constitutes the principal equity of Oglethorpe. Any
distributions of patronage capital are subject to the discretion of the Board
of Directors. However, under the Indenture, dated as of March 1, 1997, from
Oglethorpe to SunTrust Bank, as trustee (Mortgage Indenture), Oglethorpe is
prohibited from making any distribution of patronage capital to the Members
if, at the time of or after giving effect to the distribution, (i) an event
of default exists under the Mortgage Indenture, (ii) Oglethorpe's equity as
of the end of the immediately preceding fiscal quarter is less than 20% of
Oglethorpe's total capitalization, or (iii) the aggregate amount expended for
distributions on or after the date on which Oglethorpe's equity first reaches
20% of Oglethorpe's total capitalization exceeds 35% of Oglethorpe's
aggregate net margins earned after such date. This last restriction, however,
will not apply if, after giving effect to such distribution, Oglethorpe's
equity as of the end of the immediately preceding fiscal quarter is not less
than 30% of Oglethorpe's total capitalization.
RATES AND REGULATION
Pursuant to the Amended and Restated Wholesale Power Contracts, dated
August 1, 1996 (Wholesale Power Contracts) entered into between Oglethorpe and
each of the Members, Oglethorpe is required to design capacity and energy rates
that generate sufficient revenues to recover all costs, to establish and
maintain reasonable margins and to meet its financial coverage requirements.
Oglethorpe reviews its capacity rates at least annually to ensure that its fixed
costs are being adequately recovered and, if necessary, adjusts its rates to
meet its net margin goals. Oglethorpe establishes its energy rate to recover
actual fuel and variable operations and maintenance costs.
The rate schedule under the Wholesale Power Contracts implements on a
long-term basis the assignment to each Member of responsibility for fixed costs.
The monthly charges for capacity and other non-energy charges are based on a
rate formula using the Oglethorpe budget. The Board of Directors may adjust
these charges during the year through an adjustment to the annual budget. Energy
charges are based on actual energy costs, whether incurred from generation or
purchased power resources or under the power marketer arrangements.
Under the Mortgage Indenture, Oglethorpe is required, subject to any
necessary regulatory approval, to establish and collect rates that are
reasonably expected, together with other revenues of Oglethorpe, to yield a
Margins for Interest Ratio for each fiscal year equal to at least 1.10. The
Margins for Interest Ratio is
30
determined by dividing Margins for Interest by Interest Charges. Margins for
Interest equal the sum of (i) Oglethorpe's net margins (after certain defined
adjustments), (ii) Interest Charges and (iii) any amount included in net
margins for accruals for federal or state income taxes. The definition of
Margins for Interest takes into account any item of net margin, loss, gain or
expenditure of any affiliate or subsidiary of Oglethorpe only if Oglethorpe
has received such net margins or gains as a dividend or other distribution
from such affiliate or subsidiary or if Oglethorpe has made a payment with
respect to such losses or expenditures.
The rate schedule also includes a prior period adjustment mechanism
designed to ensure that Oglethorpe achieves the minimum 1.10 Margins for
Interest Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum
1.10 Margins for Interest Ratio would be accrued as of December 31 of the
applicable year and collected from the Members during the period April through
December of the following year. Amounts within a range from a 1.10 Margins for
Interest Ratio to a 1.20 Margins for Interest Ratio would be retained as
patronage capital. Amounts, if any, by which Oglethorpe exceeds the maximum 1.20
Margins for Interest Ratio would be charged against revenues as of December 31
of the applicable year and refunded to the Members during the period April
through December of the following year. The rate schedule formula is intended to
provide for the collection of revenues which, together with revenues from all
other sources, are equal to all costs and expenses recorded by Oglethorpe, plus
amounts necessary to achieve at least the minimum 1.10 Margins for Interest
Ratio.
For 1999, 1998 and 1997, 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 not subject to RUS approval, except for any reduction
in rates in a year following a year in which Oglethorpe has failed to meet the
minimum 1.10 Margins for Interest Ratio set forth in the Mortgage Indenture.
Changes to the rate schedule under the Wholesale Power Contracts are subject to
RUS approval. Oglethorpe's rates are not subject to the approval of any other
federal or state agency or authority, including the Georgia Public Service
Commission (the GPSC).
RESULTS OF OPERATIONS
POWER MARKETER ARRANGEMENTS
Oglethorpe is utilizing long-term power marketer arrangements to reduce the
cost of power to the Members. Oglethorpe entered into two power marketer
agreements with LG&E Energy Marketing Inc. (LEM) effective January 1, 1997, for
approximately 50% of the load requirements 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 Members' then
forecasted load requirements. The LEM agreements are based on the actual
requirements of the 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. Through December 31, 1999,
substantially all of Oglethorpe's generating facilities and power purchase
arrangements were 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, as described below, from LEM and Morgan Stanely for the use
of the resources.
One of the two power marketer agreements with LEM, relating to two of the
39 Members, expired on December 31, 1999. The remaining agreement with LEM
continues to cover approximately 50% of the load requirements of 37 Members.
Most of Oglethorpe's generating facilities and power purchase arrangements
continue to be available for use by LEM and Morgan Stanley under the terms of
the respective agreements.
In October 1998, LEM submitted a dispute to arbitration seeking to
terminate the contract relating to 37 of the Members. On December 21, 1999, the
arbitration panel ruled that the agreement is valid and must continue to be
honored. Oglethorpe and LEM, however, are addressing a number of issues relating
to administration of the agreement.
CORPORATE RESTRUCTURING
As a result of the Corporate Restructuring, the Statements of Revenues and
Expenses for 1999 and 1998 reflect Oglethorpe's operations solely as a power
supply company, whereas the Statements of Revenues and Expenses for 1997 reflect
operations as a combined power supply, transmission and system operations
company through March 31, 1997, and operations solely as
31
a power supply company thereafter. Although the Corporate Restructuring was
completed on March 11, 1997, pursuant to the restructuring agreement among
Oglethorpe, GTC and GSOC, all transmission-related and systems
operations-related revenues were assigned to Oglethorpe, and all
transmission-related and systems operations-related costs were paid or
reimbursed by Oglethorpe during the period March 11, 1997 through March 31,
1997.
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 2.4% for 1999 compared to 1998 and increased by 9.6% for 1998
compared to 1997. Kilowatt-hours (kWh) sales to Members were 6.2% higher in 1999
compared to 1998 and 12.8% higher in 1998 compared to 1997. The average revenue
per kWh from sales to Members decreased 3.6% for 1999 compared to 1998 and
decreased 2.7% for 1998 compared to 1997. The components of Member revenues were
as follows:
- --------------------------------------------------------
1999 1998 1997
(dollars in thousands)
- --------------------------------------------------------
Capacity revenues $ 613,974 $ 623,464 $ 652,910
Energy revenues . 508,362 472,440 347,409
---------- ---------- ----------
Total ........... $1,122,336 $1,095,904 $1,000,319
========== ========== ==========
- --------------------------------------------------------
The decrease in capacity revenues from Members from 1997 to 1998 was
primarily due to revenues of the transmission and system operations businesses
previously reflected in Oglethorpe in the first quarter of 1997 prior to the
Corporate Restructuring. For 1999, Member capacity revenues were reduced by $7
million as a result of an interim budget adjustment to reflect lower than
expected decommissioning expense and higher than anticipated investment income.
The increases in Member energy revenues over the past three years reflect
both higher prices for energy purchased by Oglethorpe in the marketplace and
greater volumes of energy sold to Members. Oglethorpe passes through actual
energy costs to the Members such that energy revenues equal energy costs. Energy
revenues from Members increased by 7.6% from 1998 to 1999 and by 36.0% from 1997
to 1998.
The following table summarizes the amounts of kWh sold to Members and total
revenues per kWh during each of the past three years:
- -------------------------------------------
KILOWATT-HOURS CENTS PER
KILOWATT-HOUR
(in thousands)
- -------------------------------------------
1999 24,755,812 4.53
1998 23,315,950 4.70
1997 20,664,786 4.83(1)
- -------------------------------------------
(1) EXCLUDES REVENUES RELATED TO THE TRANSMISSION AND SYSTEM OPERATIONS
BUSINESSES EFFECTIVE APRIL 1, 1997.
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 to offset lower delivery
of hydroelectric power from Southeastern Power Administration due to lower than
normal rainfall. In 1998, a hot summer combined with growth in the Member
systems' service territories resulted in a 12.8% increase in kWh sales to
Members.
The energy portion of Member revenues per kWh increased 1.4% in 1999
compared to 1998 and 20.5% in 1998 compared to 1997. The increases in the cost
of energy supplied to the Members resulted primarily from higher purchased power
costs as discussed under "Operating Expenses" below.
SALES TO NON-MEMBERS. Sales of electric services to non-Members were primarily
from energy sales to other utilities and power marketers, and pursuant to
contractual arrangements with Georgia Power Company (GPC). The following table
summarizes the amounts of non-Member revenues from these sources for the past
three years:
- ------------------------------------------------------------
1999 1998 1997
(dollars in thousands)
- ------------------------------------------------------------
Sales to other utilities ..... $46,186 $28,890 $18,342
Sales to power marketers ..... 7,710 19,373 14,623
GPC--power supply arrangements -- -- 12,360
ITS transmission agreements .. -- -- 2,208
------- ------- -------
Total ........................ $53,896 $48,263 $47,533
======= ======= =======
- ------------------------------------------------------------
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
32
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 other utilities were higher in 1998 compared to 1997 due to three
factors: (1) capacity revenues received from Alabama Electric Cooperative from
June 1998 through December 1998; (2) revenues received from GPC for energy
imbalance under terms of the Coordination Services Agreement; and (3) higher
energy prices experienced in the wholesale electricity markets during the summer
months of 1998.
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.
The third source of non-Member revenues was power supply arrangements with
GPC. These revenues were derived, for the most part, from energy sales arising
from dispatch situations whereby GPC caused co-owned coal-fired generating
resources to be operated when Oglethorpe's system did not require all of its
contractual entitlement to the generation. These revenues compensated Oglethorpe
for its costs because, under the operating agreements, Oglethorpe was
responsible for its share of fuel costs any time a unit operated. Pursuant to
amendments to the Plant Wansley ownership and operating agreements, Oglethorpe
elected to separately dispatch its ownership interest in Plant Wansley beginning
May 1, 1997. Thereafter, Plant Wansley ceased to be a source of this type of
sales transaction; therefore, this type of sale to GPC has ended.
The fourth source of non-Member revenues was primarily payments from GPC
for use of the Integrated Transmission System (ITS) and related transmission
interfaces. GPC compensated Oglethorpe to the extent that Oglethorpe's
percentage of investment in the Integrated Transmission System exceeded its
percentage use of the system. In such case, Oglethorpe was entitled to
compensation for the use of its investment by the other Integrated Transmission
System participants. As a result of the Corporate Restructuring, all of the
revenues in this category have accrued to GTC since April 1, 1997.
OPERATING EXPENSES
Oglethorpe's operating expenses increased 4.7% in 1999 compared to 1998 and
increased 14.4% in 1998 compared to 1997. The higher operating expenses in 1999
were primarily attributable to increases in production expenses and purchased
power costs. The increase in operating expenses from 1997 to 1998 resulted
primarily from higher purchased power costs, but were also affected by changes
in fuel and production expenses.
The increase in production expenses in 1999 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 GPC workforce reduction at Plants Vogtle and Hatch; and (3) expenses
incurred for the LEM arbitration and other special projects totaling $4.9
million. Production expenses were higher in 1998 than in 1997 partly as a result
of unscheduled maintenance outages at Plant Scherer Unit No. 1 and Plant Vogtle
Unit No. 2 and partly due to higher amortization of deferred nuclear refueling
outage costs.
Total fuel costs increased 2.5% in 1999 compared to 1998 primarily as a
result of a 2.4% increase in generation. The decrease in total fuel costs in
1998 compared to 1997 resulted partly from the difference in the mix of
generation, with a higher percentage of the generation from nuclear and less
fossil than in 1997. The higher nuclear generation was achieved as a result of
having two refueling outages in 1998 compared to three in 1997. In addition, the
average fossil fuel cost per megawatt-hour (MWh) for 1998 decreased by 8.4%
compared to 1997 primarily due to lower coal prices.
Purchased power costs increased 3.6% in 1999 compared to 1998 and increased
45.3% in 1998 compared to 1997 as result of higher purchased power energy costs,
as follows:
- -----------------------------------------------
1999 1998 1997
(dollars in thousands)
- -----------------------------------------------
Capacity costs $ 97,616 $115,599 $134,384
Energy costs . 304,103 272,063 132,491
-------- -------- --------
Total ........ $401,719 $387,662 $266,875
======== ======== ========
- -----------------------------------------------
33
Purchased power capacity costs were 15.6% lower in 1999 compared to 1998
and 14.0% lower in 1998 compared to 1997 primarily due to the elimination on
September 1 of 1998 and 1997 of a 250 MW component block (coal-fired units) of
power under a power purchase agreement between Oglethorpe and GPC.
Purchased power energy costs increased by 11.8% in 1999 compared to 1998,
and by 105.3% in 1998 compared to 1997. The average cost of purchased power
energy per MWh increased 11.1% in 1999 compared to 1998 and increased 53.3% in
1998 compared to 1997. The increase in average cost in 1999 compared to 1998
resulted from slightly higher energy prices. The increase in average cost in
1998 compared to 1997 resulted primarily from significant increases in spot
market prices of energy in the summer of 1998. Due to prolonged hot weather,
Oglethorpe was forced to purchase energy in the spot market in the summer of
1998 to meet the Members' needs.
The volumes of purchased power decreased by 6.7% in 1999 compared to 1998,
and increased by 34.0% in 1998 compared to 1997. The higher volumes of purchased
power in 1998 were utilized to serve Member load that was not contractually
provided by the power marketers, which resulted in a significant increase in the
average kWh cost of energy to the Members.
Purchased power expenses for the years 1997 through 1999 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 1997 through 1999, 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 $133 million in 1999, $173 million in 1998 and $176 million in
1997. For a discussion of the power purchase agreements, see Note 9 of Notes to
Financial Statements.
The increase in depreciation and amortization for 1999 compared to 1998
resulted from the amortization of project costs for the Vogtle radioactive waste
facility. See Note 1 of Notes to Financial Statements.
For 1997, other operating expenses reflected expenses for the power
delivery portion of the business (which was subsequently transferred to GTC in
connection with the Corporate Restructuring) for the period prior to April 1,
1997.
OTHER INCOME (EXPENSE)
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 income from Oglethorpe's
membership in GTC. In 1997, the caption "Other" reflected a margin of
approximately $1.2 million related to Oglethorpe's marketing services business
which was subsequently transferred to a third party.
INTEREST CHARGES
Net interest charges decreased for 1998 compared to 1997 due to the debt
assumed by GTC in connection with the Corporate Restructuring. The increase in
amortization of debt discount and expense for 1999 compared to 1998 and for 1998
compared to 1997 was primarily due to the accelerated amortization of $7 million
and $24 million in premiums paid to the Federal Financing Bank (FFB) for
refinancing $89 million and $424 million of debt in 1999 and 1998, respectively.
These costs are being amortized over a period of approximately 3 years and 3 1/2
years beginning in 1999 and 1998, respectively. See "Financial
Condition--REFINANCING TRANSACTIONS" for further discussion.
NET MARGIN AND COMPREHENSIVE MARGIN
Oglethorpe's net margin for 1999, 1998 and 1997 were $19.9 million, $21.1
million and $22.4 million, respectively. Oglethorpe's margin requirement is
based on a ratio applied to interest charges. Accordingly, the reduction in
interest charges resulting from interest costs savings from refinancing
transactions and the transfer of debt to GTC related to the Corporate
Restructuring 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 1999 were due
to property additions, an increase in the amount of commercial paper outstanding
and an increase in patronage capital.
34
Property additions, including nuclear fuel purchases, totaled $50 million,
and were funded entirely with funds from operations.
The $89 million of commercial paper outstanding at year-end was issued to
fund, on an interim basis, construction of a combustion turbine project as more
fully discussed below.
Oglethorpe achieved a net margin of $19.9 million in 1999; however,
Oglethorpe's equity (patronage capital) increased by only $17.3 million due to a
net change in unrealized loss 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 2000 through 2002. 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 to construct,
rather than purchase, additional capacity.
- ------------------------------------------------------------
CAPITAL EXPENDITURES
(DOLLARS IN THOUSANDS)
- ------------------------------------------------------------
YEAR GENERATING NUCLEAR GENERAL
PLANT(1) FUEL PLANT AFUDC(2) TOTAL
2000 $ 20,016 $ 46,323 $ 9,129 $ 1,959 $ 77,427
2001 26,237 48,612 3,596 1,654 80,099
2002 52,770 47,216 3,596 2,217 105,799
-------- -------- -------- -------- --------
Total $ 99,023 $142,151 $ 16,321 $ 5,830 $263,325
======== ======== ======== ======== ========
- ------------------------------------------------------------
(1) Consists of capital expenditures required for replacements and additions to
facilities in service and compliance with environmental regulations.
(2) Allowance for funds used during construction of generation and general
plant facilities.
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $3.3 billion as of December 31, 1999. Expenditures for property
additions during 1999 amounted to $50 million and were funded entirely from
operations. These expenditures were primarily for additions and replacements to
generation facilities and for purchases of nuclear fuel.
In addition to the funds needed for capital expenditures, approximately
$364 million will be required over the next three years (2000-2002) for current
sinking fund requirements and maturities of long-term debt. Of this amount, $276
million, or 76%, 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.
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 pollution control bonds (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, new generation, 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 2002
primarily with funds generated from operations and, if necessary, with
short-term borrowings.
The interest rate swap arrangements relating to two PCB transactions and
the Rocky Mountain lease transactions contain certain minimum liquidity
requirements. As of December 31, 1999, Oglethorpe was required to maintain
minimum liquidity of $79 million under these agreements, and its available
liquidity exceeded that amount. See Note 2 of Notes to Financial Statements for
further discussion of these transactions.
To meet short-term cash needs and liquidity requirements, Oglethorpe had,
as of December 31, 1999, (i) approximately $223 million in cash and temporary
cash investments, (ii) $75 million in other short-term investments and (iii) up
to $222 million available under the following credit facilities:
- ----------------------------------------------------
AUTHORIZED AVAILABLE
SHORT-TERM CREDIT FACILITIES AMOUNT AMOUNT
(DOLLARS IN THOUSANDS)
- ----------------------------------------------------
Committed line of credit:
Commercial paper ......... $260,000 $172,000
Uncommitted line of credit:
National Rural Utilities
Cooperative Finance
Corporation (CFC) ....... 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.
As of December 31, 1999, $88 million of commercial paper was outstanding.
This commercial paper was issued to fund, on an interim basis, construction of a
492 MW combustion turbine facility, Sewell Creek Energy Facility (Sewell Creek),
expected to be completed by June 2000. This facility is owned by Smarr EMC, a
cooperative owned by 37 of Oglethorpe's 39 Members. Oglethorpe expects that by
June 2000, Smarr EMC will secure, on a non-recourse basis to Oglethorpe,
permanent financing for Sewell Creek and repay Oglethorpe for the interim
financing. The maximum amount of commercial paper that is expected to be
outstanding in 2000 in conjunction with this interim financing is $186 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 $89 million under this program, including $20 million
of PCB principal which matured on January 1, 2000. Oglethorpe also has Board
approval to refinance Burke and Monroe principal maturing on January 1, 2001 and
January 1, 2002.
In connection with the Corporate Restructuring GTC assumed certain
indebtedness of Oglethorpe, including a portion of the indebtedness associated
with PCBs. Under the terms of an indemnity agreement executed in connection with
this assumption of PCB indebtedness, GTC is entitled to participate in any
refinancing of this PCB debt by Oglethorpe by agreeing to assume a portion of
the refinancing debt.
In 1997 and 1998, GTC participated in the issuance of bonds (the 98/99
Refinancing Bonds) to refinance the Burke and Monroe principal payments due
January 1, 1998 and January 1, 1999. However, in 1999, GTC agreed with
Oglethorpe not to participate in the refinancing of the principal payments due
January 1, 2000 and the refinancing of the 98/99 Refinancing Bonds. Pursuant to
this agreement, Oglethorpe provided a discount of approximately $2.6 million on
the $8.6 million of principal payments due from GTC in connection with such
refinancings. GTC has also agreed, on similar terms, not to participate in the
planned refinancings of the principal payments due January 1, 2001 and January
1, 2002.
In 1999, Oglethorpe refinanced $89 million of FFB debt with long-term fixed
rates and paid a $7 million premium in connection with the refinancing. The
premium is being amortized on an accelerated basis over three and one-half
years.
On December 30, 1999, Oglethorpe received $14 million in cash as a result
of a sale-leaseback transaction on 297 rail cars.
The average interest rate on long-term debt decreased from 6.15% at
December 31, 1998 to 6.10% at December 31, 1999.
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:
- the Energy Policy Act of 1992;
- recently adopted and proposed policies from the Federal Energy
Regulatory Commission (FERC) regarding mergers, transmission access
and pricing and regional transmission organizations;
- federal and state deregulation initiatives;
- increased consolidation and mergers of electric utilities;
- the proliferation of power marketers and independent power producers;
- generation surpluses;
- deficits and transmission constraints in certain regional markets;
- generation technology;
- and 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 considering legislation to implement retail
competition. Proposed federal legislation could mandate or encourage retail
competition in every state and otherwise deregulate the industry. No legislation
36
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. In 1997, after a series of workshops, the GPSC issued a report
identifying electric industry restructuring issues, potential resolutions and
the views of the parties who participated in the workshops. As a result of
the GPSC's order in the 1998 GPC rate case, the GPSC has 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 are
voluntarily providing information and 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 demand 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 obtain the value that can be brought by power marketers
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 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:
- additional power marketing arrangements or other alliance
arrangements;
- whether potential load fluctuation risks in a competitive retail
environment can be shifted to other wholesale suppliers;
- whether power supply requirements will continue to be met by the
current mix of ownership and purchase arrangements;
- whether power supply resources will be owned by Oglethorpe or by other
entities;
- whether disposition of existing assets or asset classes would be
advisable;
- the effects of nuclear license extensions;
- the effects of proliferation of services offered by electric
utilities;
- and 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.
Many Members are now 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
37
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.
Recent announcements relating to sales of nuclear generation units and
applications for nuclear license extensions are of interest to Oglethorpe
because of its substantial investment in nuclear generation. As a consequence of
these and other developments in the industry, in 1999 RUS and Oglethorpe began
conceptual discussions regarding nuclear generation units and related
indebtedness. Oglethorpe is currently evaluating the feasibility of this concept
and may continue further discussions with RUS on this matter.
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 options with
RUS, may present opportunities for Oglethorpe to reduce costs, reduce risks and
otherwise to respond more effectively to increasing competition. However,
Oglethorpe cannot predict at this time the results of these matters or any
action Oglethorpe might take based thereon.
Oglethorpe has deferred recognition of certain costs of providing services
to the Members and certain income items pursuant to Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation." Note 1 of Notes to Financial Statements sets forth the
regulatory assets and liabilities reflected on Oglethorpe's balance sheet as of
December 31, 1999. Regulatory assets represent certain costs that are assured to
be recoverable by Oglethorpe from the Members in the future through the
ratemaking process. Regulatory liabilities represent certain items of income
that are being retained by Oglethorpe and that will be applied in the future to
reduce Member revenue requirements. (See "General--Rates and Regulation.") In
the event that competitive or other factors result in cost recovery practices
under which Oglethorpe can no longer apply the provisions of SFAS No. 71,
Oglethorpe would be required to eliminate all regulatory assets and liabilities
that could not otherwise be recognized as assets and liabilities by businesses
in general. In addition, Oglethorpe would be required to determine any
impairment to other assets, including the plant, and write-down of those assets,
if impaired, to their fair value.
DECOMMISSIONING COSTS
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry regarding
the recognition, measurement and classification of decommissioning costs for
nuclear generating facilities in financial statements of electric utilities. In
response to these questions, the Financial Accounting Standards Board has issued
an Exposure Draft of a proposed Statement on "Accounting for Certain Liabilities
Related to Closure or Removal of Long-Lived Assets." The proposed Statement
would require the recognition of the entire obligation for decommissioning at
its present value as a liability in the financial statements. Rate-regulated
utilities would also recognize an offsetting asset for differences in the timing
of recognition of the costs of decommissioning for financial reporting and
ratemaking purposes. Oglethorpe's management does not believe that this proposed
Statement would have an adverse effect on results of operations due to its
current and future ability to recover decommissioning costs through rates.
Assuming extensions of the respective licenses are not obtained, beginning
in years 2014 through 2029, it is expected that Plant Hatch and Plant Vogtle
units will begin the decommissioning process. The expected timing of payments
for decommissioning costs will extend for a period of 9 to 14 years.
Oglethorpe's management does not expect such payments to have an adverse impact
on liquidity or capital resources due to available amounts that have been placed
in reserves for this purpose.
NEW ACCOUNTING PRONOUNCEMENT
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The standard
requires that all derivative instruments be recognized as assets or liabilities
and be measured at fair value. Oglethorpe is required to adopt SFAS No. 133 by
January 1, 2001. Oglethorpe is currently assessing the impact that adoption of
SFAS No. 133 will have on results of operations and financial condition and is
undecided as to the date the standard will be adopted.
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.
38
YEAR 2000
OGLETHORPE'S YEAR 2000 PROJECT. The Year 2000 issue, which is common to most
corporations, concerns the ability of certain hardware, software, databases and
other devices that use microprocessors to properly recognize date-sensitive
information related to the Year 2000 and thereafter. Oglethorpe is heavily
dependent upon complex computer systems for all phases of power supply
operations. Oglethorpe's operations include both information technology (IT)
systems, such as billing systems, financial accounting systems, and human
resource/payroll systems, as well as non-IT systems that may have embedded
microprocessors, such as those relating to operations of the Rocky Mountain
Pumped Storage Hydroelectric Facility (Rocky Mountain), generation substations
and Oglethorpe's headquarters facilities.
The statewide electrical system serving Georgia's electric cooperatives
experienced no outages related to the Year 2000 issue at midnight on December
31, 1999. Since then, no problems have been reported concerning any of
Oglethorpe's internal systems or any third-party systems related to Oglethorpe's
systems.
RELATIONSHIPS WITH THIRD PARTIES. As of December 31, 1999, all of the
Members met the GPSC's schedule for Year 2000 readiness. None of the Members
have reported any problems related to the Year 2000 issue.
All of Oglethorpe's co-owned generating plants, except Rocky Mountain, are
operated by GPC on behalf of itself as a co-owner and as agent for the other
co-owners. GPC's parent company, The Southern Company (Southern) performed all
Year 2000 remediation and testing on all generation plants that are operated by
GPC. Oglethorpe is not aware of any problems at these plants related to the Year
2000 issue. Oglethorpe estimates that approximately $4.7 million will be billed
by Southern based on its ownership share of the co-owned generation plants, of
which approximately $4.5 million has been paid. Remaining costs will be expensed
in 2000. Southern 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 Securities and Exchange Commission. No third
parties have reported to Oglethorpe any problems related to the Year 2000 issue.
Oglethorpe may not, however, be aware of all third parties' Year 2000 problems.
PROJECT COSTS. In addition to the $4.7 million expected to be paid to Southern,
Oglethorpe incurred project costs of approximately $5.3 million. Oglethorpe
incurred these costs to upgrade its internal systems, including those relating
to Rocky Mountain, and to upgrade or replace its externally developed financial
accounting, procurement and materials management systems. These costs also were
incurred to perform a management evaluation of the Year 2000 project,
contingency planning and preparedness evaluation of key business relationships.
Oglethorpe's policy is to expense as incurred the maintenance and
modification costs of existing software, including those associated with the
Year 2000 project, and to capitalize and amortize over its useful life the cost
of new software. Oglethorpe plans to pay for remaining Year 2000 costs with
general corporate funds. Year 2000 costs are being recovered from the Members
through Oglethorpe's rates.
Actual results, costs and risks related to Year 2000 issues may materially
differ from those that Oglethorpe expects or estimates. Factors that might cause
material differences include, but are not limited to, undetected Year 2000
problems with Oglethorpe's internal systems, unreported Year 2000 problems of
third parties, and Oglethorpe's ability to develop adequate contingency plans to
respond to unforeseen Year 2000 problems.
FORWARD-LOOKING STATEMENTS AND ASSOCIATED RISKS
This Annual Report on Form 10-K contains forward-looking statements,
including statements regarding, among other items, (i) anticipated trends in
Oglethorpe's business, (ii) Oglethorpe's future power supply resources and
arrangements, (iii) disclosures regarding market risk included in Item 7A, and
(iv) other management issues such as the Year 2000 issue. 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" and "YEAR 2000" herein and "CERTAIN FACTORS AFFECTING THE
ELECTRIC UTILITY INDUSTRY" in Item 1. In light of these risks and uncertainties,
Oglethorpe can give no assurance that events anticipated by the forward-looking
statements contained in this Annual Report will in fact transpire.
39
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Oglethorpe is exposed to market risk, including changes in interest rates,
in the value of equity securities, and in the market price of electricity.
Oglethorpe's use of derivative financial or commodity instruments is for the
purpose of mitigating business risks and is not for trading purposes.
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.
Oglethorpe currently has 13% of its debt in a variable rate mode.
The table below details Oglethorpe's debt instruments and provides the fair
value at December 31, 1999, the outstanding balance at the beginning and end of
each year and the annual principal maturities and associated average interest
rates.
(DOLLARS IN THOUSANDS)
FAIR VALUE COST
---------- ---------------------------------------------------------------------------------------
1999 2000 2001 2002 2003 2004 THEREAFTER
---- ---- ---- ---- ---- ---- ----------
FIXED RATE DEBT
- ---------------
Beginning of year ........ $ 2,531,049 $ 2,419,304 $ 2,321,480 $ 2,219,009 $ 2,059,639 $ 1,939,716
Maturities ............... (111,745) (97,824) (102,471) (159,370) (119,923)
----------- ----------- ----------- ----------- -----------
End of year .............. $ 2,457,761 $ 2,419,304 $ 2,321,480 $ 2,219,009 $ 2,059,639 $ 1,939,716
=========== =========== =========== =========== ===========
Average interest rate .... 6.04% 6.06% 6.07% 6.18% 6.08% 6.46%
VARIABLE RATE DEBT
- ------------------
Beginning of year ........ $ 428,590 $ 424,136 $ 419,594 $ 415,013 $ 364,320 $ 359,647
Maturities ............... (4,454) (4,542) (4,581) (50,693) (4,673)
----------- ----------- ----------- ----------- -----------
End of year .............. $ 405,336 $ 424,136 $ 419,594 $ 415,013 $ 364,320 $ 359,647
=========== =========== =========== =========== ===========
Average interest rate(1).. 5.08% 5.49% 5.79% 7.18% 5.86% 4.91%
INTEREST RATE SWAPS(2)
- ----------------------
Beginning of year ........ $ 264,984 $ 260,149 $ 256,001 $ 251,420 $ 246,536 $ 241,315
Maturities ............... (4,835) (4,148) (4,581) (4,884) (5,221)
----------- ----------- ----------- ----------- -----------
End of year .............. $ 264,984 $ 260,149 $ 256,001 $ 251,420 $ 246,536 $ 241,315
=========== =========== =========== =========== ===========
Average interest rate ... 5.82% 5.82% 5.83% 5.83% 5.83% 5.80%
Unrealized loss on swaps.. $ (18,935)
(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.
INTEREST RATE SWAP TRANSACTIONS
To refinance high-interest rate PCBs, Oglethorpe entered into two interest
rate swap transactions with a swap counterparty, AIG Financial Products Corp.
("AIG-FP"), which were designed to create a contractual fixed rate of interest
on $322 million of variable rate PCBs. These transactions were entered into in
early 1993 on a forward basis, pursuant to which approximately $200 million of
variable rate PCBs were issued on November 30, 1993 and approximately $122
million of variable rate PCBs were issued on
40
December 1, 1994. Oglethorpe is obligated to pay the variable interest rate that
accrues on these PCBs; however, the swap arrangements provide a mechanism for
Oglethorpe to achieve a contractual fixed rate which is lower than Oglethorpe
would have obtained had it issued fixed rate bonds. Oglethorpe's use of interest
rate derivatives is currently limited to these two swap transactions.
In connection with GTC's assumption of liability on a portion of the PCBs
pursuant to the Corporate Restructuring, commencing April 1, 1997, GTC assumed
and agreed to pay 16.86% of any amounts due from Oglethorpe under these swap
arrangements, including the net swap payments and termination payments described
below. Should GTC fail to make such payments under the assumption, Oglethorpe
remains obligated for the full amount of such payments.
Under the swap arrangements, Oglethorpe is obligated to make periodic
payments to AIG-FP based on a notional principal amount equal to the aggregate
principal amount of the bonds outstanding during the period and a contractual
fixed rate ("Fixed Rate"), and AIG-FP is obligated to make periodic payments to
Oglethorpe based on a notional principal amount equal to the aggregate principal
amount of the bonds outstanding during the period and a variable rate equal to
the variable rate of interest accruing on the bonds during the period ("Variable
Rate"). These payment obligations are netted, such that if the Variable Rate is
less than the Fixed Rate, Oglethorpe makes a net payment to AIG-FP. Likewise, if
the Variable Rate is higher than the Fixed Rate, Oglethorpe receives a net
payment from AIG-FP. Thus, although changes in the Variable Rate affect whether
Oglethorpe is obligated to make payments to AIG-FP or is entitled to receive
payments from AIG-FP, the effective interest rate Oglethorpe pays with respect
to the PCBs is not affected by changes in interest rates. The Fixed Rate for the
$200 million of variable rate bonds issued in 1993 is 5.67% and the Fixed Rate
for the $122 million of variable rate bonds issued in 1994 is 6.01%. At December
31, 1999, the bonds issued in 1993 carried a variable rate of interest of 5.40%
and the bonds issued in 1994 carried a variable rate of interest of 5.65%. For
the three years ended December 31, 1997, 1998 and 1999, Oglethorpe has made in
connection with both interest rate swap arrangements combined net swap payments
to AIG-FP (net of amounts assumed by GTC) of $6.4 million, $6.3 million, and
$6.7 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, 1999 would have
been approximately $19 million.
SCHERER UNIT NO. 2 CAPITAL LEASE
In December 1985, Oglethorpe sold and subsequently leased back from four
purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The
capital leases provide that Oglethorpe's rental payments vary to the extent of
interest rate changes associated with the debt used by the lessors to finance
their purchase of undivided ownership shares in the unit. The debt currently
consists of $224,702,000 in serial facility bonds due June 30, 2011 with a 6.97%
fixed rate of interest.
EQUITY PRICE RISK
Oglethorpe maintains trust funds, as required by the NRC, to fund certain
costs of nuclear decommissioning. (See Note 1(g) of Notes to Financial
Statements in Item 8.) As of December 31, 1999, these funds were invested
primarily in domestic equity securities, U.S. Government and corporate debt
41
securities and asset-backed securities. By maintaining a portfolio that includes
long-term equity investments, Oglethorpe intends to maximize the returns to be
utilized to fund nuclear decommissioning, which in the long-term will better
correlate to inflationary increases in decommissioning costs. However, the
equity securities included in Oglethorpe's portfolio are exposed to price
fluctuation in equity markets. A 10% decline in the value of the fund's equity
securities as of December 31, 1999 would result in a loss of value to the fund
of approximately $8 million. Oglethorpe actively monitors its portfolio by
benchmarking the performance of its investments against certain indexes and by
maintaining, and periodically reviewing, established target allocation
percentages of the assets in its trusts to various investment options. Because
realized and unrealized gains and losses from investment securities held in the
decommissioning fund are directly added to or deducted from the decommissioning
reserve, fluctuations in equity prices or interest rates do not affect
Oglethorpe's net margin in the short-term.
COMMODITY PRICE RISK
The market price of electricity is subject to price volatility associated
with changes in supply and demand in electricity markets. Oglethorpe's exposure
to electricity price risk relates to managing the supply of energy to the
Members. To secure a firm supply of electricity and to limit price volatility
associated with electricity purchases, Oglethorpe has taken several actions.
Oglethorpe supplies substantially all of the Members' requirements from a
combination of owned and leased generating plants and power purchased under
long-term contracts with other power suppliers and power marketers. Therefore,
only a small percentage of Oglethorpe's requirements is purchased in the
short-term market, and further only a small portion of these requirements is
covered by derivative commodity instruments. Oglethorpe's market price risk
exposure on these instruments is not material. (See "OGLETHORPE POWER
CORPORATION--Electric Rates" and "MEMBER REQUIREMENTS AND POWER SUPPLY
RESOURCES" in Item 1.)
Oglethorpe is reviewing its risk management practices pertaining to its
power marketing and trading activities, and plans to implement a new
comprehensive risk management policy in 2000. The policy also covers
operational, market and credit risks arising from such transactions.
CHANGES IN RISK EXPOSURE
Oglethorpe's exposure to changes in interest rates, the price of equity
securities it holds, and electricity prices have not changed materially from the
previous reporting period. Oglethorpe is not aware of any facts or circumstances
that would significantly impact such exposure in the near future.
42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Statements of Revenues and Expenses,
For the Years Ended December 31, 1999, 1998 and 1997.......................................... 45
Statements of Patronage Capital,
For the Years Ended December 31, 1999, 1998 and 1997.......................................... 45
Balance Sheets, As of December 31, 1999 and 1998................................................. 46
Statements of Capitalization, As of December 31, 1999 and 1998................................... 48
Statements of Cash Flows,
For the Years Ended December 31, 1999, 1998 and 1997 ......................................... 49
Notes to Financial Statements.................................................................... 50
Report of Management............................................................................. 63
Report of Independent Accountants................................................................ 63
43
[THIS PAGE INTENTIONALLY LEFT BLANK]
44
STATEMENTS OF REVENUES AND EXPENSES
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
- --------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998 1997
Operating revenues (Note 1):
Sales to Members .................................................. $ 1,122,336 $ 1,095,904 $ 1,000,319
Sales to non-Members .............................................. 53,896 48,263 47,533
----------- ----------- -----------
Total operating revenues ............................................ 1,176,232 1,144,167 1,047,852
----------- ----------- -----------
Operating expenses:
Fuel .............................................................. 196,182 191,399 206,315
Production ........................................................ 215,517 198,378 181,923
Purchased power (Note 9) .......................................... 401,719 387,662 266,875
Depreciation and amortization ..................................... 130,883 124,074 126,730
Income taxes (Note 3) ............................................. -- -- --
Other operating expenses .......................................... -- -- 6,334
----------- ----------- -----------
Total operating expenses ............................................ 944,301 901,513 788,177
----------- ----------- -----------
Operating margin .................................................... 231,931 242,654 259,675
----------- ----------- -----------
Other income (expense):
Investment income ................................................. 33,262 27,767 29,303
Amortization of deferred gains (Notes 1 and 4) .................... 2,475 2,486 2,441
Amortization of net benefit of sale of income
tax benefits (Note 1) ........................................... 11,195 11,195 11,195
Allowance for equity funds used during
construction (Note 1) ........................................... 180 158 157
Other ............................................................. 3,433 687 3,550
----------- ----------- -----------
Total other income .................................................. 50,545 42,293 46,646
----------- ----------- -----------
Interest charges:
Interest on long-term debt and capital leases ..................... 224,489 236,692 261,290
Other interest .................................................... 18,531 12,086 13,845
Allowance for debt funds used during construction (Note 1) ........ (1,570) (1,679) (1,674)
Amortization of debt discount and expense ......................... 21,088 16,768 10,455
----------- ----------- -----------
Net interest charges ................................................ 262,538 263,867 283,916
----------- ----------- -----------
Net margin .......................................................... 19,938 21,080 22,405
Net change in unrealized gain (loss) on available-for-sale
securities......................................................... (2,614) 1,112 738
----------- ----------- -----------
Comprehensive margin ................................................ $ 17,324 $ 22,192 $ 23,143
=========== =========== ===========
STATEMENTS OF PATRONAGE CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
- --------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998 1997
Patronage capital and membership fees -
beginning of year (Note 1) .................... $ 352,701 $ 330,509 $ 356,229
Comprehensive margin ............................ 17,324 22,192 23,143
Special patronage capital distribution
(Note 11)...................................... -- -- (48,863)
--------- --------- ---------
Patronage capital and membership fees-end of
year........................................... $ 370,025 $ 352,701 $ 330,509
========= ========= =========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
45
BALANCE SHEETS
DECEMBER 31, 1999 AND 1998
- --------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998
Assets
Electric plant (Notes 1, 4 and 6):
In service ................................................ $ 4,854,037 $ 4,856,174
Less: Accumulated provision for depreciation .............. (1,625,933) (1,510,888)
----------- -----------
3,228,104 3,345,286
Nuclear fuel, at amortized cost ........................... 84,565 84,418
Construction work in progress ............................. 18,299 20,948
----------- -----------
3,330,968 3,450,652
----------- -----------
Investments and funds (Notes 1 and 2):
Decommissioning fund, at market ........................... 135,703 122,094
Deposit on Rocky Mountain transactions, at cost ........... 59,579 55,755
Bond, reserve and construction funds, at market ........... 31,158 32,909
Investment in associated companies, at cost ............... 17,919 16,231
Other, at cost ............................................ 2,535 3,326
----------- -----------
246,894 230,315
----------- -----------
Current assets:
Cash and temporary cash investments, at cost (Note 1) ..... 222,814 106,235
Other short-term investments, at market ................... 75,482 73,356
Receivables ............................................... 109,705 110,919
Inventories, at average cost (Note 1) ..................... 89,766 76,783
Notes receivable (Note 5) ................................. 94,070 45,151
Prepayments and other current assets ...................... 19,293 21,395
----------- -----------
611,130 433,839
----------- -----------
Deferred charges:
Premium and loss on reacquired debt,
being amortized (Note 5)................................. 196,289 206,729
Deferred amortization of Scherer leasehold (Note 4) ....... 101,404 99,297
Discontinued projects, being amortized (Note 1) ........... 28,020 36,203
Deferred debt expense, being amortized .................... 17,070 15,825
Other (Note 1) ............................................ 32,847 33,405
----------- -----------
375,630 391,459
----------- -----------
$ 4,564,622 $ 4,506,265
=========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
46
- --------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998
Equity and Liabilities
Capitalization (see accompanying statements):
Patronage capital and membership fees (Note 1) .................... $ 370,025 $ 352,701
Long-term debt .................................................... 3,103,590 3,177,883
Obligation under capital leases (Note 4) .......................... 275,224 282,299
Obligation under Rocky Mountain transactions (Note 1) ............. 59,579 55,755
---------- ----------
3,808,418 3,868,638
---------- ----------
Current liabilities:
Long-term debt and capital leases due within one year (Note) ...... 129,419 97,475
Accounts payable .................................................. 69,555 46,676
Notes payable (Note 5) ............................................ 88,479 50,986
Accrued interest .................................................. 50,201 10,074
Other current liabilities ......................................... 9,344 18,115
---------- ----------
346,998 223,326
---------- ----------
Deferred credits and other liabilities:
Gain on sale of plant, being amortized (Note 4) ................... 55,807 58,282
Net benefit of sale of income tax benefits,
being amortized (Note 1)......................................... 18,021 26,030
Net benefit of Rocky Mountain transactions,
being amortized (Note 1)......................................... 86,004 89,189
Accumulated deferred income taxes (Note 3) ........................ 63,203 63,203
Decommissioning reserve (Note 1) .................................. 164,510 156,021
Other ............................................................. 21,661 21,576
---------- ----------
409,206 414,301
---------- ----------
Commitments and Contingencies (Notes 4 and 9)
$4,564,622 $4,506,265
========== ==========
47
STATEMENTS OF CAPITALIZATION
DECEMBER 31, 1999 AND 1998
- --------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998
Long-term debt (Note 5):
Mortgage notes payable to the Federal Financing Bank (FFB) at interest rates
varying from 4.66% to 8.43% (average rate of 6.38% at December 31, 1999) due
in quarterly installments through 2023 ...................................................... $ 2,326,730 $ 2,383,468
Mortgage notes payable to the Rural Utilities Service (RUS) at an interest rate of
5% due in monthly installments through 2021 ................................................. 13,749 14,133
Mortgage notes issued in conjunction with the sale by public authorities
of pollution control revenue bonds (PCBs):
- Series 1992A
Serial bonds, 5.75% to 6.80%, due serially from 2000 through 2012 ........................ 113,745* 119,360*
- Series 1993
Serial bonds, 4.15% to 5.25%, due serially from 2000 through 2013 ........................ 34,544* 35,480*
- Series 1993A
Adjustable tender bonds, 5.40%, due 2000 through 2016 .................................... 195,015* 197,425*
- Series 1993B
Serial bonds, 4.15% to 5.05%, due serially from 2000 through 2008 ........................ 113,750* 120,445*
- Series 1994
Serial bonds, 5.85% to 7.125%, due serially from 2000 through 2015 ....................... 9,315* 9,685*
Term bonds, 7.15% due 2016 to 2021 ....................................................... 11,550* 11,550*
- Series 1994A
Adjustable tender bonds, 5.65%, due 2000 to 2019 ......................................... 122,740* 122,740*
- Series 1994B
Serial bonds, 5.85% to 6.45%, due serially from 2000 through 2005 ........................ 9,125* 10,590*
- Series 1997A
Adjustable tender bonds, 3.45% to November 1999, due 2018 ................................ -- 5,330*
- Series 1997C
Adjustable tender bonds, 3.45% to November 1999, due 2018 ................................ -- 9,305*
- Series 1998A
Adjustable tender bonds, variable rates 3.50% to 3.90%, due 2019 ......................... 116,925* 116,925*
- Series 1998B
Adjustable tender bonds, variable rates 3.50% to 3.85%, due 2019 ......................... 100,000* 100,000*
- Series 1999B
Adjustable tender bonds, daily variable rates, 5.05% on December 31, 1999, due 2020 ...... 68,705 --
Unsecured notes issued in conjunction with the sale by public authorities of pollution
control revenue bonds:
- Series 1996
Adjustable tender bonds, 3.35% to December 1999, due in 2017 ............................. -- 37,885
- Series 1998A
Adjustable tender bonds, 3.45% to November 1999, due 2019 ................................ -- 5,615*
- Series 1998C
Adjustable tender bonds, 3.45% to November 1999, due 2019 ................................ -- 10,570*
- Series 1999A
Adjustable tender bonds, daily variable rates, 5.05% on December 31, 1999, due 2020 ...... 20,070 --
CoBank, ACB notes payable:
- Headquarters mortgage note payable: fixed at 5.73% through January 21, 2000,
due in quarterly installments through January 1, 2009 .................................... 3,602 3,990
- Transmission mortgage note payable: fixed at 6.85% through January 4, 2000; due in
bi-monthly installments through November 1, 2018 ........................................ 1,797 1,822
- Transmission mortgage note payable: fixed at 6.85% through January 4, 2000; due in
bi-monthly installments through September 1, 2019 ........................................ 6,906 6,987
- Medium-term loan, variable at 6.32% to 6.73%, due at various maturities
through March 2000, due March 31, 2003 ................................................... 46,065 46,065
National Rural Utilities Cooperative Finance Corporation notes payable:
- Medium-term loan fixed at 6.575%, due March 31, 2003 ...................................... 46,065 46,065
------------ -----------
3,360,398 3,415,435
*Less: Portion (16.86%) of PCBs assumed by Georgia Transmission Corporation ................... (135,775) (147,563)
------------ -----------
Total long-term debt, net ..................................................................... 3,224,623 3,267,872
Less: Long-term debt due within one year ...................................................... (121,033) (89,989)
------------ -----------
Long-term debt, excluding amount due within one year ............................................ 3,103,590 3,177,883
Obligation under capital leases, long-term (Note 4) ............................................. 275,224 282,299
Obligation under Rocky Mountain transactions, long-term (Note 1) ................................ 59,579 55,755
Patronage capital and membership fees (Note 1) .................................................. 370,025 352,701
------------ -----------
Total capitalization ............................................................................ $ 3,808,418 $ 3,868,638
============ ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
48
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
- --------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998 1997
Cash flows from operating activities:
Net margin ............................................................ $ 19,938 $ 21,080 $ 22,405
--------- --------- ---------
Adjustments to reconcile net margin to net cash provided by
operating activities:
Depreciation and amortization ..................................... 183,987 172,410 171,573
Net benefit of Rocky Mountain transactions ........................ -- -- 21,673
Interest on decommissioning reserve ............................... 12,266 9,716 12,113
Amortization of deferred gains .................................... (2,474) (2,486) (2,441)
Amortization of net benefit of sale of income tax benefits ........ (11,195) (11,195) (11,195)
Allowance for equity funds used during construction ............... (180) (158) (157)
Deferred income taxes ............................................. -- 86 1,132
Option payment on power swap agreement ............................ -- -- (2,042)
Other ............................................................. -- (4,171) 779
Change in net current assets, excluding long-term debt due within
one year:
Receivables ....................................................... 1,214 (5,025) 7,249
Inventories ....................................................... (12,983) (11,255) 15,316
Prepayments and other current assets .............................. 2,102 (8,865) 2,025
Accounts payable .................................................. 22,879 (4,427) 8,797
Accrued interest .................................................. 40,128 (2,887) (2,850)
Accrued and withheld taxes ........................................ (188) (302) (4,423)
Other current liabilities ......................................... (8,584) 9,472 2,903
--------- --------- ---------
Total adjustments ..................................................... 226,972 140,913 220,452
--------- --------- ---------
Net cash provided by operating activities ............................... 246,910 161,993 242,857
--------- --------- ---------
Cash flows from investing activities:
Property additions .................................................... (49,516) (43,904) (63,527)
Activity in decommissioning fund - Purchases .......................... (608,471) (504,720) (435,799)
- Proceeds ........................... 591,851 490,450 419,930
Activity in bond, reserve and construction funds - Purchases .......... (23,325) -- (35,646)
- Proceeds ........... 24,053 893 57,035
Decrease (increase) in other short-term investments ................... (3,718) 24,137 (5,380)
Decrease (increase) in investment in associated organizations ......... (1,688) (291) (561)
Decrease (increase) in notes receivable ............................... 97 60 (734)
Net cash received in Corporate Restructuring (Note 11) ................ -- -- 24,540
--------- --------- ---------
Net cash used in investing activities ................................... (70,717) (33,375) (40,142)
--------- --------- ---------
Cash flows from financing activities:
Debt proceeds, net .................................................... 18,196 15,957 5,671
Debt payments ......................................................... (68,517) (86,889) (229,242)
Premium paid on refinancing of debt ................................... -- (24,041) --
Increase in notes payable (Note 5) .................................... 37,493 50,986 --
Increase in note receivable under interim financing agreement (Note 5) (49,016) (44,330) --
Special patronage capital distribution ................................ -- -- (48,863)
Other ................................................................. 2,230 2,719 151
--------- --------- ---------
Net cash used in financing activities ................................... (59,614) (85,598) (272,283)
--------- --------- ---------
Net increase (decrease) in cash and temporary cash investments .......... 116,579 43,020 (69,568)
Cash and temporary cash investments at beginning of year ................ 106,235 63,215 132,783
--------- --------- ---------
Cash and temporary cash investments at end of year ...................... $ 222,814 $ 106,235 $ 63,215
========= ========= =========
Cash paid for:
Interest (net of amounts capitalized) ................................. $ 189,056 $ 240,270 $ 277,294
Income taxes .......................................................... -- -- 830
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
49
NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBER 31, 1999, 1998 AND 1997
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
a. BUSINESS DESCRIPTION
Oglethorpe Power Corporation (Oglethorpe) is an electric membership
corporation incorporated in 1974 and headquartered in suburban Atlanta.
Oglethorpe provides wholesale electric service, on a not-for-profit basis, to 39
of Georgia's 42 Electric Membership Corporations (EMCs). These 39 electric
distribution cooperatives (Members) in turn distribute energy on a retail basis
to approximately 3.1 million people across two-thirds of the State. Oglethorpe
is the nation's largest electric cooperative in terms of operating revenues,
assets, kilowatt-hour sales and, through its Members, consumers served.
Oglethorpe owns or leases undivided interests in thirteen generating units
totaling 3,335 megawatts (MW) of capacity. Oglethorpe also purchases a total of
1,250 MW of capacity pursuant to power purchase agreements.
Oglethorpe and the Members completed a corporate restructuring (the
Corporate Restructuring) in 1997, in which Oglethorpe was divided into three
separate operating companies. Oglethorpe's transmission business was sold to and
is now owned and operated by Georgia Transmission Corporation (GTC).
Oglethorpe's system operations business was sold to and is now owned and
operated by Georgia System Operations Corporation (GSOC). Oglethorpe continues
to own and operate its power supply business. For more information regarding the
Corporate Restructuring, see Note 11.
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, 1999 and 1998
and the reported amounts of revenues and expenses for each of the three years
ending December 31, 1999. Actual results could differ from those estimates.
c. PATRONAGE CAPITAL AND MEMBERSHIP FEES
Oglethorpe is organized and operates as a cooperative. The Members paid a
total of $195 in membership fees. Patronage capital includes retained net margin
of Oglethorpe and the unrealized gain or loss on available-for-sale securities,
excluding securities held in the decommissioning fund. For 1999, 1998 and 1997
the unrealized gain or loss on available-for-sale securities was ($1,609,000),
$1,005,000 and ($107,000), respectively. As provided in the bylaws, any excess
of revenue over expenditures from operations is treated as advances of capital
by the Members and is allocated to each of them on the basis of their
electricity purchases from Oglethorpe.
Any distributions of patronage capital are subject to the discretion of the
Board of Directors, subject to Mortgage Indenture requirements. Under the
Mortgage Indenture, Oglethorpe is prohibited from making any distribution of
patronage capital to the Members if, at the time thereof or giving effect
thereto, (i) an event of default exists under the Mortgage Indenture, (ii)
Oglethorpe's equity as of the end of the immediately preceding fiscal quarter is
less than 20% of Oglethorpe's total capitalization, or (iii) the aggregate
amount expended for distributions on or after the date on which Oglethorpe's
equity first reaches 20% of Oglethorpe's total capitalization exceeds 35% of
Oglethorpe's aggregate net margins earned after such date. This last
restriction, however will not apply if, after giving effect to such
distribution, Oglethorpe's equity as of the end of the immediately preceding
fiscal quarter is not less than 30% of Oglethorpe's total capitalization.
d. MARGIN POLICY
For the years 1997 through 1999 under the Mortgage Indenture, Oglethorpe
was required to produce a Margins for Interest (MFI) Ratio of at least 1.10.
50
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
conducted at the end of each month. Actual energy costs are compared, on a
monthly basis, to the billed energy costs, and an adjustment to revenues is made
such that energy revenues are equal to actual energy costs.
Revenues from Jackson EMC and Cobb EMC, two of Oglethorpe's Members,
accounted for 11.8% and 11.7% in 1999, 11.4% and 12.8% in 1998, and 11.7% and
12.8% in 1997, 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 1999, 1998 and 1997 amounted to $46,226,000, $46,751,000 and
$47,123,000, respectively.
Contracts with the U.S. Department of Energy (DOE) have been executed to
provide for the permanent disposal of spent nuclear fuel for the life of Plant
Hatch and Plant Vogtle. 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. The Plant Hatch spent fuel storage is expected to be sufficient
into 2003. The Plant Vogtle spent fuel storage is expected to be sufficient into
2017.
Activities for adding dry cask storage capacity and potentially additional
spent fuel pool rack capacity at Plant Hatch during 2000 are in progress. In
addition, GPC, as agent for the co-owners of the plant, is a member of Private
Fuel Storage, LLC, a joint utility effort to develop a private spent fuel
storage facility for temporary storage of spent nuclear fuel. This facility is
planned to begin operation as early as the year 2003.
The Energy Policy Act of 1992 required that utilities with nuclear plants
be assessed over a 15-year period an amount which will be used by DOE for the
decontamination and decommissioning of its nuclear fuel enrichment facilities.
The amount of each utility's assessment was based on its past purchases of
nuclear fuel enrichment services from DOE. Based on its ownership in Plants
Hatch and Vogtle, Oglethorpe has a remaining nuclear fuel asset of approximately
$10,814,000, which is being amortized to nuclear fuel expense over the next 10
years. Oglethorpe has also recorded an obligation to DOE which approximated
$8,265,000 at December 31, 1999.
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 .. 1998 1998 1998 1998
Expected start date
of decommissioning 2014 2018 2027 2029
Decommissioning cost:
Discounted .......... $109,000 $133,000 $107,000 $130,000
Undiscounted ........ 200,000 280,000 309,000 404,000
- --------------------------------------------------------------------
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 1999 and Oglethorpe currently does not expect to record
an annual provision for decommissioning in future years. The annual provision
for decommissioning for 1998 and 1997 was $2,597,000 and $2,597,000,
respectively. In developing the amount of the annual provision for 1998 and
1999, the escalation rate was assumed to be 2.72% and 3.6% and return on trust
assets was assumed to be 8% and 8%, respectively. Oglethorpe accounts for this
provision for decommissioning as
51
depreciation expense with an offsetting credit to a decommissioning reserve.
Oglethorpe's management is of the opinion that any changes in cost estimates
of decommissioning can be recovered in future rates. In compliance with a NRC
regulation, Oglethorpe maintains an external trust fund to provide for a
portion of the cost of decommissioning its nuclear facilities. The NRC
regulation requires funding levels based on average expected cost to
decommission only the radioactive portions of a typical nuclear facility.
h. DEPRECIATION
Depreciation is computed on additions when they are placed in service using
the composite straight-line method. Annual depreciation rates in effect in 1999,
1998 and 1997 were as follows:
- ------------------------------------------------------------------------
1999 1998 1997
- ------------------------------------------------------------------------
Steam production 2.15% 2.14% 2.13%
Nuclear production 2.69% 2.77% 2.74%
Hydro production 2.00% 2.00% 2.00%
Other production 3.75% 3.75% 3.75%
Transmission 2.75% 2.75% 2.75%
Distribution -- -- 2.88%
General 2.00-33.33% 2.00-20.00% 2.00-20.00%
- ------------------------------------------------------------------------
i. ELECTRIC PLANT
Electric plant is stated at original cost, which is the cost of the plant
when first dedicated to public service, plus the cost of any subsequent
additions. Cost includes an allowance for the cost of equity and debt funds used
during construction. The cost of equity and debt funds is calculated at the
embedded cost of all such funds.
Maintenance and repairs of property and replacements and renewals of
items determined to be less than units of property are charged to expense.
Replacements and renewals of items considered to be units of property are
charged to the plant accounts. At the time properties are disposed of, the
original cost, plus cost of removal, less salvage of such property, is
charged to the accumulated provision for depreciation.
j. BOND, RESERVE AND CONSTRUCTION FUNDS
Bond, reserve and construction funds for pollution control revenue bonds
(PCBs) are maintained as required by Oglethorpe's bond agreements. Bond funds
serve as payment clearing accounts, reserve funds maintain amounts equal to the
maximum annual debt service of each bond issue and construction funds hold bond
proceeds for which construction expenditures have not yet been made. As of
December 31, 1999 and 1998, substantially all of the funds were invested in U.S.
Government securities.
k. CASH AND TEMPORARY CASH INVESTMENTS
Oglethorpe considers all temporary cash investments purchased with a
maturity of three months or less to be cash equivalents. Temporary cash
investments with maturities of more than three months are classified as other
short-term investments.
At December 31, 1999 and 1998, $20,155,000 and $13,457,000 were
restricted by PCBs trust indentures and were utilized in January 2000 and
1999 for payment of principal on certain PCBs, respectively.
l. INVENTORIES
Oglethorpe maintains inventories of fossil fuels and spare parts for its
generation plants. These inventories are stated at weighted average cost on the
accompanying balance sheets.
At December 31, 1999 and 1998, fossil fuels inventories were $31,787,000
and $18,692,000, respectively. Inventories for spare parts at December 31, 1999
and 1998 were $57,979,000 and $58,091,000, respectively.
m. DEFERRED CHARGES
Oglethorpe accounts for nuclear refueling outage costs on a normalized
basis. Under this method of accounting, refueling outage costs are deferred and
subsequently amortized to expense over the 18-month operating cycle of each
unit. Deferred nuclear outage costs at December 31, 1999 and 1998 were
$18,483,000 and $17,163,000, respectively.
As a result of the determination that the Plant Vogtle radioactive waste
facility has no usefulness as a radioactive waste storage facility, the
remaining project costs of $23,064,000 are reflected as deferred charges on the
accompanying balance sheets. In 1998, Oglethorpe's Board of Directors authorized
that these project costs be amortized and fully recovered through rates over a
period of four years beginning in 1999.
52
n. DEFERRED CREDITS
In April 1982, Oglethorpe sold to three purchasers certain of the income
tax benefits associated with Scherer Unit No.1 and related common facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act of
1981. Oglethorpe received a total of approximately $110,000,000 from the safe
harbor lease transactions. Oglethorpe accounts for the net benefits as a
deferred credit and is amortizing the amount over the 20-year term of the
leases.
In December 1996 and January 1997, Oglethorpe entered into long-term lease
transactions for its 74.6% undivided ownership interest in Rocky Mountain,
through a wholly owned subsidiary of Oglethorpe, Rocky Mountain Leasing
Corporation (RMLC). The lease transactions are characterized as a sale and
lease-back for income tax purposes, but not for financial reporting purposes. As
a result of these leases, Oglethorpe recorded a net benefit of $95,560,000 which
was deferred and is being amortized to income over the 30-year lease-back
period.
o. REGULATORY ASSETS AND LIABILITIES
Oglethorpe is subject to the provisions of Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation." Regulatory assets represent certain costs that are assured to be
recoverable by Oglethorpe from the Members in the future through the ratemaking
process. Regulatory liabilities represent certain items of income that are being
retained by Oglethorpe and that will be applied in the future to reduce Member
revenue requirements. The following regulatory assets and liabilities were
reflected on the accompanying balance sheets as of December 31, 1999 and 1998:
- -------------------------------------------------------------------
(dollars in thousands)
1999 1998
- -------------------------------------------------------------------
Premium and loss on reacquired debt ...... $ 196,289 $ 206,729
Deferred amortization of Scherer leasehold 101,404 99,297
Discontinued projects .................... 28,020 36,203
Other regulatory assets .................. 29,017 28,668
Net benefit of sale of income tax benefits (18,021) (26,030)
Net benefit of Rocky Mountain transactions (86,004) (89,189)
--------- ---------
$ 250,705 $ 255,678
========= =========
- -------------------------------------------------------------------
In the event that competitive or other factors result in cost recovery
practices under which Oglethorpe can no longer apply the provisions of SFAS No.
71, Oglethorpe would be required to eliminate all regulatory assets and
liabilities that could not otherwise be recognized as assets and liabilities by
businesses in general. In addition, Oglethorpe would be required to determine
any impairment to other assets, including plant, and write-down those assets, if
impaired, to their fair value.
p. PRESENTATION
Certain prior year amounts have been reclassified to conform with current
year presentation.
2. FAIR VALUE OF FINANCIAL INSTRUMENTS:
A detail of the estimated fair values of Oglethorpe's financial instruments
as of December 31, 1999 and 1998 is as follows:
- --------------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998
Fair Fair
Cost Value Cost Value
- --------------------------------------------------------------------------------
Cash and temporary cash
investments:
Commercial paper .. $ 220,941 $ 220,941 $ 105,567 $ 105,567
Cash and money
market securities 1,873 1,873 668 668
----------- ----------- ----------- -----------
Total ............... $ 222,814 $ 222,814 $ 106,235 $ 106,235
=========== =========== =========== ===========
Other short term
investments ....... $ 76,673 $ 75,482 $ 72,955 $ 73,356
=========== =========== =========== ===========
Bond, reserve and
construction funds:
U.S. Government
securities ...... $ 25,443 $ 25,025 $ 20,486 $ 21,091
Repurchase
agreements ...... 6,133 6,133 11,818 11,818
----------- ----------- ----------- -----------
Total ............... $ 31,576 $ 31,158 $ 32,304 $ 32,909
=========== =========== =========== ===========
Decommissioning fund:
U.S. Government
securities ...... $ 23,858 $ 23,574 $ 27,521 $ 28,442
Foreign government
securities ...... 732 656 732 738
Commercial paper .. 2,387 2,388 4,785 4,784
Corporate bonds ... 11,215 10,891 10,855 11,465
Equity securities . 69,944 77,148 53,760 61,400
Asset-backed
securities ....... 9,954 9,751 7,442 7,593
Other bonds ....... -- -- 940 944
Cash and money
market securities 11,293 11,295 6,728 6,728
----------- ----------- ----------- -----------
Total ............... $ 129,383 $ 135,703 $ 112,763 $ 122,094
=========== =========== =========== ===========
Long-term debt ...... $ 3,103,590 $ 3,007,048 $ 3,177,883 $ 3,541,832
=========== =========== =========== ===========
Interest rate swap
(unrealized loss) . $ -- $ (18,935) $ -- $ (49,350)
=========== =========== =========== ===========
- --------------------------------------------------------------------------------
53
The contractual maturities of debt securities available for sale at
December 31, 1999 and 1998, regardless of their balance sheet classification,
are as follows:
- --------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998
Fair Fair
Cost Value Cost Value
- --------------------------------------------------------------------
Due within one year $ 6,818 $ 6,866 $16,556 $16,593
Due after one year
through five years 36,017 35,509 26,163 27,082
Due after five years
through ten years 11,597 11,262 13,504 13,739
Due after ten years 22,902 22,393 23,572 24,676
------- ------- ------- -------
$77,334 $76,030 $79,795 $82,090
======= ======= ======= =======
- --------------------------------------------------------------------
Oglethorpe uses the methods and assumptions described below to estimate the
fair value of each class of financial instruments. For cash and temporary cash
investments, the carrying amount approximates fair value because of the
short-term maturity of those instruments. The fair value of Oglethorpe's
long-term debt and the swap arrangements is estimated based on the quoted market
prices for the same or similar issues or on the current rates offered to
Oglethorpe for debt of similar maturities.
A portion (16.86%) of the interest rate swap arrangements was assumed by
GTC as part of the 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, 1999 was $195,015,000 (includes
the portion assumed by GTC) and the fixed swap rate is 5.67% (the variable
rate at December 31, 1999 and 1998 was 5.40% and 3.85%, respectively). With
respect to the Series 1994A notes, the notional principal at December 31,
1999 was $122,740,000 (includes the portion assumed by GTC) and the fixed
swap rate is 6.01% (the variable rate at December 31, 1999 and 1998 was 5.65%
and 3.85%, respectively). The notional principal amount is used to measure
the amount of the swap payments and does not represent additional principal
due to the counterparty. The swap arrangements extend for the life of the
refunding bonds, with reductions in the outstanding principal amounts of the
refunding bonds causing corresponding reductions in the notional amounts of
the swap payments. Oglethorpe's portion of the estimated fair value of the
swap arrangements at December 31, 1999 and 1998 was an unrealized loss of
$18,935,000 and $49,350,000, respectively, representing the estimated payment
Oglethorpe would pay if the swap arrangements were terminated. Oglethorpe may
be exposed to losses in the event of nonperformance of the counterparty, but
does not anticipate such nonperformance.
Under SFAS No. 115, "Accounting for Certain Investments in Debt and Equity
Securities," investment securities held by Oglethorpe are classified as either
available-for-sale or held-to-maturity. Available-for-sale securities are
carried at market value with unrealized gains and losses, net of any tax effect,
added to or deducted from patronage capital. Unrealized gains and losses from
investment securities held in the decommissioning fund, which are also
classified as available-for-sale, are directly added to or deducted from the
decommissioning reserve. Held-to-maturity securities are carried at cost. All
realized and unrealized gains and losses are determined using the specific
identification method. Gross unrealized gains and losses at December 31, 1999
were $11,451,000 and $6,740,000, respectively. Gross unrealized gains and losses
at December 31, 1998 were $12,182,000 and $1,845,000, respectively. For 1999 and
1998, proceeds from sales of available-for-sale securities totaled $592,579,000
and $491,343,000, respectively. Gross realized gains and losses from the 1999
sales were $29,429,000 and $22,167,000, respectively. Gross realized gains
and losses from the 1998 sales were $12,892,000 and $6,602,000, respectively.
Investments in associated companies were as follows at December
31, 1999 and 1998:
- ------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998
- ------------------------------------------------------------
National Rural Utilities
Cooperative Finance Corp. (CFC) $13,603 $13,476
CoBank, ACB 1,577 1,734
Other 2,739 1,021
------- -------
Total $17,919 $16,231
======= =======
- ------------------------------------------------------------
54
The investments in these associated companies are similar to compensating
bank balances in that they are required in order to maintain current financing
arrangements. Accordingly, there is no market for these investments.
The deposit, which is carried at cost, on the Rocky Mountain transactions
(see Note 1 where discussed) is invested in a guaranteed investment contract
which will be held to maturity (the end of the 30-year lease-back period). At
maturity, Oglethorpe intends to repurchase tax ownership and to retain all other
rights of ownership with respect to the plant if it is advantageous to do so.
The assets of RMLC are not available to pay creditors of Oglethorpe or its
affiliates.
In addition, from the proceeds of the Rocky Mountain transactions,
Oglethorpe paid $640,611,000 to a financial institution. In return, this
financial institution undertook to pay a portion of Oglethorpe's lease
obligations. Both Oglethorpe's interest in this payment undertaking agreement
and the corresponding lease obligations have been extinguished for financial
reporting purposes.
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities." The standard
requires that all derivative instruments be recognized as assets or liabilities
and be measured at fair value. Oglethorpe is required to adopt SFAS No. 133 by
January 1, 2001. Oglethorpe is currently assessing the impact that adoption of
SFAS No. 133 will have on results of operations and financial condition and is
undecided as to the date the standard will be adopted.
3. INCOME TAXES:
Oglethorpe is a not-for-profit membership corporation subject to federal
and state income taxes. As a taxable electric cooperative, Oglethorpe has
annually allocated its income and deductions between Member and non-Member
activities. Any Member taxable income has been offset with a patronage exclusion
and member loss carryforwards.
Oglethorpe accounts for its income taxes pursuant to SFAS No. 109. SFAS No.
109 requires the recognition of deferred tax assets and liabilities for the
expected future tax consequences of events that have been included in the
financial statements or tax returns.
A detail of the provision for income taxes in 1999, 1998 and 1997 is shown
as follows:
- -----------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998 1997
- -----------------------------------------------------
Current
Federal $ -- $ (86) $ 1,132
State -- -- --
----- ------- -------
-- (86) 1,132
----- ------- -------
Deferred
Federal -- 86 (1,132)
State -- -- --
----- ------- -------
-- 86 (1,132)
----- ------- -------
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:
- --------------------------------------------------------------
1999 1998 1997
- --------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Patronage exclusion (35.6%) (35.7%) (35.4%)
Other 0.6% 0.7% 0.4%
----- ----- -----
Effective income tax rate 0.0% 0.0% 0.0%
===== ===== =====
- --------------------------------------------------------------
The components of the net deferred tax liabilities as of December 31, 1999
and 1998 were as follows:
- ----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1999 1998
- ----------------------------------------------------------------------------
Deferred tax assets
Net operating losses $ 477,817 $ 468,337
Member loss carryforwards 78,231 134,533
Tax credits (alternative minimum tax
and other) 199,650 236,856
Accounting for Rocky Mountain
transactions 309,474 306,801
Accounting for sale of income tax benefits 27,909 61,757
Accrued nuclear decommissioning expense 60,264 55,492
Accounting for asset dispositions 28,185 30,612
Other 3,540 2,310
----------- -----------
1,185,070 1,296,698
Less: Valuation allowance (197,343) (234,549)
----------- -----------
987,727 1,062,149
----------- -----------
Deferred tax liabilities
Depreciation (771,577) (837,991)
Accounting for Rocky Mountain
transactions (199,675) (204,019)
Accounting for debt extinguishment (64,362) (67,828)
Other (15,316) (15,514)
----------- -----------
(1,050,930) (1,125,352)
----------- -----------
Net deferred tax liabilities $ (63,203) $ (63,203)
=========== ===========
- ----------------------------------------------------------------------------
55
As of December 31, 1999, 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
- -------------------------------------------------------------
1999 $ -- $ -- $ --
2000 -- 3,198 --
2001 -- 7,264 --
2002 -- 130,377 7,102
2003 -- 652 253,665
2004 -- 55,663 114,285
2005 -- 189 213,080
2006 -- -- 209,009
2007 -- -- 86,779
2008 -- -- 94,927
2009 -- -- 96,394
2010 -- -- 77,970
2018 -- -- 61,533
2019 -- -- 13,577
None 2,307 -- --
---------- ---------- ----------
$ 2,307 $ 197,343 $1,228,321
========== ========== ==========
- -------------------------------------------------------------
Oglethorpe has not recorded a valuation allowance with respect to its
deferred tax asset related to NOLs. Oglethorpe intends to implement available
tax planning strategies if necessary to utilize NOLs prior to their expiration
date. If any NOLs are not utilized prior to their expiration date, Oglethorpe
believes it has available options to offset the effect, if any, of NOLs
expiring. The NOL expiration dates start in the year 2002 and end in the year
2019. 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 1998 to 1999 was the result of the expiration of
$37,206,000 of tax credits in 1999. It is more likely than not that the AMT
credit will be utilized.
4. CAPITAL LEASES:
In December 1985, Oglethorpe sold and subsequently leased back from four
purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The gain
from the sale is being amortized over the 36-year term of the leases. The
minimum lease payments under the capital leases together with the present value
of net minimum lease payments as of December 31, 1999 are as follows:
- --------------------------------------------------------
YEAR ENDING DECEMBER 31, (DOLLARS IN THOUSANDS)
- --------------------------------------------------------
2000 $ 37,755
2001 37,629
2002 37,491
2003 37,333
2004 37,156
2005-2021 457,199
---------
Total minimum lease payments 644,563
Less: Amount representing interest (360,953)
---------
Present value of net minimum lease payments 283,610
Less: Current portion (8,386)
---------
Long-term balance $ 275,224
==========
The capital leases provide that Oglethorpe's rental payments vary to the
extent of interest rate changes associated with the debt used by the lessors to
finance their purchase of undivided ownership shares in Scherer Unit No. 2. In
December 1997, Oglethorpe refinanced the debt supporting the Scherer Unit No. 2
lease. The refunded debt consisted of $143,200,000 in serial facility bonds with
a 9.70% fixed interest rate (pertaining to three of the lessors) and $81,500,000
in bank debt with variable interest rates ranging from 6.4% to 6.9% (pertaining
to the remaining lessor). The debt was refinanced through a $224,700,000 issue
of serial facility bonds due June 30, 2011 with a 6.97% fixed interest rate. The
transaction costs related to this transaction are reported as deferred charges
on the balance sheet and are being amortized over the remaining life of the
leases. Oglethorpe's future rental payments under its leases will vary from
amounts shown in the table above to the extent that the actual interest rates
associated with the debt of the lessors varies from the 11.05% debt rate
assumed in the table.
The Scherer Unit No. 2 lease meets the definitional criteria to be reported
on Oglethorpe's balance sheets as a capital lease. For rate-making purposes,
however, Oglethorpe treats this lease as an operating lease; that is, Oglethorpe
considers the actual rental payment on the leased asset in its cost of service.
Oglethorpe's accounting treatment for this capital lease has been modified,
therefore, to reflect its rate-making treatment. Interest expense is applied to
the obligation under the capital lease; then, amortization of the leasehold is
recognized, such that interest and
56
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.
In 1991 and 1992, all four of the lessors received Notices of Proposed
Adjustments from the IRS proposing adjustments to the tax benefits claimed by
these lessors in connection with their purchase and ownership of an undivided
interest in Scherer Unit No 2. In 1994, the IRS issued a revised Notice of
Proposed Adjustments to one of the lessors which reduced the proposed
adjustments. During 1995, this lessor advised Oglethorpe that it had settled
this issue on the basis of the revised Notice of Proposed Adjustments.
Oglethorpe subsequently made a lump sum indemnity payment of $362,000 to the
lessor in order to compensate for the reduction in the lessor's tax benefits
resulting from the sale and leaseback transaction. The IRS has indicated that
it will take consistent positions with the other three lessors. If the IRS's
current positions regarding the sale and leaseback transactions were
ultimately upheld, Oglethorpe would be required to indemnify the other three
lessors. Oglethorpe's indemnification liability to the three lessors is
estimated to be approximately $1,311,000 as of December 31, 1999. This
liability has been reflected on the accompanying balance sheet.
5. LONG-TERM DEBT:
Long-term debt consists of mortgage notes payable to the United States
of America acting through the Federal Financing Bank (FFB) and the RUS,
mortgage notes and unsecured notes issued in conjunction with the sale by
public authorities of PCBs, mortgage notes and unsecured notes payable to
CoBank, and mortgage notes payable to National Rural Utilities Cooperative
Finance Corporation (CFC). Oglethorpe's headquarters facility is pledged as
collateral for the CoBank headquarters note; substantially all of the owned
tangible and certain of the intangible assets of Oglethorpe are pledged as
collateral for the FFB and RUS notes, the CoBank mortgage notes, the CFC
notes, and the mortgage notes issued in conjunction with the sale of PCBs.
The detail of the two medium-term notes is included in the statements of
capitalization.
As part of the 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 the Corporate Restructuring in March 1997, 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 November 1999, Oglethorpe completed a current refunding transaction
whereby $88,775,000 of PCBs were issued. A portion of the proceeds from this
transaction was used to fully refund $68,705,000 of PCB issues. The remaining
$20,070,000 of proceeds was used to make principal payments due January 1, 2000.
GTC agreed with Oglethorpe not to participate in this $89 million
refinancing to the extent of their assumed obligation in the PCBs. Pursuant to
this agreement, OPC provided a discount to GTC of approximately $2.6 million on
the $8.6 million of principal payments due from GTC in connection with such
refinancings. This $2.6 million loss has been reported, together with the
unamortized transaction costs, as a deferred charge on the balance sheet and is
being amortized over four years.
In 1999, Oglethorpe refinanced more than $89,000,000 in FFB debt. In
connection with this refinancing, Oglethorpe paid prepayment premiums of
approximately $7,000,000 and is amortizing these premiums over three and one
half years.
The annual interest requirement for 2000 is estimated to be $220,000,000.
57
Maturities for the long-term debt and amortization of the capital lease
obligations through 2004 are as follows:
- ---------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
2000 2001 2002 2003 2004
- ---------------------------------------------------------------------
FFB and RUS $ 98,935 $ 86,314 $ 90,830 $ 96,424 $101,383
CoBank 508 523 540 46,623 580
PCBs* 21,590 19,678 20,264 25,835 27,855
CFC -- -- -- 46,065 --
Capital Leases 8,386 7,775 8,544 9,455 10,387
-------- -------- -------- -------- --------
Total $129,419 $114,290 $120,178 $224,402 $140,205
======== ======== ======== ======== ========
* Does not contain portion assumed by GTC
- ---------------------------------------------------------------------
The weighted average interest rate for 1999 for long-term debt and capital
leases due within one year and notes payable is 6.15%.
Oglethorpe has a commercial paper program under which it may issue
commercial paper not to exceed a $260,000,000 balance outstanding at any time.
The commercial paper may be used for working capital requirements and for
general corporate purposes. Oglethorpe's commercial paper is backed 100% by
committed lines of credit.
As of December 31, 1999 and 1998, approximately $88,000,000 and
$51,000,000, respectively, of commercial paper was outstanding. The majority
of the amount outstanding at year-end 1998 relates to commercial paper issued to
fund, on an interim basis, the construction of a combustion turbine (CT) project
completed in June 1999. This project is owned by a newly formed cooperative,
Smarr EMC, which is owned by 37 of Oglethorpe's 39 Members. The commercial paper
was retired in June 1999 with proceeds from permanent financing secured by Smarr
EMC on a non-recourse basis to Oglethorpe. All of the commercial paper
outstanding at year-end 1999 was issued to fund, on an interim basis,
construction of a second CT project owned by Smarr EMC. It is expected that by
the time the project is completed in June 2000, Smarr EMC will secure, on a
non-recourse basis to Oglethorpe, permanent financing for this CT project and
repay Oglethorpe for the interim financing.
Oglethorpe has a $50,000,000 uncommitted short-term line of credit with
CFC. No balance was outstanding on this line of credit at either December 31,
1999 or 1998.
6. ELECTRIC PLANT AND RELATED AGREEMENTS:
Oglethorpe and GPC have entered into agreements providing for the purchase
and subsequent joint operation of certain of GPC's electric generating plants. A
summary of Oglethorpe's plant investments and related accumulated depreciation
as of December 31, 1998 is as follows:
- ----------------------------------------------------------------
(DOLLARS IN THOUSANDS)
Accumulated
Plant Investment Depreciation
- ----------------------------------------------------------------
In-service
Owned property
Vogtle Units No. 1 & No. 2
(NUCLEAR - 30% OWNERSHIP) $2,734,539 $ 860,549
Hatch Units No. 1 & No. 2
(NUCLEAR - 30% OWNERSHIP) 522,824 233,332
Wansley Units No. 1 & No. 2
(FOSSIL - 30% OWNERSHIP) 172,730 91,907
Scherer Unit No. 1
(FOSSIL - 60% OWNERSHIP) 425,909 217,039
Rocky Mountain Units No. 1,
No. 2 & No. 3
(HYDRO - 74.6% OWNERSHIP) 556,930 50,859
Tallassee (Harrison Dam)
(HYDRO - 100% OWNERSHIP) 9,270 2,330
Wansley (COMBUSTION TURBINE -
30% OWNERSHIP) 3,629 1,462
Generation step-up substations 58,253 23,547
Other 68,756 28,210
Property under capital lease
Scherer Unit No. 2
(FOSSIL - 60% LEASEHOLD) 301,197 116,698
-- ---------- ----------
Total in-service $4,854,037 $1,625,933
========== ==========
Construction work in progress
Generation improvements $ 17,923
Other 376
----------
Total construction work in progress $ 18,299
==========
- ----------------------------------------------------------------
Oglethorpe, as of December 31, 1999, estimates property additions
(including capitalized interest but excluding nuclear fuel) to be approximately
$31,000,000 in 2000, $31,000,000 in 2001 and $59,000,000 in 2002, primarily for
replacements and additions to generation facilities.
Oglethorpe's proportionate share of direct expenses of joint operation of
the above plants is included in the corresponding operating expense captions
(e.g., fuel, production or depreciation) on the accompanying statements of
revenues and expenses.
58
7. EMPLOYEE BENEFIT PLANS:
Effective December 31, 1998, Oglethorpe's Board of Directors approved
termination of the noncontributory defined benefit pension plan that covered
substantially all employees, resulting in a net gain of $1,645,000.
In 1999, Oglethorpe contributed cash into the pension plan equal to the
unfunded pension plan balance of $1,859,000. The plan assets were distributed
to all employees entitled to benefits under the pension plan.
The changes in obligations, plan assets and funded status of the pension
plan at December 31, 1998 was as follows:
- ---------------------------------------------------------
(DOLLARS IN THOUSANDS)
1998
- ---------------------------------------------------------
Projected Benefit Obligation
Beginning of year $ 11,294
Service cost 415
Interest cost 756
Divestitures --
Actuarial gain (202)
Benefit payments (406)
Change in discount rate 1,035
Assumption change 1,037
Net effect of termination (892)
--------
End of year $ 13,037
========
Change in plan assets
Fair value of plan assets at
beginning of year $ 9,568
Divestitures --
Actual return on assets 1,992
Employer contributions 58
Benefits paid (406)
--------
Fair value of plan assets at end of year $ 11,212
========
Funded status
Obligation in excess of assets $ (1,825)
Unrecognized net actuarial gain --
Unrecognized prior service cost --
Unrecognized net asset --
--------
Net accrued pension cost $ (1,825)
========
- ---------------------------------------------------------
The plan's pension cost recognized in 1998 and 1997 were as follows:
- -----------------------------------------------------------------
(DOLLARS IN THOUSANDS)
1998 1997
- -----------------------------------------------------------------
Components of net periodic benefit cost
Service cost $ 415 $ 560
Interest cost 756 791
Less, expected return on plan assets (802) (666)
Amount of prior service cost recognized 40 40
Amortization of unrecognized
transition asset (10) (10)
Amount of gain from prior years (562) (61)
------- -------
Net periodic benefit cost (163) 654
Estimated gain on termination (1,645) --
------- -------
Net pension cost $(1,808) $ 654
======= =======
- -----------------------------------------------------------------
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 was approximately $365,000
in 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 IRS
limitations, 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. Oglethorpe's
contributions to the plan were approximately $226,000 in 1999, $214,000 in 1998
and $248,000 in 1997.
8. NUCLEAR INSURANCE:
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member
of Nuclear Electric Insurance, Ltd. (NEIL), a mutual insurer
established to provide property damage insurance coverage in an amount up to
$500,000,000 for members' nuclear generating facilities. In the event that
losses exceed accumulated reserve funds, the members are subject to retroactive
assessments (in proportion to their participation in the mutual insurer). The
portion of the current maximum annual assessment for GPC that would
59
be payable by Oglethorpe, based on ownership share, is limited to approximately
$4,673,000 for each nuclear incident.
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, has
coverage under NEIL II, which provides insurance to cover decontamination,
debris removal and premature decommissioning as well as excess property damage
to nuclear generating facilities for an additional $2,250,000,000 for losses in
excess of the $500,000,000 primary coverage described above. Under the NEIL
policies, members are subject to retroactive assessments in proportion to their
participation if losses exceed the accumulated funds available to the insurer
under the policy. The portion of the current maximum annual assessment for GPC
that would be payable by Oglethorpe, based on ownership share, is limited to
approximately $4,110,000.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
annually renewed on or after April 2, 1991 shall be dedicated first for the sole
purpose of placing the reactor in a safe and stable condition after an accident.
Any remaining proceeds are next to be applied toward the costs of
decontamination and debris removal operations ordered by the NRC, and any
further remaining proceeds are to be paid either to the company or to its bond
trustees as may be appropriate under the policies and applicable trust
indentures.
The Price-Anderson Act, as amended in 1988, limits public liability claims
that could arise from a single nuclear incident to $9,500,000,000, which amount
is to be covered by private insurance and agreements of indemnity with the NRC.
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
into by and between each of the co-owners and the NRC. In the event of a nuclear
incident involving any commercial nuclear facility in the country involving
total public liability in excess of $200,000,000, a licensee of a nuclear power
plant could be assessed a deferred premium of up to $88,095,000 per incident for
each licensed reactor operated by it, but not more than $10,000,000 per reactor
per incident to be paid in a calendar year. On the basis of its sell-back
adjusted ownership interest in four nuclear reactors, Oglethorpe could be
assessed a maximum of $105,714,000 per incident, but not more than $12,000,000
in any one year.
All retrospective assessments, whether generated for liability or property,
may be subject to applicable state premium taxes.
9. COMMITMENTS:
a. POWER PURCHASE AND SALE AGREEMENTS
Oglethorpe is utilizing long-term power marketer arrangements to reduce the
cost of power to the Members. Oglethorpe has entered into two power marketer
agreements with LG&E Energy Marketing, Inc. (LEM) effective January 1, 1997, for
approximately 50% of the load requirements of the Members and with Morgan
Stanley Capital Group Inc. (Morgan Stanley), effective May 1, 1997, with respect
to 50% of the Members' then forecasted load requirements. The LEM agreements are
based on the actual requirements of the 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. Through December 31, 1999, substantially all of Oglethorpe's generating
facilities and power purchase arrangements were 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, as described below, from LEM and
Morgan Stanley for use of the resources.
One of the two power marketer agreements with LEM, relating to two of the
39 Members, expired on December 31, 1999. The remaining agreement with LEM
continues to cover approximately 50% of the load requirements of 37 Members.
Most of Oglethorpe's generating facilities and power purchase arrangements
continue to be available for use by LEM and Morgan Stanley under the terms of
the respective agreements.
In October 1998, LEM submitted a dispute to arbitration seeking to
terminate the contract relating to 37 of the Members. On December 21, 1999, the
arbitration panel ruled that the agreement is valid and must continue to be
honored. Oglethorpe and LEM, however, are addressing a number of issues relating
to the administration of the agreement.
60
In addition, Oglethorpe has entered into various long-term power purchase
agreements. As of December 31, 1999, Oglethorpe's minimum purchase commitments
under these agreements, without regard to capacity reductions or adjustments for
changes in costs, for the next five years are as follows:
- -------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- -------------------------------------------------------------
2000 $ 79,735
2001 66,505
2002 59,139
2003 46,288
2004 49,956
- -------------------------------------------------------------
Oglethorpe's power purchases from these agreements amounted to
approximately $132,721,000 in 1999, $172,897,000 in 1998 and $175,818,000 in
1997.
Oglethorpe has entered into an agreement with Alabama Electric Cooperative
to sell 100 MW of capacity for the period June 1998 through December 2005.
b. OPERATING LEASES
In December 1999, Oglethorpe sold existing coal rail cars and subsequently
entered into rental agreements with various terms and expiration dates for the
existing and for additional new coal rail cars. As of December 31, 1999,
Oglethorpe's estimated minimum rental commitments for these operating leases
over the next five years are as follows:
- -------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- -------------------------------------------------------------
2000 $ 1,859
2001 1,859
2002 1,859
2003 1,859
2004 1,859
- -------------------------------------------------------------
10. QUARTERLY FINANCIAL DATA (UNAUDITED):
Summarized quarterly financial information for 1999 and 1998 is as follows:
- ----------------------------------------------------------------------------
(DOLLARS IN THOUSANDS)
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
- ----------------------------------------------------------------------------
1999
Operating revenues $250,764 $273,917 $393,636 $257,915
Operating margin 62,293 58,342 59,961 51,335
Net margin 8,099 4,483 6,241 1,115
1998
Operating revenues $235,267 $316,727 $345,775 $246,398
Operating margin 62,781 58,045 55,823 66,005
Net margin 7,626 1,590 86 11,778
- ----------------------------------------------------------------------------
Fourth quarter 1999 net margin was lower than the same period of 1998
primarily as a result of a $7,000,000 reduction in revenue requirement approved
by Oglethorpe's Board of Directors. Such reduction in revenues was implemented
by reducing the capacity charges billed to Members in December 1999. The fourth
quarter of 1998 reflects a $1,645,000 net gain from a decision to terminate
Oglethorpe's pension plan (see Note 7).
11. CORPORATE RESTRUCTURING:
Oglethorpe and the Members completed in 1997 a Corporate Restructuring in
which Oglethorpe, effective April 1, 1997, was divided into three separate
operating companies. Oglethorpe's transmission business was sold to and is now
owned and operated by GTC. Oglethorpe's system operations business was sold to
and is now owned and operated by GSOC. Oglethorpe continues to own and operate
its power supply business.
61
The total purchase price GTC and GSOC paid Oglethorpe for the transmission
and system operations business was approximately $717 million. The following
summarizes the assets and liabilities sold by Oglethorpe to GTC and GSOC as a
result of the restructuring:
- ------------------------------------------------
(DOLLARS IN THOUSANDS)
- ------------------------------------------------
Assets
Plant in service $ 847,172
Accumulated depreciation (195,944)
Construction work in progress 13,313
Plant acquisition adjustment 3,887
Inventories 8,980
Prepayments 71
Premium on reacquired debt 33,410
Deferred debt expense 1,920
---------
Total assets sold 712,809
Deferred gain on sale 4,670
---------
Total purchase price $ 717,479
=========
Equity and Liabilities
Long-term debt $ 686,054
Accounts payable 585
Accrued interest 121
Accrued pension cost 1,047
Deferred revenues 310
---------
Total liabilities extinguished 688,117
Notes received from GSOC 4,822
Net cash received 24,540
---------
Total purchase price $ 717,479
=========
- ------------------------------------------------
In addition, Oglethorpe also made a special patronage capital distribution
to the Members which was used by the Members to establish equity in and to
provide working capital to GTC.
62
REPORT OF MANAGEMENT
The management of Oglethorpe Power Corporation has prepared this report and
is responsible for the financial statements and related information. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
Oglethorpe maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions. Limitations exist in any system of
internal control based upon the recognition that the cost of the system should
not exceed its benefits. Oglethorpe believes that its system of internal
accounting control, together with the internal auditing function, maintains
appropriate cost/benefit relations.
Oglethorpe's system of internal controls is evaluated on an ongoing basis
by a qualified internal audit staff. The Corporation's independent public
accountants (PricewaterhouseCoopers LLP) also consider certain elements of the
internal control system in order to determine their auditing procedures for the
purpose of expressing an opinion on the financial statements.
PricewaterhouseCoopers LLP also provides an objective assessment of how
well management meets its responsibility for fair financial reporting.
Management believes that its policies and procedures provide reasonable
assurance that Oglethorpe's operations are conducted with a high standard of
business ethics. In management's opinion, the financial statements present
fairly, in all material respects, the financial position, results of operations,
and cash flows of Oglethorpe.
Thomas A. Smith
President and Chief Executive Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of Oglethorpe Power Corporation:
In our opinion, the accompanying balance sheets and statements of
capitalization and the related statements of revenues and expenses, patronage
capital and of cash flows present fairly, in all material respects, the
financial position of Oglethorpe Power Corporation at December 31, 1999 and
1998, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 1999 in conformity with generally
accepted accounting principles in the United States. These financial statements
are the responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with generally accepted
auditing standards in the United States which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Atlanta, Georgia,
February 25, 2000.
63
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Oglethorpe has a ten-member board of directors consisting of six directors
elected from the Members (the "Member Directors") and four independent outside
directors (the "Outside Directors"). Each Member Director must be a director or
general manager of an Oglethorpe Member. Five of the six Member Directors must
be located in each of five geographical regions of the State of Georgia. The
sixth Member Director is elected statewide. None of the four Outside Directors
may be a director, officer or employee of GTC, GSOC or any Member. All ten
directors are nominated by representatives from each Member whose weighted
nomination is based on the number of retail customers served by each Member.
After nomination, the directors are elected by a majority vote of each Member,
voting on a one-Member, one-vote basis. One Outside Director position is
currently vacant as a result of the resignation of Newton A. Campbell, effective
February 29, 2000. Oglethorpe expects the vacancy to be filled at the annual
meeting of the Members in March.
The Bylaws provide for staggered three-year terms of the directors by
dividing the number of directors into three groups. The terms of approximately
one-third of the directors expire each year
Oglethorpe is managed and operated under the direction of a President and
Chief Executive Officer, who is appointed by the Board of Directors. The Senior
Officers and Directors of Oglethorpe and significant employees of subsidiaries
of Oglethorpe are as follows:
NAME AGE POSITION
J. Calvin Earwood 58 Chairman of the Board of Directors, Member Director, Statewide
Thomas A. Smith 45 President and Chief Executive Officer
Michael W. Price 39 Chief Operating Officer
W. Clayton Robbins 53 Senior Vice President, Finance and Administration
Larry N. Chadwick 59 Member Director, Northwest Region
Benny W. Denham 69 Member Director, Southwest Region and Vice Chairman
Sammy M. Jenkins 73 Member Director, Southeast Region
Mac F. Oglesby 67 Member Director, Northeast Region and Treasurer
J. Sam L. Rabun 68 Member Director, Central Region
Ashley C. Brown 54 Outside Director
Wm. Ronald Duffey 58 Outside Director
John S. Ranson 70 Outside Director
J. Calvin Earwood is the Chairman of the Board and is the Member Director
elected statewide. Mr. Earwood has served as an executive officer of Oglethorpe
since March 1984 (from March 1984 to July 1986, as Vice President; from July
1986 to March 1989, as Vice Chairman of the Board; and since March 1989, as
Chairman of the Board). Mr. Earwood has served on the Board of Directors of
Oglethorpe since March 1981. His present term will expire in March 2000. He is
the Chairman of the Compensation
64
Committee. From 1965 through 1982, Mr. Earwood was a salesman and part owner of
Builders Equipment Company. Since January 1983, he has been the owner and
President of Sunbelt Fasteners, Inc., which sells specialty tools and fasteners
to the commercial construction trade. He is also Vice Chairman of the Board of
Directors of both Community Trust Financial Services and Community Trust Bank in
Hiram, Georgia and a Director of GreyStone Power Corporation.
Thomas A. Smith is the President and Chief Executive Officer of Oglethorpe
and has served in that capacity since September 1999. He previously served as
Senior Vice President and Chief Financial Officer of Oglethorpe from September
1998 to August 1999, Senior Financial Officer from 1997 to August 1998, Vice
President, Finance from 1986 to 1990, Manager of Finance from 1983 to 1986 and
Manager, Financial Services from 1979 to 1983. From 1990 to 1997, Mr. Smith was
Senior Vice President of the Rural Utility Banking Group of CoBank, where he
managed the bank's eastern division, rural utilities. Mr. Smith is a Certified
Public Accountant, has a Master of Science degree in Industrial
Management-Finance from the Georgia Institute of Technology, a Master of Science
degree in Analytical Chemistry from Purdue University and a Bachelor of Arts
degree in Mathematics and Chemistry from Catawba College.
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 has 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.
Larry N. Chadwick is the Member Director from the Northwest Region. He has
been the owner of Chadwick's Hardware in Woodstock, Georgia since 1983. He has
served on the Board of Directors of Oglethorpe since July 1989. His present term
will expire in March 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 Vice-Chairman of the Board and 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. He
was previously the Vice-Chairman of the Executive Committee and a member of the
Power Planning and Technical Advisory Committee. Mr. Denham has been co-owner of
Denham Farms in Turner County, Georgia since 1980. He served on the Turner
County Commission from 1980 to 1990, and was Chairman for six of those years.
Mr. Denham is a Director of Community National Bank in Ashburn, Georgia and a
Director of Irwin EMC.
Sammy M. Jenkins is the Member Director from the Southeast Region. He has
retired from farming after 25 years. In addition, from 1973 to 1995, he was
President of Jenkins Ford Tractor Co., Inc., a seller of farm machinery. He has
served on the Board of Directors of Oglethorpe since March 1988. His present
65
term will expire in March 2002. He was Vice Chairman of the Board of Oglethorpe
from March 1989 to March 1990.
Mac F. Oglesby is the Member Director from the Northeast Region and the
Treasurer of Oglethorpe. He served as Assistant Secretary-Treasurer of the Board
of Directors of Hart EMC from July 1986 through December 1987, when he was
appointed President of the Board. He has served on the Board of Directors of
Oglethorpe since February 1987. His present term will expire in March 2000. Mr.
Oglesby was a U.S. Postal Service Rural Carrier for 30 years until he retired in
1991.
J. Sam L. Rabun is the Member Director from the Central Region. He is also
a member of the Compensation Committee. He has been the owner and operator of a
farm in Jefferson County, Georgia since 1979. He is also a 50% owner of R&R
Livestock Farms, Inc. He has served on the Board of Directors of Oglethorpe
since March 1993. His present term will expire in March 2001. Mr. Rabun served
as the President of the Board of Jefferson EMC from 1993 to 1996, was employed
as General Manager from 1974 to 1979 and as Office Manager and Accountant from
1970 to 1974.
Ashley C. Brown is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. His present term will expire in March
2002. He has been Executive Director of the Harvard Electricity Policy Group at
Harvard University's John F. Kennedy School of Government since 1993. In
addition, he is Of Counsel to the law firm of LeBouef, Lamb, Greene and MacRae.
From April 1983 through April 1993, Mr. Brown served as Commissioner of the
Public Utilities Commission of Ohio. Prior to his appointment to the Ohio
Commission, he was Coordinator and Counsel of the Montgomery County, Ohio, Fair
Housing Center. From 1979 to 1981, he was Managing Attorney for the Legal Aid
Society of Dayton (Ohio), Inc. From 1977 to 1979, he was Legal Advisor of the
Miami Valley Regional Planning Commission in Dayton, Ohio. In addition, Mr.
Brown has extensive teaching experience in public schools and universities and
has published widely in the field of utility regulation. Mr. Brown has a law
degree from the University of Dayton School of Law, a Master of Arts degree from
the University of Cincinnati, and a Bachelor of Science degree from Bowling
Green State University.
Wm. Ronald Duffey is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. His term will expire in March 2001.
Mr. Duffey is the President and Chief Executive Officer and a director of
Peachtree National Bank in Peachtree City, Georgia, a wholly owned subsidiary of
Synovus Financial Corp. Prior to his employment in 1985 with Peachtree National
Bank, Mr. Duffey served as Executive Vice President and Member of the Board of
Directors for First National Bank in Newnan, Georgia. He holds a Bachelor of
Business Administration from Georgia State College with a concentration in
finance and has completed banking courses at the Banking School of the South,
the American Bankers Association School of Bank Investments, and The Stonier
Graduate School of Banking, Rutgers University.
John S. Ranson is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. His term will expire in March 2002. He
is also a member of the Compensation Committee. He has been the President of
Ranson Municipal Consultants, L.L.C. in Wichita, Kansas since 1994. From 1990 to
1994, Mr. Ranson was Chairman of Ranson Capital Corp. an investment banking
firm. Mr. Ranson has approximately 47 years experience in the investment banking
business. His public finance clients have included the Kansas Local Utility
Improvement 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.
66
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth, for Oglethorpe's President and Chief
Executive Officer and for two other senior executives, all compensation paid or
accrued for services rendered in all capacities during the years ended December
31, 1999, 1998 and 1997. For 1999 and 1998, the amounts included in the table
under "Bonus" represent a compensation program based on the achievement of
corporate and team goals and individual performance. For 1997, the amounts
included in the table under "Bonus" represent payments based on Oglethorpe's
prior incentive compensation policy.
NAME AND ANNUAL COMPENSATION
--------------------- ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION
- ------------------ ---- ------ ----- ------------
Thomas A. Smith(1) 1999 $ 202,008 $ 65,283 $ 14,237(2)
President and Chief Executive Officer 1998 183,935 12,180 1,247
1997 70,192 0 0
Jack L. King(3) 1999 177,083 0 275,337(4)
Former President and Chief Executive Officer 1998 115,555 37,500 3,731
1997 0 0 0
Jerry J. Saacks(5) 1999 180,000 46,800 15,245(2)
Former Chief Operating Officer 1998 7,732 0 116
1997 0 0 0
- ------------------
(1) Prior to September 1, 1998, Mr. Smith provided services to Oglethorpe under
a contractual arrangement and the amounts reflected in the above table
include those contract payments.
(2) Includes contributions made in 1999 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. Smith and Saacks of $4,800 and
$4,800, respectively; contributions under the Money Purchase Pension Plan
on behalf of Messrs. Smith and Saacks of $9,147, and $8,250; and insurance
premiums paid on term life insurance on behalf of Messrs. Smith, and Saacks
of $290, and $ 2,195, respectively.
(3) Mr. King resigned from Oglethorpe effective September 15, 1999.
(4) Includes separation payments of $145,833 in continued salary through April
15, 2000 and a $100,000 payment on April 15, 2000. Also includes
contributions on behalf of Mr. King under the 401(k) Retirement Savings
Plan of $7,584 and under the Money Purchase Pension Plan of $16,979; and
insurance premiums paid on term life insurance on behalf of Mr. King of
$4,941.
(5) Mr. Saacks resigned as Chief Operating Officer of Oglethorpe in January
2000 to become Chief Executive Officer of GSOC. Amounts paid to Mr. Saacks
for 1998 reflect his employment by Oglethorpe beginning December 11, 1998.
PENSION PLAN
Oglethorpe terminated its pension plan effective April 5, 1999 and
distributed benefits under the pension plan to all eligible recipients in the
form of a cash payment, an annuity, or a contribution to the recipient's Money
Purchase Plan account.
COMPENSATION OF DIRECTORS
Oglethorpe pays its Outside Directors a fee of $5,500 per Board meeting for
four meetings in a year; a fee of $1,000 per Board meeting will be paid for the
remaining other Board meetings in a year. Outside Directors are also paid $1,000
per day for attending committee meetings, annual meetings of the Members or
other official meetings of Oglethorpe. Member Directors are paid a fee of $1,000
per Board meeting and $600 per day for attending committee meetings, annual
meetings of the Members or other official business of Oglethorpe. In addition,
Oglethorpe reimburses all Directors for out-of-pocket expenses incurred in
attending a meeting. All Directors are paid $50 per day when participating in
meetings by
67
conference call. The Chairman of the Board is paid an additional 20%
of his Director's fee per Board meeting for time involved in preparing for the
meetings.
EMPLOYMENT CONTRACTS
Oglethorpe entered into an Employment Agreement with Thomas A. Smith,
Oglethorpe's President and Chief Executive Officer, effective September 15,
1999. The agreement extends until December 31, 2002, and automatically renews
for successive one-year periods unless either party gives notice of termination
prior to December 31, 2000 or 25 months prior to the expiration of any extension
of the agreement. Mr. Smith's minimum base salary is $250,000 per year, and is
annually adjusted by the Board of Directors of Oglethorpe. In addition, Mr.
Smith has opportunities for variable pay for accomplishing goals set by
Oglethorpe's Board of Directors each year.
Upon the occurrence of any of the following events, Mr. Smith will be
entitled to a lump-sum severance payment: (1) Oglethorpe terminates Mr.
Smith's employment without cause; (2) Mr. Smith resigns within 180 days of a
material reduction or alteration of his title or responsibilities or a change
in the location of Mr. Smith's principal office by more than 50 miles; (3)
Oglethorpe is sold or Oglethorpe sells essentially all of its assets or
control of its assets, and the sale results in a termination of Mr. Smith's
employment as President and Chief Executive Officer of Oglethorpe or a
material reduction of his title or responsibilities; or (4) an event of
default under Oglethorpe's RUS loan contract occurs and is continuing and RUS
requests that Oglethorpe terminate Mr. Smith. The severance payment will
equal Mr. Smith's base salary through the rest of the term of the agreement
(with a minimum of one year's pay and a maximum of two years' pay) plus the
cost of providing all health and dental insurance for the longer of one year
or the remaining term of the agreement. In the case of (3) above, Oglethorpe
also agrees to hire Mr. Smith as a consultant for one year at a rate equal to
his then-applicable base salary.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
J. Calvin Earwood, John S. Ranson and J. Sam L. Rabun served as members of
the Oglethorpe Power Corporation Compensation Committee in 1999. Mr. Earwood has
served as an executive officer of Oglethorpe since 1984 and has served as the
Chairman of the Board since 1989.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Oglethorpe paid $162,000 to Hartrampf Engineering, Inc. for construction
and project management services relating to Smarr EMC in 1999. William
Hartrampf, the father-in-law of Michael Price, Oglethorpe's Chief Operating
Officer, owned a minority interest in Hartrampf Engineering during 1999. Mr.
Hartrampf sold his interest in Hartrampf Engineering in March 2000 and no
longer has any interest in the firm.
68
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
PAGE
----
(a) LIST OF DOCUMENTS FILED AS A PART OF THIS REPORT.
(1) FINANCIAL STATEMENTS (Included under "Item 8. Financial
Statements and Supplementary Data")
Statements of Revenues and Expenses, For the Years Ended
December 31, 1999, 1998 and 1997 45
Statements of Patronage Capital, For the Years Ended
December 31, 1999, 1998 and 1997 45
Balance Sheets, As of December 31, 1999 and 1998 46
Statements of Capitalization, As of December 31, 1999 and 1998 48
Statements of Cash Flows,
For the Years Ended December 31, 1999, 1998 and 1997 49
Notes to Financial Statements 50
Report of Management 63
Report of Independent Accountants 63
(2) FINANCIAL STATEMENT SCHEDULES
None applicable.
(3) EXHIBITS
Exhibits marked with an asterisk (*) are hereby incorporated by reference
to exhibits previously filed by the Registrant as indicated in parentheses
following the description of the exhibit.
NUMBER DESCRIPTION
- ------ ----------
*2.1 -- Second Amended and Restated Restructuring Agreement, dated
February 24, 1997, by and among Oglethorpe, Georgia Transmission
Corporation (An Electric Membership Corporation) and Georgia
System Operations Corporation. (Filed as Exhibit 2.1 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*2.2 -- Member Agreement, dated August 1, 1996, by and among Oglethorpe,
Georgia Transmission Corporation (An Electric Membership
Corporation), Georgia System Operations Corporation and the
Members of Oglethorpe. (Filed as Exhibit 2.2 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*3.1(a) -- Restated Articles of Incorporation of Oglethorpe, dated as of
July 26, 1988. (Filed as Exhibit 3.1 to the Registrant's Form
10-K for the fiscal year ended December 31, 1988, File No.
33-7591.)
*3.1(b) -- Amendment to Articles of Incorporation of Oglethorpe, dated as of
March 11, 1997. (Filed as Exhibit 3(i)(b) to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
3.2 -- Bylaws of Oglethorpe, as amended on January 10, 2000.
69
*4.1 -- Form of Serial Facility Bond Due June 30, 2011 (included in
Collateral Trust Indenture filed as Exhibit 4.2.)
*4.2 -- Collateral Trust Indenture, dated as of December 1, 1997, between
OPC Scherer 1997 Funding Corporation A, Oglethorpe and SunTrust
Bank, Atlanta, as Trustee. (Filed as Exhibit 4.2 to the
Registrant's Form S-4 Registration Statement, File No.
333-42759.)
*4.3 -- Nonrecourse Promissory Lessor Note No. 2, with a Schedule
identifying three other substantially identical Nonrecourse
Promissory Lessor Notes and any material differences. (Filed as
Exhibit 4.3 to the Registrant's Form S-4 Registration Statement,
File No. 333-42759.)
*4.4 -- Amended and Restated Indenture of Trust, Deed to Secure Debt and
Security Agreement No. 2, dated December 1, 1997, between
Wilmington Trust Company and NationsBank, N.A. collectively as
Owner Trustee, under Trust Agreement No. 2, dated December 30,
1985, with DFO Partnership, as assignee of Ford Motor Credit
Company, and The Bank of New York Trust Company of Florida, N.A.
as Indenture Trustee, with a Schedule identifying three other
substantially identical Amended and Restated Indentures of Trust,
Deeds to Secure Debt and Security Agreements and any material
differences. (Filed as Exhibit 4.4 to the Registrant's Form S-4
Registration Statement, File No. 333-42759.)
*4.5(a) -- Lease Agreement No. 2 dated December 30, 1985, between Wilmington
Trust Company and William J. Wade, as Owner Trustees under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, Lessor, and Oglethorpe, Lessee, with a Schedule
identifying three other substantially identical Lease Agreements.
(Filed as Exhibit 4.5(b) to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*4.5(b) -- First Supplement to Lease Agreement No. 2 (included as Exhibit B
to the Supplemental Participation Agreement No. 2 listed as
10.1.1(b)).
*4.5(c) -- First Supplement to Lease Agreement No. 1, dated as of June 30,
1987, between The Citizens and Southern National Bank as Owner
Trustee under Trust Agreement No. 1 with IBM Credit Financing
Corporation, as Lessor, and Oglethorpe, as Lessee. (Filed as
Exhibit 4.5(c) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1987, File No. 33-7591.)
*4.5(d) -- Second Supplement to Lease Agreement No. 2, dated as of December
17, 1997, between NationsBank, N.A., acting through its agent,
The Bank of New York, as an Owner Trustee under the Trust
Agreement No. 2, dated December 30, 1985, among DFO Partnership,
as assignee of Ford Motor Credit Company, as the Owner
Participant, and the Original Trustee, as Lessor, and Oglethorpe,
as Lessee, with a Schedule identifying three other substantially
identical Second Supplements to Lease Agreements and any material
differences. (Filed as Exhibit 4.5(d) to the Registrant's Form
S-4 Registration Statement, File No. 333-42759.)
*4.6 -- Amended and Consolidated Loan Contract, dated as of March 1,
1997, between Oglethorpe and the United States of America,
together with four notes executed and delivered pursuant thereto.
(Filed as Exhibit 4.7 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*4.7.1(a) -- Indenture, dated as of March 1, 1997, made by Oglethorpe to
SunTrust Bank, Atlanta, as trustee. (Filed as Exhibit 4.8.1 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
70
*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.
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.
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.
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.
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.
*4.7.2 -- Security Agreement, dated as of March 1, 1997, made by Oglethorpe
to SunTrust Bank, Atlanta, as trustee. (Filed as Exhibit 4.8.2 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
4.8.1(1) -- Loan Agreement, dated as of October 1, 1992, between Development
Authority of Monroe County and Oglethorpe relating to Development
Authority of Monroe County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Scherer Project), Series 1992A, and
five other substantially identical loan agreements.
71
4.8.2(1) -- Note, dated October 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated as
of October 1, 1992, between Development Authority of Monroe
County and Trust Company Bank, and five other substantially
identical notes.
4.8.3(1) -- Trust Indenture, dated as of October 1, 1992, between Development
Authority of Monroe County and Trust Company Bank, Trustee,
relating to Development Authority of Monroe County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Scherer
Project), Series 1992A, and five other substantially identical
trust indentures.
4.9.1(1) -- Loan Agreement, dated as of December 1, 1992, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Adjustable Tender Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A, and one other substantially identical loan
agreement.
4.9.2(1) -- Note, dated December 1, 1992, from Oglethorpe to Trust Company
Bank, as trustee acting pursuant to a Trust Indenture, dated as
of December 1, 1992, between Development Authority of Burke
County and Trust Company Bank, and one other substantially
identical note.
4.9.3(1) -- Trust Indenture, dated as of December 1, 1992, from Development
Authority of Burke County to Trust Company Bank, as trustee,
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1993A, and one other
substantially identical trust indenture.
4.9.4(1) -- Interest Rate Swap Agreement, dated as of December 1, 1992, by
and between Oglethorpe and AIG Financial Products Corp. relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A, and one other substantially
identical agreement.
4.9.5(1) -- Liquidity Guaranty Agreement, dated as of December 1, 1992, by
and between Oglethorpe and AIG Financial Products Corp. relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A, and one other substantially
identical agreement.
4.9.6(1) -- Standby Bond Purchase Agreement, dated as of December 1, 1998,
between Oglethorpe and Bayerische Landesbank Girozentrale,
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1993A.
4.9.7(1) -- Standby Bond Purchase Agreement, dated as of November 30, 1994,
between Oglethorpe and Credit Local de France, Acting through its
New York Agency, relating to Development Authority of Burke
County Adjustable Tender Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1994A.
4.10.1(1) -- Loan Agreement, dated as of October 1, 1996, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1996, and
one other substantially identical loan agreements.
72
4.10.2(1) -- Note, dated October 1, 1996, from Oglethorpe to SunTrust Bank,
Atlanta, as trustee pursuant to an Indenture of Trust, dated as
of October 1, 1996, between Development Authority of Burke County
and SunTrust Bank, Atlanta, and one other substantially identical
note.
4.10.3(1) -- Indenture of Trust, dated as of October 1, 1996, between
Development Authority of Burke County and SunTrust Bank, Atlanta,
as trustee, relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1996, and one other substantially
identical indenture.
4.11.1(1) -- Loan Agreement, dated as of December 1, 1997, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project) Series 1997C, and
three other substantially identical loan agreements.
4.11.2(1) -- Note, dated January 14, 1998, from Oglethorpe to SunTrust Bank,
Atlanta, as trustee pursuant to an Indenture of Trust, dated as
of December 1, 1997, between Development Authority of Burke
County and SunTrust Bank, Atlanta, and three other substantially
identical notes.
4.11.3(1) -- Indenture of Trust, dated as of December 1, 1997, between
Development Authority of Burke County and SunTrust Bank, Atlanta,
as trustee, relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1997C, and three other substantially
identical indentures.
4.12.1(1) -- Loan Agreement, dated as of March 1, 1998, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series 1998A, and
one other substantially identical loan agreement.
4.12.2(1) -- Note, dated March 17, 1998, from Oglethorpe to SunTrust Bank,
Atlanta, as trustee pursuant to a Trust Indenture, dated as of
March 1, 1998, between Development Authority of Burke County and
SunTrust Bank, Atlanta, and one other substantially identical
note.
4.12.3(1) -- Trust Indenture, dated as of March 1, 1998, between Development
Authority of Burke County and SunTrust Bank, Atlanta, as trustee,
relating to Development Authority of Burke County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1998A, and one other substantially identical
indenture.
4.12.4(1) -- Standby Bond Purchase Agreement, dated March 17, 1998, between
Oglethorpe and Cooperatieve Centrale Raiffeisen-Boerenleenbank
B.A., "Rabobank Nederland", acting through its New York Branch,
relating to Development Authority of Burke County Pollution
Control Revenue Bonds (Oglethorpe Power Corporation Vogtle
Project), Series 1998A, and one other substantially identical
agreement.
*4.13.1 -- Indemnity Agreement, dated as of March 1, 1997, by and between
Oglethorpe and Georgia Transmission Corporation (An Electric
Membership Corporation). (Filed as Exhibit 4.13.1 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
73
*4.13.2 -- Indemnification Agreement, dated as of March 11, 1997, by
Oglethorpe and Georgia Transmission Corporation (An Electric
Membership Corporation) for the benefit of the United States of
America. (Filed as Exhibit 4.13.2 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1996, File No. 33-7591.)
4.14.1(1) -- Master Loan Agreement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, MLA No. 0459.
4.14.2(1) -- Consolidating Supplement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T1.
4.14.3(1) -- Promissory Note, dated March 1, 1997, in the original principal
amount of $7,102,740.26, from Oglethorpe to CoBank, ACB, relating
to Loan No. ML0459T1.
4.14.4(1) -- Consolidating Supplement, dated as of March 1, 1997, between
Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T2.
4.14.5(1) -- Promissory Note, dated March 1, 1997, in the original principal
amount of $1,856,475.12, made by Oglethorpe to CoBank, ACB,
relating to Loan No. ML0459T2.
4.14.6(1) -- Single Advance Term Loan Supplement, dated as of March 31, 1998,
between Oglethorpe and CoBank, ACB, relating to Loan No.
ML0459T3.
4.14.7(1) -- Promissory Note, dated March 31, 1998, in the original principal
amount of $46,065,000.00, made by Oglethorpe to CoBank, ACB,
relating to Loan No. ML0459T3.
*4.15.1 -- Loan Agreement, Loan No. T-830404, between Oglethorpe and
Columbia Bank for Cooperatives, dated as of April 29, 1983.
(Filed as Exhibit 4.18.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*4.15.2 -- Promissory Note, Loan No. T-830404-1, in the original principal
amount of $9,935,000, from Oglethorpe to Columbia Bank for
Cooperatives, dated as of April 29, 1983. (Filed as Exhibit
4.18.2 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*4.15.3 -- Security Deed and Security Agreement, dated April 29, 1983,
between Oglethorpe and Columbia Bank for Cooperatives. (Filed as
Exhibit 4.18.3 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*4.16 -- Exchange and Registration Rights Agreement, dated December 17,
1997, by and among Oglethorpe, OPC Scherer 1997 Funding
Corporation A, and Goldman, Sachs & Co. as representative of the
purchasers identified therein. (Filed as Exhibit 4.15 to the
Registrant's Form S-4 Registration Statement, File No.
333-42759.)
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.
74
*10.1.1(a)-- Participation Agreement No. 2 among Oglethorpe as Lessee,
Wilmington Trust Company as Owner Trustee, The First National
Bank of Atlanta as Indenture Trustee, Columbia Bank for
Cooperatives as Loan Participant and Ford Motor Credit Company as
Owner Participant, dated December 30, 1985, together with a
Schedule identifying three other substantially identical
Participation Agreements. (Filed as Exhibit 10.1.1(b) to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.1(b)-- Supplemental Participation Agreement No. 2. (Filed as Exhibit
10.1.1(a) to the Registrant's Form S-1 Registration Statement,
File No. 33-7591.)
*10.1.1(c)-- Supplemental Participation Agreement No. 1, dated as of June 30,
1987, among Oglethorpe as Lessee, IBM Credit Financing
Corporation as Owner Participant, Wilmington Trust Company and
The Citizens and Southern National Bank as Owner Trustee, The
First National Bank of Atlanta, as Indenture Trustee, and
Columbia Bank for Cooperatives, as Loan Participant. (Filed as
Exhibit 10.1.1(c) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1987, File No. 33-7591.)
*10.1.1(d)-- Second Supplemental Participation Agreement No. 2, dated as of
December 17, 1997, among Oglethorpe as Lessee, DFO Partnership,
as assignee of Ford Motor Credit Company, as Owner Participant,
Wilmington Trust Company and NationsBank, N.A. as Owner Trustee,
The Bank of New York Trust Company of Florida, N.A. as Indenture
Trustee, CoBank, ACB as Loan Participant, OPC Scherer Funding
Corporation, as Original Funding Corporation, OPC Scherer 1997
Funding Corporation A, as Funding Corporation, and SunTrust Bank,
Atlanta, as Original Collateral Trust Trustee and Collateral
Trust Trustee, with a Schedule identifying three substantially
identical Second Supplemental Participation Agreements and any
material differences. (Filed as Exhibit 10.1.1(d) to Registrant's
Form S-4 Registration Statement, File No. 333-4275.)
*10.1.2 -- General Warranty Deed and Bill of Sale No. 2 between Oglethorpe,
Grantor, and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Grantee, together with a
Schedule identifying three substantially identical General
Warranty Deeds and Bills of Sale. (Filed as Exhibit 10.1.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.3(a)-- Supporting Assets Lease No. 2, dated December 30, 1985, between
Oglethorpe, Lessor, and Wilmington Trust Company and William J.
Wade, as Owner Trustees, under Trust Agreement No. 2, dated
December 30, 1985, with Ford Motor Credit Company, Lessee,
together with a Schedule identifying three substantially
identical Supporting Assets Leases. (Filed as Exhibit 10.1.3 to
the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*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.)
75
*10.1.3(c)-- Second Amendment to Supporting Assets Lease No. 2, dated as of
October 3, 1989, together with a Schedule identifying three
substantially identical Second Amendments to Supporting Assets
Leases. (Filed as Exhibit 10.1.3(c) to the Registrant's Form 10-Q
for the quarterly period ended March 31, 1998, File No. 33-7591.)
*10.1.4(a)-- Supporting Assets Sublease No. 2, dated December 30, 1985,
between Wilmington Trust Company and William J. Wade, as Owner
Trustees under Trust Agreement No. 2 dated December 30, 1985,
with Ford Motor Credit Company, Sublessor, and Oglethorpe,
Sublessee, together with a Schedule identifying three
substantially identical Supporting Assets Subleases. (Filed as
Exhibit 10.1.4 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.1.4(b)-- First Amendment to Supporting Assets Sublease No. 2, dated as of
November 19, 1987, together with a Schedule identifying three
substantially identical First Amendments to Supporting Assets
Subleases. (Filed as Exhibit 10.1.4(a) to the Registrant's Form
10-K for the fiscal year ended December 31, 1987, File No.
33-7591.)
*10.1.4(c)-- Second Amendment to Supporting Assets Sublease No. 2, dated as of
October 3, 1989, together with a Schedule identifying three
substantially identical Second Amendments to Supporting Assets
Subleases. (Filed as Exhibit 10.1.4(c) to the Registrant's Form
10-Q for the quarterly period ended March 31, 1998, File No.
33-7591.)
*10.1.5(a)-- Tax Indemnification Agreement No. 2, dated December 30, 1985,
between Ford Motor Credit Company, Owner Participant, and
Oglethorpe, Lessee, together with a Schedule identifying three
substantially identical Tax Indemnification Agreements. (Filed as
Exhibit 10.1.5 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.1.5(b)-- Amendment No. 1 to the Tax Indemnification Agreement No. 2, dated
December 17, 1997, between DFO Partnership, as assignee of Ford
Motor Credit Company, as Owner Participant, and Oglethorpe, as
Lessee, with a Schedule identifying three substantially identical
Amendments No. 1 to the Tax Indemnification Agreements and any
material differences. (Filed as Exhibit 10.1.5(b) to the
Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*10.1.6 -- Assignment of Interest in Ownership Agreement and Operating
Agreement No. 2, dated December 30, 1985, between Oglethorpe,
Assignor, and Wilmington Trust Company and William J. Wade, as
Owner Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Assignee, together with
Schedule identifying three substantially identical Assignments of
Interest in Ownership Agreement and Operating Agreement. (Filed
as Exhibit 10.1.6 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*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.)
76
*10.1.7(a)-- Amendment to Consent, Amendment and Assumption No. 2, dated as of
August 16, 1993, among Oglethorpe, Georgia Power Company,
Municipal Electric Authority of Georgia, City of Dalton, Georgia,
Gulf Power Company, Jacksonville Electric Authority, Florida
Power & Light Company and Wilmington Trust Company and
NationsBank of Georgia, N.A., as Owner Trustees under Trust
Agreement No. 2, dated December 30, 1985, with Ford Motor Credit
Company, together with a Schedule identifying three substantially
identical Amendments to Consents, Amendments and Assumptions.
(Filed as Exhibit 10.1.9(a) to the Registrant's Form 10-Q for the
quarterly period ended September 30, 1993, File No. 33-7591.)
*10.2.1 -- Section 168 Agreement and Election dated as of April 7, 1982,
between Continental Telephone Corporation and Oglethorpe. (Filed
as Exhibit 10.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.2.2 -- Section 168 Agreement and Election dated as of April 9, 1982,
between Rollins, Inc. and Oglethorpe. (Filed as Exhibit 10.4 to
the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.3.1(a)-- Plant Robert W. Scherer Units Numbers One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit
10.6.1 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.3.1(b)-- Amendment to Plant Robert W. Scherer Units Numbers One and Two
Purchase and Ownership Participation Agreement among Georgia
Power Company, Oglethorpe, Municipal Electric Authority of
Georgia and City of Dalton, Georgia, dated as of December 30,
1985. (Filed as Exhibit 10.1.8 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.3.1(c)-- Amendment Number Two to the Plant Robert W. Scherer Units Numbers
One and Two Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia, dated as of July 1, 1986.
(Filed as Exhibit 10.6.1(a) to the Registrant's Form 10-K for the
fiscal year ended December 31, 1987, File No. 33-7591.)
*10.3.1(d)-- Amendment Number Three to the Plant Robert W. Scherer Units
Numbers One and Two Purchase and Ownership Participation
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 1, 1988. (Filed as Exhibit 10.6.1(b) to the
Registrant's Form 10-Q for the quarterly period ended September
30, 1993, File No. 33-7591.)
*10.3.1(e)-- Amendment Number Four to the Plant Robert W. Scherer Units Number
One and Two Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia, dated as of December 31,
1990. (Filed as Exhibit 10.6.1(c) to the Registrant's Form 10-Q
for the quarterly period ended September 30, 1993, File No.
33-7591.)
*10.3.2(a)-- Plant Robert W. Scherer Units Numbers One and Two Operating
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of May 15, 1980. (Filed as Exhibit 10.6.2 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
77
*10.3.2(b)-- Amendment to Plant Robert W. Scherer Units Numbers One and Two
Operating Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.7
to the Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*10.3.2(c)-- Amendment Number Two to the Plant Robert W. Scherer Units Numbers
One and Two Operating Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of December 31, 1990. (Filed as Exhibit
10.6.2(a) to the Registrant's Form 10-Q for the quarterly period
ended September 30, 1993, File No. 33-7591.)
*10.3.3 -- Plant Scherer Managing Board Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia,
City of Dalton, Georgia, Gulf Power Company, Florida Power &
Light Company and Jacksonville Electric Authority, dated as of
December 31, 1990. (Filed as Exhibit 10.6.3 to the Registrant's
Form 10-Q for the quarterly period ended September 30, 1993, File
No. 33-7591.)
*10.4.1(a)-- Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and
Ownership Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit
10.7.1 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.4.1(b)-- Amendment Number One, dated January 18, 1977, to the Alvin W.
Vogtle Nuclear Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia. (Filed as Exhibit 10.7.3 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.1(c)-- Amendment Number Two, dated February 24, 1977, to the Alvin W.
Vogtle Nuclear Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company, Oglethorpe,
Municipal Electric Authority of Georgia and City of Dalton,
Georgia. (Filed as Exhibit 10.7.4 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.2 -- Alvin W. Vogtle Nuclear Units Numbers One and Two Operating
Agreement among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton, Georgia, dated
as of August 27, 1976. (Filed as Exhibit 10.7.2 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.5.1 -- Plant Hal Wansley Purchase and Ownership Participation Agreement
between Georgia Power Company and Oglethorpe, dated as of March
26, 1976. (Filed as Exhibit 10.8.1 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.5.2(a)-- Plant Hal Wansley Operating Agreement between Georgia Power
Company and Oglethorpe, dated as of March 26, 1976. (Filed as
Exhibit 10.8.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
78
*10.5.2(b)-- Amendment, dated as of January 15, 1995, to the Plant Hal Wansley
Operating Agreements by and among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and City of
Dalton, Georgia. (Filed as Exhibit 10.5.2(a) to the Registrant's
Form 10-Q for the quarterly period ended September 30, 1996, File
No. 33-7591.)
*10.5.3 -- Plant Hal Wansley Combustion Turbine Agreement between Georgia
Power Company and Oglethorpe, dated as of August 2, 1982 and
Amendment No. 1, dated October 20, 1982. (Filed as Exhibit 10.18
to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.6.1 -- Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation
Agreement between Georgia Power Company and Oglethorpe, dated as
of January 6, 1975. (Filed as Exhibit 10.9.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591.)
*10.6.2 -- Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia
Power Company and Oglethorpe, dated as of January 6, 1975. (Filed
as Exhibit 10.9.2 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.7.1 -- Rocky Mountain Pumped Storage Hydroelectric Project Ownership
Participation Agreement, dated as of November 18, 1988, by and
between Oglethorpe and Georgia Power Company. (Filed as Exhibit
10.22.1 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1988, File No. 33-7591.)
*10.7.2 -- Rocky Mountain Pumped Storage Hydroelectric Project Operating
Agreement, dated as of November 18, 1988, by and between
Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.2
to the Registrant's Form 10-K for the fiscal year ended December
31, 1988, File No. 33-7591.)
*10.8.1 -- Amended and Restated Wholesale Power Contract, dated as of August
1, 1996, between Oglethorpe and Altamaha Electric Membership
Corporation and all schedules thereto, together with a Schedule
identifying 37 other substantially identical Amended and Restated
Wholesale Power Contracts, and an additional Amended and Restated
Wholesale Power Contract that is not substantially identical.
(Filed as Exhibit 10.8.1 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.2 -- Amended and Restated Supplemental Agreement, dated as of August
1, 1996, by and between Oglethorpe, Altamaha Electric Membership
Corporation and the United States of America, together with a
Schedule identifying 38 other substantially identical Amended and
Restated Supplemental Agreements. (Filed as Exhibit 10.8.2 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.8.3 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of January 1, 1997, by and among Georgia
Power Company, Oglethorpe and Altamaha Electric Membership
Corporation, together with a Schedule identifying 38 other
substantially identical Supplemental Agreements. (Filed as
Exhibit 10.8.3 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
79
*10.8.4 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of March 1, 1997, by and between
Oglethorpe and Altamaha Electric Membership Corporation, together
with a Schedule identifying 36 other substantially identical
Supplemental Agreements, and an additional Supplemental Agreement
that is not substantially identical. (Filed as Exhibit 10.8.4 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.8.5 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of March 1, 1997, by and between
Oglethorpe and Coweta-Fayette Electric Membership Corporation,
together with a Schedule identifying 1 other substantially
identical Supplemental Agreement. (Filed as Exhibit 10.8.5 to the
Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.8.6 -- Supplemental Agreement to the Amended and Restated Wholesale
Power Contract, dated as of May 1, 1997 by and between Oglethorpe
and Altamaha Electric Membership Corporation, together with a
Schedule identifying 38 other substantially identical
Supplemental Agreements. (Filed as Exhibit 10.8.6 to the
Registrant's Form 10-Q for the quarterly period ended June 30,
1997, File No. 33-7591.)
*10.9(a) -- Joint Committee Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and the City
of Dalton, Georgia, dated as of August 27, 1976. (Filed as
Exhibit 10.14(b) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.9(b) -- First Amendment to Joint Committee Agreement among Georgia Power
Company, Oglethorpe, Municipal Electric Authority of Georgia and
the City of Dalton, Georgia, dated as of June 19, 1978. (Filed as
Exhibit 10.14(a) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*10.10 -- Letter of Commitment (Firm Power Sale) Under Service Schedule
J--Negotiated Interchange Service between Alabama Electric
Cooperative, Inc. and Oglethorpe, dated March 31, 1994. (Filed as
Exhibit 10.11(b) to the Registrant's Form 10-Q for the quarter
ended June 30, 1994, File No. 33-7591.)
*10.11.1 -- Assignment of Power System Agreement and Settlement Agreement,
dated January 8, 1975, by Georgia Electric Membership Corporation
to Oglethorpe. (Filed as Exhibit 10.20.1 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591.)
*10.11.2 -- Power System Agreement, dated April 24, 1974, by and between
Georgia Electric Membership Corporation and Georgia Power
Company. (Filed as Exhibit 10.20.2 to the Registrant's Form S-1
Registration Statement, File No. 33-7591.)
*10.11.3 -- Settlement Agreement, dated April 24, 1974, by and between
Georgia Power Company, Georgia Municipal Association, Inc., City
of Dalton, Georgia Electric Membership Corporation and Crisp
County Power Commission. (Filed as Exhibit 10.20.3 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.12 -- Long-Term Firm Power Purchase Agreement between Big Rivers
Electric Corporation and Oglethorpe, dated as of December 17,
1990. (Filed as Exhibit 10.24.3 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1990, File No. 33-7591.)
80
*10.13 -- 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.)
*10.14 -- Revised and Restated Coordination Services Agreement between and
among Georgia Power Company, Oglethorpe and Georgia System
Operations Corporation, dated as of September 10, 1997. (Filed as
Exhibit 10.14 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1997, File No. 33-7591.)
*10.15 -- 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.)
*10.16 -- 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.)
*10.17 -- Supplemental Agreement by and among Oglethorpe, Tri-County
Electric Membership Corporation and Georgia Power Company, dated
as of November 12, 1990, together with a Schedule identifying 38
other substantially identical Supplemental Agreements. (Filed as
Exhibit 10.30 to the Registrant's Form 8-K, filed January 4,
1991, File No. 33-7591.)
*10.18 -- 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.)
*10.19 -- 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).
*10.20(2) -- Power Purchase and Sale Agreement among LG&E Power Marketing
Inc., LG&E Energy Corp. and Oglethorpe, dated as of November 19,
1996. (Filed as Exhibit 10.30 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.21(2) -- Power Purchase and Sale Agreement among LG&E Power Marketing
Inc., LG&E Power Inc. and Oglethorpe, dated as of January 1,
1997. (Filed as Exhibit 10.31 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.22.1 -- Participation Agreement (P1), dated as of December 30, 1996,
among Oglethorpe, Rocky Mountain Leasing Corporation, Fleet
National Bank, as Owner Trustee, SunTrust Bank, Atlanta, as
Co-Trustee, the Owner Participant named therein and
Utrecht-America Finance Co., as Lender, together with a Schedule
identifying five other substantially identical Participation
Agreements. (Filed as Exhibit 10.32.1 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
81
*10.22.2 -- Rocky Mountain Head Lease Agreement (P1), dated as of December
30, 1996, between Oglethorpe and SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other
substantially identical Rocky Mountain Head Lease Agreements.
(Filed as Exhibit 10.32.2 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.22.3 -- Ground Lease Agreement (P1), dated as of December 30, 1996,
between Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other substantially
identical Ground Lease Agreements. (Filed as Exhibit 10.32.3 to
the Registrant's Form 10-K for the fiscal year ended December 31,
1996, File No. 33-7591.)
*10.22.4 -- Rocky Mountain Agreements Assignment and Assumption Agreement
(P1), dated as of December 30, 1996, between Oglethorpe and
SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Rocky Mountain
Agreements Assignment and Assumption Agreements. (Filed as
Exhibit 10.32.4 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
*10.22.5 -- Facility Lease Agreement (P1), dated as of December 30, 1996,
between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain
Leasing Corporation, together with a Schedule identifying five
other substantially identical Facility Lease Agreements. (Filed
as Exhibit 10.32.5 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.22.6 -- Ground Sublease Agreement (P1), dated as of December 30, 1996,
between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain
Leasing Corporation, together with a Schedule identifying five
other substantially identical Ground Sublease Agreements. (Filed
as Exhibit 10.32.6 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.22.7 -- Rocky Mountain Agreements Re-assignment and Assumption Agreement
(P1), dated as of December 30, 1996, between SunTrust Bank,
Atlanta, as Co-Trustee and Rocky Mountain Leasing Corporation,
together with a Schedule identifying five other substantially
identical Rocky Mountain Agreements Re-assignment and Assumption
Agreements. (Filed as Exhibit 10.32.7 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.22.8 -- Facility Sublease Agreement (P1), dated as of December 30, 1996,
between Oglethorpe and Rocky Mountain Leasing Corporation,
together with a Schedule identifying five other substantially
identical Facility Sublease Agreements. (Filed as Exhibit 10.32.8
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*10.22.9 -- Ground Sub-sublease Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation and Oglethorpe,
together with a Schedule identifying five other substantially
identical Ground Sub-sublease Agreements. (Filed as Exhibit
10.32.9 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.22.10 -- Rocky Mountain Agreements Second Re-assignment and Assumption
Agreement (P1), dated as of December 30, 1996, between Rocky
Mountain Leasing Corporation and Oglethorpe, together with a
Schedule identifying five other substantially identical Rocky
Mountain Agreements Second Re-assignment and Assumption
Agreements. (Filed as Exhibit 10.32.10 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
82
*10.22.11 -- Payment Undertaking Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation and Cooperatieve
Centrale Raiffeisen-Boerenleenbank B.A., New York Branch, as the
Bank, together with a Schedule identifying five other
substantially identical Payment Undertaking Agreements. (Filed as
Exhibit 10.32.11 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.22.12 -- Payment Undertaking Pledge Agreement (P1), dated as of December
30, 1996, between Rocky Mountain Leasing Corporation, Fleet
National Bank, as Owner Trustee, and SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other
substantially identical Payment Undertaking Pledge Agreements.
(Filed as Exhibit 10.32.12 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1996, File No. 33-7591.)
*10.22.13 -- Equity Funding Agreement (P1), dated as of December 30, 1996,
between Rocky Mountain Leasing Corporation, AIG Match Funding
Corp., the Owner Participant named therein, Fleet National Bank,
as Owner Trustee, and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other substantially
identical Equity Funding Agreements. (Filed as Exhibit 10.32.13
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*10.22.14 -- Equity Funding Pledge Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation and SunTrust
Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Equity Funding
Pledge Agreements. (Filed as Exhibit 10.32.14 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.22.15 -- Deed to Secure Debt, Assignment of Surety Bond and Security
Agreement (P1), dated as of December 30, 1996, between Rocky
Mountain Leasing Corporation, SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five other
substantially identical Collateral Assignment, Assignment of
Surety Bond and Security Agreements. (Filed as Exhibit 10.32.15
to the Registrant's Form 10-K for the fiscal year ended December
31, 1996, File No. 33-7591.)
*10.22.16 -- Subordinated Deed to Secure Debt and Security Agreement (P1),
dated as of December 30, 1996, among Oglethorpe, AMBAC Indemnity
Corporation and SunTrust Bank, Atlanta, as Co-Trustee, together
with a Schedule identifying five other substantially identical
Subordinated Deed to Secure Debt and Security Agreements. (Filed
as Exhibit 10.32.16 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.22.17 -- Tax Indemnification Agreement (P1), dated as of December 30,
1996, between Oglethorpe and the Owner Participant named therein,
together with a Schedule identifying five other substantially
identical Tax Indemnification Agreements. (Filed as Exhibit
10.32.17 to the Registrant's Form 10-K for the fiscal year ended
December 31, 1996, File No. 33-7591.)
*10.22.18 -- Consent No. 1, dated as of December 30, 1996, among Georgia Power
Company, Oglethorpe, SunTrust Bank, Atlanta, as Co-Trustee, and
Fleet National Bank, as Owner Trustee, together with a Schedule
identifying five other substantially identical Consents. (Filed
as Exhibit 10.32.18 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
83
*10.22.19(a) -- OPC Intercreditor and Security Agreement No. 1, dated as of
December 30, 1996, among the United States of America, acting
through the Administrator of the Rural Utilities Service,
SunTrust Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing
Corporation, SunTrust Bank, Atlanta, as Co-Trustee, Fleet
National Bank, as Owner Trustee, Utrecht-America Finance Co.,
as Lender and AMBAC Indemnity Corporation, together with a
Schedule identifying five other substantially identical
Intercreditor and Security Agreements. (Filed as Exhibit
10.32.19 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1996, File No. 33-7591.)
*10.22.19(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.)
*10.23.1 -- Member Transmission Service Agreement, dated as of March 1,
1997, by and between Oglethorpe and Georgia Transmission
Corporation (An Electric Membership Corporation). (Filed as
Exhibit 10.33.1 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
*10.23.2 -- Generation Services Agreement, dated as of March 1, 1997, by
and between Oglethorpe and Georgia System Operations
Corporation. (Filed as Exhibit 10.33.2 to the Registrant's Form
10-K for the fiscal year ended December 31, 1996, File No.
33-7591.)
*10.23.3 -- 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.)
*10.24(2) -- Power Purchase and Sale Agreement between Morgan Stanley
Capital Group Inc. and Oglethorpe, dated as of April 7, 1997.
(Filed as Exhibit 10.34 to the Registrant's Form 10-Q for the
quarterly period ended March 31, 1997, File No. 33-7591.)
*10.25 -- 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.)
10.26(3) -- Employment Agreement, dated as of September 15, 1999, between
Oglethorpe and Thomas A. Smith.
21.1 -- Rocky Mountain Leasing Corporation, a Delaware corporation.
27.1 -- Financial Data Schedule (for SEC use only).
- -----------
(1) Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this document(s) is not filed
herewith; however the registrant hereby agrees that such document(s) will
be provided to the Commission upon request.
(2) Certain portions of this document have been omitted as confidential and
filed separately with the Commission.
(3) Indicates a management contract or compensatory arrangement required to be
filed as an exhibit to this Report.
84
(B) REPORTS ON FORM 8-K.
Oglethorpe filed a Current Report on Form 8-K on December 21, 1999
containing disclosure under Item 5, Other Events, stating that on December 20,
1999, an arbitration panel ruled that Oglethorpe's power marketing contract with
LEM and LG&E Energy Corp. is valid and must continue to be honored.
85
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 24th day of
March, 2000.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
By: /s/ J. Calvin Earwood
--------------------------------------
J. Calvin Earwood
Chairman of the Board
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
--------- ----- ----
/s/ J. Calvin Earwood Chairman of the Board, Director (Principal March 24, 2000
- --------------------------------------- Executive Officer)
J. Calvin Earwood
/s/ Thomas A. Smith President and Chief Executive Officer March 24, 2000
- --------------------------------------- (Principal Executive Officer)
Thomas A. Smith
/s/ Mac F. Oglesby Treasurer, Director (Principal Financial March 24, 2000
- --------------------------------------- Officer)
Mac F. Oglesby
/s/ W. Clayton Robbins Senior Vice President, Finance and March 24, 2000
- --------------------------------------- Administration (Principal Financial Officer)
W. Clayton Robbins
/s/ Willie B. Collins Controller and Chief Risk Officer March 24, 2000
- ---------------------------------------
Willie B. Collins
/s/ Ashley C. Brown Director March 24, 2000
- ---------------------------------------
Ashley C. Brown
/s/ Larry N. Chadwick Director March 24, 2000
- ---------------------------------------
Larry N. Chadwick
/s/ Benny W. Denham Director March 24, 2000
- ---------------------------------------
Benny W. Denham
86
SIGNATURE TITLE DATE
--------- ----- ----
/s/ Wm. Ronald Duffey Director March 24, 2000
- ---------------------------------------
Wm. Ronald Duffey
/s/ Sammy M. Jenkins Director March 24, 2000
- ---------------------------------------
Sammy M. Jenkins
/s/ J. Sam L. Rabun Director March 24, 2000
- ---------------------------------------
J. Sam L. Rabun
/s/ John S. Ranson Director March 24, 2000
- ---------------------------------------
John S. Ranson
87
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.