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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
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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, 1998
/ /
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ___________ TO _____________
COMMISSION FILE NO. 33-7591
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OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP CORPORATION)
(Exact name of registrant as specified in its charter)
GEORGIA 58-1211925
(State or other jurisdiction of (I.R.S. employer
incorporation or organization) identification no.)
POST OFFICE BOX 1349
2100 EAST EXCHANGE PLACE
TUCKER, GEORGIA 30085-1349
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (770) 270-7600
Securities registered pursuant to Section 12(b) of the Act: NONE
Securities registered pursuant to Section 12(g) of the Act: NONE
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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
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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
1998 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
ITEM PAGE
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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..................................................................... 19
2 Properties.............................................................................. 20
Generating Facilities................................................................. 20
Co-Owners of the Plants and the Plant Agreements...................................... 23
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................... 28
6 Selected Financial Data................................................................. 28
7 Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................................... 29
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.................................................................. 68
12 Security Ownership of Certain Beneficial Owners and Management.......................... 70
13 Certain Relationships and Related Transactions.......................................... 70
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K........................ 71
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SELECTED DEFINITIONS
When used herein the following terms will have the meanings indicated below:
TERM MEANING
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ADSCR Annual Debt Service Coverage Ratio
AFUDC Allowance For Funds Used During Construction
CFC National Rural Utilities Cooperative Finance Corporation
DSC Debt Service Coverage Ratio
EMC Electric Membership Corporation
EPI Entergy Power, Inc.
FERC Federal Energy Regulatory Commission
FFB Federal Financing Bank
GPC Georgia Power Company
GPSC Georgia Public Service Commission
GSOC Georgia System Operations Corporation
GTC Georgia Transmission Corporation (An Electric Membership
Corporation)
ITS Integrated Transmission System
kWh Kilowatt-hours
LEM LG&E Energy Marketing Inc.
MEAG Municipal Electric Authority of Georgia
MFI Margins for Interest
MW Megawatts
MWh Megawatt-hours
NRC Nuclear Regulatory Commission
PCBs Pollution Control Revenue Bonds
PCR Percentage Capacity Responsibility
PPA Prior Period Adjustment
PURPA Public Utility Regulatory Policies Act
RUS Rural Utilities Service
SEPA Southeastern Power Administration
SONOPCO Southern Nuclear Operating Company
TIER Times Interest Earned Ratio
TVA Tennessee Valley Authority
ii
PART I
ITEM 1. BUSINESS
OGLETHORPE POWER CORPORATION
GENERAL
Oglethorpe Power Corporation (An Electric Membership Corporation)
("Oglethorpe") is a Georgia electric membership corporation incorporated in 1974
and headquartered in metropolitan Atlanta. Oglethorpe is owned by 39 retail
electric distribution cooperative members (the "Members"), 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 125 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 2.9 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 (i.e., margins) to increase its patronage capital, which is the
equity component of its capitalization. Any such margins, which are considered
capital contributions (i.e., equity) from the members, 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 RESTRUCTURING
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 continues to
operate its power supply business. Oglethorpe retained all of its owned and
leased generation assets and, as of December 31, 1998, had total assets of
approximately $4.5 billion and total long-term debt and capital lease
obligations of approximately $3.5 billion. (See "Power Supply Business,"
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"Relationship with GTC," and "Relationship with GSOC" herein and "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES.")
POWER SUPPLY BUSINESS
Oglethorpe provides wholesale electric service to the 39 Members pursuant
to long-term, take-or-pay Wholesale Power Contracts described herein that
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 under long-term contracts with 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, with Oglethorpe having 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 entered into 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 forecasted load requirements of the Members. 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. 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. All of Oglethorpe's existing generating facilities and
power purchase arrangements are available for use by LEM and Morgan Stanley for
the term 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
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"MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--General" and "--Power Marketer
Arrangements" and Item 3 "LEGAL PROCEEDINGS".)
Oglethorpe purchases a total of approximately 1,000 MW of power pursuant to
power purchase agreements with GPC, Big Rivers Electric Corporation ("Big
Rivers"), Entergy Power, Inc. ("EPI"), and Hartwell Energy Limited Partnership
("Hartwell"). (See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--Power
Purchase and Sale Arrangements" and "--Future Power Resources.")
WHOLESALE POWER CONTRACTS
In connection with the Corporate Restructuring, Oglethorpe and each of the
Members entered into substantially similar Amended and Restated Wholesale Power
Contracts, dated August 1, 1996 (the "Wholesale Power Contracts"), each of which
extends 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 Purchases.") 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.
Each Member's cost responsibility under its Wholesale Power Contract is
based on agreed-upon fixed percentage capacity responsibilities ("PCRs"). PCRs
have been assigned for all of Oglethorpe's existing generation and purchased
power resources. PCRs 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.
The Wholesale Power Contracts contain covenants by each Member (i) to
establish, maintain and collect rates and charges for the service of its
electric system, and (ii) to conduct its business in a manner which will produce
revenues and receipts at least sufficient to enable the Member to pay to
Oglethorpe, when due, all amounts payable by the Member under its Wholesale
Power Contract and to pay any and all other amounts payable from, or which might
constitute a charge or a lien upon, the revenues and receipts derived from its
electric system, including all operation and maintenance expenses and the
principal of, premium, if any, and interest on all indebtedness related to the
Member's electric system.
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
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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 revise its rates as necessary so that the revenues derived from such
rates, together with its revenues from all other sources, will be sufficient,
but only sufficient to pay all costs of its system, including operating and
maintenance costs, the cost of purchased power, the cost of transmission
services, and principal and interest on all indebtedness (including capital
lease obligations) of Oglethorpe, all costs associated with decommissioning or
otherwise retiring any generating facility, to provide for the establishment and
maintenance of reasonable reserves, and to enable Oglethorpe to comply with all
financial requirements under the Indenture, dated as of March 1, 1997, from
Oglethorpe to SunTrust Bank, Atlanta ("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 an
MFI Ratio described herein for each fiscal year equal to at least 1.10.
Margins for Interest ("MFI") is defined in the Mortgage Indenture to be the
sum of net margins of Oglethorpe (which includes revenues of Oglethorpe
subject to refund at a later date but excludes provisions for (i)
non-recurring charges to income, including the non-recoverability of assets
or expenses, except to the extent Oglethorpe determines to recover such
charges in rates, and (ii) refunds of revenues collected or accrued subject
to refund) plus interest charges, whether capitalized or expensed, on all
indebtedness secured under the Mortgage Indenture or by a lien equal or prior
to the lien of the Mortgage Indenture, including amortization of debt
discount or premium on issuance, but excluding interest charges on
indebtedness assumed by GTC ("Interest Charges"), plus any amount included in
net margins for accruals for federal or state income taxes imposed on income
after deduction of interest expense. MFI 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.
"MFI Ratio" is the ratio of MFI 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 (i.e., the PCR). 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 ("PPA")
mechanism designed to ensure that Oglethorpe achieves the minimum 1.10 MFI
Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum 1.10 MFI
Ratio would be accrued as of December 31 of the applicable year and collected
from the Members during the period April through December of the following year.
Amounts within a range from a 1.10 MFI Ratio to a 1.20 MFI Ratio are retained as
margins. Amounts, if any, by which Oglethorpe exceeds the maximum 1.20 MFI Ratio
would be charged against revenues as of
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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 MFI
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 MFI 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 (the "Member Transmission Agreements") under which GTC provides
transmission service to the Members pursuant to a transmission tariff. The
Member Transmission Agreements have a minimum term for network service for
current load until December 31, 2025. After an initial ten-year term, load
growth above 1995 requirements may, with notice to GTC, be served by others. The
Member Transmission 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 Agreements, Members have the right to design,
construct and own new distribution substations.
In connection with the Corporate Restructuring, GTC succeeded to
Oglethorpe's rights in the Integrated Transmission System ("ITS"), which
consists of transmission facilities owned by GTC, GPC, MEAG and Dalton. Through
agreements, common access to the combined facilities that compose the ITS
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 ITS was established in order to
obtain the benefits of a coordinated development of the parties' transmission
facilities and to make it unnecessary for any party to construct duplicative
facilities.
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.
RELATIONSHIP WITH ENERVISION
In connection with the Corporate Restructuring, Oglethorpe undertook to
remove the costs of its marketing services business from its general rates and
recover these costs on a fee-for-service basis. To do so, Oglethorpe created a
wholly owned subsidiary, EnerVision, Inc., Tailored Energy Solutions
("EnerVision"), to which it transferred its marketing services business. On
October 15, 1998, the senior associates of EnerVision purchased the company from
Oglethorpe. EnerVision continues to serve the
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Georgia electric cooperatives and also provides services to Oglethorpe and other
clients. The sale of EnerVision did not have a material effect on Oglethorpe's
financial condition or results of operations.
RELATIONSHIP WITH INTELLISOURCE
In conjunction with the Corporate Restructuring and as a part of its
continuing efforts to reduce costs, Oglethorpe implemented in 1997 a business
alliance with Intellisource, Inc., a national provider of outsourcing services.
Pursuant to an agreement with Intellisource, approximately 150 support services
division employees of Oglethorpe in the areas of accounting, auditing,
communications, human resources, facility management, purchasing,
telecommunications and information technology became employees of Intellisource.
Oglethorpe, GTC and GSOC are key customers of Intellisource and are being served
by on-site employees of Intellisource.
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," "MEMBER
REQUIREMENTS AND POWER SUPPLY RESOURCES--Power Purchase and Sale
Arrangements--POWER PURCHASES FROM GPC," and "--Power Purchase and Sale
Arrangements--OTHER POWER PURCHASES". 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 ("FFB") 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, (i)
significant additions to or dispositions of system assets, (ii) significant
power purchase and sale contracts, (iii) changes to the Wholesale Power
Contracts, including the rate schedule contained therein, (iv) changes to plant
ownership and operating agreements and (v) 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 changes in the 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, an EMC Pataula EMC Washington EMC
The Members serve approximately 1.3 million electric consumers (meters)
representing approximately 2.9 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 1998 amounted to approximately 23 million
megawatt-hours ("MWh"), with approximately 69% to residential consumers, 29%
to commercial and industrial consumers and 2% to other consumers. The Members
are the principal suppliers for the power needs of rural Georgia. While the
Members do not serve any major cities, portions of their service territories are
in close proximity to urban areas and are experiencing substantial growth due to
the expansion of urban areas, including metropolitan Atlanta, into suburban
areas and the growth of suburban areas into neighboring rural areas. The Members
have experienced average annual compound growth rates from 1996 through 1998 of
5% in number of consumers, 8% in MWh sales and 7% 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 may not
consolidate or merge with any person or reorganize or change the form of its
business organization from an electric membership corporation or sell, transfer,
lease or otherwise dispose of all or substantially all of its assets to any
person, whether in a single transaction or series of transactions, unless
either: (i) the transaction is approved by Oglethorpe or (ii) other specified
conditions are satisfied including, but not limited to, an assumption agreement
by the transferee, satisfactory to Oglethorpe, containing an assumption by the
transferee of the performance and observance of every covenant and condition of
the Member under the Wholesale Power Contract, and certifications of accountants
as to certain specified financial requirements of the transferee (taking into
account the transfer).
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
("TIER") of not less than 1.50 and an average Debt Service Coverage Ratio
("DSC") 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.
Recent changes and proposals for further changes have made the direct loan
program administered by RUS more costly. The Rural Electrification Loan
Restructuring Act of 1993 eliminated the long-standing 5% loan program and
substituted a new program, the interest rates for which 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 still eligible for special loans at 5%. The President's
budget proposal for fiscal year 2000 includes a reduction under these loan
programs, and replacement with a new program with interest rates based on
Treasury rates. However, no legislation has yet been introduced to implement
this proposed program. The future cost, availability and amount of RUS direct
and guaranteed loans which may be available to the Members cannot be predicted.
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.
In 1998, the aggregate SEPA allocation to the
9
Members was 523 MW plus associated energy, representing approximately 9% of
total Member peak demand and approximately 5% of total Member energy
requirements. New 20-year contracts between each of the Members and SEPA were
effective as of October 1, 1996. The provisions of the new contracts are
essentially the same as the prior contracts with a few exceptions. Each Member
must schedule its energy allocation, and each Member has designated Oglethorpe
to perform this function. Pursuant to a separate agreement, Oglethorpe will
schedule, through GSOC, the Members' SEPA power deliveries. Further, each Member
may be required, if certain conditions are met, to contribute funds for capital
improvements for Corps of Engineers projects from which its allocation is
derived in order to retain the allocation. 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.)
During 1996, legislative proposals were made that would have resulted in
the privatization of several of the federal power marketing administrations, in
particular SEPA. Ultimately, no proposal for the privatization of the power
marketing administrations was passed by Congress. The President's Budget for
fiscal year 2000 does not include any proposals to privatize the federal power
marketing administrations. The ultimate outcome of this issue in Congress cannot
be predicted with certainty.
OTHER POWER PURCHASES
Under the Wholesale Power Contracts, a Member may choose to supply all or a
portion of its future requirements with purchases from suppliers other than
Oglethorpe. A new entity, Smarr EMC, was formed in 1998 by 36 of the Members to
construct and own a 217 MW combustion turbine facility. Commercial operation of
this facility is scheduled for June 1999. Construction and operation management
services are currently being provided by Oglethorpe. Smarr EMC, or similar
entities, may also construct and own future generation facilities, including 500
MW of combustion turbine capacity currently under consideration by the Members.
In addition, two Members have an arrangement that provides for the
construction of 90 MW of combustion turbine capacity for commercial operation by
the summer of 1999.
All of these combustion turbines are currently anticipated to be dispatched
in the Oglethorpe pool. (See "OGLETHORPE POWER CORPORATION--Wholesale Power
Contracts.")
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 1996 through 1998, and also shows the amounts of
such requirements supplied by Oglethorpe and SEPA. From 1996 through 1998,
demand and energy requirements increased at an average annual compound growth
rate of 7.3% and 8.5%, respectively.
DEMAND (MW) ENERGY REQUIREMENTS (MWH)
----------------------------------------- ---------------------------------------------
TOTAL SUPPLIED BY SUPPLIED BY TOTAL SUPPLIED BY SUPPLIED BY
REQUIREMENTS(1) OGLETHORPE(2) SEPA (3) REQUIREMENTS OGLETHORPE (2) SEPA (3)
--------------- ----------- ------------ ------------ -------------- -----------
1996............... 5,045 4,503 542 20,793,864 19,807,101 986,763
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
- -------------
(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.)
(3) Supplied by SEPA through contracts with the Members. (See "THE
MEMBERS--Contracts with SEPA.") Under the SEPA contracts effective
October 1, 1996, the SEPA capacity allocation has been reduced by
approximately 3.7% for losses.
In 1998, Cobb EMC and Jackson EMC accounted for approximately 12.8% and
11.4% of Oglethorpe's total revenues, respectively. None of the other Members
accounted for as much as 10% of Oglethorpe's total revenues in 1998. Due to
greater than average growth rates, certain of Oglethorpe's customers, including
its larger customers such as Cobb EMC and Jackson 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--Other Power Purchases.")
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
11
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
In 1996, Oglethorpe began utilizing power marketer arrangements to reduce
the cost of power to the Members. 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. All of
Oglethorpe's existing generating facilities and power purchase arrangements are
available for use by LEM and Morgan Stanley for the term 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 power marketer
agreements for 50% of the load requirements of the Members with LEM, an
indirect, wholly owned subsidiary of LG&E Power Inc., a Delaware corporation
("LPI"), and of LG&E Energy Corp. ("LG&E"), which is a diversified energy
services company headquartered in Louisville, Kentucky. Under the agreements,
LEM is obligated to deliver, and Oglethorpe is obligated to take, approximately
50% of the load requirements of the participating Members less the load
requirements for certain customers who have the right to choose electric
suppliers, plus 50% 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 participating
Member's PCR share of the "must run" units (primarily nuclear units). Oglethorpe
is also obligated to make available the same share of all other resources, which
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 37 of the 39 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. The LEM agreement relating to the
other two Members has a term extending through 1999.
At the request of LEM, the parties have discussed the future of these
arrangements. LEM also has initiated the contractually defined binding
arbitration process as to certain load projections provided by Oglethorpe to LEM
in connection with the execution of the larger of the two agreements. Oglethorpe
continues to receive power under the LEM agreements and believes the agreements
are enforceable against LEM and LG&E (with respect to the agreement relating to
the 37 Members) and LPI (with respect to the agreement relating to the other two
Members). Even so, given LG&E's announced intention to discontinue its merchant
energy trading and sales business, instead of performing itself, LEM could, with
consent of Oglethorpe and RUS, make alternative arrangements, including
assigning performance to an acceptable third party, or otherwise make Oglethorpe
whole from any damages incurred as a result of termination. Oglethorpe believes
that LEM, LG&E and LPI have the ability, financial and otherwise, to perform
their obligations under these agreements.
12
The current uncertainty relating to the LEM arrangements does not adversely
affect Oglethorpe's ability to meet its Members' load requirements but could, in
the future, affect the sources and prices for such power. If LEM, LG&E and LPI
were to cease to perform their obligations under the LEM agreements or the LEM
agreements were to be terminated, Oglethorpe expects to be able to serve its
Members' needs through its existing owned and purchased capacity, supplemented
by additional capacity either purchased in the wholesale market, constructed or
otherwise acquired. Termination of the LEM agreements would however eliminate a
source of power at contractually fixed prices and thus would introduce
additional uncertainty regarding future power costs and Member rates.
Oglethorpe's management does not expect the ultimate resolution of the LEM
arrangements will have a material adverse effect on its financial condition or
results of operations.
LG&E 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.
MORGAN STANLEY AGREEMENT
Effective May 1, 1997, Oglethorpe entered into a power marketer agreement
with Morgan Stanley with respect to 50% of the Members' 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 PCR 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 all
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 ITS any energy sold to LEM or Morgan
Stanley, as well as any other wholesale power purchase. Each Member will use its
Member Transmission 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 PCR 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
13
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 purchases 500 MW of capacity and associated energy from GPC on a
take-or-pay basis under the Block Power Sale Agreement ("BPSA"), which extends
through December 31, 2003. The capacity purchases under the BPSA are from three
Component Blocks (as defined in the BPSA), composed of one Component Block of
250 MW (coal-fired units) and two Component Blocks of 125 MW each (combustion
turbine units). The capacity in one or more Component Blocks may, however, be
less than the MW stated above, as the result of scheduled retirement of units or
retirements due to force majeure events. Although Oglethorpe may not increase
its capacity purchases under the BPSA, it may reduce or extend its purchases of
one or more Component Blocks upon proper notice to GPC. Oglethorpe has given
notice of its intent to reduce its purchases by the 250 MW Component Block
(coal-fired units) effective September 1, 1999 and by one 125 MW Component Block
(combustion turbine units) effective September 1, 2000. Also, pursuant to its
long-term power marketer agreements with LEM, Oglethorpe has committed to reduce
its purchases from GPC by the remaining Component Block as permitted under the
BPSA and thus will no longer purchase any energy under the BPSA effective
September 1, 2001. However, see "Future Power Resources" herein for a discussion
of a replacement for the BPSA.
OTHER POWER PURCHASES
Oglethorpe purchases 100 MW of capacity from each of EPI 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 EPI. The Tennessee Valley
Authority ("TVA") provides the transmission service to deliver the power from
the Big Rivers electric system to the ITS. TVA and Southern Company Services, as
agent for Alabama Power Company and Mississippi Power Company, provide the
transmission service necessary to deliver the power from EPI to the ITS. (See
Note 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 intends to use the units for peaking capacity
but has the right to dispatch the units fully. Prior to the merger of Destec
Energy, Inc. and NGC Corporation, Oglethorpe notified Hartwell that Oglethorpe's
rights under the power purchase agreement to consent to the merger or to
exercise its rights of first refusal to purchase equity interests in the
partnership would be triggered by the merger. Hartwell, however, refused to
recognize Oglethorpe's rights and the parties are seeking a court order to
clarify Oglethorpe's contractual rights with respect to the merger.
In addition to the purchases from GPC, Big Rivers, EPI and Hartwell,
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
0.2% of Oglethorpe's energy requirements for the Members in 1998. As a result of
the Corporate Restructuring, the Members may make such purchases in the future
instead of Oglethorpe.
14
LONG-TERM POWER SALES
Oglethorpe has an agreement to sell 100 MW of base capacity to Alabama
Electric Cooperative beginning June 1, 1998, and extending through December 31,
2005. 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 ITS 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 will continue to offer
planning services for requirements beyond the contract terms as well as for
evaluation of contract options and balancing of actual requirements against
fixed purchase obligations. Consequently, Oglethorpe has forecasted that peak
requirements for the Members will exceed contracted purchases over the next
several years and issued a request for proposals for an aggregate of 100 MW to
1,100 MW to supply these additional requirements.
As a result of this process, arrangements have been made to acquire or
construct additional capacity beginning in 1999. A combustion turbine plant is
currently under construction by Smarr EMC, a new cooperative formed by 36 of the
Members, and is scheduled for commercial operation by June 1999. Oglethorpe has
also procured an option to construct a 500 MW combustion turbine facility by the
summer of 2000 for the benefit of the Members, who are currently considering
participation in these turbines, either through Smarr EMC or a similar entity.
See "THE MEMBERS--Other Power Purchases" for a discussion of capacity purchased
by the Members from sources other than Oglethorpe.
Oglethorpe has also signed an agreement with GPC to replace the remaining
500 MW of the BPSA through March 31, 2006. This agreement, to be effective
April 1, 1999, is contingent on sufficient Member participation. The contract
also includes 250 MW for a one-year period beginning June 1, 1999, contingent on
sufficient Member participation. Upon the effectiveness of this agreement, the
BPSA will be terminated.
Oglethorpe expects to sign additional short-term contracts for peaking
power and may also contract for or otherwise acquire additional capacity.
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: (i) the transition to increasing competition in the generation of
electricity and the corresponding increase in competition from other suppliers
of electricity, (ii) fluctuations in the market price for electricity, (iii)
effects of compliance with changing environmental, licensing and regulatory
requirements, (iv) regulatory and other changes in national and state energy
policy, including open access transmission, (v) uncertain access to low cost
capital for replacement of aging fixed assets, (vi) increases in operating
costs, including the cost of fuel for the generation of electric energy, (vii)
uncertain recovery of the cost of existing facilities, (viii) fluctuations in
demand, including rates of load growth and changes in competitive market share,
(ix) unbundling of services and corresponding corporate and functional
restructurings by electric utility companies, and (x) 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 Restructuring,"
"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
oxides and nitrogen oxides into the air and discharges of other pollutants,
including heat, into waters of the United States. Oglethorpe is also subject to
federal, state and local waste disposal requirements that regulate the manner of
transportation, storage and disposal of various types of waste.
In general, environmental requirements are becoming increasingly stringent.
New requirements may substantially increase the cost of electric service, by
requiring changes in the design or operation of existing facilities or changes
or delays in the location, design, construction or operation of new facilities.
Failure to comply with these requirements could result in the imposition of
civil and criminal penalties as well as the complete shutdown of individual
generating units not in compliance. 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. Based on the current
status of regulatory requirements, Oglethorpe does not anticipate that any
capital expenditures or operating expenses associated with its compliance with
current laws and regulations will have a material effect on its results of
operations or its financial condition. Oglethorpe's direct capital costs to
achieve compliance with current environmental requirements
16
are expected to be minimal for 1998, 1999 and 2000. As further discussed below,
however, capital costs to achieve compliance with potential future environmental
requirements could be significant.
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. In particular, on
November 15, 1990, legislation was enacted (the "1990 Amendments") that
substantially revised the Clean Air Act. One of the principal purposes of the
1990 Amendments 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 that generate electric power at Plants Wansley and Scherer.
These 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 limited reductions on certain affected units in Phase I
(1995-1999) and more stringent reductions on all affected units in Phase II
(after the year 1999). After 1999, aggregate emissions of sulfur dioxide from
all units subject to this program will be capped at 8.9 million tons per year.
Oglethorpe is now complying with this program by using lower-sulfur fuel at
Plant Wansley. After 1999, Oglethorpe could use a variety of options for
compliance at Plants Wansley and Scherer, including the use of emission
allowances (issued, banked or purchased, if needed), fuel-switching or
installation of flue gas desulfurization equipment.
A number of recently finalized regulations, proposed regulations, petitions
and on-going studies 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 may impose further
limits on emissions of nitrogen oxides at Plants Wansley and Scherer. Second,
EPA has tightened 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 are continuing.
Third, EPA has issued a regulation calling for regional reductions in nitrogen
oxides emissions from 22 states, including Georgia, and the District of
Columbia. The regulation imposes a fixed cap on nitrogen oxides emissions from
such states, beginning in the year 2003. Although states remain free to choose
the sources on which to impose reductions needed to stay below the cap,
indications are that Georgia will require large fossil fuel-fired units,
including those at Plants Wansley and Scherer, to participate in achieving the
required reductions. In the regulation, EPA recommends that all affected states
participate in a nitrogen oxides allowance trading program that would be similar
to the sulfur dioxide program discussed above. Such a program would allow for
the trading, banking and selling of nitrogen oxides allowances throughout the
22-state region and the District of Columbia and could affect the level of
controls needed at specific utility units like those at Plants Wansley or
Scherer. EPA's regulation has been appealed and Georgia's implementation plan,
which has not yet been finalized, may also be challenged. Therefore, it is not
yet known what controls, if any, will be needed at Plants Wansley and/or Scherer
to comply with this regional nitrogen oxides reduction program. Fourth, EPA has
proposed a new regional haze program, an action that could affect 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. Fifth, EPA has 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 preliminary finding is that Georgia is not significantly
contributing to nonattainment in any of the petitioning states. EPA has not made
a final determination, however, regarding these petitions. Sixth,
17
although EPA had decided not to impose a new NAAQS for sulfur dioxide, that
decision has been remanded (after appeal) to EPA for further rulemaking, so it
is still possible that a new short-term standard for sulfur dioxide could be
established. Finally, the 1990 Amendments require that several studies be
conducted regarding the health effects from power plant emissions of certain
hazardous air pollutants. These studies, which have now been completed, indicate
that further research is needed before decisions can be made on whether
additional controls of utility emissions of such pollutants are necessary.
Depending on the final outcome of these developments, and the
implementation approach selected by EPA and the State of Georgia, significant
capital expenditures and increased operation expenses could be incurred by
Oglethorpe for the continued operation of Plants Wansley and/or Scherer. The
power marketer arrangements generally do not provide for the recovery from the
power marketers of increased environmental costs. (See "MEMBER REQUIREMENTS AND
POWER SUPPLY RESOURCES--Power Marketer Arrangements.") Because of the
uncertainty associated with these various developments, Oglethorpe cannot now
predict the effect that any of these potential requirements may have on the
operations of Plants Wansley and Scherer.
Compliance with the requirements of the Clean Air Act may also require
increased capital or operating expenses on the part of GPC. Any increases in
GPC's capital or operating expenses may cause an increase in the cost of power
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.
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. Such 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. Oglethorpe is a party to agreements with DOE regarding Plants Hatch
and Vogtle. 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.
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 January 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. If DOE does not begin receiving the spent fuel from
Plant Hatch in 2003 or from Plant Vogtle in 2017, alternative methods
18
of spent fuel storage will be needed. Activities for adding dry cask storage
capacity at Plant Hatch by 2000 are in progress. (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.
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.
19
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
Unit No. 2........................ Nuclear 30 246.0 1979 2018
Plant Vogtle (near Waynesboro, Ga.)
Unit No. 1........................ Nuclear 30 348.0 1987 2027
Unit No. 2........................ Nuclear 30 348.0 1989 2029
Plant Wansley (near Carrollton, Ga.)
Unit No. 1........................ Coal 30 259.5 1976 N/A(1)
Unit No. 2........................ Coal 30 259.5 1978 N/A(1)
Combustion Turbine................ Oil 30 14.8 1980 N/A(1)
Plant Scherer (near Forsyth, Ga.)
Unit No. 1........................ Coal 60 490.8 1982 N/A(1)
Unit No. 2........................ Coal 60 490.8 1984 N/A(1)
Tallassee (near Athens, Ga.)......... Hydro 100 2.1 1986 2023
Rocky Mountain (near Rome, Ga.)...... Pumped
Storage
Hydro 74.61 632.5 1995 2027
-------
Total Ownership 3,335.0
-------
-------
- ----------------
(1) 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.
20
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(2)
---------------------------- -------------------------
UNIT 1998 1997 1996 1998 1997 1996
---- ---- ---- ---- ---- ---- ----
Plant Hatch
Unit No. 1........... 100% 86% 83% 99% 86% 83%
Unit No. 2........... 81 85 97 81 84 99
Plant Vogtle
Unit No. 1........... 100 81 80 102 81 80
Unit No. 2.......... 82 100 88 82 101 89
Plant Wansley
Unit No. 1........... 86 91 88 56 62 58
Unit No. 2........... 92 92 91 50 59 62
Plant Scherer
Unit No. 1........... 93 76 92 70 57 74
Unit No. 2........... 89 99 84 75 84 72
Rocky Mountain(3)
Unit No. 1........... 90 96 94 24 20 15
Unit No. 2........... 95 96 95 13 13 13
Unit No. 3........... 94 97 95 22 19 10
- ----------------
(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 28, 1999, there was a
57-day coal supply at Plant Wansley based on nameplate rating.
Low-sulfur "compliance" coal for Scherer Units No. 1 and No. 2 is purchased
under long-term contracts and in spot market transactions. As of February 28,
1999, the coal stockpile at Plant Scherer contained a 46-day supply based on
nameplate rating. During 1994, Plant Scherer was converted to burn both
sub-bituminous and bituminous coals, and a separate stockpile of sub-bituminous
coal is maintained in addition to the stockpile of bituminous coal.
The Plant Scherer and Wansley ownership and operating agreements were
amended in 1993 and 1996, respectively, to allow each co-owner (i) to dispatch
separately its respective ownership interest in conjunction with contracting
separately for long-term coal purchases procured by GPC and (ii) to procure
separately long-term coal purchases. Pursuant to the amendments, Oglethorpe
implemented separate dispatch of Plant Scherer in 1994 and at Plant Wansley in
May 1997. Oglethorpe continues to use GPC as its agent for fuel procurement.
21
To take advantage of these changes at Plants Scherer and Wansley,
Oglethorpe formed a wholly owned subsidiary, Black Diamond Energy, Inc., to
acquire rail cars. This subsidiary has purchased or leased approximately 300
rail cars. Oglethorpe entered into 15-year leases with this subsidiary which
obligates Oglethorpe to pay all of the ownership and operating expenses of the
subsidiary relating to the respective rail cars during each lease term.
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.
22
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 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,
23
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.
SALE AND LEASEBACK TRANSACTIONS. 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. The Operating Agreements gives GPC, as agent, sole authority and
responsibility for the management, control, maintenance and operation of the
plant to which it relates and provides for the use of power and energy from such
plant and the sharing of the costs thereof by the parties thereto in accordance
with their respective interests therein. In performing its responsibilities
under the Ownership and Operating Agreements, GPC is required to comply with
prudent utility practices. GPC's liabilities with respect to its duties under
the Ownership and Operating Agreements are limited by the terms thereof.
Under the Ownership Agreements, Oglethorpe is obligated to pay a percentage
of capital costs of the respective plants, as incurred, equal to the percentage
interest which it owns or leases at each plant. GPC has responsibility for
budgeting capital expenditures subject to, in the case of Scherer Units No. 1
and No. 2, certain limited rights of the Participants to disapprove capital
budgets proposed by GPC and to substitute alternative capital budgets and, in
the case of Plants Hatch and Vogtle, the right of any co-owner to disapprove
large discretionary capital improvements.
In 1990, the co-owners of Plants Hatch and Vogtle entered into the Nuclear
Managing Board Agreement which amended the Plant Hatch and Plant Vogtle
Ownership and Operating Agreements, primarily with respect to GPC's reporting
requirements, but did not alter GPC's role as agent with respect to the nuclear
plants. In 1993, the co-owners entered into the Amended and Restated Nuclear
Managing Board Agreement (the "Amended and Restated NMBA") which provides for a
managing board (the "Nuclear Managing Board") to coordinate the implementation
and administration of the Plant Hatch and Plant Vogtle Ownership and Operating
Agreements, 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. Upon approval in March 1997 by the NRC of GPC's application to
add SONOPCO to the operating license of each unit of Plants Hatch and Vogtle and
designate SONOPCO as the operator, the Nuclear Operating Agreement between GPC
and SONOPCO, which the co-owners had previously approved, became effective. 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 (the "Plant Scherer
Managing Board") to coordinate the implementation and administration of the
Plant Scherer Ownership and Operating Agreements and provides for increased
rights for the co-owners regarding certain decisions, but does not alter GPC's
role as agent with respect to Plant Scherer.
24
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. Pursuant to
amendments to the plant agreements, Oglethorpe began separately dispatching its
ownership share of Scherer Units No. 1 and No. 2 in 1993 and of Plant Wansley in
1997. (See "GENERATING FACILITIES--Fuel Supply.") Except as otherwise provided,
each party 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 will
be responsible for its fuel costs and for variable Operating Costs in proportion
to the net energy output for its ownership interest, while responsibility for
fixed Operating Costs will continue to be equal to the percentage undivided
ownership interest which is owned or leased in such unit. GPC is required to
furnish budgets for Operating Costs, fuel plans and scheduled maintenance plans
subject to, in the case of Scherer Units No. 1 and No. 2, certain limited rights
of the Participants to disapprove such budgets proposed by GPC and to substitute
alternative budgets. The Ownership Agreements and Operating Agreements provide
that, should a 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's rights and obligations with respect to Rocky Mountain are
contained in several contracts between Oglethorpe and GPC, the co-owners of
Rocky Mountain (the "Co-Owners"). Pursuant to Rocky Mountain Pumped Storage
Hydroelectric Ownership Participation Agreement, by and between Oglethorpe and
GPC (the "Rocky Mountain Ownership Agreement"), Oglethorpe owns a 74.61%
undivided interest in Rocky Mountain and GPC, 25.39%. In connection with this
acquisition, Oglethorpe and GPC also entered into the Rocky Mountain Pumped
Storage Hydroelectric Project Operating Agreement (the "Rocky Mountain Operating
Agreement").
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 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
25
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, together with interests, had been paid. The
capacity and energy of a non-paying Co-Owner may be purchased by a paying
Co-Owner or sold to a third party.
In late 1996 and early 1997, Oglethorpe completed lease transactions for
its 74.61% undivided ownership interest in Rocky Mountain. The lease
transactions are characterized as a sale and leaseback for income tax purposes,
but not for financial reporting purposes. Under the terms of these transactions,
Oglethorpe leased the facility to three institutional investors for the useful
life of the facility, who in turn leased it back to Oglethorpe for a term of 30
years. Oglethorpe will continue to control and operate Rocky Mountain during the
leaseback term, and it 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.
26
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-ITS interface to the
Florida-ITS 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.
LEM has initiated a binding arbitration process as to certain load
projections provided by Oglethorpe to LEM in connection with the execution of
certain of the power marketer agreements between LEM and Oglethorpe. (See
"MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES--Power Marketer
Arrangements--LEM AGREEMENTS" in Item 1 for a discussion of the LEM Agreements
and the future of these power marketer arrangements.)
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
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, 1998, 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)
1998 1997 1996 1995 1994
Operating revenues:
Sales to Members........................ $ 1,095,904 $1,000,319 $1,023,094 $1,030,797 $ 930,875
Sales to non-Members.................... 48,263 47,533 78,343 118,764 125,207
----------- ---------- ---------- ---------- -----------
Total operating revenues................... 1,144,167 1,047,852 1,101,437 1,149,561 1,056,082
----------- ---------- ---------- ---------- -----------
Operating expenses:
Fuel.................................... 191,399 206,315 206,524 219,062 203,444
Production.............................. 198,378 181,923 173,497 175,777 170,880
Purchased power......................... 387,662 266,875 229,089 264,844 227,477
Depreciation and amortization........... 124,074 126,730 163,130 139,024 131,056
Other operating expenses................ - 6,334 46,448 42,177 35,818
----------- ---------- ---------- ---------- -----------
Total operating expenses................... 901,513 788,177 818,688 840,884 768,675
----------- ---------- ---------- ---------- -----------
Operating margin........................... 242,654 259,675 282,749 308,677 287,407
Other income, net.......................... 42,293 46,646 65,334 33,710 40,795
Net interest charges....................... (263,867) (283,916) (326,331) (320,129) (305,120)
----------- ---------- ---------- ---------- -----------
Net margin................................. $ 21,080 $ 22,405 $ 21,752 $ 22,258 $ 23,082
----------- ---------- ---------- ---------- -----------
----------- ---------- ---------- ---------- -----------
Electric plant, net:
In service.............................. $ 3,429,704 $3,588,204 $4,345,200 $4,436,009 $3,980,439
Construction work in progress........... 20,948 13,578 31,181 35,753 538,789
----------- ---------- ---------- ---------- -----------
$ 3,450,652 $3,601,782 $4,376,381 $4,471,762 $4,519,228
----------- ---------- ---------- ---------- -----------
----------- ---------- ---------- ---------- -----------
Total assets............................... $ 4,506,265 $4,509,857 $5,362,175 $5,438,496 $5,346,330
----------- ---------- ---------- ---------- -----------
----------- ---------- ---------- ---------- -----------
Capitalization:
Long-term debt.......................... $ 3,177,883 $3,258,046 $4,052,470 $4,207,320 $4,128,080
Obligation under capital leases......... 282,299 288,638 293,682 296,478 303,749
Other obligations....................... 55,755 52,176 41,685 - -
Patronage capital and membership fees... 352,701 330,509 356,229 338,891 309,496
----------- ---------- ---------- ---------- -----------
$ 3,868,638 $3,929,369 $4,744,066 $4,842,689 $4,741,325
----------- ---------- ---------- ---------- -----------
----------- ---------- ---------- ---------- -----------
Property additions......................... $ 43,904 $ 63,527 $ 93,704 $ 138,921 $ 206,345
----------- ---------- ---------- ---------- -----------
----------- ---------- ---------- ---------- -----------
Energy supply (megawatt-hours):
Generated............................... 17,781,896 17,722,059 17,866,143 18,402,839 16,924,038
Purchased............................... 8,544,714 6,377,643 6,606,931 5,738,634 4,381,087
----------- ---------- ---------- ---------- -----------
Available for sale...................... 26,326,610 24,099,702 24,473,074 24,141,473 21,305,125
----------- ---------- ---------- ---------- -----------
----------- ---------- ---------- ---------- -----------
Member revenue per kWh sold................ 4.70(cent) 4.83(cent) 5.11(cent) 5.53(cent) 5.65(cent)
----------- ---------- ---------- ---------- -----------
----------- ---------- ---------- ---------- -----------
28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
CORPORATE RESTRUCTURING
Oglethorpe Power Corporation (Oglethorpe) and its 39 electric distribution
cooperative members (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 continues to operate its power supply business and
retains all of its owned and leased generation assets.
In connection with the Corporate Restructuring, Oglethorpe undertook to
remove the costs of its marketing services business from its general rates and
recover these costs on a fee-for-service basis. To do so, Oglethorpe created a
wholly owned subsidiary, EnerVision, Inc., Tailored Energy Solutions
(EnerVision) to which it transferred its marketing services business. On
October 15, 1998, the senior associates of EnerVision purchased the company
from Oglethorpe. EnerVision continues to serve the Georgia electric
cooperatives and also provides services to Oglethorpe and other clients. The
sale of EnerVision did not have a material effect on Oglethorpe's financial
condition or results of operations.
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 $353 million in patronage capital as of December 31, 1998.
Oglethorpe's equity ratio (patronage capital and membership fees divided by
total capitalization) increased from 8.4% at December 31, 1997 to 9.1% at
December 31, 1998.
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, Atlanta, as trustee (Mortgage Indenture),
Oglethorpe is prohibited from making any distribution of patronage capital to
the Members if, at the time thereof or after 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.
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 as described in such
contracts, to establish and maintain reasonable margins and to meet its
financial coverage requirements. Oglethorpe reviews its capacity rates at least
annually to ensure that its fixed costs are being adequately recovered and, if
necessary, adjusts its rates to meet its net margin goals. Oglethorpe's energy
rate is established to recover actual fuel and variable operations and
maintenance costs.
A new rate schedule became effective under the Wholesale Power Contracts on
April 1, 1997, in connection with the Corporate Restructuring. This new rate
schedule implements on a long-term basis the assignment to each Member of
responsibility for fixed costs. The monthly charges for capacity and other
non-energy charges are based on a rate formula using the Oglethorpe budget. The
Board of Directors may adjust such capacity and other non-energy 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 (MFI) Ratio for each fiscal year equal to at least 1.10.
The MFI Ratio is determined by dividing the sum of
29
(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 by Interest Charges. The definition of MFI 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 (PPA) mechanism
designed to ensure that Oglethorpe achieves the minimum 1.10 MFI Ratio. Amounts,
if any, by which Oglethorpe fails to achieve a minimum 1.10 MFI Ratio would be
accrued as of December 31 of the applicable year and collected from the Members
during the period April through December of the following year. Amounts within a
range from a 1.10 MFI Ratio to a 1.20 MFI Ratio are retained as patronage
capital. Amounts, if any, by which Oglethorpe exceeds the maximum 1.20 MFI 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 MFI Ratio.
For 1998 and 1997, Oglethorpe achieved an MFI Ratio of 1.10. For comparative
purposes only, the pro forma MFI Ratio for 1996 would have been 1.09.
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 MFI 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 (GPSC).
Prior to 1997, Oglethorpe utilized a Times Interest Earned Ratio (TIER) as
the basis for establishing its annual net margin goal. Under Oglethorpe's prior
mortgage, Oglethorpe was required to implement rates that were designed to
maintain an annual TIER of not less than 1.05. For 1996, Oglethorpe's Board of
Directors set a net margin goal to be the amount required to produce a TIER of
1.07 and such TIER was achieved. In addition to the TIER requirement, Oglethorpe
was also required under the prior mortgage to implement rates designed to
maintain a Debt Service Coverage Ratio (DSC) of not less than 1.0 and an Annual
Debt Service Coverage Ratio (ADSCR) of not less than 1.25. Oglethorpe always met
or exceeded the TIER, DSC and ADSCR requirements of the prior mortgage.
TIER is determined by dividing the sum of Oglethorpe's net margin plus
interest on long-term debt (including interest charged to construction) by
Oglethorpe's interest on long-term debt (including interest charged to
construction). DSC is determined by dividing the sum of Oglethorpe's net margin
plus interest on long-term debt (including interest charged to construction)
plus depreciation and amortization (excluding amortization of nuclear fuel and
debt discount and expense) by Oglethorpe's interest and principal payable on
long-term debt (including interest charged to construction). ADSCR is determined
by dividing the sum of Oglethorpe's net margin plus interest on long-term debt
(excluding interest charged to construction) plus depreciation and amortization
(excluding amortization of nuclear fuel and debt discount and expense) by
Oglethorpe's interest and principal payable on long-term debt secured under the
prior mortgage (excluding interest charged to construction).
RESULTS OF OPERATIONS
POWER MARKETER ARRANGEMENTS
Oglethorpe is utilizing long-term power marketer arrangements to reduce the
cost of power to the Members. Oglethorpe has entered into 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. All of Oglethorpe's existing generating facilities and power purchase
arrangements are available for use by LEM and Morgan Stanley for the term 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.
At the request of LEM, the parties have discussed the future of the LEM
arrangements. LEM has initiated the contractually defined binding arbitration
process as to certain load projections provided by Oglethorpe to LEM. Oglethorpe
continues to receive power under the LEM
30
agreements and believes the agreements are enforceable against LEM. Even so,
given LEM's announced intention to discontinue its merchant energy trading and
sales business, instead of performing itself, LEM could, with consent of
Oglethorpe and the RUS, make alternative arrangements, including assigning
performance to an acceptable third party, or otherwise make Oglethorpe whole
from any damages incurred as a result of termination. Oglethorpe believes that
LEM has the ability, financial and otherwise, to perform its obligations under
these agreements.
The current uncertainty relating to the LEM arrangements does not adversely
affect Oglethorpe's ability to meet its Members' load requirements but could, in
the future, affect the sources and prices for such power. If LEM was to cease to
perform its obligations under the LEM agreements or the LEM agreements were to
be terminated, Oglethorpe expects to be able to serve its Members' needs through
its existing owned and purchased capacity, supplemented by additional capacity
either purchased in the wholesale market, constructed or otherwise acquired.
Termination of the LEM agreements would however eliminate a source of power at
contractually fixed prices and thus would introduce additional uncertainty
regarding future power costs and Member rates. Oglethorpe's management does not
expect the ultimate resolution of the LEM arrangements will have a material
adverse effect on its financial condition or results of operations.
Oglethorpe utilized short-term power marketer arrangements during 1996. The
initial agreement was with Enron Power Marketing, Inc. (EPMI) and was in place
January through August. From September through December 1996, another power
marketer arrangement was utilized with Duke/Louis Dreyfus L.L.C. (DLD). Under
each of the agreements, the power marketer was required to provide to Oglethorpe
at a favorable fixed rate all the energy needed to meet the Members'
requirements and Oglethorpe was required to provide to the power marketer at
cost, subject to certain limitations, upon request, all energy available from
Oglethorpe's total power resources. Under both agreements, Oglethorpe continued
to operate the power supply system and continued to dispatch the generating
resources to ensure system reliability.
CORPORATE RESTRUCTURING
As a result of the Corporate Restructuring, the Statements of Revenues and
Expenses for 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 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 9.6% for 1998 compared to 1997 and decreased by 2.2% for 1997
compared to 1996. The components of Member revenues were as follows:
- ------------------------------------------------------------
1998 1997 1996
(dollars in thousands)
- ------------------------------------------------------------
Capacity revenues $ 623,464 $ 652,910 $ 755,501
Energy revenues 472,440 347,409 267,593
---------- ---------- ----------
Total $1,095,904 $1,000,319 $1,023,094
---------- ---------- ----------
---------- ---------- ----------
- ------------------------------------------------------------
The decrease in capacity revenues was primarily the result of the Corporate
Restructuring. For 1997 compared to 1996, Member capacity revenues declined by
approximately $75 million due to the transfer of the transmission and system
operations businesses to GTC and GSOC. Also, as discussed under "Other Income
(Expense)" herein, Member revenues for 1997 of approximately $19.5 million
related to EnerVision were reflected in "Other Income" since these marketing
support activities are no longer part of operations of the power supply
business. In addition, in August 1997, capacity revenues were reduced by a $4
million refund to the Members as a result of an interim budget adjustment to
reflect higher than anticipated investment income. For 1998 compared to 1997,
Member capacity revenues were reduced by an additional $28 million related to
revenues of the transmission and system operations businesses previously
reflected in Oglethorpe in the first quarter of 1997.
The increases in Member energy revenues over the past three years reflect
both higher energy prices in the marketplace and greater volumes of energy sold
to Members. Actual energy costs are passed through to the Members such that
energy revenues equal energy costs. Energy revenues from Members increased by
36.0% from 1997 to 1998 and by 29.8% from 1996 to 1997.
The following table summarizes the amounts of kilowatt-hours (kWh) sold to
Members and total operating revenues per kWh during each of the past three
years:
- ------------------------------------------------------
Kilowatt-hours Cents per
Kilowatt-hour
(in thousands)
- ------------------------------------------------------
1998 23,315,950 4.70
1997 20,664,786 4.83(1)
1996 19,807,101 5.11
- ------------------------------------------------------
(1) Excludes revenues related to the transmission and system operations business
effective April 1, 1997.
31
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. In spite of
mild weather in 1997, kWh sales to Members increased by 4.3% compared to 1996
due to continued growth in the Member systems' service territories.
The energy portion of Member revenues per kWh increased 20.5% in 1998
compared to 1997 and 24.4% in 1997 compared to 1996. The increase in the cost of
energy supplied to the Members resulted primarily from higher purchased power
costs as discussed under "Operating Expenses" below. For 1998 compared to 1997,
the increase was the result of significantly higher prices experienced in the
wholesale electricity markets. For 1997 compared to 1996, the increase was the
result of the short-term power marketer arrangements with DLD and EPMI which
allowed Oglethorpe to pass through significant savings during 1996.
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:
- --------------------------------------------------------------------------------
1998 1997 1996
(dollars in thousands)
- --------------------------------------------------------------------------------
Sales to other utilities $ 28,890 $ 18,342 $ 39,567
Sales to power marketers 19,373 14,623 15,895
GPC-power supply arrangements - 12,360 13,092
ITS transmission agreements - 2,208 9,789
--------- --------- ---------
Total $ 48,263 $ 47,533 $ 78,343
--------- --------- ---------
--------- --------- ---------
- --------------------------------------------------------------------------------
Revenues from sales to non-Members increased in 1998 compared to 1997 and
declined in 1997 compared to 1996. Sales to other utilities in 1998 and 1997
represent sales made directly by Oglethorpe. Oglethorpe sells for its own
account any energy available from the portion of its resources dedicated to
Morgan Stanley that is not scheduled by Morgan Stanley pursuant to its power
marketer arrangements. Sales to other utilities were higher in 1998 due to three
factors: (1) capacity revenues received under an agreement entered into with
Alabama Electric Cooperative to sell 100 megawatts (MW) of capacity for the
period June 1998 through December 2005; (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. EPMI and DLD initiated sales to other utilities in 1996.
In 1996, where the power marketer did not have a contractual relationship with
the purchaser and Oglethorpe did, Oglethorpe recorded the sale and credited the
revenues to the power marketer in its monthly billing.
Under the LEM and Morgan Stanley power marketer arrangements, and previously,
under the EPMI and DLD power marketer arrangements, sales to the power marketers
represented the net energy transmitted on behalf of LEM, Morgan Stanley, EPMI
and DLD off-system on a daily basis from Oglethorpe's total resources. Such
energy was sold to LEM, EPMI and DLD 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 (before the agreements
were amended as discussed below), Oglethorpe was responsible for its share of
fuel costs any time a unit operated. Pursuant to the 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 ITS exceeded its percentage use of the system.
In such case, Oglethorpe was entitled to compensation for the use of its
investment by the other ITS 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 14.4% in 1998 compared to 1997 and
decreased 3.7% in 1997 compared to 1996. The increase in operating expenses in
1998 resulted primarily from higher purchased power costs, however, there were
also changes in fuel and production expenses. The overall decrease in operating
expenses for 1997 compared to 1996 was primarily attributable to the expenses
relating to the transmission business assumed by GTC in connection with the
Corporate Restructuring.
Production expenses were higher in 1998 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.
The increase in 1997 production operations and maintenance costs was partly
attributable to a maintenance outage at Scherer Unit No. 1. In addition,
effective January 1, 1996, the costs of nuclear refueling outages are deferred
and amortized over the 18-month period following
32
the outage. Such change in accounting resulted in a $12.4 million deferral of
maintenance costs in 1996.
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 45.3% in 1998 compared to 1997 and
increased 16.5% in 1997 compared to 1996 as result of significantly higher
purchased power energy costs, as follows:
- --------------------------------------------------------------------------------
1998 1997 1996
(dollars in thousands)
- --------------------------------------------------------------------------------
Capacity costs $115,599 $134,384 $141,047
Energy costs 272,063 132,491 88,042
-------- -------- --------
Total $387,662 $266,875 $229,089
-------- -------- --------
-------- -------- --------
- --------------------------------------------------------------------------------
Purchased power capacity costs were 14.0% lower in 1998 compared to 1997 and
4.7% lower in 1997 compared to 1996 primarily due to the elimination on
September 1 of each year of a 250 MW component block (coal-fired units) of the
Block Power Sale Agreement (the BPSA) between Oglethorpe and GPC. Purchased
power energy costs increased by 105.3% in 1998 compared to 1997, and by 50.5% in
1997 compared to 1996. The average cost of purchased power energy per MWh
increased 53.3% in 1998 compared to 1997 and increased 55.9% in 1997 compared to
1996. The increase in average cost in 1998 resulted from significant price
increases experienced in the wholesale electricity markets. The increase in
average cost in 1997 resulted from significant energy cost savings realized in
1996 from the EPMI and DLD power marketer arrangements. The volumes of purchased
power increased by 34.0% in 1998 compared to 1997, and decreased by 3.5% in 1997
compared to 1996. The higher volumes of purchased power in 1998 utilized to
serve Member load that was not contractually provided by the power marketers
resulted in a significant increase in the average kWh cost of energy to the
Members, as noted under "Operating Revenue-Sales to Members" above.
Purchased power expenses for the years 1996 through 1998 reflect the cost of
capacity and energy purchases under various long-term power purchase agreements.
These long-term agreements have, in some cases, take-or-pay minimum energy
requirements. For 1996 through 1998, 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 $173 million in 1998, $176 million in 1997 and $191 million in
1996. For a discussion of the power purchase agreements, see Note 9 of Notes to
Financial Statements.
The decrease in depreciation and amortization for 1998 and 1997 compared to
1996 resulted from the Corporate Restructuring.
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
operating expenses for 1996 represent both power delivery expenses and marketing
services expenses. As discussed under "Other Income (Expense)" herein, such
marketing services expenses for 1997 of approximately $18.3 million related to
EnerVision were shown (net of marketing support activities revenues) in "Other
Income (Expense)" since these marketing support activities were no longer part
of operations of the power supply business.
OTHER INCOME (EXPENSE)
Investment income was higher in 1997 compared to 1996 as a result of higher
earnings from the decommissioning fund and partly due to income from the
deposits from the Rocky Mountain transactions. (See "Financial Condition-Rocky
MOUNTAIN LEASE TRANSACTIONS.") The deposits were made in December 1996 and
January 1997.
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 EnerVision. As discussed in "General--Corporate Restructuring"
above, EnerVision was purchased from Oglethorpe by its senior associates on
October 15, 1998. For 1998, the caption "Other" includes no net margin or loss
from the results of operations and sale of EnerVision.
Prior to the completion of the first unit of Plant Vogtle in 1987,
Oglethorpe's Board of Directors implemented a rate mechanism that facilitated
the gradual absorption of the costs of Plant Vogtle by the Members. In each of
the years 1985 through 1995, Oglethorpe exceeded its annual net margin goal, and
under this rate mechanism, Oglethorpe retained such excess margins for later use
in mitigating rate increases associated with Plant Vogtle and, subsequently,
with the Rocky Mountain Pumped Storage Hydroelectric Facility (Rocky Mountain).
In each year beginning with 1989, a portion of these margins was returned to the
Members through billing credits and the previously deferred revenues were
recognized as "Other income". In 1996, Oglethorpe utilized all remaining amounts
available ($32.0 million) under the deferred margin rate mechanism and this
mechanism ended.
INTEREST CHARGES
Net interest charges decreased for 1998 compared to 1997 and for 1997
compared to 1996 due to the debt assumed by GTC in connection with the
Corporate Restructuring and due to interest costs savings from
33
refinancings. The increase in amortization of debt discount and expense for
1998 compared to 1997 was primarily due to the accelerated amortization of
$24 million in premiums paid to the Federal Financing Bank (FFB) for
refinancing $424 million of debt. These costs will be amortized over a period
of approximately 3 1/2 years beginning in 1998. See "Financial
Condition-Refinancing Transactions" for further discussion.
NET MARGIN AND COMPREHENSIVE MARGIN
Oglethorpe's net margin for 1998 was $21.1 million compared to $22.4 million
for 1997. Since Oglethorpe's margin requirement is based on a ratio applied to
interest charges, the reduction in interest charges resulting from the Corporate
Restructuring also reduced Oglethorpe's margin requirement effective April 1,
1997.
Comprehensive margin is now reported on the Statements of Revenues and
Expenses, consistent with Statement of Financial Accounting Standards (SFAS) No.
130, "Reporting Comprehensive Income", issued by the Financial Accounting
Standards Board. This Statement requires the reporting of all components of
changes in equity on the Statement of Revenues and Expenses. For Oglethorpe, the
only additional item being reported is the net change in unrealized gains on
investments in available-for-sale securities.
FINANCIAL CONDITION
GENERAL
The principal changes in Oglethorpe's financial condition in 1998 were due to
property additions, reductions in the cost of capital and an increase in
patronage capital. Property additions totaled $44 million and were funded
entirely with funds from operations.
A decrease in the cost of capital was achieved through the refinancing of
$194 million (net of amounts assumed by GTC) of tax-exempt pollution control
revenue bonds (PCBs) and $424 million of FFB debt. The average interest rate on
long-term debt decreased from 6.46% at December 31, 1997 to 6.15% at December
31, 1998. (See "Refinancing Transactions" herein.)
Oglethorpe's equity (patronage capital) increased by $22 million primarily
due to the retained net margins achieved in 1998.
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 1999 through 2001. 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
1999 $ 23,358 $ 35,060 $ 5,382 $ 985 $ 64,785
2000 44,971 39,007 4,000 1,416 89,394
2001 46,794 33,892 4,120 1,360 86,166
-------- -------- ------- ------- --------
Total $115,123 $107,959 $13,502 $ 3,761 $240,345
-------- -------- ------- ------- --------
-------- -------- ------- ------- --------
- --------------------------------------------------------------------------------
(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 $3.5 billion as of December 31, 1998. Expenditures for property
additions during 1998 amounted to $44 million and were funded entirely from
operations. These expenditures were primarily for additions and replacements to
generation facilities.
In addition to the funds needed for capital expenditures, approximately $296
million will be required over the next three years (1999-2001) for current
sinking fund requirements and maturities of long-term debt. Of this amount, $242
million, or 82%, 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 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 2001
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, 1998, Oglethorpe was required to maintain
minimum liquidity of $80 million under these agreements, and its
available liquidity exceeded that amount.
34
See "Rocky Mountain Lease Transactions" herein and 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, 1998, (i) approximately $106 million in cash and temporary cash
investments, (ii) $73 million in other short-term investments and (iii) up to
$290 million total available under the following credit facilities ($51 million
of which was in use):
- -----------------------------------------------------------
Short-Term Credit Facilities Amount
- -----------------------------------------------------------
Commercial paper $240,000,000
Committed line of credit:
SunTrust Bank, Atlanta 30,000,000
Uncommitted line of credit:
National Rural Utilities Cooperative
Finance Corporation (CFC) 50,000,000
- -----------------------------------------------------------
Under its commercial paper program, Oglethorpe may issue commercial paper not
to exceed $240 million outstanding at any one time. The commercial paper is
backed 100% by committed lines of credit provided by a group of banks for which
SunTrust Bank acts as agent. The maximum amount that can be outstanding at any
one time under the commercial paper program and the other lines of credit totals
$290 million due to certain restrictions contained in the SunTrust Bank
committed line of credit agreement.
As of December 31, 1998, $51 million of commercial paper was outstanding. Of
this amount, $43 million relates to the interim financing of a 217 MW combustion
turbine (CT) project expected to be completed by June 1999. This project is
owned by a newly formed cooperative, Smarr EMC, which is owned by 36 of
Oglethorpe's 39 Members. It is expected that by June 1999, Smarr EMC will
secure, on a non-recourse basis to Oglethorpe, permanent financing for this CT
project and repay Oglethorpe for the interim financing.
The remaining $8 million of the commercial paper outstanding as of
December 31, 1998 was issued to finance, also on an interim basis, the
construction of an additional 500 MW of CT projects expected to be completed
by the summer of 2000. These CTs will be owned by some or all of the Members
in Smarr EMC or a similar entity.
The maximum amount of commercial paper that is estimated to be outstanding in
conjunction with the interim financing of these CT projects is $100 million in
1999 and $150 million in 2000.
REFINANCING TRANSACTIONS
Since the early 1990s, Oglethorpe has had an on-going program to reduce its
interest costs by refinancing or prepaying a sizeable portion of its
high-interest rate debt. This program continued in 1998 with the refinancing of
$424 million of FFB debt and $194 million of PCB debt. As a result of this
program, Oglethorpe has reduced the average interest rate on its total long-term
debt from 8.83% at December 31, 1991 to 6.15% at December 31, 1998.
Oglethorpe has also implemented a program under which it is refinancing, on a
continued tax-exempt basis, the annual principal maturities of certain
tax-exempt serial bonds and the annual sinking fund payments on certain
tax-exempt term bonds. The refinancing of these principal maturities allows
Oglethorpe to preserve a low-cost source of financing while conserving cash. To
date, Oglethorpe has refinanced approximately $64 million under this program
(including $13.5 million in 1998; net of amounts assumed by GTC) and plans to
refinance PCB principal maturing through the year 2002.
In connection with the Corporate Restructuring, Oglethorpe defeased
approximately $92 million in principal amount of Series 1992 PCBs. Initially
these bonds were defeased with proceeds from the issuance of approximately $92
million in commercial paper. In March and April of 1998, Oglethorpe repaid the
commercial paper issuance with two medium-term loans of $46.1 million each, one
from CoBank and one from CFC. Oglethorpe ultimately expects to refinance the two
medium-term loans with an issuance of PCBs in the fall of 2002.
Also, in connection with the Corporate Restructuring, Oglethorpe refinanced
approximately $217 million in principal amount of Series 1992A PCBs through the
issuance of PCBs maturing on December 1, 1997 (the Series 1997A Bonds), which
were in turn refinanced through the issuance of PCBs maturing on May 28, 1998
(the Series 1997B Bonds). The Series 1997B Bonds were refunded through the
issuance of $116,925,000 of Series 1998A PCBs and $100,000,000 of Series 1998B
PCBs (the Series 1998 Bonds) (including amounts assumed by GTC), having a
January 1, 2019 maturity. The Series 1998 Bonds were issued as variable rate
bonds and are supported by both a municipal bond insurance policy and bank
liquidity agreements.
ROCKY MOUNTAIN LEASE TRANSACTIONS
Oglethorpe completed, in two separate closings on December 31, 1996 and
January 3, 1997, lease transactions for its 74.61% undivided ownership
interest in Rocky Mountain, through a wholly owned subsidiary, Rocky Mountain
Leasing Corporation (RMLC). 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 through RMLC to Oglethorpe for a term of
30 years. Rocky Mountain is subject to the lien of the Mortgage Indenture.
The leasehold interest transferred is subject and subordinate to such lien.
Oglethorpe will continue to control and operate the plant during the
leaseback term, and intends to exercise its fixed
35
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. The assets of RMLC are not available to pay
creditors of Oglethorpe or its affiliates.
As a result of these transactions, Oglethorpe received net present value cash
benefits of approximately $96 million that is being recorded as a deferred
credit and will be recognized in income over the term of the leaseback.
Approximately $92 million was used for the early retirement of FFB debt and
approximately $4 million was used to pay alternative minimum taxes on the
transactions. The combination of the debt prepayment and the amortized gain will
result in an estimated $11 million in annual savings through 2001, and
additional savings in declining amounts for the remaining 24 years of the lease.
MISCELLANEOUS
COMPETITION
The electric utility industry in the United States is undergoing fundamental
change and is becoming increasingly competitive. This change is promoted by the
Energy Policy Act of 1992, recently adopted and proposed policies from the
Federal Energy Regulatory Commission (FERC) regarding mergers, transmission
access and pricing, state deregulation initiatives, increased consolidation and
mergers of electric utilities, the proliferation of power marketers and
independent power producers, generation surpluses and deficits and transmission
constraints in certain regional markets and other factors.
Several states are in the process of implementing varying forms of "retail
wheeling" (the transmission of power for a third party directly to a retail
customer) and most others are in the various stages of considering retail
competition. Proposed federal legislation could mandate retail wheeling in every
state and otherwise deregulate the industry. No legislation related to retail
wheeling 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, the staff
of the GPSC conducted a series of workshops to solicit views from the various
parties impacted by electric industry restructuring and to discuss potential
resolutions of these issues. The GPSC issued a report identifying electric
industry restructuring issues, potential resolutions and the views of the
parties who participated in the workshops. The GPSC's order in the 1998 GPC rate
case provides that there will be a docket opened to address the mechanics of how
stranded costs and stranded benefits should be calculated, the estimated range
of GPC's 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 wheeling or amend the Territorial
Act. Oglethorpe and the Members participated in the GPSC staff workshops and are
actively monitoring and studying the GPSC proceedings and 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 operate in an increasingly competitive market.
Oglethorpe has taken several steps to prepare for and adapt to the
fundamental changes that have occurred or are likely to occur in the electric
utility industry and to reduce the possibility of incurring stranded costs. Most
importantly, Oglethorpe completed the Corporate Restructuring and divided itself
into separate generation, transmission and system operations companies in order
to better serve its Members in a deregulated and competitive environment. (See
"General-Corporate Restructuring".) Since 1992, 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. (See
"Financial Condition-Refinancing Transactions".)
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 and to maintain their competitiveness in
anticipation of future competition. These activities on the part of Oglethorpe
and the Members are in various stages of study or preliminary consideration.
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 Georgia,
there could be reasons for the Members to
36
separate their physical distribution business from their energy business, or
otherwise restructure their current businesses to operate effectively under
retail competition. Oglethorpe continues to seek to identify and evaluate
opportunities to reduce the cost of wholesale power to the Members.
Oglethorpe has deferred recognition of certain costs of providing services to
the Members and certain income items pursuant to 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, 1998. 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 plant, and write-down those assets, if
impaired, to their fair value.
At this time, Oglethorpe cannot predict 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.
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, 2000. 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.
YEAR 2000
BACKGROUND. 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 Rocky Mountain,
generation substations and Oglethorpe's headquarters facilities.
Management recognizes the seriousness of the Year 2000 issue and believes it
has dedicated adequate resources to address the issue. Oglethorpe's Senior Vice
President and Chief Financial Officer is in charge of its Year 2000 program, and
he reports directly to Oglethorpe's President and Chief Executive Officer. As
part of its business alliance with Oglethorpe, Intellisource is providing
administration of Oglethorpe's Year 2000 program. Oglethorpe's Board of
Directors and its audit committee are monitoring this issue through periodic
updates from project management.
PROJECT PHASES. Oglethorpe has developed and is implementing a detailed
strategy to prevent any material disruption to operations.
37
Phase I began in April 1997 and included an inventory and assessment of
potential Year 2000 problems in its systems. Substantially all IT and non-IT
systems have been inventoried and assessed. Oglethorpe has not yet completed an
inventory and assessment on its systems at Rocky Mountain. Oglethorpe expects to
complete inventory and assessment of these systems in the second quarter of
1999.
Phase II began in the fall of 1997 and includes remediation and testing of
all inventoried IT and non-IT systems. Remediation and testing efforts for all
inventoried internally developed systems applications have been completed.
Financial accounting systems, procurement and materials management systems and
human resource/payroll systems are externally developed and supported. None of
these systems is Year 2000 ready. Oglethorpe is replacing most of its financial
accounting system modules and is retaining and upgrading one module. Oglethorpe
expects its financial accounting systems to be Year 2000 ready by the fourth
quarter of 1999. Oglethorpe is replacing its procurement and materials
management systems and expects to complete this remediation in the second
quarter of 1999. Oglethorpe is upgrading its human resource/payroll systems and
expects to complete this remediation in the third quarter of 1999. Remediation
and testing efforts for systems at Rocky Mountain are expected to be completed
by the third quarter of 1999.
Phase III began recently and includes contingency planning, an assessment of
Year 2000 readiness of material third parties and verification that all material
systems were properly inventoried, remediated and tested in Phases I and II.
This phase will be on-going throughout 1999.
RELATIONSHIPS WITH THIRD PARTIES. GTC and GSOC have implemented detailed
strategies to ensure Year 2000 readiness of the systems utilized in their
transmission and systems control operations. The Year 2000 readiness plans
for Oglethorpe, GTC and GSOC were jointly developed and are being implemented
on the same schedule, as described above.
Oglethorpe has gathered information from the Members regarding their Year
2000 readiness. Based on this information, Oglethorpe will implement a follow-up
program to monitor the Members' Year 2000 readiness and will further assess any
impact on Oglethorpe's risks and contingency planning. Oglethorpe expects to
complete the information gathering process from the Members by September 30.
During 1998, Georgia Electric Membership Corporation (the Members' trade
association) and Intellisource conducted workshops for the Members and assisted
some Members in their Year 2000 planning by providing information for their use
in this process.
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. Year 2000 remediation and testing on all generation plants which are
operated by GPC are being performed by GPC's parent company, Southern Company
(Southern). Southern estimates that total costs related to this project at the
GPC-operated plants will be approximately $38 million, of which approximately
$4.5 million is expected to be billed to Oglethorpe based on its ownership share
of these generation plants. To date, Oglethorpe has paid approximately $3.2
million for this project. Remaining costs will be expensed primarily in 1999.
Southern reports that its Year 2000 program for the Georgia-based generating
plants is scheduled to be completed by June 1999. 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.
During Phase III of its program, Oglethorpe plans to assess the Year 2000
readiness of other significant third parties, including power marketers (such as
LEM and Morgan Stanley), other utilities and vendors of materials and services.
Oglethorpe has identified over 400 such third parties, and is in the process of
prioritizing the parties from which Oglethorpe will require Year 2000
information. Oglethorpe expects to begin requesting information from these third
parties in March 1999. This information will allow Oglethorpe to perform
contingency planning, including assessing the need to identify alternative
vendors. Oglethorpe may not be able to identify all third parties' Year 2000
problems, and may not be able to develop adequate contingency plans if third
parties do not correct their Year 2000 problems.
PROJECT COSTS. In addition to the $4.5 million expected to be paid to GPC,
Oglethorpe currently estimates costs of approximately $370,000 to upgrade its
internal systems, including those relating to Rocky Mountain. To date,
Oglethorpe has spent approximately $270,000 of the estimated $370,000 on this
effort. In addition, Oglethorpe is upgrading or replacing its externally
developed financial accounting, procurement and materials management, and
human resource/payroll systems to improve functionality and to avoid Year
2000 remediation efforts on those systems, at an estimated cost of
approximately $4.0 million, of which $300,000 has been spent. 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.
These costs are estimates, and actual costs could be higher.
Oglethorpe plans to pay for Year 2000 costs with general corporate funds.
Year 2000 costs are being recovered from the Members through Oglethorpe's rates.
RISK ASSESSMENT. Oglethorpe has implemented a detailed process to minimize
the possibility of power supply interruptions related to Year 2000 challenges
and expects its IT and non-IT systems to be Year 2000 ready by December 31,
1999. The most reasonably likely worst case scenario would be service
interruptions to Oglethorpe's Members or the Members' retail consumers. These
scenarios include the
38
loss of a generating unit or a source of purchased power, or a disruption in
transmission or distribution services by GTC or the Members. Because Oglethorpe
is taking prudent steps to prepare for the Year 2000 challenges, it expects any
interruptions in power supply to be isolated and short in duration. However,
because of material relationships with third parties, it is too early to fully
assess the possibility of service interruptions to the ultimate retail
consumers.
There is also risk to the Members of billing and other business system
failures and of some reduction in net margin caused by interruptions in service
and reduced electrical demand by consumers because of their Year 2000 issues.
Oglethorpe has not fully assessed the impact of these risks on its financial
condition or results of operations.
Actual results, costs, risks, or worst case scenarios 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,
Oglethorpe's ability to locate and correct all microprocessors that are not Year
2000 ready, the readiness of third parties, and Oglethorpe's ability to develop
adequate contingency plans to respond to foreseen or unforeseen Year 2000
problems.
CONTINGENCY PLANNING. Oglethorpe recently began developing contingency
plans for its IT and non-IT systems. The contingency plans will also focus on
non-compliance by material third parties and assess the need to identify
alternative vendors and the need to increase inventory of materials and
supplies. The contingency plans are expected to be in place by June 30, 1999
and will continue to be evaluated and implemented throughout 1999. The goal
of the contingency planning process is to keep any service interruptions to a
minimum and of short duration and to avoid disruptions in its billing or
other management processes. Oglethorpe may incur additional costs as a result
of its contingency plans.
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, there can be 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. Currently, interest rate swaps are used to convert a portion of
Oglethorpe's debt portfolio from a variable rate to a fixed rate.
The table below details Oglethorpe's debt instruments and provides the
outstanding balance at the beginning and end of each year, annual principal
maturities, average interest rates for debt outstanding at the beginning of each
year, fair value of debt at December 31, 1998, and for interest rate swaps, the
contractual fixed rate of interest achieved through these transactions.
(dollars in thousands)
Fair Value -------------------------Cost---------------------------------
1998 1999 2000 2001 2002 2003
FIXED RATE DEBT
Beginning of year $2,593,878 $2,510,346 $2,419,351 $2,321,527 $2,219,055
Maturities (83,532) (90,995) (97,824) (102,472) (159,370)
---------- ---------- ---------- ---------- ----------
End of year $2,957,828 $2,510,346 $2,419,351 $2,321,527 $2,219,055 $2,059,685
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Average interest rate 6.49% 6.50% 6.51% 6.53% 6.44%
VARIABLE RATE DEBT
Beginning of year $ 407,822 $ 403,368 $ 398,868 $ 394,326 $ 389,745
Maturities (4,454) (4,500) (4,542) (4,581) (50,693)
---------- ---------- ---------- ---------- ----------
End of year $ 407,822 $ 403,368 $ 398,868 $ 394,326 $ 389,745 $ 339,052
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Average interest rate 4.20% 4.19% 4.17% 4.16% 3.59%
INTEREST RATE SWAPS *
Beginning of year $ 266,172 $ 264,168 $ 260,148 $ 256,000 $ 251,419
Maturities (2,004) (4,020) (4,148) (4,581) (4,884)
---------- ---------- ---------- ---------- ----------
End of year $ 315,521 $ 264,168 $ 260,148 $ 256,000 $ 251,419 $ 246,535
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Fixed Swap rate 5.80% 5.80% 5.80% 5.80% 5.80%
* Interest Rate Swap
Unrealized Loss $ (49,350)
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
40
contractual fixed rate of interest on $322 million of variable rate PCBs. These
transactions were entered into in early 1993 on a forward basis, pursuant to
which approximately $200 million of variable rate PCBs were issued on
November 30, 1993 and approximately $122 million of variable rate PCBs were
issued on December 1, 1994. Oglethorpe is obligated to pay the variable
interest rate that accrues on these PCBs; however, the swap arrangements
provide a mechanism for Oglethorpe to achieve a contractual fixed rate which
is lower than Oglethorpe would have obtained had it issued fixed rate bonds.
Oglethorpe's use of interest rate derivatives is currently limited to these
two swap transactions.
In connection with GTC's assumption of liability on a portion of the PCBs
pursuant to the Corporate Restructuring, 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, 1998, both bond issues underlying the swaps carried a variable
rate of interest of 3.85%. For the three years ended December 31, 1996, 1997
and 1998, 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 $8.2 million, $6.4 million and $6.3 million, respectively.
The swap arrangements extend for the life of these PCBs. If the swap
arrangements were to be terminated while the PCBs are still outstanding,
Oglethorpe or AIG-FP may owe the other party a termination payment depending on
a number of factors, including whether the fixed rate then being offered under
comparable swap arrangements is higher or lower than the Fixed Rate. Under the
terms of the swap agreements, AIG-FP has limited rights to terminate the swaps
only upon the occurrence of specified events of default or a reduction in
ratings on Oglethorpe's PCBs, without credit enhancement, to a level that is
below investment grade. Oglethorpe estimates that its maximum aggregate
liability (net of GTC's assumed percentage) for termination payments under both
swap arrangements had such payments been due on December 31, 1998 would have
been approximately $49.4 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
41
decommissioning. (See Note 1(g) of Notes to Financial Statements in Item 8.) As
of December 31, 1998, these funds were invested primarily in domestic equity
securities, U.S. Government and corporate debt securities and asset-backed
securities. By maintaining a portfolio that includes long-term equity
investments, Oglethorpe intends to maximize the returns to be utilized to fund
nuclear decommissioning, which in the long-term will better correlate to
inflationary increases in decommissioning costs. However, the equity securities
included in Oglethorpe's portfolio are exposed to price fluctuation in equity
markets. A 10% decline in the value of the fund's equity securities as of
December 31, 1998 would result in a loss of value to the fund of $6.1 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
Member's 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.)
42
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGE
----
Statements of Revenues and Expenses,
For the Years Ended December 31, 1998, 1997 and 1996.......................................... 45
Statements of Patronage Capital,
For the Years Ended December 31, 1998, 1997 and 1996.......................................... 45
Balance Sheets, As of December 31, 1998 and 1997................................................. 46
Statements of Capitalization, As of December 31, 1998 and 1997................................... 48
Statements of Cash Flows,
For the Years Ended December 31, 1998, 1997 and 1996 ......................................... 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, 1998, 1997 AND 1996
(dollars in thousands)
1998 1997 1996
Operating revenues (Note 1):
Sales to Members.................................. $ 1,095,904 $ 1,000,319 $ 1,023,094
Sales to non-Members.............................. 48,263 47,533 78,343
----------- ------------ -----------
Total operating revenues............................. 1,144,167 1,047,852 1,101,437
----------- ------------ -----------
Operating expenses:
Fuel.............................................. 191,399 206,315 206,524
Production........................................ 198,378 181,923 173,497
Purchased power (Note 9).......................... 387,662 266,875 229,089
Depreciation and amortization..................... 124,074 126,730 163,130
Income taxes (Note 3)............................. - - -
Other operating expenses.......................... - 6,334 46,448
----------- ------------ -----------
Total operating expenses............................. 901,513 788,177 818,688
----------- ------------ -----------
Operating margin..................................... 242,654 259,675 282,749
----------- ------------ -----------
Other income (expense):
Investment income................................. 27,767 29,303 23,485
Amortization of deferred gains (Notes 1 and 4).... 2,486 2,441 2,341
Amortization of net benefit of sale of income
tax benefits (Note 1)........................ 11,195 11,195 8,054
Amortization of deferred margins (Note 1)......... - - 32,047
Allowance for equity funds used during
construction (Note 1)........................ 158 157 238
Other............................................. 687 3,550 (831)
----------- ------------ -----------
Total other income................................... 42,293 46,646 65,334
----------- ------------ -----------
Interest charges:
Interest on long-term debt and capital leases..... 236,692 261,290 308,013
Other interest.................................... 12,086 13,845 10,006
Allowance for debt funds used during construction
(Note 1)..................................... (1,679) (1,674) (2,576)
Amortization of debt discount and expense......... 16,768 10,455 10,888
----------- ------------ -----------
Net interest charges................................. 263,867 283,916 326,331
----------- ------------ -----------
Net margin........................................... 21,080 22,405 21,752
Net change in unrealized gain on available-for-sale
securities........................................... 1,112 738 (4,414)
----------- ------------ -----------
Comprehensive margin................................. $ 22,192 $ 23,143 $ 17,338
----------- ------------ -----------
----------- ------------ -----------
STATEMENTS OF PATRONAGE CAPITAL
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
(dollars in thousands)
1998 1997 1996
Patronage capital and membership fees -
beginning of year (Note 1)........................ $ 330,509 $ 356,229 $ 338,891
Comprehensive margin................................. 22,192 23,143 17,338
Special patronage capital
distribution (Note 11)............................... - (48,863) -
----------- ------------ -----------
Patronage capital and
membership fees-end of year....................... $ 352,701 $ 330,509 $ 356,229
----------- ------------ -----------
----------- ------------ -----------
The accompanying notes are an integral part of these financial statements.
45
BALANCE SHEETS
DECEMBER 31, 1998 AND 1997
- --------------------------------------------------------------------------------------------------
(dollars in thousands)
ASSETS 1998 1997
Electric plant (Notes 1, 4 and 6):
In service.......................................... $ 4,856,174 $ 4,910,067
Less: Accumulated provision for depreciation........ (1,510,888) (1,412,287)
-------------- -------------
3,345,286 3,497,780
Nuclear fuel, at amortized cost..................... 84,418 90,424
Construction work in progress....................... 20,948 13,578
-------------- -------------
3,450,652 3,601,782
-------------- -------------
Investments and funds (Notes 1 and 2):
Decommissioning fund, at market..................... 122,094 105,817
Deposit on Rocky Mountain transactions, at cost..... 55,755 52,176
Bond, reserve and construction funds, at market..... 32,909 33,161
Investment in associated companies, at cost......... 16,231 15,940
Other, at cost...................................... 3,326 3,858
-------------- -------------
230,315 210,952
-------------- -------------
Current assets:
Cash and temporary cash investments, at cost
(Note 1).......................................... 106,235 63,215
Other short-term investments, at market............. 73,356 97,021
Receivables......................................... 110,919 105,894
Inventories, at average cost (Note 1)............... 76,783 65,528
Notes receivable (Note 5)........................... 45,151 881
Prepayments and other current assets................ 21,395 12,530
-------------- -------------
433,839 345,069
-------------- -------------
Deferred charges:
Premium and loss on reacquired debt, being
amortized (Note 5)................................ 206,729 196,583
Deferred amortization of Scherer leasehold
(Note 4).......................................... 99,297 96,303
Discontinued projects, being amortized (Note 1)..... 36,203 5,947
Deferred debt expense, being amortized.............. 15,825 15,345
Other (Note 1)...................................... 33,405 37,876
-------------- -------------
391,459 352,054
-------------- -------------
$ 4,506,265 $ 4,509,857
-------------- -------------
-------------- -------------
The accompanying notes are an integral part of these financial statements.
46
(dollars in thousands)
EQUITY AND LIABILITIES 1998 1997
Capitalization (see accompanying statements):
Patronage capital and membership fees (Note 1)................ $ 352,701 $ 330,509
Long-term debt................................................ 3,177,883 3,258,046
Obligation under capital leases (Note 4)...................... 282,299 288,638
Obligation under Rocky Mountain transactions (Note 1)......... 55,755 52,176
-------------- --------------
3,868,638 3,929,369
-------------- --------------
Current liabilities:
Long-term debt and capital leases due within one year
(Note 5).................................................... 97,475 89,556
Accounts payable.............................................. 46,676 51,103
Notes payable (Note 5)........................................ 50,986 -
Accrued interest.............................................. 10,074 12,961
Other current liabilities..................................... 18,115 8,945
-------------- --------------
223,326 162,565
-------------- --------------
Deferred credits and other liabilities:
Gain on sale of plant, being amortized (Note 4)............... 58,282 60,756
Net benefit of sale of income tax benefits, being amortized
(Note 1).................................................... 26,030 34,039
Net benefit of Rocky Mountain transactions, being amortized
(Note 1).................................................... 89,189 92,375
Accumulated deferred income taxes (Note 3).................... 63,203 63,117
Decommissioning reserve (Note 1).............................. 156,021 142,354
Other......................................................... 21,576 25,282
-------------- --------------
414,301 417,923
-------------- --------------
Commitments and Contingencies (Notes 4 and 9)
$ 4,506,265 $ 4,509,857
-------------- --------------
-------------- --------------
47
STATEMENTS OF CAPITALIZATION
DECEMBER 31, 1998 AND 1997
- -----------------------------------------------------------------------------------------------------------------------------
(dollars in thousands)
1998 1997
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 6.55% at December 31, 1998) due
in quarterly installments through 2023 ...................................................... $ 2,383,468 $ 2,456,300
Mortgage notes payable to the Rural Utilities Service (RUS) at an interest rate of
5% due in monthly installments through 2021.................................................. 14,133 14,499
Mortgage notes issued in conjunction with the sale by public authorities of pollution
control revenue bonds (PCBs):
* Series 1992A
Serial bonds, 5.55% to 6.80%, due serially from 1999 through 2012 ........................ 119,360^^ 124,690^^
* Series 1993
Serial bonds, 3.95% to 5.25%, due serially from 1999 through 2013 ........................ 35,480^^ 36,380^^
* Series 1993A
Adjustable tender bonds, 3.85%, due 1999 through 2016 .................................... 197,425^^ 199,690^^
* Series 1993B
Serial bonds, 3.95% to 5.05%, due serially from 1999 through 2008 ........................ 120,445^^ 126,935^^
* Series 1994
Serial bonds, 5.70% to 7.125%, due serially from 1999 through 2015 ....................... 9,685^^ 10,035^^
Term bonds, 7.15% due 2016 to 2021 ....................................................... 11,550^^ 11,550^^
* Series 1994A
Adjustable tender bonds, 3.85%, due 2000 to 2019 ......................................... 122,740^^ 122,740^^
* Series 1994B
Serial bonds, 5.70% to 6.45%, due serially from 1999 through 2005 ........................ 10,590^^ 11,140^^
* Series 1997A
Adjustable tender bonds, 3.40% to May 1999, due 2018 ..................................... 5,330^^ 5,330^^
* Series 1997B
Term bonds, 3.80% due May 1998 ........................................................... -- 216,925^^
* Series 1997C
Adjustable tender bonds, 3.40% to May 1999, due 2018 ..................................... 9,305^^ 9,305^^
* Series 1998A
Adjustable tender bonds, variable rates 2.95% to 3.45%, due 2019 ......................... 116,925^^ --
* Series 1998B
Adjustable tender bonds, variable rates 2.95% to 3.35%, due 2019 ......................... 100,000^^ --
Unsecured notes issued in conjunction with the sale by public authorities of pollution
control revenue bonds:
* Series 1996
Adjustable tender bonds, 3.45% to May 1999, due in 2017 .................................. 37,885 37,885
* Series 1998A
Adjustable tender bonds, 3.50% to May 1999, due 2019 ..................................... 5,615^^ --
* Series 1998C
Adjustable tender bonds, 3.50% to May 1999, due 2019 ................................... 10,570^^ --
CoBank, ACB notes payable:
* Headquarters mortgage note payable: fixed at 6.47% through January 1999,
due in quarterly installments through January 1, 2009 .................................... 3,990 4,380
* Transmission mortgage note payable: fixed at 6.71% through February 1999; due in
bi-monthly installments through November 1, 2018 ........................................ 1,822 1,844
* Transmission mortgage note payable: fixed at 6.71% to March 1999; due in bi-monthly
installments through September 1, 2019 ................................................... 6,987 7,060
* Medium-term loan, variable at 5.61% to 6.39%, due at various maturities
through September 1999, due March 31, 2003 .............................................. 46,065 --
National Rural Utilities Cooperative Finance Corporation notes payable:
* Medium-term loan fixed at 6.575%, due March 31, 2003 ...................................... 46,065 --
Commercial Paper, 5.84% to 6.15%, due at various maturities through February 1998 ............. -- 91,992
----------- -----------
3,415,435 3,488,680
^^Less: Portion (16.86%) of PCBs assumed by Georgia Transmission Corporation ................... (147,563) (147,513)
----------- -----------
Total long-term debt, net .................................................................... 3,267,872 3,341,167
Less:Long-term debt due within one year ...................................................... (89,989) (83,121)
----------- -----------
Total long-term debt, excluding amount due within one year ....................................... 3,177,883 3,258,046
Obligation under capital leases, long-term (Note 4) .............................................. 282,299 288,638
Obligation under Rocky Mountain transactions, long-term (Note 1) ................................. 55,755 52,176
Patronage capital and membership fees (Note 1) ................................................... 352,701 330,509
----------- -----------
Total capitalization ............................................................................. $ 3,868,638 $ 3,929,369
----------- -----------
----------- -----------
The accompanying notes are an integral part of these financial statements.
48
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBER 31, 1998, 1997 AND 1996
- --------------------------------------------------------------------------------
(dollars in thousands)
1998 1997 1996
Cash flows from operating activities:
Net margin......................................................... $ 21,080 $ 22,405 $ 21,752
-------- -------- --------
Adjustments to reconcile net margin to net cash provided by
operating activities:
Depreciation and amortization.................................. 182,343 171,573 196,593
Net benefit of Rocky Mountain transactions..................... - 21,673 70,701
Interest on decommissioning reserve............................ 9,716 12,113 7,167
Amortization of deferred gains................................. (2,486) (2,441) (2,341)
Deferred margins and amortization of deferred margins.......... - - (32,047)
Amortization of net benefit of sale of income tax benefits..... (11,195) (11,195) (8,145)
Allowance for equity funds used during construction............ (158) (157) (238)
Deferred income taxes.......................................... 86 1,132 (3,525)
Option payment on power swap agreement......................... - (2,042) (3,750)
Other.......................................................... (4,171) 779 (13)
Change in net current assets, excluding long-term debt due
within one year and deferred margins to be refunded
within one year:
Receivables.................................................... (5,025) 7,249 (13,884)
Inventories.................................................... (11,255) 15,316 (6,875)
Prepayments and other current assets........................... (8,865) 2,025 (299)
Accounts payable............................................... (4,427) 8,797 (5,964)
Accrued interest............................................... (2,887) (2,850) (75,165)
Accrued and withheld taxes..................................... (302) (4,423) 3,155
Other current liabilities...................................... 9,472 2,903 (3,985)
-------- -------- --------
Total adjustments.................................................. 150,846 220,452 121,385
-------- -------- --------
Net cash provided by operating activities............................. 171,926 242,857 143,137
-------- -------- --------
Cash flows from investing activities:
Property additions............................................... (43,904) (63,527) (93,704)
Activity in decommissioning fund - Purchases..................... (504,720) (435,799) (327,233)
- Proceeds...................... 490,450 419,930 316,542
Activity in bond, reserve and construction funds - Purchases..... - (35,646) (107,890)
- Proceeds...... 893 57,035 109,230
Decrease (increase) in other short-term investments.............. 24,137 (5,380) (15,532)
Decrease (increase) in investment in associated organizations.... (291) (561) 474
Decrease (increase) in notes receivable.......................... 60 (734) 153
Net cash received in Corporate Restructuring (Note 11)........... - 24,540 -
-------- -------- --------
Net cash used in investing activities................................. (33,375) (40,142) (117,960)
-------- -------- --------
Cash flows from financing activities:
Debt proceeds, net............................................... 6,024 5,671 2,243
Debt payments.................................................... (86,889) (229,242) (95,367)
Premium paid on refinancing of debt.............................. (24,041) - -
Increase in notes payable (Note 5)............................... 50,986 - -
Increase in note receivable under interim financing
agreement (Note 5)............................................... (44,330) - -
Special patronage capital distribution........................... - (48,863) -
Other............................................................ 2,719 151 (421)
-------- -------- --------
Net cash used in financing activities................................. (95,531) (272,283) (93,545)
-------- -------- --------
Net increase (decrease) in cash and temporary cash investments........ 43,020 (69,568) (68,368)
Cash and temporary cash investments at beginning of year.............. 63,215 132,783 201,151
-------- -------- --------
Cash and temporary cash investments at end of year.................... $106,235 $ 63,215 $132,783
-------- -------- --------
-------- -------- --------
Cash paid for:
Interest (net of amounts capitalized)............................ $240,270 $277,294 $383,440
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, 1998, 1997 AND 1996
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 2.9 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
1,000 MW of power 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, 1998 and 1997 and the
reported amounts of revenues and expenses for each of the three years ending
December 31, 1998. Actual results could differ from those estimates.
c. PATRONAGE CAPITAL AND MEMBERSHIP FEES
Oglethorpe is organized and operates as a cooperative. The Members paid a
total of $195 in membership fees. Patronage capital is the retained net margin
of Oglethorpe. 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 1998 and 1997 under the Mortgage Indenture, Oglethorpe was required to
produce a Margins for Interest (MFI) Ratio of at least 1.10. Under Oglethorpe's
prior RUS mortgage, Oglethorpe's margin policy was based on the provision of a
Times Interest Earned Ratio (TIER) established annually by the Oglethorpe Board
of Directors. Pursuant to this policy, the annual net margin goal for 1996 was
the amount required to produce a TIER of 1.07.
50
The Oglethorpe Board of Directors adopted resolutions annually requiring that
Oglethorpe's net margins for the years 1985 through 1995 in excess of its annual
margin goals be deferred and used to mitigate rate increases associated with
Plant Vogtle and Rocky Mountain Pumped Storage Hydroelectric Project (Rocky
Mountain). Pursuant to rate actions by Oglethorpe's Board of Directors,
specified amounts of deferred margins were returned in 1989 through 1995 and all
remaining amounts were returned in 1996.
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 Cobb EMC and Jackson EMC, two of Oglethorpe's Members,
accounted for 12.8% and 11.4% in 1998, 12.8% and 11.7% in 1997, and 12.5% and
11.2% in 1996, 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 1998, 1997 and 1996 amounted to $46,751,000, $47,123,000 and
$49,298,000, 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. Plant Vogtle's spent fuel storage capacity includes the installation in
1998 of additional rack capacity. Activities for adding dry cask storage
capacity at Plant Hatch by as early as 1999 are in progress.
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
$12,200,000, which is being amortized to nuclear fuel expense over the next 10
years. Oglethorpe has also recorded an obligation to DOE which approximated
$9,400,000 at December 31, 1998.
g. NUCLEAR DECOMMISSIONING
Oglethorpe's portion of the costs of decommissioning co-owned nuclear
facilities is estimated as follows:
- --------------------------------------------------------------------------------
(dollars in thousands) Hatch Hatch Vogle Vogle
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.
The annual provision, based on the 1994 site study, for decommissioning for
1998, 1997 and 1996 was $2,597,000, $2,597,000 and $2,597,000, respectively. In
developing the amount of the annual provision for 1997 and 1998, the escalation
rate was assumed to be 2.72% and return on trust assets was
51
assumed to be 8%. The 1998 site study was utilized in developing the annual
provision for 1999 and subsequent years. Oglethorpe accounts for this provision
for decommissioning as 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 Nuclear Regulatory Commission (NRC) regulation,
Oglethorpe maintains an external trust fund to provide for a portion of the cost
of decommissioning its nuclear facilities. The NRC regulation requires funding
levels based on average expected cost to decommission only the radioactive
portions of a typical nuclear facility. Oglethorpe's decommissioning reserve
reflects its obligation to decommission both the radioactive and most of the
non-radioactive portions of its nuclear facilities.
Realized investment earnings from the external trust fund, while increasing
the fund and interest income, also are applied to the decommissioning reserve
and charged to interest expense. Interest income earned from the external trust
fund is offset by the recognition of interest expense such that there is no
effect on Oglethorpe's net margin.
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 1998,
1997 and 1996 were as follows:
- ----------------------------------------------------------------------------------
1998 1997 1996
- ----------------------------------------------------------------------------------
Steam production 2.14% 2.13% 2.13%
Nuclear production 2.77% 2.74% 2.73%
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% 2.88%
General 2.00-20.00% 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, 1998 and 1997, 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, 1998 and 1997, $13,457,000 and $12,167,000 were restricted by
PCBs trust indentures and were utilized in January 1999 and 1998 for payment of
principal on certain PCBs, respectively.
l. INVENTORIES
Oglethorpe maintains inventories of fossil fuels for its generation plant
and spare parts for certain of its generation and transmission plant. These
inventories
52
are stated at weighted average cost on the accompanying balance sheets.
At December 31, 1998 and 1997, fossil fuels inventories were $18,692,000 and
$7,288,000, respectively. Inventories for spare parts at December 31, 1998 and
1997 were $58,091,000 and $58,240,000, respectively.
m. DEFERRED CHARGES
Prior to 1996, Oglethorpe expensed nuclear refueling outage costs as
incurred. In 1996, Oglethorpe began accounting for these costs on a normalized
basis. Under this method of accounting, refueling outage costs are deferred and
subsequently amortized to expense over the 18-month operating cycle of each
unit. Deferred nuclear outage costs at December 31, 1998 and 1997 were
$17,163,000 and $19,802,000, 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 $30,752,000 have been reclassified from electric
plant in service to deferred charges on the accompanying balance sheets.
Oglethorpe's Board of Directors has authorized that these costs be amortized and
fully recovered through rates over a period of four years beginning in 1999.
n. DEFERRED CREDITS
In April 1982, Oglethorpe sold to three purchasers certain of the income tax
benefits associated with Scherer Unit No.1 and related common facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act of
1981. Oglethorpe received a total of approximately $110,000,000 from the safe
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. The lease transactions initially increased Oglethorpe's Capitalization
and Investments and funds by $57,495,000, respectively (see Note 2 where
discussed further).
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, 1998 and 1997:
- --------------------------------------------------------------------------------
(dollars in thousands) 1998 1997
- --------------------------------------------------------------------------------
Premium and loss on reacquired debt $206,729 $196,583
Deferred amortization of Scherer leasehold 99,297 96,303
Discontinued projects 36,203 5,947
Other regulatory assets 28,668 32,371
Net benefit of sale of income tax benefits (26,030) (34,039)
Net benefit of Rocky Mountain transactions (89,189) (92,375)
-------- --------
$255,678 $204,790
-------- --------
-------- --------
- --------------------------------------------------------------------------------
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.
53
2. Fair value of financial instruments:
A detail of the estimated fair values of Oglethorpe's financial instruments
as of December 31, 1998 and 1997 is as follows:
- ------------------------------------------------------------------------------------------------------
(dollars in thousands) 1998 1997
Fair Fair
Cost Value Cost Value
- ------------------------------------------------------------------------------------------------------
Cash and temporary cash investments:
Commercial paper $ 105,567 $ 105,567 $ 62,772 $ 62,772
Cash and money market
securities 668 668 443 443
----------- ----------- ----------- -----------
Total $ 106,235 $ 106,235 $ 63,215 $ 63,215
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Other short term
investments $ 72,955 $ 73,356 $ 97,092 $ 97,021
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Bond, reserve and construction funds:
U.S. Government
securities $ 20,486 $ 21,091 $ 20,542 $ 20,505
Repurchase agreements 11,818 11,818 12,655 12,656
----------- ----------- ----------- -----------
Total $ 32,304 $ 32,909 $ 33,197 $ 33,161
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Decommissioning fund:
U.S. Government
securities $ 27,521 $ 28,442 $ 21,070 $ 21,668
Foreign government
securities 732 738 641 695
Commercial paper 4,785 4,784 5,507 5,506
Corporate bonds 10,855 11,465 12,537 12,967
Equity securities 53,760 61,400 45,044 51,252
Asset-backed securities 7,442 7,593 9,202 9,237
Other bonds 940 944 -- --
Cash and money market
securities 6,728 6,728 4,492 4,492
----------- ----------- ----------- -----------
Total $ 112,763 $ 122,094 $ 98,493 $ 105,817
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Long-term debt $ 3,177,883 $ 3,541,832 $ 3,258,046 $ 3,497,842
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
Interest rate swap
(unrealized loss) $ -- $ (49,350) $ -- $ (38,349)
----------- ----------- ----------- -----------
----------- ----------- ----------- -----------
- ------------------------------------------------------------------------------------------------------
The contractual maturities of debt securities available for sale at December
31, 1998 and 1997, regardless of their balance sheet classification, are as
follows:
- --------------------------------------------------------------------------------------------------------
(dollars in thousands) 1998 1997
Fair Fair
Cost Value Cost Value
- --------------------------------------------------------------------------------------------------------
Due within one year $ 16,556 $ 16,593 $ 14,147 $ 14,158
Due after one year through five years 26,163 27,082 18,798 18,825
Due after five years through ten years 13,504 13,739 22,677 22,781
Due after ten years 23,572 24,676 21,025 21,964
-------- -------- -------- --------
$ 79,795 $ 82,090 $ 76,647 $ 77,728
-------- -------- -------- --------
-------- -------- -------- --------
- --------------------------------------------------------------------------------------------------------
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, 1998 was $197,425,000 (includes the portion assumed by GTC) and the
fixed swap rate is 5.67% (the variable rate at December 31, 1998 and 1997 was
3.85% and 3.65%, respectively). With respect to the Series 1994A notes, the
notional principal at December 31, 1998 was $122,740,000 (includes the portion
assumed by GTC) and the fixed swap rate is 6.01% (the variable rate at December
31, 1998 and 1997 was 3.85% and 3.65%, respectively). The notional principal
amount is used to measure the amount of the swap payments and does not represent
additional principal due to the counterparty. The swap arrangements extend for
the life of the refunding bonds, with reductions in the outstanding principal
amounts of the refunding bonds causing corresponding reductions in the notional
amounts of the swap payments. Oglethorpe's portion of the estimated fair
value of the swap arrangements at December 31, 1998 and 1997 was an
unrealized loss of $49,350,000 and $38,349,000, respectively, representing
the estimated payment Oglethorpe would pay if the swap arrangements
54
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, 1998
were $12,182,000 and $1,845,000, respectively. Gross unrealized gains and losses
at December 31, 1997 were $12,800,000 and $5,583,000, respectively. For 1998 and
1997, proceeds from sales of available-for-sale securities totaled $491,343,000
and $476,965,000, respectively. Gross realized gains and losses from the 1998
sales were $12,892,000 and $6,602,000, respectively. Gross realized gains and
losses from the 1997 sales were $11,415,000 and $3,010,000, respectively.
Investments in associated companies were as follows at December 31, 1998 and
1997:
- ---------------------------------------------------------------
(dollars in thousands) 1998 1997
- ---------------------------------------------------------------
National Rural Utilities
Cooperative Finance Corp. (CFC) $ 13,476 $ 13,476
CoBank, ACB 1,734 1,955
Other 1,021 509
-------- --------
Total $ 16,231 $ 15,940
-------- --------
-------- --------
- ---------------------------------------------------------------
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, 2000. 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.
55
A detail of the provision for income taxes in 1998, 1997 and 1996 is shown as
follows:
- ----------------------------------------------------------
(dollars in thousands) 1998 1997 1996
- ----------------------------------------------------------
Current
Federal $ (86) $(1,132) $ 3,525
State -- -- --
------ ------- -------
(86) (1,132) 3,525
------ ------- -------
Deferred
Federal 86 1,132 (3,525)
State -- -- --
------ ------- -------
86 1,132 (3,525)
------ ------- -------
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:
- --------------------------------------------------------------------------------
1998 1997 1996
- --------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Patronage exclusion (35.7%) (35.4%) (35.7%)
Other 0.7% 0.4% 0.7%
------ ------ ------
Effective income tax rate 0.0% 0.0% 0.0%
------ ------ ------
------ ------ ------
- --------------------------------------------------------------------------------
The components of the net deferred tax liabilities as of December 31, 1998
and 1997 were as follows:
- --------------------------------------------------------------------------------
(dollars in thousands) 1998 1997
- --------------------------------------------------------------------------------
Deferred tax assets
Net operating losses $ 468,337 $ 444,590
Member loss carryforwards 134,533 189,414
Tax credits (alternative minimum tax
and other) 236,856 243,707
Accounting for Rocky Mountain
transactions 306,801 213,575
Accounting for sale of income tax benefits 61,757 75,041
Accrued nuclear decommissioning expense 55,492 51,713
Accounting for asset dispositions 30,612 31,584
Other 2,310 2,742
--------- ---------
1,296,698 1,252,366
Less: Valuation allowance (234,549) (241,483)
--------- ---------
1,062,149 1,010,883
--------- ---------
Deferred tax liabilities
Depreciation (837,991) (848,585)
Accounting for Rocky Mountain
transactions (204,019) (145,805)
Accounting for debt extinguishment (67,828) (61,094)
Other (15,514) (18,516)
--------- ----------
(1,125,352) (1,074,000)
--------- ----------
Net deferred tax liabilities $ (63,203) $ (63,117)
--------- ----------
--------- ----------
- --------------------------------------------------------------------------------
As of December 31, 1998, 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 $ - $ 37,206 $ -
2000 - 3,198 -
2001 - 7,264 -
2002 - 130,377 -
2003 - 652 240,341
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 - - 71,164
None 2,307 - -
------- -------- ----------
$ 2,307 $234,549 $1,203,949
------- -------- ----------
------- -------- ----------
- ------------------------------------------------------
Based on Oglethorpe's historical taxable transactions, the timing of the
reversal of existing temporary differences, future income, and tax planning
strategies, it is more likely than not that Oglethorpe's future taxable income
will be sufficient to realize the benefit of NOLs before their respective
expiration dates. The NOLs expiration dates start in the year 2003 and end in
the year 2018. 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 1997 to 1998 was the
result of the expiration of $6,934,000 of tax credits in 1998. 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
56
present value of net minimum lease payments as of December 31, 1998 are as
follows:
- ---------------------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- ---------------------------------------------------------------------------
1999 $ 37,890
2000 37,755
2001 37,629
2002 37,491
2003 37,333
2004-2021 494,355
------------
Total minimum lease payments 682,453
Less: Amount representing interest (392,668)
------------
Present value of net minimum lease payments 289,785
Less: Current portion (7,486)
------------
Long-term balance $ 282,299
------------
------------
- ---------------------------------------------------------------------------
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 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 $1,246,000 as of December 31, 1998. 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
57
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 connection with the Corporate Restructuring in March 1997, Oglethorpe
refinanced $216,925,000 (includes portion assumed by GTC) in principal amount of
Series 1992A PCBs through the issuance of Series 1997A PCBs which matured on
December 1, 1997, which in turn were refunded through the issuance of Series
1997B PCBs which matured on May 28, 1998. The series 1997B PCBs were refunded
through the issuance of $116,925,000 of Series 1998A PCBs and $100,000,000 of
Series 1998B PCBs (the Series 1998 Bonds), having a January 1, 2019 maturity.
The Series 1998 Bonds were issued as variable rate bonds and are supported by
both a municipal bond insurance policy and bank liquidity agreements. The
unamortized transaction costs related to these various PCB issues are reported
as deferred charges on the balance sheet and are being amortized over the
twenty-year life of the Series 1998 Bonds.
In October 1998, Oglethorpe completed a current refunding transaction whereby
$16,185,000 (includes portion assumed by GTC) of PCBs were issued. The proceeds
of this transaction were used to retire $16,185,000 of existing bonds in January
1999. At December 31, 1998 both the current and existing bonds were reported as
outstanding debt on the balance sheet. The unamortized transaction costs related
to this transaction have been reported as a deferred charge on the balance sheet
and are being amortized over the life of the related bonds.
In 1998, Oglethorpe refinanced more than $424,000,000 in FFB debt. In
connection with this refinancing, Oglethorpe paid prepayment premiums of
approximately $24,000,000 and is amortizing these premiums over three and one
half years.
The annual interest requirement for 1999 is estimated to be $231,000,000.
Maturities for the long-term debt and amortization of the capital lease
obligations through 2003 are as follows:
- --------------------------------------------------------------------------------
(dollars in thousands)1999 2000 2001 2002 2003
- --------------------------------------------------------------------------------
FFB and RUS $ 74,954 $ 81,058 $ 86,314 $ 90,830 $ 96,424
CoBank 495 508 523 540 46,623
PCBs* 14,540 17,949 19,678 20,264 25,835
CFC -- -- -- -- 46,065
Capital Leases 7,486 7,075 7,775 8,544 9,455
-------- -------- -------- -------- --------
Total $ 97,475 $106,590 $114,290 $120,178 $224,402
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
*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 6.14%.
Oglethorpe has a commercial paper program under which it may issue
commercial paper not to exceed a $240,000,000 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, 1998 and 1997, approximately $51,000,000 and
$92,000,000, respectively, of commercial paper was outstanding. The majority of
the amount outstanding at year-end 1997 was in connection with the defeasance of
the Series 1992 PCBs discussed above. 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 expected to be completed
by June 1999. This project is owned by a newly formed cooperative, Smarr EMC,
which is owned by 36 of Oglethorpe's 39 Members. It is expected that by June
1999, Smarr
58
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
and a $30,000,000 committed line of credit with SunTrust Bank, Atlanta
(SunTrust). The maximum combined amount that can be outstanding under these
lines of credit and the commercial paper program at any one time totals
$290,000,000 due to certain restrictions contained in the SunTrust line of
credit agreement. No balance was outstanding on either of these two lines of
credit at either December 31, 1998 or 1997.
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) $2,732,506 $ 790,303
Hatch Units No. 1 & No. 2
(Nuclear - 30% ownership) 515,665 225,000
Wansley Units No. 1 & No. 2
(Fossil - 30% ownership) 172,067 88,834
Scherer Unit No. 1
(Fossil - 60% ownership) 427,304 209,342
Rocky Mountain Units No. 1,
No. 2 & No. 3
(Hydro - 74.6% ownership) 556,880 39,689
Tallassee (Harrison Dam)
(Hydro - 100% ownership) 9,270 2,153
Wansley (Combustion Turbine -
30% ownership) 3,655 1,374
Generation step-up substations 58,193 21,946
Other 79,504 23,995
Property under capital lease
Scherer Unit No. 2
(Fossil - 60% leasehold) 301,130 108,252
---------- ----------
Total in-service $4,856,174 $1,510,888
---------- ----------
---------- ----------
Construction work in progress
Generation improvements $ 20,271
Other 677
----------
Total construction work in progress $ 20,948
----------
----------
- --------------------------------------------------------------------------------
Oglethorpe, as of December 31, 1998, estimates property additions (including
capitalized interest but excluding nuclear fuel) to be approximately $30,000,000
in 1999, $50,000,000 in 2000 and $52,000,000 in 2001, primarily for replacements
and additions to generation facilities.
Oglethorpe's proportionate share of direct expenses of joint operation of the
above plants is included in the corresponding operating expense captions (e.g.,
fuel, production or depreciation) on the accompanying statements of revenues and
expenses.
7. Employee benefit plans:
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.
Effective for fiscal year 1998, Oglethorpe adopted SFAS No. 132, "Employers
Disclosure about Pensions and Other Postretirement Benefits." The new standard
requires revisions of disclosures for Oglethorpe's pension plan, but does not
change the measurement or recognition of the plan.
The changes in obligations, plan assets and funded status of the pension plan
at December 31, 1998 and 1997 were as follows:
- --------------------------------------------------------------------------
(dollars in thousands) 1998 1997
- --------------------------------------------------------------------------
Projected Benefit Obligation
Beginning of year $ 11,294 $ 13,211
Service cost 415 560
Interest cost 756 791
Divestitures -- (3,150)
Actuarial gain (202) (128)
Benefit payments (406) (451)
Change in discount rate 1,035 461
Assumption change 1,037 --
Net effect of termination (892) --
--------- ---------
End of year $ 13,037 $ 11,294
--------- ---------
--------- ---------
Change in plan assets
Fair value of plan assets at
beginning of year $ 9,568 $ 9,218
Divestitures -- (1,291)
Actual return on assets 1,992 1,872
Employer contributions 58 220
Benefits paid (406) (451)
--------- ---------
Fair value of plan assets at end of year $ 11,212 $ 9,568
--------- ---------
--------- ---------
Funded status
Obligation in excess of assets $ (1,825) $ (1,726)
Unrecognized net actuarial gain -- (2,243)
Unrecognized prior service cost -- 355
Unrecognized net asset -- (77)
--------- ---------
Net accrued pension cost $ (1,825) $ (3,691)
--------- ---------
--------- ---------
- --------------------------------------------------------------------------
59
The plan's pension cost recognized in 1998, 1997 and 1996 were as follows:
- -------------------------------------------------------------------------------
(dollars in thousands) 1998 1997 1996
- -------------------------------------------------------------------------------
Components of net periodic benefit cost
Service cost $ 415 $ 560 $ 1,149
Interest cost 756 791 872
Less, expected return on plan assets (802) (666) (670)
Amount of prior service cost recognized 40 40 49
Amortization of unrecognized transition
asset (10) (10) (12)
Amount of gain from prior years (562) (61) --
-------- -------- --------
Net periodic benefit cost (163) 654 1,388
Estimated gain on termination (1,645) -- --
-------- -------- --------
Net pension cost $(1,808) $ 654 $ 1,388
-------- -------- --------
-------- -------- --------
- -------------------------------------------------------------------------------
The discount rate used in determining the actuarial present value of the
projected benefit obligation at termination was 5.25%. The discount rate and
rate of increase in future compensation levels used in determining the actuarial
present value of the projected benefit obligation for 1997 shown above were
7.25% and 5.0%. The expected long-term rate of return on plan assets was 8.5% in
1998, 1997 and 1996 and the discount rate used in determining the pension
expense was 7.25% in 1998, 7.5% in 1997 and 7.25% in 1996.
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 will contribute 5%, subject to IRS limitations, of each employee's
annual compensation.
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 $214,000 in 1998, $248,000 in 1997
and $561,000 in 1996.
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 be payable by Oglethorpe,
based on ownership share, is limited to approximately $4,512,000 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 $5,006,000.
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 $9,700,000,000, 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
60
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. 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 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. These agreements
extend through 2011 and into 2005, respectively. 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. All of
Oglethorpe's existing generating facilities and power purchase arrangements are
available for use by LEM and Morgan Stanley for the term of the respective
agreements. Oglethorpe continues to be responsible for all of the costs of its
system resources but receives revenue from LEM and Morgan Stanley for the use of
the resources. The Morgan Stanley agreement requires both Oglethorpe and Morgan
Stanley to make minimum purchases from each other, however, the net requirement
between the parties is immaterial. Under the LEM agreement there is no minimum
purchase required.
At the request of LEM, the parties have discussed the future of the LEM
arrangements. LEM has initiated the contractually defined binding arbitration
process as to certain load projections provided by Oglethorpe to LEM. Oglethorpe
continues to receive power under the LEM agreements and believes the agreements
are enforceable against LEM. Even so, given LEM's announced intention to
discontinue its merchant energy trading and sales business, instead of
performing itself, LEM could, with consent of Oglethorpe and the RUS, make
alternative arrangements, including assigning performance to an acceptable third
party, or otherwise make Oglethorpe whole from any damages incurred as a result
of termination. Oglethorpe believes that LEM has the ability, financial and
otherwise, to perform its obligations under these agreements.
The current uncertainty relating to the LEM arrangements does not adversely
affect Oglethorpe's ability to meet its Members' load requirements but could, in
the future, affect the sources and prices for such power. If LEM was to cease to
perform its obligations under the LEM agreements or the LEM agreements were to
be terminated, Oglethorpe expects to be able to serve its Members' needs through
its existing owned and purchased capacity, supplemented by additional capacity
either purchased in the wholesale market, constructed or otherwise acquired.
Termination of the LEM agreements would however eliminate a source of power at
contractually fixed prices and thus would introduce additional uncertainty
regarding future power costs and Member rates. Oglethorpe's management does not
expect the ultimate resolution of the LEM arrangements will have a material
adverse effect on its financial condition or results of operations.
In addition, Oglethorpe has entered into various long-term power purchase
agreements. As of December 31, 1998, 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)
- ---------------------------------------------------------
1999 $ 84,578
2000 69,075
2001 61,071
2002 44,375
2003 26,903
- ---------------------------------------------------------
Oglethorpe's power purchases from these agreements amounted to approximately
$172,897,000 in 1998, $175,818,000 in 1997 and $190,760,000 in 1996.
61
Oglethorpe has entered into an agreement with Alabama Electric Cooperative to
sell 100 MW of capacity for the period June 1998 through December 2005.
10. Quarterly financial data (unaudited):
Summarized quarterly financial information for 1998 and 1997 is as follows:
- ------------------------------------------------------------------------------------
First Second Third Fourth
(dollars in thousands) Quarter Quarter Quarter Quarter
- ------------------------------------------------------------------------------------
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
1997
Operating revenues $271,485 $242,876 $286,579 $246,912
Operating margin 77,818 61,423 56,753 63,681
Net margin 9,436 5,510 (872) 8,331
- ------------------------------------------------------------------------------------
Oglethorpe's business is influenced by seasonal weather conditions. The
fourth quarter of 1998 reflects a $1,645,000 net gain from a decision to
terminate Oglethorpe's pension plan (see Note 7). The negative net margin for
the third quarter of 1997 reflects a $4,000,000 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 August 1997.
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.
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
its 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.
Jack L. King
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, 1998 and
1997, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1998 in conformity with generally
accepted accounting principles. 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 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 26, 1999.
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
As part of the Corporate Restructuring, Oglethorpe amended its Bylaws to
provide for an eleven member board of directors consisting of six directors
elected from the Members (the "Member Directors"), four independent outside
directors (the "Outside Directors") and Oglethorpe's President and Chief
Executive Officer. 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 eleven directors are
nominated by representatives from each Member whose weighted nomination is based
on the number of retail customers served by each Member. After nomination, the
directors are elected by a majority vote of each Member, voting on a one-Member,
one-vote basis.
The Bylaws provide for staggering the terms of the Member Directors and
Outside Directors by dividing the number of directors into three groups. As
noted below, some of the directors were elected to an initial term of one year,
some two years and some three years. As these initial terms expire, directors
will thereafter be elected for a term of three years.
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............ 57 Chairman of the Board of Directors, Member Director, Statewide
Jack L. King................. 59 President and Chief Executive Officer and Director
Jerry J. Saacks.............. 58 Chief Operating Officer
Thomas A. Smith.............. 44 Senior Vice President and Chief Financial Officer
Larry N. Chadwick............ 58 Member Director, Northwest Region
Benny W. Denham.............. 68 Member Director, Southwest Region and Vice Chairman
Sammy M. Jenkins............. 72 Member Director, Southeast Region
Mac F. Oglesby............... 66 Member Director, Northeast Region and Treasurer
J. Sam L. Rabun.............. 67 Member Director, Central Region
Ashley C. Brown.............. 52 Outside Director
Newton A. Campbell........... 70 Outside Director
Wm. Ronald Duffey............ 57 Outside Director
John S. Ranson............... 69 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
64
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 was previously a member of the
Operations Review 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.
Jack L. King is the President and Chief Executive Officer of Oglethorpe and
has served in that office since July 1998. He also currently serves as the
President and Chief Executive Officer and as a director of both GTC and GSOC.
Mr. King has a total of 29 years of utility experience in all phases of utility
operations. Until last year, he was President of the Control Systems Division of
Scientific-Atlanta, Inc. From 1987 to 1994, Mr. King was employed by Entergy
Corporation, as Executive Vice President - Operations and as President of
Entergy Enterprises. From 1966 to 1987, he held several management positions
with Arkansas Power & Light, including Executive Vice President and Chief
Operating Officer. Mr. King's previous Board participation included GTC,
Arkansas Power & Light, Mississippi Power & Light, Louisiana Power & Light, New
Orleans Public Service Inc., Entergy Enterprises, System Fuels, Inc., First
Pacific Networks, Entergy Systems and Services, Entergy Power, Inc., Entergy
Argentina S.A., Entergy Power Development Corp. and Entergy S.A. Mr. King has a
Bachelor of Science degree and Master of Science degree in Electrical
Engineering from the University of Arkansas and has completed the Advanced
Management Program at the Harvard Graduate School of Business.
Jerry J. Saacks is the Chief Operating Officer of Oglethorpe and has served
in that office since December 1998. Prior to that time, Mr. Saacks served as the
Chief Operating Officer of GSOC from January 1997 to December 1998. He served as
an independent consultant for Oglethorpe from July 1994 through 1996. Prior to
that, Mr. Saacks held several positions at Entergy, including Vice President,
System Transmission Officer. He is also a member of the Southeastern Electric
Reliability Council Executive Committee. Mr. Saacks has a Bachelor of Science
degree in Electrical Engineering from Tulane University and has completed the
Advanced Management Program at the Harvard Graduate School of Business.
Thomas A. Smith is the Senior Vice President and Chief Financial Officer of
Oglethorpe and has served in that capacity since September 1998. He previously
served as Senior Financial Officer of Oglethorpe 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.
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 1999. 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
65
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
been a self-employed farmer for over 20 years. In addition, from 1973 to 1995,
he was President of Jenkins Ford Tractor Co., Inc., a seller of farm machinery.
He has served on the Board of Directors of Oglethorpe since March 1988. His
present term will expire in March 1999. 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 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
1999. 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.
Newton A. Campbell is an Outside Director. He has served on the Board of
Directors of Oglethorpe since March 1997. His term will expire in March 2000. He
retired in January 1994 as Chairman and Chief Executive Officer of Burns &
McDonnell Engineering Company after serving 41 years with the firm. Mr. Campbell
directed the overall operations of Burns & McDonnell from 1982 until his
retirement. From 1976 through 1982, he served as Vice President and General
Manager of the Power Division, and was responsible for directing the company's
work in the planning and design of fossil fueled power generation facilities,
high voltage transmission systems, and other power related facilities. Mr.
Campbell has been involved in feasibility, planning and financial studies for
numerous new and existing public and privately owned electric utilities during
various phases of their organization and development. He has over 40 years of
experience in conceptual studies, design, and project management for large
electric utility generation, transmission, substation and distribution
facilities throughout the United States. Mr. Campbell received a Master of
Business Administration degree from the University of Missouri at Kansas City
with a concentration in finance. He also holds a Bachelor of Science degree in
Electrical Engineering from the University of Illinois. Mr. Campbell is a
Director of UMB Financial Corporation in Kansas City, Missouri.
66
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 1999. 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 45 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.
67
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table sets forth, for Oglethorpe's President and Chief
Executive Officer and for other senior executives, all compensation paid or
accrued for services rendered in all capacities during the years ended December
31, 1998, 1997 and 1996. For 1998, the amounts included in the table under
"Bonus" represent a new compensation program based on the achievement of
corporate and team goals and individual performance. For 1997 and 1996, the
amounts included in the table under "Bonus" represent payments based on
Oglethorpe's prior incentive compensation policy.
ANNUAL COMPENSATION
NAME AND -------------------- ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS COMPENSATION
- ------------------ ---- ------ ----- ------------
Jack L. King......................................... 1998 $ 115,555 $ 37,500 $ 3,731 (1)
President and Chief Executive Officer 1997 0 0 0
1996 0 0 0
T. D. Kilgore........................................ 1998 188,147 0 5,167 (1)
Former President and Chief Executive Officer 1997 300,368 0 6,316
1996 265,627 0 6,246
Thomas A. Smith (2).................................. 1998 183,935 12,180 1,247 (1)
Sr. Vice President and Chief Financial Officer 1997 70,192 0 0
1996 0 0 0
Clarence D. Mitchell................................. 1998 159,866 42,524 4,591 (1)
Sr. Vice President, Operations and Projects 1997 155,210 18,810 3,774
1996 133,369 17,112 3,887
Nelson G. Hawk (3)................................... 1998 129,928 0 4,573 (1)
Former Sr. Vice President, Marketing 1997 155,210 0 5,658
1996 142,535 16,530 5,246
- ------------------
(1) Includes contributions made in 1998 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. King, Kilgore, Smith, Mitchell
and Hawk of $1,875, $3,763, $1,200, $3,025 and $3,686, respectively; and
insurance premiums paid on term life insurance on behalf of Messrs. King,
Kilgore, Smith, Mitchell and Hawk of $1,856, $1,404, $47, $1,566 and $887,
respectively.
(2) 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.
(3) In connection with Oglethorpe's transfer of its marketing services business
to EnerVision, a former wholly owned subsidiary of Oglethorpe, Mr. Hawk
ceased to be an employee of Oglethorpe as of December 31, 1997, but
remained an executive of Oglethorpe through EnerVision until October 15,
1998. At that date, EnerVision was sold its senior associates, and Mr. Hawk
ceased to be an executive of Oglethorpe. (See "OGLETHORPE POWER
CORPORATION--Relationship with EnerVision" in Item 1 for further
discussion.)
PENSION PLAN
Oglethorpe has a noncontributory defined benefit pension plan covering
substantially all employees. An amendment to the pension plan was adopted in
1998, which stipulated that benefit accruals under the pension plan would cease
as of December 31, 1998. On February 4, 1999, a notice of intent to terminate
the pension plan was distributed to all employees entitled to benefits under the
pension plan, advising such parties that Oglethorpe intended to terminate the
pension plan effective April 5, 1999. Benefits under the pension plan will be
distributed at a later date after approvals of the termination are obtained from
the Internal Revenue Service and the Pension Benefit Guaranty Corporation.
68
Benefits under the pension plan are determined by a formula based on years
of service, average final compensation and Social Security covered compensation.
The projected annual single life annuity benefit beginning at age 65 for the
senior executives listed in the Summary Compensation Table are as follows:
Name Projected Annuity Benefits
---- --------------------------
Mr. King $ 0
Mr. Kilgore 58,704
Mr. Smith 0
Mr. Mitchell 27,401
Mr. Hawk 8,074
COMPENSATION OF DIRECTORS
Oglethorpe pays its Outside Directors a fee of $5,500 per Board meeting for
four meetings in a year; a fee of $1,000 per Board meeting will be paid for the
remaining other Board meetings in a year. Outside Directors are also paid $1,000
per day for attending committee meetings, annual meetings of the Members or
other official meetings of Oglethorpe. Member Directors are paid a fee of $1,000
per Board meeting and $600 per day for attending committee meetings, annual
meetings of the Members or other official business of Oglethorpe. In addition,
Oglethorpe reimburses all Directors for out-of-pocket expenses incurred in
attending a meeting. All Directors are paid $50 per day when participating in
meetings by conference call. The Chairman of the Board is paid an additional 20%
of his Director's fee per Board meeting for time involved in preparing for the
meetings.
EMPLOYMENT CONTRACTS
In July 1998, Oglethorpe employed Jack L. King as Oglethorpe's President
and Chief Executive Officer. In January 1999, Oglethorpe and Mr. King entered
into an agreement setting forth in writing certain terms of his employment
through July 31, 2000. Mr. King's salary will be determined by Oglethorpe's
Board with annual base salary being at least $250,000. Mr. King will participate
in Oglethorpe's incentive compensation program for executive officers and is
eligible for certain other incentive compensation. If Oglethorpe terminates Mr.
King's employment without cause, he will be entitled to severance payments equal
to his salary through the date of termination plus an amount equal to six months
of salary, all incentive compensation earned or owed on the date of termination,
and the continuation for six months of all life insurance maintained for Mr.
King by Oglethorpe.
Effective September 1, 1998, Oglethorpe entered into an employment
agreement with Thomas A. Smith as Oglethorpe's Senior Vice President and Chief
Financial Officer. The agreement extends to August 31, 2003. Mr. Smith's base
salary is currently $185,000 per year, with annual increases to be determined on
each anniversary of the employment agreement by mutual agreement. Mr. Smith will
participate in Oglethorpe's incentive compensation program for executive
officers and is eligible for certain other incentive compensation. If Oglethorpe
terminates Mr. Smith's employment without cause or materially reduces the scope
of his duties or responsibilities, compensation or benefits, he will be entitled
to severance payments equal to his salary through the date of termination plus
an amount equal to up to six months of his base compensation, all incentive
compensation earned but unpaid on the date of termination, the continuation for
up to six months of all life and health insurance maintained for Mr. Smith by
Oglethorpe, and outplacement services.
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 1998. Mr. Earwood has
served as an executive officer of Oglethorpe since 1984 and has served as the
Chairman of the Board since 1989.
69
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Jack L. King is the President and Chief Executive Officer and a Director of
Oglethorpe, GTC and GSOC. Oglethorpe made payments to GSOC for system operations
services in 1998 of approximately $7.9 million, which was 59% of GSOC's revenues
for 1998. Oglethorpe made payments to GTC for transmission service in 1998 of
approximately $9.8 million, which was 8% of GTC's total operating revenues for
1998. (See "OGLETHORPE POWER CORPORATION--Corporate Restructuring" in Item 1.)
70
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, 1998, 1997 and 1996..................................................... 45
Statements of Patronage Capital, For the Years Ended
December 31, 1998, 1997 and 1996..................................................... 45
Balance Sheets, As of December 31, 1998 and 1997....................................... 46
Statements of Capitalization, As of December 31, 1998 and 1997......................... 48
Statements of Cash Flows, For the Years Ended
December 31, 1998, 1997 and 1996..................................................... 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 September 14, 1998.
71
*4.1 -- Form of Serial Facility Bond Due June 30, 2011 (included in
Collateral Trust Indenture filed as Exhibit 4.2.)
*4.2 -- Collateral Trust Indenture, dated as of December 1, 1997,
between OPC Scherer 1997 Funding Corporation A, Oglethorpe and
SunTrust Bank, Atlanta, as Trustee. (Filed as Exhibit 4.2 to
the Registrant's Form S-4 Registration Statement, File No.
333-42759.)
*4.3 -- Nonrecourse Promissory Lessor Note No. 2, with a Schedule
identifying three other substantially identical Nonrecourse
Promissory Lessor Notes and any material differences. (Filed
as Exhibit 4.3 to the Registrant's Form S-4 Registration
Statement, File No. 333-42759.)
*4.4 -- Amended and Restated Indenture of Trust, Deed to Secure
Debt and Security Agreement No. 2, dated December 1, 1997,
between Wilmington Trust Company and NationsBank, N.A.
collectively as Owner Trustee, under Trust Agreement No. 2,
dated December 30, 1985, with DFO Partnership, as assignee of
Ford Motor Credit Company, and The Bank of New York Trust
Company of Florida, N.A. as Indenture Trustee, with a Schedule
identifying three other substantially identical Amended and
Restated Indentures of Trust, Deeds to Secure Debt and
Security Agreements and any material differences. (Filed as
Exhibit 4.4 to the Registrant's Form S-4 Registration
Statement, File No. 333-42759.)
*4.5(a) -- Lease Agreement No. 2 dated December 30, 1985, between
Wilmington Trust Company and William J. Wade, as Owner
Trustees under Trust Agreement No. 2, dated December 30, 1985,
with Ford Motor Credit Company, Lessor, and Oglethorpe,
Lessee, with a Schedule identifying three other substantially
identical Lease Agreements. (Filed as Exhibit 4.5(b) to the
Registrant's Form S-1 Registration Statement, File No.
33-7591.)
*4.5(b) -- First 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.)
72
*4.7.1(b) -- First Supplemental Indenture, dated as of October 1, 1997,
made by Oglethorpe to SunTrust Bank, Atlanta, as trustee,
relating to the Series 1997B (Burke) Note. (Filed as Exhibit
4.8.1(b) to the Registrant's Form 10-Q for the quarterly
period ended September 30, 1997, File No. 33-7591).
*4.7.1(c) -- Second Supplemental Indenture, dated as of January 1, 1998,
made by Oglethorpe to SunTrust Bank, Atlanta, 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, Atlanta, 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.
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.
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.
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.
*4.7.2 -- Security Agreement, dated as of March 1, 1997, made by
Oglethorpe to SunTrust Bank, Atlanta, as trustee. (Filed as
Exhibit 4.8.2 to the Registrant's Form 10-K for the fiscal
year ended December 31, 1996, File No. 33-7591.)
4.8.1(1) -- Loan Agreement, dated as of October 1, 1992, between
Development Authority of Monroe County and Oglethorpe relating
to Development Authority of Monroe County Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Scherer Project),
Series 1992A, and five other substantially identical loan
agreements.
4.8.2(1) -- Note, dated October 1, 1992, from Oglethorpe to Trust
Company Bank, as trustee acting pursuant to a Trust Indenture,
dated as of October 1, 1992, between Development Authority of
Monroe County and Trust Company Bank, and five other
substantially identical notes.
4.8.3(1) -- Trust Indenture, dated as of October 1, 1992, between
Development Authority of Monroe County and Trust Company Bank,
Trustee, relating to Development Authority of Monroe County
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Scherer Project), Series 1992A, and five other substantially
identical trust indentures.
4.9.1(1) -- Loan Agreement, dated as of December 1, 1992, between
Development Authority of Burke County and Oglethorpe relating
to Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A, and one other substantially
identical loan agreement.
4.9.2(1) -- Note, dated December 1, 1992, from Oglethorpe to Trust
Company Bank, as trustee acting pursuant to a Trust Indenture,
dated as of December 1, 1992, between Development Authority of
Burke County and Trust Company Bank, and one other
substantially identical note.
73
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.
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 notes.
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 indentures.
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.
74
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.)
*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.
75
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.
*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.)
76
*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.)
*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.)
77
*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.)
*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 National Service Industries, Inc. and
Oglethorpe. (Filed as Exhibit 10.3 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591.)
78
*10.2.3 -- Section 168 Agreement and Election dated as of April 9,
1982, between Rollins, Inc. and Oglethorpe. (Filed as Exhibit
10.4 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591.)
*10.2.4 -- Section 168 Agreement and Election dated as of December 13,
1982, between Selig Enterprises, Inc. and Oglethorpe. (Filed
as Exhibit 10.5 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591.)
*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.)
*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.)
79
*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.)
*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.)
80
*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.)
*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.)
81
*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.)
*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.)
82
*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 Cooperation 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.)
*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.)
83
*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.)
*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.)
84
*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.)
85
*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 30, 1997, File No. 33-7591.)
10.25(3) -- Agreement Regarding Continued Employment, between Jack L.
King and Oglethorpe.
10.26(3) -- Employment Agreement, dated as of September 1, 1998,
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.
(b) REPORTS ON FORM 8-K.
No reports on Form 8-K were filed by Oglethorpe for the quarter ended
December 31, 1998.
86
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 15th day of
March, 1999.
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 March 15, 1999
- ----------------------------- (Principal Executive Officer)
J. Calvin Earwood
/s/ Jack L. King President and Chief Executive Officer March 15, 1999
- ----------------------------- (Principal Executive Officer)
Jack L. King
/s/ Mac F. Oglesby Treasurer, Director (Principal Financial March 15, 1999
- ----------------------------- Officer)
Mac F. Oglesby
/s/ Thomas A. Smith Senior Vice President and Chief March 15, 1999
- ----------------------------- Financial Officer (Principal Financial
Thomas A. Smith Officer)
/s/ Robert D. Steele Controller March 15, 1999
- -----------------------------
Robert D. Steele
/s/ Ashley C. Brown Director March 15, 1999
- -----------------------------
Ashley C. Brown
/s/ Newton A. Campbell Director March 15, 1999
- -----------------------------
Newton A. Campbell
/s/ Larry N. Chadwick Director March 15, 1999
- -----------------------------
Larry N. Chadwick
/s/ Benny W. Denham Director March 15, 1999
- -----------------------------
Benny W. Denham
87
/s/ Wm. Ronald Duffey Director March 15, 1999
- -----------------------------
Wm. Ronald Duffey
/s/ Sammy M. Jenkins Director March 15, 1999
- -----------------------------
Sammy M. Jenkins
/s/ J. Sam L. Rabun Director March 15, 1999
- -----------------------------
J. Sam L. Rabun
/s/ John S. Ranson Director March 15, 1999
- -----------------------------
John S. Ranson
88
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.
89