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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