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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C.D. C. 20549
-------------------------------------
FORM 10-K
(MARK ONE)
/X/(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D)15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBERFor the fiscal year ended December 31, 19951996
OR
/ /[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D)15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NO.For the Transition Period From ___________ to _____________
Commission File No. 33-7591
------------------------
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION & TRANSMISSION CORPORATION)-------------
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 BOXGeorgia 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
2100 EAST EXCHANGE PLACE (Zip Code)
TUCKER, GEORGIA
(Address of principal executive offices)
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
------------------------(Zip Code)
Registrant's telephone number, including area code: (770) 270-7600
Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes _X_[X] No ____[_]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be contained,
to the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. /X/[_]
State the aggregate market value of the voting stock held by
nonaffiliates of the registrant. NONENone
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.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
19951996 FORM 10-K ANNUAL REPORT
TABLE OF CONTENTS
ITEM PAGE
---- ----
PART I
1 Business ............................................................... 1
Oglethorpe Power Corporation ......................................... 1
The Members of Oglethorpe ............................................ 8
The Power Supply System .............................................. 11
Co-Owners of the Plants and the Plant and Transmission Agreements .... 21
2 Properties ............................................................. 25
3 Legal Proceedings ...................................................... 25
4 Submission of Matters to a Vote of Security Holders .................... 25
PART II
5 Market for Registrant's Common Equity and Related Stockholder Matters .. 26
6 Selected Financial Data ................................................ 26
7 Management's Discussion and Analysis of Financial Condition
and Results of Operations ............................................. 27
8 Financial Statements and Supplementary Data ............................ 35
9 Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure .............................................. 53
PART III
10 Directors and Executive Officers of the Registrant ..................... 53
11 Executive Compensation ................................................. 65
12 Security Ownership of Certain Beneficial Owners and Management ......... 67
13 Certain Relationships and Related Transactions ......................... 67
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K .......Table of Contents
Item Page
- ---- ----
PART I
1 Business ............................................................ 1
Oglethorpe Power Corporation....................................... 1
The Members of Oglethorpe.......................................... 8
Member Requirements and Power Supply Resources..................... 12
Other Information.................................................. 16
2 Properties........................................................... 17
Generating Facilities.............................................. 17
Co-Owners of the Plants and the Plant Agreements................... 20
Environmental and Other Regulations................................ 24
3 Legal Proceedings.................................................... 29
4 Submission of Matters to a Vote of Security Holders.................. 29
PART II
5 Market for Registrant's Common Equity and Related Stockholder
Matters.............................................................. 30
6 Selected Financial Data.............................................. 30
7 Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................ 31
8 Financial Statements and Supplementary Data.......................... 42
9 Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure................................................. 62
PART III
10 Directors and Executive Officers of the Registrant................... 62
11 Executive Compensation............................................... 65
12 Security Ownership of Certain Beneficial Owners and Management....... 68
13 Certain Relationships and Related Transactions....................... 68
PART IV
14 Exhibits, Financial Statement Schedules, and Reports on Form 8-K..... 69
i
SELECTED DEFINITIONS
When used herein the following terms will have the meanings indicated below:
TERM MEANINGTerm Meaning
- ---- -------
ADSCR Annual Debt Service Coverage Ratio
AFUDC Allowance for Debt and Equity Funds Used During Construction
BPSA Block Power Sale Agreement
CFC National Rural Utilities Cooperative Finance Corporation
CoBank CoBank, ACB, formerly known as the National Bank for
Cooperatives
Commission Securities and Exchange Commission
CSA Coordination Services Agreement
Dalton City of Dalton, Georgia
DOE United States Department of Energy
DSC Debt Service Coverage Ratio
EPA United States Environmental Protection Agency
EPI Entergy Power, Inc.
EPMI Enron Power Marketing, Inc.
FERC Federal Energy Regulatory Commission
FFB Federal Financing Bank
G&T Generation and Transmission Cooperative
GEMC Georgia Electric Membership Corporation
GPC Georgia Power Company
GPSC Georgia Public Service Commission
GSOC Georgia System Operations Corporation
GTC Georgia Transmission Corporation
ITS Integrated Transmission System
ITSA Revised and Restated Integrated Transmission System
Agreement
kWh Kilowatt-hours
LPM LG&E Power Marketing Inc.
Members The 39 retail distribution cooperatives that are members
of Oglethorpe
MEAG Municipal Electric Authority of Georgia
MFI Margins for Interest
Morgan Stanley Morgan Stanley Capital Group
MW Megawatts
MWh Megawatt-hours
NRC Nuclear Regulatory Commission
Oglethorpe Oglethorpe Power Corporation
PURPA Public Utility Regulatory Policies Act
RUS Rural Utilities Service, formerly known as the Rural Electrification
Administration
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
Generation &
TransmissionCorporation)
PCBs Pollution Control Revenue Bonds
PCR Percentage Capacity Responsibility
PURPA Public Utility Regulatory Policies Act
RUS Rural Utilities Service
SEPA Southeastern Power Administration
SONOPCO Southern Nuclear Operating Company
TIER Times Interest Earned Ratio
ii
PART I
Item 1. BUSINESS
OGLETHORPE POWER CORPORATION
General
Oglethorpe Power Corporation (An Electric Membership Corporation)
("Oglethorpe") is ana Georgia electric generation and
transmission cooperative ("G&T")membership corporation incorporated in 1974
in the State of
Georgia. It isand headquartered in metropolitan Atlanta. Oglethorpe is entirely owned by its
39 retail electric distribution cooperative members (the "Members"), who, in
turn, are entirely owned by their retail consumers. Oglethorpe is the largest
G&Telectric cooperative in the United States in terms of operating revenues,
assets, kilowatt-hour ("kWh") sales and, through the Members, consumers served.
It is one of the ten largest electric utilities in the United States in terms of
land area served. Oglethorpe has approximately 427146 full-time and 3918 part-time employees.employees, after
reflecting the effect of a corporate restructuring and a business alliance
transaction. (See "Corporate Restructuring" and "Relationship with
Intellisource" herein.)
As with cooperatives generally, Oglethorpe operates on a not-for-profit
basis. Oglethorpe's principal business is providing wholesale electric servicepower to
the Members. The Members are local consumer-owned distribution cooperatives
providing retail electric service on a not-for-profit basis. In general, the
membership of the distribution cooperative Members consists of residential,
commercial and industrial consumers within specific geographic areas. The
Members serve approximately 1.11.2 million electric consumers (meters) representing
a total population of approximately 2.6 million people.
MEMBER CONTRACTS
Each Member currently purchases capacity and energy from Oglethorpe
pursuant to a long-term, "all-requirements" wholesale power contract between
Oglethorpe and the Member (each a "Wholesale Power Contract" and collectively
the "Wholesale Power Contracts"). The existing Wholesale Power Contracts
have a term ending December 31, 2025 and continue thereafter until terminated
by three years' written notice by Oglethorpe or the respective Member. Each
Wholesale Power Contract provides that, except for power purchased from the
Southeastern Power Administration ("SEPA"), Oglethorpe shall sell and deliver
to the Member, and the Member shall purchase and receive from Oglethorpe, all
electric capacity and energy that the Member requires for the operation of
its system to the extent that Oglethorpe has capacity and energy and
facilities available. Oglethorpe supplies the capacity and energy
requirements of the Members from a combination of owned and leased generating
plants and from power purchased under long-term contracts with other power
suppliers, principally Georgia Power Company ("GPC"), a wholly owned
subsidiary of The Southern Company. In 1995, the aggregate SEPA allocation
to the Members was 542 megawatts ("MW") plus associated energy, representing
approximately 11% of total Member peak demand and approximately 5% of total
Member energy requirements. 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 "Member
Demand and Energy Requirements" herein and "THE MEMBERS OF OGLETHORPE--Contracts
with SEPA".)
PROPOSED RESTRUCTURING
For some time,Corporate Restructuring
Oglethorpe and the Members have been discussing various
optionscompleted a corporate restructuring (the
"Corporate Restructuring") on March 11, 1997 (the "Closing") pursuant to provide the Members greater flexibility for meeting their power
supply needs in an increasingly competitive utility environment. These
discussions led to a restructuring plan approved by Oglethorpe's Board of
Directors in December 1995 to divide Oglethorpe into three specialized
companies to respond to increasing competitionterms
and conditions set forth in the electric industrySecond Amended and to settle certain issues confrontingRestated Restructuring
Agreement, dated February 24, 1997, by and among Oglethorpe, and the Members,
including several Members' previously stated intention to withdraw from
membership in Oglethorpe in order to gain more flexibility. The December
plan proposed the creation of a new transmission company and a new system
operations company and Oglethorpe's retention of the generation business.
Oglethorpe's Board believes there are significant potential benefits to
the Members of having the transmission business and the system operations
business operated in
1
separate companies. Among the principal benefits is that the Members' freedom
to choose among power suppliers, including Oglethorpe, for their future growth
would be enhanced.
The current target date for full implementation of the
restructuring is January 1, 1997. As a preliminary step, Georgia
Transmission Corporation (An Electric Membership Corporation) ("GTC") has
been incorporated for future use as the transmission company and
Georgia System Operations Corporation ("GSOC") has been incorporated as. Pursuant to the Corporate
Restructuring, Oglethorpe divided itself into three specialized operating
companies to respond to increasing competition and regulatory changes in the
electric industry. As part of the Corporate Restructuring, the transmission
business is now owned and operated by GTC, a newly formed Georgia non-profitelectric
membership corporation, for future use asand the system operations company. On
March 29, 1996, the Boards ofbusiness is now owned and
operated by GSOC, a newly formed Georgia nonprofit corporation. Oglethorpe
GTC and GSOC approved an agreement
(the "Restructuring Agreement") which sets forth the terms and conditions on
which the restructuring and related changes would occur. The Restructuring
Agreement contemplates that Oglethorpe would operate primarily as a power
supply company, but initially would retain economic development, marketing and
service functions.
Oglethorpe would transfer its transmission business, including its
existing transmission assets,continues to GTC. GTC would thereafter own and operate its power supply business.
On October 1, 1996, Oglethorpe transferred to GSOC its system
operations assets, consisting of its system control center and related energy
control and revenue metering systems equipment. The purchase price totaled
approximately $9.4 million and was paid by GSOC's assumption of Oglethorpe's
obligations under an existing note held by the transmissionRural Utilities Service ("RUS"),
by delivery of a purchase money note payable to Oglethorpe and by the assumption
of certain other liabilities of Oglethorpe. Since October 1, 1996, Oglethorpe
had been the sole member of GSOC. The Members and GTC became members of GSOC at
the Closing. GSOC now operates the system control center and provide transmissionprovides system
operations services to the Members, Oglethorpe and third parties. (See Note 6 of NotesGTC.
At the Closing, Oglethorpe transferred to Financial Statements
in Item 8 for a summary of Oglethorpe's investments in electric plant,
includingGTC its transmission business
and distribution plant.)assets. The purchase price for the transmission business would be equal towas based on an
appraisal of the sum of (1) the higher of: (a) the
appraised fair market value of such business, as determined by an
independent appraiser, or (b) Oglethorpe's net book value for the transmission assets,
plus (2) the value of certain deferred charges. If the appraised value of
the transmission business exceeds Oglethorpe's net book value for the
transmission assets by more than 5%, GTC's Board would have to approve the
payment of any resulting purchase price.and was approximately $708 million. The purchase price
would bewas paid primarily by GTC's assumption of a portion (approximately 16.86%) of
Oglethorpe's long-term secured debt in an amount equal to approximately $686
million. Approximately $541 million of this debt (payable to RUS, the Federal
Financing Bank ("FFB") and CoBank, ACB ("CoBank")) became the sole obligation of
GTC, and Oglethorpe was released from all liability with regard to this debt.
The remaining debt assumed by GTC in connection with the Corporate
1
Restructuring, approximately $145 million, relates to Oglethorpe's pollution
control revenue bonds ("PCBs"). While GTC assumed and agreed to pay this $145
million of debt, Oglethorpe is not legally released from its obligation to pay
for this debt. The remainder of the purchase price was paid by GTC from cash
obtained through third party borrowing.a borrowing from National Rural Utilities Cooperative Finance
Corporation ("CFC") and the assumption of approximately $1 million of other
Oglethorpe would transfer its system operations business, consistingliabilities. Oglethorpe also made a special patronage capital
distribution of its operations centerapproximately $49 million to the Members which was used by the
Members to establish equity in and related computerto provide initial working capital to GTC.
Oglethorpe and dispatch equipment, to GSOC.
GSOC would thereafter own and operate the operations center and provide system
operation39 Members are members of GTC. GTC now provides transmission
services to the Members and Oglethorpe. GTC has succeeded to all of Oglethorpe's
rights and obligations with respect to the Integrated Transmission System
("ITS"). (See "Relationship with GTC" herein for further discussion of the ITS.)
Oglethorpe GTCcontinues to operate its power supply business. Oglethorpe
retained all of its owned and third parties.leased generation assets and has total assets of
approximately $4.7 billion and total long-term debt of approximately $3.9
billion. Oglethorpe also planscontinues to administer its power purchase contracts
and provide marketing support functions to the Members.
Effective with the Corporate Restructuring, Oglethorpe amended its
Bylaws to implement a new governance structure when: (a)
it receives a favorable ruling from the Internal Revenue Service that such
structure would not affect Oglethorpe's status for federal income tax purposes
as a corporation operating on a cooperative basis, and (b) a new rate
schedule which allocates to each Member responsibility for a specified
percentage of all costs of Oglethorpe's existing resources becomes legally
binding and effective. It is contemplated that the new governance structure
would become effective at the same time as the restructuring, although it is
possible that it could become effective independent of the restructuring.
The new governance structure provides for awith an 11-member board of
directors consisting of six directors elected from the Members, four independent
outside directors and Oglethorpe's President and Chief Executive Officer, rather thanOfficer. This
smaller board replaced Oglethorpe's currentformer 39-member board which is comprised of
directors nominated from and by each Member. To be elected,(See "DIRECTORS AND EXECUTIVE
OFFICERS OF THE REGISTRANT" in Item 10 for further information.)
Contemporaneously with the new directors must be nominatedCorporate Restructuring, Oglethorpe replaced
its Consolidated Mortgage and Security Agreement, dated as of September 1, 1994
(the "RUS Mortgage"), by and among Oglethorpe, as mortgagor, the United States
of America, acting through the Administrator of the RUS, CoBank, Credit Suisse
First Boston, acting by and through its New York Branch ("Credit Suisse"), and
SunTrust Bank, Atlanta ("SunTrust"), as trustee under certain pollution control
bond indentures identified in the RUS Mortgage, with an Indenture, dated as of
March 1, 1997, from Oglethorpe to SunTrust, as trustee (the "Master Indenture").
As did the RUS Mortgage, the Master Indenture provides for a committee
composedlien on
substantially all of a representative fromthe owned tangible and certain intangible property of
Oglethorpe. (See "Electric Rates" herein and "General--Rates and Financial
Coverage Requirements" in Item 7 for further discussion of the revenue
requirements of the Master Indenture.)
New Wholesale Power Contracts
In connection with the Closing, Oglethorpe and each of the Members
entered into an Amended and Restated Wholesale Power Contract, dated August 1,
1996 (collectively, the "New Wholesale Power Contracts") which extends through
December 31, 2025. The New Wholesale Power Contracts permit each Member whose vote would be weightedto take
future incremental power requirements either from Oglethorpe or other sources.
Under the New Wholesale Power Contracts, a Member is unconditionally obligated
on an express "take-or-pay" basis for a fixed allocation of Oglethorpe's costs
for its existing resources, as well as the costs with respect to any future
resources in which such Member elects to participate. The New Wholesale Power
Contracts specifically provide that the Member must make payments whether or not
power is delivered and whether or not a plant has been sold or is otherwise
unavailable. Oglethorpe is obligated to use its reasonable best efforts to
operate, maintain and manage its resources in accordance with prudent utility
practices. The New Wholesale Power Contracts provide that Oglethorpe will be
responsible for power supply planning, resource procurement and sales of
capacity and energy for a Member unless the numberMember notifies Oglethorpe that it
does not want Oglethorpe to provide these services.
Each Member's cost responsibility is allocated in the New Wholesale
Power Contracts by assigning each Member an agreed-upon fixed percentage
capacity responsibility ("PCR"). PCRs have been assigned for all of retail customers served byOglethorpe's
existing resources. PCRs for any future resource will be assigned only to
Members choosing to participate in that resource. The New Wholesale Power
Contracts provide that each Member will be jointly and
2
severally responsible for all costs and expenses of all existing 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 then
elected by a vote75% of the Members. For resources so approved in which
less than all Members participate, costs of a defaulting Member are shared first
among the participating Members, and if all participating Members default, each
non-participating Member is expressly obligated to pay a proportionate share of
such default.
The New Wholesale Power Contracts contain covenants by the Member (i)
to establish, maintain and collect rates and charges for the service of its
electric system, and (ii) to conduct its business in a manner that will produce
revenues and receipts at least sufficient to enable the Member to pay to
Oglethorpe, when due, all amounts payable by the Member under the New Wholesale
Power Contracts and to pay any and all other amounts payable from, or which
might constitute a charge or a lien upon, the revenues and receipts derived from
its electric system, including all operation and maintenance expenses and the
principal and interest on a one-member, one-vote basis.
In adopting the Restructuring Agreement, Oglethorpe's Board recommendedall indebtedness related to the Members that they become membersMember's electric
system.
In connection with the implementation of GTC and GSOC and that they joinlong-term power marketer
arrangements with Oglethorpe, GTC and GSOC in executing an agreement (the "Member Agreement")
as to those matters contemplated in the Restructuring Agreement that directly
involve the Members in their capacities as separate corporations. The Member
Agreement will specify the form of transmission contracts and system
operation contracts to be signed by the Members. The Member Agreement will
also provide, subject to the approval of the Rural Utilities ServiceLG&E Power Marketing Inc. ("RUS"LPM"),
formerly known as the Rural Electrification Administration, that Oglethorpe and each Member
executing the Member Agreement would execute a new wholesale
power contract to govern the purchase and sale of power between Oglethorpe
and each such Member. Each Member signing the new wholesale power contract
would have a choice as to whether or not to participate in future power supply
projects sponsored by Oglethorpe. Such Members would be free to own
generation directly and to engage in purchases and sales with other power
suppliers. To the extent such Members
2
choose to satisfy their projected load growth from sources other than
Oglethorpe, the growth in Oglethorpe's revenues from the sale of power would
decrease but the growth in related expenses also would decrease.
Members agreeingentered into supplemental agreements to the new wholesale power contracts would haveNew Wholesale Power Contracts which
relate to certain provisions of the option to have energyNew Wholesale Power Contracts and reserves priced on a pooled basis or to schedule
their capacity and associated energy separately at prices based onapply
during the costterm of production. GSOC would administer the new power pool contemplated by the
new wholesale power contracts and would implement the separate schedules for
Members electing that option. Under the power pool, Oglethorpe resources and
any Member-procured resources would be committed to economic dispatch (pooled)
formarketer arrangements. The supplemental agreements
clarify the benefit of all pool participants. The power pool arrangement also would
allow the participants to pool resource reserves.
In connection with the restructuring, Oglethorpe plans to adopt specific
implementation procedures for the existing bylaw provision that grants a
Member the right to withdraw from membership in Oglethorpe upon satisfying
certain conditions. These conditions generally would require the withdrawing
Member either to affirm its obligations under its then-existing wholesale
power contract or to assign its rights and obligations under such wholesale
power contract to another party with a credit rating meeting certain
specified requirements. Withdrawal by a Member would continue to be
conditioned upon approval by RUS.
The restructuring is subject to a number of conditions, including (1)
implementation of Oglethorpe's new governance structure, (2) executionapplication of the Member AgreementNew Wholesale Power Contract rate schedule to the
power marketer agreements. The 75% requirement described above has been met with
respect to the LPM agreements. The supplemental agreements assure that all costs
incurred by Oglethorpe under the Members, execution of new wholesaleLPM agreement are recoverable under the New
Wholesale Power Contracts. As the expected additional power contractsmarketer
arrangements are finalized, additional supplemental agreements to the New
Wholesale Power Contracts will be entered into by Oglethorpe and the Members, and executionMembers.
See "MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES" for a description
of the transmission
contracts and system operation contracts specified in the Member Agreement,
(3) RUS approval of new wholesale power contracts and the restructuring,
(4) governmental, lender and other third party consents, authorizations,
waivers, orders and approvals, (5) receipt by GTC and GSOC of certain capital
contributions by the Members and (6) assurances from rating agencies that the
ratings on Oglethorpe's outstanding fixed rate PCBs would not be lowered as a
result of the restructuring and that such rating agencies would assign to any
comparable bonds issued by GTC the same or better credit rating as assigned
to Oglethorpe's fixed rate PCBs. Most of these conditions may be waived by
Oglethorpe's Board, subject to RUS approval in certain instances.
The restructuring is expected to take the remainder of 1996 to complete,
although limited aspects of the restructuring may become effective sooner if
specific conditions set forth in the Restructuring Agreement are met. In
light of the significant conditions that must be satisfied, including RUS and
other governmental and third-party approvals and assurances and receipt of
various agreements from the Members, Oglethorpe cannot predict the actual timing
of or the ultimate likelihood of full implementation of the restructuring or
governance changes. Until implementation of the restructuring, Oglethorpe
will continue its current operations, and until satisfaction of the conditions
applicable to the new governance structure, Oglethorpe will continue under
its existing governance structure.
MEMBER DEMAND AND ENERGY REQUIREMENTS
The following table shows the aggregate peakMembers' demand and energy requirements of the Members for the years 1993 through 1995 and also shows
the amounts of such requirements supplied by Oglethorpe and SEPA. For the
years 1993 through 1995, demand and energy requirements increased at an
average annual compound growth rate of 6.4% and 5.9%, respectively.
3
DEMAND (MW) ENERGY REQUIREMENTS (MWH)
--------------------------------------- -----------------------------------------
TOTAL TOTAL
REQUIRE- SUPPLIED BY SUPPLIED BY REQUIRE- SUPPLIED BY SUPPLIED BY
MENTS(1) OGLETHORPE(2) SEPA(3) MENTS OGLETHORPE(2) SEPA(3)
--------- ------------- ----------- ---------- ------------- -----------
1993 4,283 3,736 542 17,313,313 16,253,283 1,060,030
1994 3,938 3,396 542 17,278,812 16,285,127 993,685
1995 4,850 4,308 542 19,403,703 18,442,153 961,550
______________________
(1) System peak demand of the Members measured at the Members' delivery
points (net of system losses). The reduction in peak demand in 1994 was
due to a milder than normal summer in 1994.
(2) Includes purchased power. (See "THE POWER SUPPLY SYSTEM--Power Sales to
and Purchases from GPC--POWER PURCHASE ARRANGEMENTS" and "--Other Power
Purchases".)
(3) Supplied by SEPA through existing contracts with the Members. (See "THE
MEMBERS OF OGLETHORPE--Contracts with SEPA".)
In 1995, Cobb EMC and Jackson EMC accounted for approximately 11.3% and
10.4% of Oglethorpe's total revenues, respectively.
SEASONAL VARIATIONS
The demand for energy by the Members is influenced by seasonal weather
conditions. Historically, Oglethorpe's peak demand occurs during the months
of June through September. (See "Electric Rates" herein.) Energy revenues
track energy costs as they are incurred and also fluctuate month to month.
Capacity revenues reflect the recovery of Oglethorpe's fixed costs which do
not vary significantly from month to month; therefore, the capacity revenues
are billed and recognized in equal monthly amounts.
DEMAND MANAGEMENT
Oglethorpe and the Members have implemented various demand management
programs. The program goal, developed in conjunction with Oglethorpe's
integrated resource planning process, is to modify demand patterns so that
current resources are used efficiently and the need for additional generating
resources is delayed. The programs that have been implemented include an
energy efficient home program (the "Good Cents Home" program),
remote-controlled switching of air conditioners, water heaters and irrigation
pumps, residential energy audits and public appeals to encourage consumers to
use less energy during periods of peak demand. The demand management programs
have reduced, and are expected to continue to reduce, the growth of peak
demand and have also resulted in an increase in off-peak sales. (See "THE
POWER SUPPLY SYSTEM--Future Power Resources".)
ELECTRIC RATESrelated power supply
resources.
Electric Rates
Each Member is required to pay Oglethorpe for capacity and energy
furnished under its New Wholesale Power Contract in accordance with rates
established by Oglethorpe. Oglethorpe reviews its rates at such intervals as it
deems appropriate but is required to do so at least once every year. Oglethorpe
is required to revise its rates as necessary so that the revenues derived from
such rates will be sufficient, but only sufficient, with its revenues from all
other sources to pay operating and maintenance costs, the cost of purchased
power, the cost of transmission services, and principal and interest on all
indebtedness (including capital lease obligations) of Oglethorpe, all costs
associated with decommissioning or otherwise retiring any generating facility,
and to provide for the establishment and maintenance of reasonable reserves.
Rates are also required to be established so as to enable Oglethorpe to comply
with all financial requirements (including coverage ratios) under the Consolidated MortgageMaster Indenture. (See "General--Rates
and Security Agreement, dated as of September 1,
1994 (the "RUS Mortgage"), among Oglethorpe, as mortgagor, and the United
States of America acting through the Administrator of RUS, CoBank, ACB,
formerly known as the National Bank for Cooperatives ("CoBank"), Credit
Suisse, acting by and through its New York Branch ("Credit Suisse"), and
SunTrust Bank, Atlanta, formerly known as Trust Company Bank ("SunTrust"), as
4
trustee under certain pollution control bond indentures identified in the RUS
Mortgage. (See "General--RATES AND FINANCIAL COVERAGE REQUIREMENTS"Financial Coverage Requirements" in Item 7.)
Oglethorpe's current monthly rate for electric service for capacity and
energy delivered to each Member includes energy charges that recover fuel and
variable operation and maintenance costs, adjusted semiannually to assure
full recovery of such costs, and capacity charges. The rate also includes a
provision to reflect the amortization of the deferred margins accumulated
from 1985 through 1995, which amounts will be fully amortized by the end of
1996. (See Note 1 of Notes to Financial Statements in Item 8.) Oglethorpe's
rate policy provides for a number of separate rates for certain qualified
consumer loads, which are designed to have a favorable impact on the Members'
competitiveness for certain new commercial and industrial loads. (See "THE
MEMBERS OF OGLETHORPE--Service Area and Competition".)
Oglethorpe's rates, as established by its Board of Directors, are
subject to review and approval by RUS. Oglethorpe ishad been required under the prior RUS Mortgage to implement
rates designed to maintain a Times Interest Earned Ratio ("TIER") of not less
than 1.05, a Debt Service Coverage Ratio ("DSC") of not less than 1.0 and an
Annual Debt Service Coverage Ratio ("ADSCR") of not less than 1.25. Oglethorpe
has always met or exceeded the TIER, DSC and ADSCR requirements of the RUS
Mortgage. Oglethorpe's current policy isfor 1996 was to set rates to meet a TIER of 1.071.07.
Under the Master Indenture, Oglethorpe is required to establish and collect
rates which are reasonably expected, together with other revenues of Oglethorpe,
to yield a Margins for Interest ("MFI") for each fiscal year equal to at least
1.10 times total interest charges during such fiscal year on all indebtedness
secured under the Master Indenture (or by a lien equal or prior to the lien of
the Master Indenture), excluding indebtedness assumed by GTC. MFI is determined
by adding (i) Oglethorpe's net margins (after certain defined adjustments), (ii)
interest charges on indebtedness secured under the Master Indenture (or by lien
equal to
3
or prior to the lien of the Master Indenture), excluding indebtedness assumed by
GTC, and (iii) any amount included in 1996.net margins for accruals for federal or
state income taxes. The definition of MFI takes into account any item of net
margin, loss, gain or expenditure of any affiliate or subsidiary of Oglethorpe
only if Oglethorpe has received such net margins or gains as a dividend or other
distribution or if Oglethorpe has made a payment with respect to such losses or
expenditures. (See "General-RATES AND FINANCIAL
COVERAGE REQUIREMENTS""General--Rates and Financial Coverage Requirements" in Item
7.)
TheUnder the formulary rate established by Oglethorpe in the new rate
schedule to the New Wholesale Power Contracts, provide that nothe rates charged by Oglethorpe
are developed using a rate revision shallmethodology under which all categories of costs are
specifically separated as components of the formula to determine Oglethorpe's
revenue requirements. The rate schedule formula implements the assignment of
responsibility for fixed costs (i.e., the PCR). The monthly charges for capacity
and other non-energy charges are based on a rate formula using Oglethorpe's
annual budget. Such capacity and other non-energy charges may be effective unless approvedadjusted by the
Board of Directors, if necessary, during the year through an adjustment to the
annual budget. Energy charges reflect the passthrough of actual energy costs.
However, under the supplemental agreements for the LPM agreements, each Member
pays a fixed rate for energy, plus certain adjustments, while LPM pays all
energy costs, within an agreed upon range of costs. The new rate schedule
formula also includes a prior period adjustment ("PPA") mechanism. The PPA
serves to facilitate the achievement of the minimum 1.10 MFI ratio, and it
provides for the retention of margins within a range from a 1.10 MFI ratio to a
1.20 MFI ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum
1.10 MFI ratio would be accrued as of December 31 of the applicable year and
collected during the period April through December of the following year.
Amounts, if any, earned by Oglethorpe in excess of a 1.20 MFI ratio would be
charged against revenues as of December 31 of the applicable year and refunded
during the period April through December of the following year. The new rate
schedule formula is intended to permit 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 terms of Oglethorpe's prior RUS but suchMortgage, all rate revisions
by Oglethorpe were subject to the approval of RUS. Under the Master Indenture
and related loan contract with RUS, however, adjustments to Oglethorpe's rates
to reflect changes in Oglethorpe's budgets are not subject to RUS approval,
except for reductions in rates in a fiscal year following a fiscal year in which
Oglethorpe has failed to meet the minimum 1.10 MFI ratio set forth in the Master
Indenture. Any change to the underlying rate formula would be subject to RUS
approval. Rate revisions are not subject to the approval of any other Federalfederal or
state agency or authority, including the Georgia Public Service Commission (the
"GPSC").
To date, RUS has not reduced
or delayed the effectiveness of any rate increase proposed by Oglethorpe.
For information regarding future rates, see "General--RATES AND FINANCIAL
COVERAGE REQUIREMENTS","General--Rates and
Financial Coverage Requirements" and "Results of Operations--FACTORS AFFECTING FUTURE
FINANCIAL PERFORMANCE" and "Proposed Restructuring"Operations--Factors Affecting
Future Financial Performance" in Item 7.
CERTAIN FACTORS AFFECTINGRelationship with GTC
GTC purchased and is operating the transmission system as described in
"Corporate Restructuring" herein. Oglethorpe and all 39 Members are members of
GTC. GTC is providing 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
the Rocky Mountain Project, a pumped storage hydroelectric facility ("Rocky
Mountain").
In connection with the Corporate Restructuring, GTC and the Members
entered into transmission agreements (the "Transmission Agreements") under which
GTC provides transmission service to the Members pursuant to a transmission
tariff. The Transmission Agreements have a minimum term of network service for
current load until December 31, 2025. After an initial ten-year term, load
growth above 1995 requirements may, with notice to GTC, be served by others. The
Transmission Agreements provide that if a Member elects to
4
purchase a part of its network service elsewhere, it must pay appropriate
stranded costs to protect the other Members from any rate increase that could
otherwise occur. Under the Transmission Agreements, Members have the right to
design, construct and own new distribution substations.
The Transmission Agreements provide that the Members are responsible,
on a joint and several basis, for all of GTC's obligations relating to its
transmission business. The Transmission Agreements contain an express covenant
of the Members to set and collect retail rates sufficient to allow the Members
to meet their respective obligations under the Transmission Agreements. The rate
formula set forth in the transmission tariff is intended to recover all costs
and expenses paid or incurred by GTC. The rate expressly includes in the
description of costs to be recovered all principal and interest on indebtedness
of GTC (including any indebtedness of Oglethorpe assumed by GTC). The rate
further expressly provides for GTC to earn sufficient margins to satisfy the
requirements of its new indenture, which is substantially similar to
Oglethorpe's Master Indenture.
The GTC transmission tariff and associated Transmission Agreements have
been developed to implement the Corporate Restructuring and to be consistent
with federal transmission policy as expressed in Order 888 of the Federal Energy
Regulatory Commission ("FERC"). FERC's Order 888 mandates open access of
essentially all transmission systems in order to promote competition in the bulk
power markets and provides that non-regulated utilities (such as GTC) must
provide access to their transmission systems on reciprocal terms and conditions
in order to obtain transmission from FERC-regulated utilities. The transmission
tariff and Transmission Agreements have been designed to facilitate the
operation of GTC in the new regulatory environment and provide for GTC to serve
on a nondiscriminatory basis both member and non-member customers on terms
intended to meet FERC's reciprocity requirement.
Prior to the Closing, Oglethorpe, together with Georgia Power Company
("GPC"), the Municipal Electric Authority of Georgia ("MEAG") and the City of
Dalton ("Dalton"), owned transmission facilities which together form the ITS.
GTC succeeded to Oglethorpe's rights in the ITS at the Closing, and GTC now owns
approximately 2,267 miles of transmission line and 426 substations of various
voltages. Through agreements, common access to the combined facilities that
compose the 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.
GTC's rights and obligations with respect to the ITS are governed by
the Revised and Restated Integrated Transmission System Agreement (the "ITSA"),
which was assigned to GTC in connection with the Corporate Restructuring. The
ITSA provides for the transmission and distribution of electric energy in the
State of Georgia, other than in certain counties, and for bulk power
transactions, through use of the ITS. The ITS was established in order to obtain
the benefits of a coordinated development of the parties' transmission
facilities and to make it unnecessary for any party to construct duplicative
facilities. The ITS consists of all transmission facilities, including land,
owned by the parties on the date the ITSA became effective and those thereafter
acquired, which are located in the State of Georgia other than in the excluded
counties and which are used or usable to transmit power of a certain minimum
voltage and to transform power of a certain minimum voltage and a certain
minimum capacity (the "Transmission Facilities"). GPC has entered into
agreements with MEAG and Dalton that are substantially similar to the ITSA, and
GPC may enter into such agreements with other entities. The ITSA will remain in
effect through December 31, 2012 and, if not then terminated by five years'
prior written notice by either party, will continue until so terminated.
The ITSA is administered by a committee (the "Joint Committee")
composed of GTC, GPC, MEAG and Dalton. Each year, the Joint Committee determines
a four-year plan of additions to the Transmission Facilities that will reflect
the current and anticipated future transmission requirements of the parties.
Each ITS participant is generally required to maintain an original cost
investment in the Transmission Facilities in proportion to their respective Peak
Loads (as defined in the ITSA).
GTC and GPC are parties to a Transmission Facilities Operation and
Maintenance Contract (the "Transmission Operation Contract"), under which GPC
provides System Operator Services (as defined in the
5
Transmission Operation Contract) for GTC. In addition, GPC is required to
provide such supervision, operation and maintenance supplies, spare parts,
equipment and labor for the operation, maintenance and construction as may be
specified by GTC. GPC is also required to perform certain emergency work under
the Transmission Operation Contract. GTC is permitted, upon notice to GPC, to
perform, or contract with others for the performance of, certain services
performed by GPC. Absent termination or amendment of the Transmission Operation
Contract, however, GPC will continue to perform System Operator Services for
GTC. The term of the Transmission Operation Contract will continue from year to
year unless terminated by either party upon four years' notice. GTC is required
to pay its proportionate share of the cost for the services provided by GPC.
Relationship with GSOC
From October 1, 1996 until the Closing, Oglethorpe was the sole member
of GSOC. The Members and GTC became members of GSOC upon the Closing. GSOC now
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 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 (the "Territorial Act"). For further
information regarding the various relationships and agreements with GPC, see
"THE MEMBERS OF OGLETHORPE--Service Area and Competition", "MEMBER REQUIREMENTS
AND POWER SUPPLY RESOURCES--Power Purchase and Sale Arrangements--Power
Purchases from GPC", "--Other Power System Arrangements" herein, and "GENERATING
FACILITIES--Fuel Supply", "CO-OWNERS OF THE UTILITY INDUSTRY IN GENERALPLANTS 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 FFB have been a major source of funding for Oglethorpe. In
recent years, there have been legislative, administrative and budgetary
initiatives intended to reduce or, in some cases, eliminate federal funding for
electric cooperatives. However, Oglethorpe does not have any new generation
facilities under construction, and management does not anticipate the need for
construction of any new capacity well into the future. (See "MEMBER REQUIREMENTS
AND POWER SUPPLY RESOURCES--Power Purchase and Sale Arrangements--Power Marketer
Arrangements" for a discussion of the long-term power marketer arrangements.) In
addition, the Master Indenture improves Oglethorpe's ability to borrow funds in
the public capital markets. See "THE MEMBERS OF OGLETHORPE--Members'
Relationship with RUS" for a discussion of the impact of changes in the RUS
lending program on the Members.
Through provisions of the prior RUS Mortgage, RUS exercised substantial
control and supervision over Oglethorpe in such areas as accounting, the
issuance of secured indebtedness, rates and charges for the sale of power,
construction and acquisition of facilities, and the purchase and sale of power.
Under the Master Indenture
6
and the new loan contact entered into with RUS in connection therewith, RUS has
significantly reduced these controls.
Relationship with Intellisource
In conjunction with the Corporate Restructuring and as a part of its
continuing efforts to reduce costs, effective February 1, 1997, Oglethorpe
implemented a business alliance with Intellisource, Inc., a national provider of
outsourcing services. Pursuant to an agreement with Intellisource, approximately
150 support services division employees in the areas of accounting, auditing,
communications, human resources, facility management, purchasing,
telecommunications and information technology became employees of the
Intellisource organization. Oglethorpe, GTC and GSOC are key customers of
Intellisource and are being served on-site by the managers and employees of
Oglethorpe's former support services division.
Certain Factors Affecting the Utility Industry in General
The electric utility industry in the United States is undergoing
fundamental change and is becoming increasingly competitive as a
result of deregulation, competing energy suppliers, technologies, and other
factors. Thecompetitive. This change is
promoted by the Energy Policy Act of 1992 (the "Energy Policy Act") amended, recently
adopted and proposed policies from FERC regarding transmission access and
pricing, increased consolidation and mergers of electric utilities, the
Federal Powerproliferation of self-generators and independent power producers, surplus
generation in certain regional markets and other factors. The Energy Policy Act
and the Public Utility Holding Company Act toFERC policies allow for increased competition among wholesale electric
suppliers and increased access to transmission services by such suppliers. The
new competitive environment is subject to rapidly evolving regulatory policy at
both the federal and state levels, which is based on a shift to a market-driven
environment from a regulated one. Significant legislative developments at the
federal level and in various state legislative bodies, and regulatory
developments at the Federal Energy Regulatory Commission ("FERC")FERC and in state commissions are expected to continue to
clarify the policy and regulatory framework for increased competition. The GPSC
staff has scheduled a series of workshops, the stated purpose of which is to
solicit views from the various parties impacted by electric industry
restructuring and to discuss potential resolutions to these issues. At the
conclusion of the workshops, the GPSC staff anticipates presenting a report to
the GPSC that will identify electric industry restructuring issues, potential
resolutions and the views of the parties who participated in the workshop. (See
"THE MEMBERS OF OGLETHORPE--Service Area and Competition".)
A number of other significant factors have affected the operations of
electric utilities. They include the cost of fuel for the generation of electric
energy, recovery of the cost of existing facilities, fluctuating rates of load
growth, the effects of conservation and energy management on the use of electric
energy and compliance with environmental and other governmental regulations.
All of the factors mentioned above present an increasing challenge to
companies in the electric utility industry, including Oglethorpe and the
Members, to reduce costs, improve the management of resources and respond to the
changing environment. (See "Proposed"Corporate Restructuring" herein and "THE"MEMBER
REQUIREMENTS AND POWER SUPPLY SYSTEM--General", "--Future Power Resources" and
"--Environmental and Other Regulations".)
5
RELATIONSHIP WITH GPC
Oglethorpe's relationship with GPC is a significant factor in several aspects
of Oglethorpe's business. GPC is Oglethorpe's principal supplier of
purchased power, and Oglethorpe is one of GPC's largest customers. In 1995,
Oglethorpe derived 6% of its total revenues from sales to GPC, making GPC one
of Oglethorpe's largest customers. Substantially all of Oglethorpe's
generating facilities were purchased at various stages of construction from
GPC and most were constructed and are now operated by GPC. Oglethorpe
completed the construction of and is now the primary owner and operating
agent for the Rocky Mountain Project, a pumped storage hydroelectric facility
("Rocky Mountain"), in which it acquired an interest from GPC. Oglethorpe
purchases coordination services from GPC to schedule its power resources and
its off-system purchases and sales. Oglethorpe, through the Members, is one
of GPC's principal 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 (the "Territorial Act"). Likewise, GPC is the principal
competitor of the Members for such customers. Oglethorpe and GPC also own
transmission facilities that are part of the Integrated Transmission System
(the "ITS"). GPC provides system operator services and performs most of the
required maintenance of Oglethorpe's transmission facilities. GPC and
Oglethorpe are parties to an agreement that makes allowance for the joint
planning of future generation and transmission facilities. For further
information regarding the various relationships and agreements with GPC, see
"THE MEMBERS OF OGLETHORPE--Service Area and Competition", "THE POWER SUPPLY
SYSTEM--General", "--Fuel Supply"RESOURCES--General", "--Power Sales toPurchase and Purchases from GPC",
"--Transmission and OtherSale
Arrangements--Other Power System Arrangements", "CO-OWNERS OF THE
PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--Co-Owners of the
Plants--Georgia Power Company", "--The Plant Agreements", "--Agreements
Relating to the Integrated Transmission System"Purchases", and "--The Joint Committee
Agreement".
RELATIONSHIP WITH RUS
Federal loan programs administered by RUS have provided the principal
source of financing for electric cooperatives. Direct loans from RUS have
been a major source of funding for the Members, while loans guaranteed by RUS
and made by the Federal Financing Bank ("FFB") have been a major source of
funding for Oglethorpe. Through provisions of the RUS Mortgage, RUS exercises
substantial control and supervision over Oglethorpe"ENVIRONMENTAL AND OTHER REGULATIONS"
in such areas as
accounting, the issuance of secured indebtedness, rates and charges for the
sale of power, construction and acquisition of facilities, and the purchase
and sale of power.
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.
For fiscal year 1996, the Congress set the level of funding for the 100%
guarantee program at $300 million, which if sustained at that level in future
years would not likely provide adequate funding for the transmission and
power supply needs of RUS borrowers. For fiscal year 1997, the
Administration's budget proposal to Congress calls for a level of $400
million for the guarantee program. Congress historically has increased
Administration-proposed lending levels to those necessary to meet borrower
demand. Notwithstanding historical practices, the future cost, availability
and magnitude of RUS-guaranteed loans cannot be predicted. See "THE MEMBERS
OF OGLETHORPE--Members' Relationship with RUS" for a discussion of the impact
of the budget proposal on the direct loan program.
For a number of years, RUS has been re-evaluating its regulatory and
lending relationship with its borrowers through what it has described as a
comprehensive rule-making project. RUS has said the purpose of the project
is to improve the credit-worthiness of loans made or guaranteed by RUS. In
addition to adopting new rules regulating policies and procedures for insured
and guaranteed loans and lien accommodations, RUS has published a proposed
rule describing a new form of wholesale power contract and a new standard
form of loan contract for distribution borrowers. RUS has not, however,
pursued finalization of the new form of wholesale power contract earlier
proposed. RUS has adopted a new standard form of mortgage for distribution
borrowers.
6
In advance notices of proposed rule-makings, RUS also has requested
suggestions for revisions to its standard form of mortgage for power supply
borrowers and comments on proposals for credit support for loans to power
supply borrowers. While no formal notice has been issued by RUS, RUS has
advised borrowers informally that it will for the present use a case-by-case
approach to power supply borrower mortgage reform and member credit support.
These rule-makings continue to take many months or years to complete and the
outcome of these various rule-making initiatives, whether others may be
forthcoming, whether any of such rule-making initiatives may achieve the
objectives stated by RUS, or the extent to which such initiatives may affect
Oglethorpe or the Members cannot be predicted.Item 2.)
7
THE MEMBERS OF OGLETHORPE
SERVICE AREA AND COMPETITIONService Area and Competition
The Members are identified in Item 10(a) of this Reportlisted 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 EMC Slash Pine EMC
Coastal EMC Lamar EMC Snapping Shoals EMC
Cobb EMC Little Ocmulgee EMC Sumter EMC
Colquitt EMC Middle Georgia EMC Three Notch EMC
Coweta-Fayette EMC Mitchell EMC Tri-County EMC
Excelsior EMC Ocmulgee EMC Troup EMC
Flint EMC Oconee EMC Upson County EMC
Grady EMC Okefenoke Rural EMC Walton EMC
GreyStone Power Corporation Pataula EMC Washington EMC
The Members serve approximately 1.11.2 million electric consumers (meters)
representing a total population of approximately 2.6 million people. The Members
serve a region covering approximately 40,000 square miles, which is
approximately 70% of the land area of Georgia served by the owners of the ITS,
encompassing 150 of the State's 159 counties. Sales by the Members in 19951996
amounted to approximately 18.219.6 million megawatt-hours ("MWh"), with 72% to
residential consumers, 26% to commercial and industrial consumers and 2% to
other consumers. No single consumer of any Member constituted more than
1% of the Members' aggregate sales in 1995. 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 19931994 through 19951996 of 4.0%5% in number of consumers, 5.9%9% in MWh
sales and 6.3%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;
however, the Territorial Act permits competition among electric suppliers for
new retail loads of 900 kilowatts or more outside existing municipal limits.
Except for these 900-kilowatt loads,suppliers.
With limited exceptions, the Members have the exclusive right to provide retail
electric service in their respective assigned territories, which are predominately
outside of the municipal limits.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 not reassign territory or transfer service except in
limited circumstances provided by the Territorial Act. The GPSC may reassign
territory only if it determines that an electric supplier has breached the
tenets of public convenience and necessity. The GPSC may transfer service for
specific premises only: (i) upon a determination by the GPSC, after joint
application of electric suppliers and proper notice and hearing, that the public
convenience and necessity require a transfer of service from one electric
supplier to another; or (ii) upon a finding by GPSC, 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.
The GPSC may reassign territory only
if it determines that an assignee electric supplier has breached the tenets
of public convenience and necessity.
As referenceddiscussed above, the Territorial Act allows the owner of any new
facility located outside of existing 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 industrialcommercial and commercialindustrial loads. The number of
8
commercial and industrial loads served by the Members continues to increase
annually. Retail competition in the electric utility industry has historically
been rare. While the competition for 900-kilowatt loads represents only limited
competition in Georgia, retail competition in the electric
utility industry is currently rare and this competition has given Oglethorpe and the Members
the opportunity to develop resources and strategies to operate in an
increasingly competitive market.
From time to time, utilities are approached by other parties interested
in purchasing their systems. Some of the Members have been approached in the
past by third parties indicating an interest in purchasing their systems. The
New Wholesale Power Contracts provide that a Member may not dissolve, liquidate
or otherwise wind up its affairs without Oglethorpe's approval. The 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 of its assets to any person, whether in a
single transaction or series of transactions, unless either (i) the transaction
is approved by Oglethorpe or (ii) other specified conditions are satisfied
including, but not limited to, an assumption agreement by the transferee,
satisfactory to Oglethorpe, containing an assumption by the transferee of the
performance and observance of every covenant and condition of the Member under
the New Wholesale Power Contract, between Oglethorpe and each Member provides that no
Member may reorganize, consolidate or merge, or sell, lease or transfer all
or a substantial portioncertifications of its assets (or make any agreement therefor), so
longaccountants as Oglethorpe has notes outstanding to
RUS and the FFB, without first
paying such portion of any such outstanding notes as may be determined by
Oglethorpe with the prior written consent of RUS and otherwise complying with
such reasonable terms and conditions as Oglethorpe and RUS may require. The
enforceabilitycertain specified financial requirements of the RUS form of wholesale power contract has been
consistently upheld bytransferee (taking into account
the courts in several jurisdictions. In addition, RUS
has stated its policy that it will not encourage or facilitate the buyout of
borrowers by third parties and that it will expect cooperative distribution
utilities to retire a proportionate share of the
8
associated G&T indebtedness and to pay other appropriate costs and expenses
of the G&T as a condition of a buyout.
COOPERATIVE STRUCTUREtransfer).
Cooperative Structure
The Members 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% of its total assets, except that
distributions may be made of up to 25% of the margins and patronage capital
received by the Member in the preceding year. As a general matter, the Members
that borrow from RUS distribute accumulated patronage capital from time to time
subject to their respective financial policies and in conformity with their
respective RUS mortgages. (See "Members' Relationship Withwith 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 New Wholesale Power Contract with Oglethorpe and
Oglethorpe's rights under such contracts to receive payment for power and energy
supplied, Oglethorpe has no legal interest in, or obligations in respect of, any
of the assets, liabilities, equity, revenues or margins of the Members. (See
"OGLETHORPE POWER CORPORATION--MemberCORPORATION--New 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 New Wholesale Power Contracts. Revenues of the Members that borrow
from RUS are, however, pledged under thetheir respective RUS mortgagesmortgages.
Rate Regulation of the Members.
RATE REGULATION OF MEMBERSMembers
Through provisions in the loan documents securing loans to the Members,
RUS exercises control and supervision over the Members that borrow from it in
such areas as: (i) accounting; (ii) borrowings; (iii) rates and charges for the
sale of power; (iv) construction and acquisition of facilities; and (v) the
purchase and sale of power. The individual RUS mortgages of the Members require
them to design rates with a view to maintaining an average TIER of not less than
1.50 and an average DSC of not less than 1.25 for the two highest out of every
three successive years.
Snapping Shoals EMC in 1994, Mitchell EMC, Troup EMC and Walton EMC in
1995, and Cobb EMC in 1996 prepaid their RUS indebtedness and are no longer
RUS borrowers. It is likely that other Members will also pursue this option.
Each of these Members now have financial and other requirements under their
loan documents with the National Rural Utilities Cooperative Finance
Corporation ("CFC") and, for Troup EMC, with CoBank also.
Although the setting of the rates of the Members is not subject to
approval ofby any Federal or state agency or authority other than RUS, the
Territorial Act prohibits the Members from unreasonable discrimination in the
9
setting of rates, charges, service rules or regulations and requires the Members
to obtain GPSC approval of long-term borrowings.
CONTRACTS WITH SEPA
In additionSnapping Shoals EMC, Mitchell EMC, Troup EMC, Walton EMC and Cobb EMC
have prepaid their RUS indebtedness and are no longer RUS borrowers. Each of
these Members now have financial and other requirements under loan documents
with their new lenders. Other Members may also pursue this option. To the extent
that these five Members and others that in the future prepay their RUS
indebtedness engage in wholesale sales or transmission in interstate commerce,
they will be subject to energy received from Oglethorperegulation by FERC under the WholesaleFederal Power Contracts, the Members purchase hydroelectric power under contractsAct.
Members' Relationship with SEPA. In 1995, the aggregate SEPA allocation to the Members was 542 MW plus
associated energy, representing approximately 11% of total Member peak demand
and
9
approximately 5% of total Member energy requirements. (See "OGLETHORPE POWER
CORPORATION--Member Contracts" and "--Member Demand and Energy Requirements"
and the table thereunder.)
On December 8, 1994, SEPA issued its final Power Marketing Policy for the
Georgia - Alabama - South Carolina System of Projects. This policy will
govern the renewal of SEPA's contracts with the Members. There were no
significant changes in this final marketing policy and the Members'
allocation of capacity and energy remained unchanged.
SEPA has contracted with The Southern Company for scheduling and
dispatching services for SEPA's generating projects in Georgia and Alabama
and for transmission services to certain preference customers. During 1994,
SEPA began negotiating revised arrangements for these services. Originally
scheduled for renewal on May 31, 1994, SEPA extended the term of the Members'
contracts until January 31, 1995, with a provision automatically to extend
one month at a time thereafter until negotiations with The Southern Company
are completed. An order was sought from FERC requiring the provision of
these services at just and reasonable rates; however, SEPA and The Southern
Company have continued negotiations in an effort to reach agreement.
During 1995, legislative proposals were made that would have resulted in
the privatization of several of theRUS
Historically, federal power marketing administrations,
in particular SEPA. Ultimately, no proposal for the privatization of the
power marketing administrations was included in the final budget proposal.
The President's Budget for fiscal year 1997 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.
MEMBERS' RELATIONSHIP WITH RUS
Federal loan programs providing direct loans from RUS to
electric cooperatives have been a major source of funding for the Members. In
recent years, there have been legislative, administrative and budgetary
initiatives intended to reduce or, in some cases, eliminate federal funding for
electric cooperatives. In addition, 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 a
new standard form of mortgage and has published a proposed rule describing a new
standard form of loan contract for distribution borrowers.
Recent changes and proposals for further changes have made the direct
loan program administered by RUS more costly. Uncertainties continue about the level of
funding available under the RUS loan program. The Rural Electrification Loan
Restructuring Act of 1993 eliminated the long-standing 2% loan program and
substituted a new program, the interest rates for which are based on rates being
paid on municipal bonds with comparable maturities. Certain borrowers with
either low consumer density or higher-than-average rates and lower-than-average
consumer income are eligible for a 5% loan program. The future cost,
availability and amount of RUS direct and guaranteed loans which may be
available to the Members cannot be predicted.
A number ofFive Members have recently prepaid their RUS indebtedness and are no longer RUS
borrowers. Other Members may also pursue this option. (See "Rate Regulation of
Members" herein.)
Members' Relationship with GTC and GSOC
For further information regardingabout the RUS program,Members' relationship with GTC and GSOC, see
"OGLETHORPE POWER CORPORATION--RelationshipCorporation--Relationship with RUS"GTC" and "--Relationship with
GSOC".
Contracts with SEPA
In addition to energy received from Oglethorpe under the New Wholesale
Power Contracts, the Members purchase hydroelectric power under contracts with
SEPA. In 1996, the aggregate SEPA allocation to the Members was 542 megawatts
("MW") plus associated energy, representing approximately 11% of total Member
peak demand and approximately 5% of total Member energy requirements. New
20-year contracts between each of the Members and SEPA have recently been
executed. The provisions of the new contracts are essentially the same as the
existing contracts with a few exceptions. The Members must schedule their energy
allocation, and each has designated Oglethorpe to perform this function. In a
separate agreement, Oglethorpe will schedule, through GSOC, the Members' SEPA
power deliveries. Further, the Members 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.
SEPA and Oglethorpe have entered into new transmission arrangements under which
Oglethorpe would deliver the Members' SEPA purchases. GTC, as assignee of this
agreement, will
10
THEdeliver the SEPA power under its network tariff and contract with each Member.
The new contracts are subject to RUS approval. 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--New Wholesale Power Contracts" and "MEMBER
REQUIREMENTS AND POWER SUPPLY SYSTEM
GENERALRESOURCES--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 1998 does not include any proposals to privatize the federal power
marketing administrations. The ultimate outcome of this issue in Congress cannot
be predicted with certainty.
11
MEMBER REQUIREMENTS AND POWER SUPPLY RESOURCES
General
Oglethorpe supplies the current capacity and energy requirements of the
Members from a combination of owned and leased generating plants and from power
purchased under long-term contracts with other power suppliers.suppliers and power
marketers. Oglethorpe owns or leases 3,335.0 MW of nameplate capacity,
consisting of 1,500.6 MW of coal-fired capacity, 1,185 MW of nuclear-fueled
capacity, 632.5 MW of pumped storage hydroelectric capacity, 14.8 MW of
oil-fired combustion turbine capacity and 2.1 MW of conventional hydroelectric
capacity. (SEE "GENERATING FACILITIES--General" and "--Plant Performance" in
Item 2 for a description of Oglethorpe's generating facilities.) These resources
are generally scheduled and dispatched so as to minimize the operating cost of
Oglethorpe's system. In addition,However, Oglethorpe purchases and sells capacity
and energy in the bulkhas entered into long-term arrangements
with power marketmarketers to make the best use ofbetter utilize its resources and
thus minimizeto reduce the cost of
capacity and energy delivered to the Members, in part by giving certain dispatch
rights to the power marketers. (See "Power Purchase and Sale Arrangements--Power
Marketer Arrangements" herein.)
Member Demand and Energy Requirements
The following table shows the aggregate peak demand and energy
requirements of the Members for the years 1994 through 1996 and also shows the
amounts of such requirements supplied by Oglethorpe and SEPA. For the years 1994
through 1996, demand and energy requirements increased at an average annual
compound growth rate of 13.2% and 9.7%, respectively.
Demand (MW) Energy Requirements (MWh)
--------------------------------------- --------------------------------------------
Total Total
Require- Supplied by Supplied by Require- Supplied by Supplied by
ments(1) Oglethorpe(2) SEPA(3) ments Oglethorpe(2) SEPA(3)
-------- ------------- ------- ----- ------------- -------
1994 3,938 3,396 542 17,278,812 16,285,127 993,685
1995 4,850 4,308 542 19,403,703 18,442,153 961,550
1996 5,045 4,503 542 20,793,864 19,807,101 986,763
- ----------
(1) System peak demand of the Members measured at the Members' delivery points
(net of system losses). The significant increase in peak demand in 1995
was due in large part to a milder than normal summer in 1994.
(2) Includes purchased power. (See "Power Purchase and Sale
Arrangements--Power Purchases from GPC" and "--Other Power Purchases"
herein.)
(3) Supplied by SEPA through existing contracts with the Members. (See "THE
MEMBERS OF OGLETHORPE--Contracts with SEPA".)
In 1996, Cobb EMC and Jackson EMC accounted for approximately 12.5% and
11.2% of Oglethorpe's total revenues, respectively.
Seasonal Variations
The demand for energy by the Members is influenced by seasonal weather
conditions. Historically, Oglethorpe's peak demand occurs during the months of
June through September. (See "OGLETHORPE POWER Corporation--Electric Rates".)
Energy revenues track energy costs as they are incurred and also fluctuate month
to month. Capacity revenues reflect the recovery of Oglethorpe's fixed costs
which do not vary significantly from month to month; therefore, the capacity
revenues are billed and recognized in equal monthly amounts.
12
Demand Management
Oglethorpe and the Members have implemented various demand management
programs. The program goal, developed in conjunction with Oglethorpe's
integrated resource planning process, has been to modify demand patterns so that
current resources are used efficiently and the need for additional generating
resources is delayed. The programs that have been implemented include an energy
efficient home program (the "Good Cents Home" program), remote-controlled
switching of air conditioners, water heaters and irrigation pumps, residential
energy audits and public appeals to encourage consumers to use less energy
during periods of peak demand. The demand management programs have reduced the
growth of peak demand and have also resulted in an increase in off-peak sales.
(See "Power Purchase and Sale Arrangements--Other Power Purchases" herein.)
Power Purchase and Sale Arrangements
Power Marketer Arrangements
As a means of reducing the cost of power provided to the Members,
Oglethorpe utilized short-term power marketer arrangements during 1996 with two
different power marketers. Under both of the arrangements, the power marketer
was required to provide to Oglethorpe at a favorable fixed rate all of the
energy needed to meet the Members' requirements, and Oglethorpe was required to
provide upon request to the power marketers at cost (subject to certain
limitations) all energy available from Oglethorpe's total power resources. Under
these arrangements, Oglethorpe continued to operate the power supply system and
continued to dispatch the generating resources to ensure system reliability.
Oglethorpe is now utilizing power marketer arrangements on a long-term
basis to reduce the cost of power. It has entered into power marketer agreements
with LPM for 50% of the load requirements of the Members, and is working to
finalize an agreement with Morgan Stanley Capital Group ("Morgan Stanley") for
the remaining 50% of the Members' load requirements.
Effective January 1, 1997, Oglethorpe entered into power marketer
agreements with LPM for 50% of the load requirements of the Members. Under the
agreements, LPM is obligated to deliver, and Oglethorpe is obligated to take,
50% of the load requirements of the participating Members less the load
requirements for certain customer choice loads (900 kilowatt or greater), plus
50% of the delivery obligations under Oglethorpe's existing firm power
off-system sale contracts. For customer choice loads of three megawatts or less,
LPM is obligated to deliver, if Oglethorpe requests, 50% of the associated load
requirements. Oglethorpe has the option of purchasing the energy requirements
for customer choice loads from another supplier. Oglethorpe is obligated to sell
and LPM is obligated to buy 50% of the output of each participating Member's PCR
share of the "must run" units (primarily nuclear units). Oglethorpe is also
obligated to make available the same share of all other resources, which LPM may
schedule. LPM does not have the right to the output of upgrades to these
resources. LPM must pay Oglethorpe the cost of fuel associated with the energy
taken. There is a price adjustment if the plant performance does not meet
specified levels of availability and output. Oglethorpe must pay LPM a
contractually specified price for each MWh purchased.
Oglethorpe has contracted with GTC to provide available transmission
services to deliver to the border of the ITS any energy sold to LPM. Each Member
will use its Transmission Agreement for delivery of energy purchased from LPM
and others.
Effective with the Corporate Restructuring and the execution of
supplemental agreements to the New Wholesale Power Contracts, the LPM agreement
relating to 37 of the 39 Members has a term extending to 2011. With one years'
notice, Oglethorpe has the right to terminate the LPM agreement for any year
beginning with 2002. With one years' notice, LPM has the right to terminate the
LPM agreement for any year beginning with 2005. The LPM agreement relating to
the other two Members has a term extending through the end of 1999. The
13
supplemental agreements are the vehicle through which Oglethorpe and the Members
assure that the Members receive the benefits of and support the obligations for
the new power marketer arrangements under the New Wholesale Power Contracts.
LPM is an indirect wholly owned subsidiary of LG&E Energy Corp., a
Kentucky corporation, which is a diversified energy services holding company.
LG&E Energy Corp. is subject to the informational requirements of the Securities
Exchange Act of 1934, as amended, and, in accordance therewith, files reports
and other information with the Securities and Exchange Commission (the
"Commission"). Copies of this material can be obtained at prescribed rates from
the Commission's Public Reference Section at 450 Fifth Street, N.W., Room 1024,
Washington, D.C. 20549. Certain securities of LG&E Energy Corp. are listed on
the New York Stock Exchange, and reports and other information concerning LG&E
Energy Corp. can be inspected at the office of such Exchange.
Oglethorpe is now working to finalize power marketer arrangements with
Morgan Stanley that would supply the remaining 50% of the Members' load
requirements. The agreement is expected to allow each Member to have Oglethorpe
elect a term from three to eight years. Each Member is currently deciding
whether to have Oglethorpe obtain its remaining load requirements from Morgan
Stanley. The proposed agreement would obligate Oglethorpe to purchase fixed
quantities of energy, averaging 50% of the Members' forecasted requirements
during the term of the agreement. Initially, Oglethorpe would manage the system
through purchases or sales to balance this fixed requirement against the actual
requirements. Oglethorpe would have considerably more discretion in the
management of the power supply system under the proposed Morgan Stanley contract
than under the LPM contract. In order to complete the implementation of the
Morgan Stanley power marketer arrangements, Oglethorpe and each participating
Member will enter into supplemental agreements to the New Wholesale Power
Contract to conform the provisions of the New Wholesale Power Contracts to the
terms of the power marketing arrangements. Any Member that elects not to
participate in the Morgan Stanley agreement would have other options available,
including having Oglethorpe manage this portion of the Member's load
requirements and, beginning as early as January 1, 1998, contract with other
power marketers.
In the interim, Oglethorpe is supplying this portion of the Members'
requirements from its own resources and by off-system purchase and sales. In the
event Oglethorpe does not enter into power marketer agreements for the remainder
of its load, it can continue to operate effectively in this manner
Oglethorpe will continue to plan for each Member's requirements beyond
the term of the respective power marketer agreements, including decisions
regarding early termination.
Power Purchases from GPC
Oglethorpe currently purchases 1,000 MW of capacity and associated
energy from GPC on a take-or-pay basis under the Block Power Sale Agreement
("BPSA"), which extends through December 31, 2003. The capacity purchases under
the BPSA are from five Component Blocks (as defined in the BPSA), composed of
three Component Blocks of 250 MW each (coal-fired units) and two Component
Blocks of 125 MW each (combustion turbine units). The capacity in one or more
Component Blocks may, however, be less than the MW stated above, as the result
of scheduled retirement of units or retirements due to force majeure events. All
units in the combustion turbine Component Blocks are scheduled to be retired by
2003. Although Oglethorpe may not increase its capacity purchases under the
BPSA, it may reduce or extend its purchases of one or more Component Blocks upon
proper notice to GPC. Oglethorpe has given notice of its intent to reduce its
purchases by two 250 MW Component Blocks (coal-fired units) effective September
1, 1997 and September 1, 1998. Also, pursuant to its long-term power marketer
agreements with LPM, Oglethorpe has committed to continue reducing its purchases
from GPC as permitted under the BPSA and thus will no longer purchase any energy
under the BPSA effective September 1, 2001. (See "Power Marketer Arrangements"
herein for a discussion of the LPM agreement.)
14
Other Power Purchases
Oglethorpe purchases 100 MW of capacity from each of Entergy Power,
Inc. ("EPI") and Big Rivers Electric Corporation ("Big Rivers"), under
agreements extending through June and July 2002, respectively. The availability
of capacity under the EPI contract is dependent on the availability of two
specific generating units available to EPI. The Tennessee Valley Authority
("TVA") provides the transmission service to deliver the power from the Big
Rivers electric system to the ITS. TVA and Southern Company Services, as agent
for Alabama Power Company and Mississippi Power Company, provide the
transmission service necessary to deliver the power from EPI to the ITS. (See
Note 9 of Notes to Financial Statements in Item 8.)
Oglethorpe also has a contract through 2019 to purchase approximately
300 MW of capacity with Hartwell Energy Limited Partnership ("Hartwell"), a
partnership owned 50% by Destec Energy, Inc. and 50% by American National Power,
Inc., a subsidiary of National Power, PLC. Oglethorpe intends to use the units
for peaking capacity but has the right to dispatch the units fully.
In addition to the purchases from GPC, Big Rivers and EPI, 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 has historically made all purchases the
Members would have otherwise been required to make under PURPA and Oglethorpe
was relieved of its obligation to sell certain services to "qualifying
facilities" so long as the Members make those sales. Oglethorpe has historically
provided the Members with the necessary services to fulfill these sale
obligations. Purchases by Oglethorpe from such qualifying facilities provided
0.2% of Oglethorpe's energy requirements for the Members in 1996. As a result of
the Corporate Restructuring, the Member may make such purchases in the future.
Oglethorpe has contracted with Florida Power Corporation to purchase 50
MW of peaking capacity during the summer of 1997 and 275 MW of peaking capacity
during the summer of 1998.
Under the New Wholesale Power Contracts, Oglethorpe will provide joint
planning services for all participating Members. A Member may elect not to have
Oglethorpe provide joint planning, procurement or bulk power marketing. Although
the long-term power marketer arrangements may provide substantially all of the
Members' requirements for the contract term, Oglethorpe will continue to supply
these planning services for requirements beyond the contract term as well as for
evaluation of contract options.
Long-Term Power Sales
Oglethorpe has an agreement to sell 100 MW of base capacity to Alabama
Electric Cooperative beginning June 1, 1998, and extending through December 31,
2005.
Other Power System Arrangements
Oglethorpe has interchange, transmission and/or short-term capacity and
energy purchase or sale agreements with over 20 utilities and other power
suppliers. The agreements provide variously for the purchase and/or sale of
capacity and energy and/or for the purchase of transmission service. The
development of and access to a statewide transmission network and the
interconnections with other utilities are key elements in Oglethorpe's ability
to make off-system sales and purchases through its contract with GTC and to
compete in an increasingly competitive market.
15
OTHER INFORMATION
Information with respect to fuel supply for Oglethorpe's plants is set
forth under the caption "GENERATING FACILITIES--Fuel Supply" included in Item 2
and is incorporated herein by reference. Information with respect to
environmental and other regulations affecting Oglethorpe and its plants is set
forth under the caption "ENVIRONMENTAL AND OTHER REGULATIONS" included in Item 2
and is incorporated herein by reference.
16
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. The Edwin I. Hatch Plant
("Plant Hatch"), the Hal B. Wansley Plant ("Plant Wansley"), the Alvin W. Vogtle
Plant ("Plant Vogtle") and the Robert W. Scherer Units No. 1 and No. 2 ("Scherer
Units No. 1 and No. 2") are co-owned by Oglethorpe, GPC, the Municipal Electric Authority of Georgia ("MEAG")MEAG and the City of Dalton
("Dalton").Dalton. GPC is
the operating agent for each of these plants, except
Rocky Mountain.co-owned plants. Rocky Mountain is
co-owned by Oglethorpe and GPC, and Oglethorpe is the operating agent.
Oglethorpe is the sole owner of the Tallassee Project at the Walter W. Harrison
Dam ("Tallassee"). (See "CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--The
Plant Agreements".)
OGLETHORPE'S
SHARE OF NAME- COMMERCIAL LICENSE
PERCENTAGE PLATE CAPACITY OPERATION EXPIRATION
TYPE OF FUEL INTEREST(1)Oglethorpe's
Share of Name- Commercial License
Percentage Plate Capacity Operation Expiration
Type of Fuel Interest(1) (MW) DATE DATEDate Date
------------ ----------- --------------- ---------- -------------- ---- ----
FACILITIES IN SERVICE:
FACILITIES IN SERVICE:
- ----------------------
Plant Hatch (near Baxley)
Unit No. 1 Nuclear 30 243.0 1975 2014
Unit No. 2 Nuclear 30 246.0 1979 2018
Plant Vogtle (near Waynesboro)
Unit No. 1 Nuclear 30 348.0 1987 2027
Unit No. 2 Nuclear 30 348.0 1989 2029
Plant Wansley (near Carrollton)
Unit No. 1 Coal 30 259.5 1976 N/A(2)
Unit No. 2 Coal 30 259.5 1978 N/A(2)
Combustion Turbine Oil 30 14.8 1980 N/A(2)
Plant Scherer (near Forsyth)
Unit No. 1 Coal 60 490.8 1982 N/A(2)
Unit No. 2 Coal 60 490.8 1984 N/A(2)
Tallassee (near Athens) Hydro 100 2.1 1986 2023
Rocky Mountain Pumped Storage
(near Rome) Hydro 74.61 632.5 1995 2027
----------------
Total Ownership 3,335.0
-------
-------=========
______________________- ----------
(1) Oglethorpe has an ownership interest in all of the facilities except
Scherer Unit No. 2. The 60% interest in Scherer Unit No. 2 is leased under
leases that expire in 2013, subject to options to renew for a total of 8.5
years.
(2) Coal-fired units and combustion turbines do not operate under operating
licenses similar to those granted to nuclear units by the Nuclear
Regulatory Commission and to hydroelectric plants by the Federal Energy
Regulatory Commission.
Oglethorpe owns or leases 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 and the other co-owners of the above plants also own
transmission facilities which together form the ITS. Through agreements,
common access to the combined facilities that compose the ITS enables the
11FERC.
17
owners to use their combined resources to make deliveries to their respective
consumers, to provide transmission service to third parties and to make
off-system purchases and sales. (See "Transmission and Other Power System
Arrangements" herein and "CO-OWNERS OF THE PLANTS AND THE PLANT AND
TRANSMISSION AGREEMENTS--Agreements Relating to Integrated Transmission
System".)
PLANT PERFORMANCEPlant 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)
-------------------------- ------------------Equivalent Availability (1) Capacity Factor (2)
------------------------------ -------------------------
Unit 1996 1995 1994 19931996 1995 1994 1993
- ---- ---- ---- ---- ---- ---- ----
Plant Hatch
Unit No. 1 ..........1................... 83% 98% 84% 76%83% 100% 85%
77%
Unit No. 2 ..........2................... 97 75 78 7599 75 79 75
Plant Vogtle
Unit No. 1 ..........1................... 80 98 86 8580 98 86 86
Unit No. 2 ..........2................... 88 89 91 8789 90 91 87
Plant Wansley
Unit No. 1 ..........1................... 88 90 92 8858 56 62
71
Unit No. 2 ..........2................... 91 89 88 9062 56 58
73
Plant Scherer(3)Scherer
Unit No. 1 ..........1................... 92 95 97 8874 73 64
36
Unit No. 2 ..........2................... 84 97 85 9572 85 60
37
Rocky Mountain(4)Mountain (3)
Unit No. 1 ..........1................... 94 83 N/A N/A15 16 N/A N/A
Unit No. 2 ..........2................... 95 92 N/A N/A13 15 N/A N/A
Unit No. 3 ..........3................... 95 92 N/A N/A10 16 N/A N/A
______________________- ---------------------
(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) Prior to 1994, Plant Scherer operated in peaking service due to its higher
cost fuel supply. Oglethorpe's efforts to reduce Plant Scherer's fuel
costs in recent years have made the units more economical to operate,
resulting in higher capacity factors.
(4) Rocky Mountain Commercial Operation Dates: Unit 1 - July 24, 1995; Unit 2
- June 19, 1995; Unit 3 - June 1, 1995. This information was calculated
beginning from the commercial operation date for each unit. As a pumped
storage plant, Rocky Mountain primarily operates in peaking service.
The nuclear refueling cycle for Plants Hatch and Vogtle exceeds twelve
months. Therefore, in some calendar years the units at these plants are not
taken out of service for refueling, resulting in higher levels of equivalent
availability and capacity factor.
12
FUEL SUPPLYFuel Supply
Coal for Plant Wansley is purchased under a long-term contract,contracts, which isare
estimated to be sufficient to provide the majority of the coal requirements of
Plant Wansley through 1997, with the remainder being provided through spot
market transactions. As of February 29, 1996,28, 1997, there was a 33-day38-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 spot market transactions. As of February
29, 1996,28, 1997, the coal stockpile at Plant Scherer contained a 21-day37-day
18
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 was built 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. Oglethorpe intendsexpects to
continueimplement separate dispatch at Plant Wansley by early to mid-summer 1997.
Oglethorpe continues to use GPC as its agent for fuel procurement. The co-owners have negotiated similar amendments to the
Plant Wansley Operating Agreement. Upon approval by RUS, Oglethorpe expects
to implement separate dispatch at Plant Wansley as well.
To take advantage of these changes at Plants Scherer and Wansley,
Oglethorpe formed a wholly owned subsidiary to acquire rail cars designed for
hauling coal from the western coal mining regions. The subsidiary, Black Diamond
Energy, Inc., has acquired 231purchased or leased 299 rail cars. Oglethorpe has entered into
an initial 15-year lease with the subsidiary which obligates Oglethorpe to pay
all of the ownership and operating expenses of the subsidiary relating to the
leased rail cars during the lease term.
For information relating to the impact that the Clean Air Act will have
on Oglethorpe, see "Environmental and Other Regulations" herein."ENVIRONMENTAL AND OTHER REGULATIONS--Clean Air Act".
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") to provide nuclear services, including nuclear fuel
procurement. SONOPCO employs both spot purchases and long-term contracts to
satisfy nuclear fuel requirements. The nuclear fuel supply and related services
are expected to be adequate to satisfy current and future nuclear generation
requirements.
Plants Hatch and Vogtle currently have on-site spent fuel storage
capacity. Based on normal operations and retention of all spent fuel in the
reactor, it is anticipated that existing on-site pool capacity would not be
sufficient in 2003 and 2009,2008, respectively, to accept the number of spent fuel
assemblies that would normally be removed from the reactor during a refueling.
Contracts with the Department of Energy ("DOE") have been executed to provide
for the permanent disposal of spent nuclear fuel produced at Plants Hatch and
Vogtle. The services to be provided by DOE are scheduled to begin in 1998;
however, the DOE has stated that permanent nuclear waste storage facilities will
not be available by that date, and it is uncertain when they will be available.
If DOE does not begin receiving the spent fuel from Plant Hatch in 2003 or from
Plant Vogtle in 2009,2008, alternative methods of spent fuel storage will be needed.
One option available is expansion of
spent fuelActivities for adding dry cast storage capacity at the plant sites.Plant Hatch by as early as
1999 are in progress. (See "Environmental and Other
Regulations" herein"ENVIRONMENTAL AND OTHER REGULATIONS--Nuclear
Regulation" for a discussion of the Nuclear Waste Policy Act and Note 1 of Notes
to Financial Statements in Item 8 regarding nuclear fuel cost.)
PROPOSED CHANGES TO NUCLEAR PLANT OPERATING ARRANGEMENTS
In September 1992, GPC filed applications with the Nuclear Regulatory
Commission (the "NRC") to add SONOPCO to the operating license of each unit
of Plants Hatch and Vogtle and designate SONOPCO as the operator. The
application is currently pending before the Atomic Safety and Licensing
Board. SONOPCO, a
13
subsidiary of The Southern Company specializing in nuclear services,
currently provides certain operating, maintenance, and other services to GPC
in accordance with the Amended and Restated Nuclear Managing Board Agreement
(the "Amended and Restated NMBA") and the agreements referenced in the
Amended and Restated NMBA. The co-owners have agreed to a Nuclear Operating
Agreement between GPC and SONOPCO, which will be entered into in the event
the NRC approves the application. (See "CO-OWNERS OF THE PLANTS AND THE
PLANT AND TRANSMISSION AGREEMENTS--The Plant Agreements--HATCH, WANSLEY,
VOGTLE AND SCHERER".)
POWER SALES TO AND PURCHASES FROM GPC
A significant portion of Oglethorpe's sales are made to GPC and a
significant portion of Oglethorpe's purchased power is obtained from GPC.
The following table sets forth a summary of Oglethorpe's electric purchases
from and sales to GPC and all other utilities as a group:
MWh
--------------------------
1995 1994
---------- ----------
SOURCES OF ENERGY:
Owned or Leased Generation ....... 18,402,839 16,924,038
Purchased -- GPC ............... 2,711,203 2,632,039
-- Others ............ 3,027,431 1,749,048
---------- ----------
Total Sources .............. 24,141,473 21,305,125
---------- ----------
DISTRIBUTION OF ENERGY:
Members .......................... 18,442,153 16,285,127
Non-Members -- GPC ............. 2,195,012 2,140,526
-- Others .......... 2,520,462 2,067,443
Transmission Losses .............. 983,846 812,029
---------- ----------
Total Distribution ......... 24,141,473 21,305,125
---------- ----------
The sales to GPC were made under the GPC Sell-back (as herein defined)
and the Coordination Services Agreement (the "CSA"). The purchases from GPC
were made under the Block Power Sale Agreement (the "BPSA") and the CSA.
GPC SELL-BACK
Pursuant to the contractual arrangements with GPC, Oglethorpe had an
obligation to sell to GPC, and GPC had an obligation to buy from Oglethorpe,
commencing with the commercial operation of each co-owned unit (other than
Rocky Mountain) and extending for various periods, a declining percentage of
Oglethorpe's entitlement to the capacity and energy of such unit (the "GPC
Sell-back"). As of May 31, 1995, the GPC Sell-back expired in accordance
with its terms for all units. For 1995, energy sales from the GPC Sell-back
represented less than 1% of total sales by Oglethorpe. Capacity and energy
revenues from the GPC Sell-back represented 1% of Oglethorpe's total revenues
in 1995.
As GPC's entitlement to capacity and energy under the GPC Sell-back
decreased, Oglethorpe's increased entitlement to the output of each unit was
used to serve its own requirements. The increased costs thereof are
recovered through Member rates and through off-system sales transactions.
The historical ability of Oglethorpe to sell power from new units to GPC
under the GPC Sell-back while at the same time purchasing power from GPC
under lower-cost arrangements enabled Oglethorpe to moderate the effects of
the higher costs associated with new generating units on Oglethorpe's costs
of service, and therefore on the rates charged the Members. (See "CO-OWNERS
OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--The Plant
Agreements--HATCH,
14
WANSLEY, VOGTLE AND SCHERER", "General--HISTORICAL FACTORS AFFECTING
FINANCIAL PERFORMANCE" in Item 7 and Note 1 of Notes to Financial Statements
in Item 8.)
POWER PURCHASE ARRANGEMENTS
Oglethorpe currently purchases 1,250 MW of capacity and associated energy
from GPC on a take-or-pay basis under the BPSA, which extends through
December 31, 2003. The BPSA, along with the Revised and Restated Integrated
Transmission System Agreement (the "ITSA") and the CSA, became effective in
1991. Together these agreements enabled Oglethorpe to restructure the way it
plans for and meets the Members' power requirements. These agreements have
improved Oglethorpe's ability to buy and sell power and transmission services
in the bulk power markets. The capacity purchases under the BPSA are from six
Component Blocks (as defined in the BPSA), composed of four Component Blocks
of 250 MW each (coal-fired units) and two Component Blocks of 125 MW each
(combustion turbine units). 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 two 250 MW Component Blocks (coal-fired units)
effective September 1, 1996 and September 1, 1997 respectively, and is
currently evaluating replacement purchases. The capacity in one or more
Component Blocks may, however, be less than 250 MW, as the result of
scheduled retirement of units or retirements due to force majeure events.
All units in the combustion turbine Component Blocks are scheduled to be
retired by 2003.
Under the CSA, GPC provides various control-area services to Oglethorpe.
Oglethorpe schedules and directs GPC to dispatch and coordinate power from
all of Oglethorpe's generation and purchased power resources through December
31, 1999. The CSA requires Oglethorpe to give GPC one hour's notice in order
to schedule any off-system transactions, which could limit Oglethorpe's
ability to compete with GPC for short-term energy transactions requiring less
than one hour's notice. Oglethorpe may elect to establish its own control
area and terminate regulation services under the CSA upon one year's notice
to GPC. Upon such termination, the parties will, if necessary, negotiate new
service schedules and applicable rates. In order to optimize its use of
coordination services, Oglethorpe is currently installing the equipment that
would provide Oglethorpe with the capability to operate its own control area.
For a further discussion of the new power supply arrangements, see "Other
Power Purchases", "Future Power Resources", and "Transmission and Other Power
System Arrangements" herein, and "CO-OWNERS OF THE PLANTS AND THE PLANT AND
TRANSMISSION AGREEMENTS--The Plant Agreements--HATCH, WANSLEY, VOGTLE AND
SCHERER".
OTHER POWER PURCHASES
Oglethorpe has entered into power purchase contracts with Entergy Power,
Inc. ("EPI") and Big Rivers Electric Corporation ("Big Rivers"), each for the
purchase of 100 MW, 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 "Transmission and Other Power System
Arrangements" herein and Note 9 of Notes to Financial Statements in Item 8.)
Oglethorpe also has a contract to purchase approximately 300 MW of
capacity with Hartwell Energy Limited Partnership ("Hartwell"), a partnership
owned 50% by Destec Energy, Inc. and 50% by American National Power, Inc., a
subsidiary of National Power, PLC, through April 2019. Oglethorpe intends to
use the units for peaking capacity but has the right to dispatch the units
fully.
15
In addition to the purchases from GPC, Big Rivers and EPI, 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 will make 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
provides the Members with the necessary services to fulfill these sale
obligations. Purchases by Oglethorpe from such qualifying facilities provided
0.3% of Oglethorpe's energy requirements for the Members in 1995.
EPMI POWER PURCHASE AND SALE
As a means of reducing the cost of power provided to the Members,
Oglethorpe and Enron Power Marketing, Inc. ("EPMI") entered into a power
supply swap agreement effective January 4, 1996 through April 30, 1996.
Pursuant to such agreement, EPMI must provide all the energy necessary to
meet the Members requirements at a favorable fixed rate, and Oglethorpe is
required to sell to EPMI at cost, subject to certain limitations, all energy
available from Oglethorpe's total power resources. Under the agreement,
Oglethorpe still maintains the responsibility of operating the power supply
system and continues to dispatch the generating resources to ensure system
reliability.
FUTURE POWER RESOURCES
Oglethorpe uses an integrated resource planning process to study
regularly the need for and feasibility of adding additional generation
facilities. This planning process also considers demand-side management
options that could be implemented by the Members as well as off-system sales
of capacity and energy to optimize the use of Oglethorpe's resources.
In its current integrated resource plan, Oglethorpe has identified a
potential need for additional peaking capacity in the late 1990s. Oglethorpe
has agreed to purchase from Florida Power Corporation 50 MW of peaking
capacity during the Summer of 1997 and 275 MW of peaking capacity during the
Summer of 1998. In 1993, Oglethorpe issued a request for proposals for the
purchase of up to 600 MW of long-term peaking capacity to be available by
June 1, 1999. While Oglethorpe is still considering some of these proposals,
it continues to pursue other options to keep the Members power cost as low as
possible.
On February 7, 1996, Oglethorpe issued another request for proposals.
This RFP did not seek a specific amount of power; instead, it requested
proposals for meeting the combined power needs of the Members with term
options ranging from two to 15 years. Action is anticipated by Oglethorpe's
Board of Directors during April, with implementation of a new arrangement as
soon thereafter as possible.
FUTURE 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. Oglethorpe has also submitted bids to various formal and informal
solicitations for capacity sales. Whether any such bid will be successful is
uncertain.
TRANSMISSION AND OTHER POWER SYSTEM ARRANGEMENTS
Oglethorpe owns approximately 2,267 miles of transmission line and 426
substations of various voltages. Oglethorpe provides power and energy to the
Members through the ITS consisting of transmission system facilities owned by
Oglethorpe, GPC, MEAG and Dalton. As a result of its participation in the
ITS, Oglethorpe is entitled to use any of the transmission facilities
included in the system, regardless of ownership. Oglethorpe's rights and
obligations with respect to the system are governed by the ITSA. (See "Power
Sales to and Purchases from
16
GPC--POWER PURCHASE ARRANGEMENTS" herein and "CO-OWNERS OF THE PLANTS AND THE
PLANT AND TRANSMISSION AGREEMENTS--Agreements Relating to Integrated
Transmission System".)
In addition to the interconnections available to Oglethorpe through the
ITS, Oglethorpe has interconnection, interchange, transmission and/or
short-term capacity and energy purchase or sale agreements with over 20
utilities and other power suppliers. The agreements provide variously for the
purchase and/or sale of capacity and energy and/or for transmission service.
Implementation of such contracts and other off-system transactions are
accomplished by the CSA. (See "Power Sales to and Purchases from GPC--POWER
PURCHASE ARRANGEMENTS" herein.) Oglethorpe has purchased from GPC sufficient
entitlement to the interface between the ITS and TVA to implement the
purchases from Big Rivers and EPI. Oglethorpe regularly buys and sells power
in the short-term bulk power market. The development of and access to a
statewide transmission network and the interconnections with other utilities
are key elements in Oglethorpe's ability to make off-system sales and
purchases, to provide transmission service to third parties and to compete in
an increasingly competitive market.
ENVIRONMENTAL AND OTHER REGULATIONS
GENERAL
As is typical in the utility industry, Oglethorpe is subject to Federal,
State and local air and water quality requirements which, among other things,
regulate emissions of pollutants, such as particulate matter, sulfur oxides
and nitrogen oxides ("NO(x)") into the air and discharges of other pollutants,
including heat, into waters of the United States. Oglethorpe is also subject
to Federal, State and local waste disposal requirements which regulate the
manner of transportation, storage and disposal of solid and other waste. In
general, environmental requirements are becoming increasingly stringent, and
further or new requirements may substantially increase the cost of electric
service by requiring changes in the design or operation of existing
facilities as well as changes or delays in the location, design, construction
or operation of new facilities. Failure to comply with these requirements
could result in the imposition of civil and criminal penalties as well as the
complete shutdown of individual generating units not in compliance. There is
no assurance that the units in operation or under construction will always
remain subject to the regulations currently in effect or will always be in
compliance with future regulations.
Compliance with environmental standards or deadlines will continue to be
reflected in Oglethorpe's capital and operating costs. Oglethorpe's direct
capital costs to achieve compliance with environmental requirements are
expected to be approximately $1.0 million in 1996, $3.6 million in 1997 and
$1.4 million in 1998.
CLEAN AIR ACT
The Clean Air Act ("Act") seeks to improve air quality throughout the United
States. The acid rain provisions of the Act require the reduction of sulfur
dioxide and NO(x) emissions from affected units, including coal-fired electric
power facilities. The sulfur dioxide reductions required by the Act will be
achieved in two phases. Phase I addresses specific generating units named in
the Act. Both units of Plant Wansley are "affected units" under Phase I.
Scherer Units No. 1 and No. 2 are not "affected units" under Phase I but are
"affected units" under Phase II. Beginning in 1995, Phase I affected units
became subject to the sulfur dioxide emission allowance trading program.
Emission allowances are issued by the U.S. Environmental Protection Agency
("EPA"), based on statutory allocations in Phase I and on fossil fuel
consumption for affected units from 1985 through 1987 for Phase II. An
allowance, which gives the holder the authority to emit one ton of sulfur
dioxide during a calendar year, is transferable and can be bought, sold or
banked for use in the years following its issuance. Oglethorpe expects to
comply with Phase I requirements through the use of its allowances coupled
with switching to lower sulfur coal, a compliance strategy that has required
some equipment upgrades at Plant Wansley and may result in unused allowances
that can be banked for future use.
17
For Phase II, which begins in the year 2000, when total U.S. emissions of
sulfur dioxide will be capped at 8.9 million tons, Oglethorpe could use a
variety of options for sulfur dioxide compliance, including use of emission
allowances (allocated, banked or purchased, if needed), fuel-switching or
installation of flue gas desulfurization equipment. Achieving compliance
with Phase II has already resulted in some equipment upgrades at Scherer
Units No. 1 and No. 2.
Although some NO(x) regulations implementing the requirements of the Act
have been finalized, there remains the possibility that other regulations
could be imposed. For example, EPA recently proposed lowering the NO(x)
emission standard for boiler types such as those found at Scherer Units No. 1
and No. 2. Whether those regulations will be finalized and in what form is not
known. Depending on the NO(x) rules when finalized, additional expenditures
for pollution control equipment may be incurred.
In general, compliance with the Act will continue to require expenditures
for monitoring and permitting, and in some instances may involve increased
operating or maintenance expenses. Capital expenditures of Oglethorpe through
1995 for pollution control equipment needed to comply with the Act at Plant
Wansley have been approximately $7,200,000 and at Scherer Units No. 1 and No. 2
have been approximately $720,000. The estimated cost of any additional
improvements at Plant Wansley and Scherer Units No. 1 and No. 2 remains
dependent upon the chosen compliance plan and may be affected by future plan
amendments and/or future regulations. In addition, the final capital cost of
improvements and any effect on operating costs will be determined by the
compliance plan as finally implemented and any applicable regulatory changes.
Metropolitan Atlanta is classified as a "serious nonattainment area" with
regard to the ozone ambient air quality standards. The Act, under which these
standards are promulgated, requires the State of Georgia to conduct specific
studies and establish new rules regulating sources of NO(x) and volatile organic
compounds, to achieve attainment of the standards by 1999 and to maintain
compliance thereafter. As a required first step, Georgia has issued rules for
the application of reasonably available control technology for NO(x) emissions.
Those regulations, however, did not affect Plant Wansley or Scherer Units No. 1
and No. 2, which are not in the Atlanta ozone nonattainment area. Georgia is
still performing photochemical grid modeling, however, and as a result may yet
promulgate new rules for power plants in the State. Plant Wansley is near the
nonattainment area while Plant Scherer is located further away. The results of
these studies and new rules could require NO(x) controls more stringent than
those now required under the acid rain provisions of the Act for compliance.
Portions of Subchapter I of the Act require that several studies be conducted
regarding the health effects of power plant emissions of certain hazardous
air pollutants. The studies will be used in making decisions on whether
additional controls of these pollutants are necessary. The effect of any of
these potential regulatory changes under the Act, including new rules under the
amended provisions, cannot now be predicted.
The Act also requires EPA to review all National Ambient Air Quality
Standards ("NAAQS") periodically, revising such standards as necessary. EPA
continues to evaluate the need for a new short-term standard for sulfur oxides
(measured as sulfur dioxide). If a new short-term NAAQS for sulfur dioxide were
imposed, it might require numerous power plants to install emission controls,
perhaps in addition to any required under the acid rain provisions of the Act.
These controls could result in substantial costs to Oglethorpe. Although EPA
has evaluated the need and decided for now not to revise the NAAQS for nitrogen
dioxides, there is no certainty that that standard will not be revised in the
future. In addition, EPA has finalized a criteria document and is updating a
staff paper for ozone, which could lead to a change in the NAAQS for ozone.
EPA is also updating a criteria document and staff paper for particulate matter,
which could lead to a revision of the NAAQS for particulate matter. The impact
of any change in the ozone, sulfur dioxide, nitrogen dioxides or particulate
matter NAAQS cannot now be determined because the effect of any change would
depend in part on the final ambient standards developed.
Although Oglethorpe's management is currently unable to determine the
overall effect that compliance with requirements under the Act will have on
its operations, it does not believe that any required increases in capital or
operating expenses would have a material effect on its results of operations
or financial condition. Compliance with requirements under the Act may also
require increased capital or operating
18
expenses on the part of GPC. Any increases in GPC's capital or operating
expenses may cause an increase in the cost of power purchased from GPC. (See
"Power Sales to and Purchases from GPC--POWER PURCHASE ARRANGEMENTS" herein.)
CLEAN WATER ACT
Congress is considering reauthorization of the Clean Water Act. If that
occurs, Oglethorpe's operations could be affected. However, the full impact
of any reauthorization cannot now be determined and will depend on the
specific changes to the statute, as well as to any implementing state or
federal regulations that might be promulgated.
NUCLEAR REGULATION
Oglethorpe is subject to the provisions of the Atomic Energy Act of 1954,
as amended (the "Atomic Energy Act"), which vests jurisdiction in the NRC
over the construction and operation of nuclear reactors, particularly with
regard to certain public health, safety and antitrust matters. The National
Environmental Policy Act has been construed to expand the jurisdiction of the
NRC to consider the environmental impact of a facility licensed under the
Atomic Energy Act. Plants Hatch and Vogtle are being operated under licenses
issued by the NRC. All aspects of the operation and maintenance of nuclear
power plants are regulated by the NRC. From time to time, new NRC
regulations require changes in the design, operation and maintenance of
existing nuclear reactors. Operating licenses issued by the NRC are subject
to revocation, suspension or modification, and the operation of a nuclear
unit may be suspended if the NRC determines that the public interest, health
or safety so requires. (See "Proposed Changes to Nuclear Plant Operating
Arrangements" herein.)
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 DOE for such material. These contracts require
each such owner to pay a fee which is currently one dollar per MWh for the
net electricity generated and sold by each of its reactors. (See "Fuel
Supply" herein.)
For information concerning nuclear insurance, see Note 8 of Notes to
Financial Statements in Item 8. For information regarding NRC's regulation
relating to decommissioning of nuclear facilities and regarding DOE's
assessments pursuant to the Energy Policy Act for decontamination and
decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to
Financial Statements in Item 8.
OTHER ENVIRONMENTAL REGULATION
In 1993, EPA issued a ruling confirming the non-hazardous status of coal
ash. That ruling may apply, however, only to situations where those wastes
are not co-managed, i.e. not mixed with other wastes. Pursuant to court
order, EPA has until 1998 to classify co-managed utility wastes as either
hazardous or non-hazardous. If the wastes are classified as hazardous,
substantial additional costs for the management of such wastes might be
required, although the full impact would depend on the subsequent development
of requirements pertaining to these wastes.
Oglethorpe is subject to other environmental statutes including, but not
limited to, the Toxic Substances Control Act, the Resource Conservation &
Recovery Act ("RCRA"), the Endangered Species Act ("ESA"), the Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA"), the
Emergency Planning and Community Right to Know Act, the Georgia Hazardous
Site Response 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 operations. Changes to any of
these laws, however, could affect many areas of Oglethorpe's operations.
Congress is considering amending the ESA and reauthorizing CERCLA and perhaps
RCRA. Although compliance with new environmental legislation could have a
significant impact on Oglethorpe,
19
those impacts cannot be fully determined at this time and would depend in
part on the final legislation and the development of implementing regulations.
The scientific community, regulatory agencies and the electric utility
industry are continuing to examine the issues of global warming and the
possible health effects of electromagnetic fields. While no definitive
scientific conclusions have been reached regarding these issues, it is
possible that new laws or regulations pertaining to these matters could
increase the capital and operating costs of electric utilities, including
Oglethorpe or entities from which Oglethorpe purchases power. In addition,
the potential for liability exists from lawsuits alleging damages from
electromagnetic fields.
ENERGY POLICY ACT
The Energy Policy Act allows for increased competition among wholesale
electric suppliers and increased access to transmission services by such
suppliers. It creates a new class of utilities called Exempt Wholesale
Generators ("EWGs"), which are exempt from certain restrictions otherwise
imposed by the Public Utility Holding Company Act. The effect of this
exemption is to facilitate the development of independent third-party
generators potentially available to satisfy utilities' needs for increased
power supplies. Unlike purchases from qualifying facilities under PURPA (see
"Other Power Purchases" herein), however, utilities have no statutory
obligation to purchase power from EWGs. Furthermore, EWGs are precluded from
making direct sales to retail electricity customers.
The Energy Policy Act also broadens the authority of FERC to require a
utility to transmit power to or on behalf of other participants in the
electric utility industry, including EWGs and qualifying facilities, but FERC
is precluded from requiring a utility to transmit power from another entity
directly to a retail customer. In March 1995, FERC issued a proposed rule
implementing the open access provisions of the Energy Policy Act. The Chair
of FERC has publicly predicted a final rule before mid-1996. Although
RUS-financed cooperatives will not be subject to all provisions of the FERC
rule, they will be subject to FERC orders to provide transmission on just and
reasonable terms and conditions.
A significant outgrowth of the Energy Policy Act is the rapid increase of
power marketers. Power marketers are FERC-regulated public utilities that
sell under "market-based" rates. Power marketers rely heavily on
transmission access to buy and sell power across several systems. (See "EPMI
Power Purchase and Sale" and "Future Power Resources" herein.)
20
CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS
CO-OWNERS OF THE PLANTSCo-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). GPC is the construction and operating agent for each of
these plants, except for Rocky Mountain for which Oglethorpe is the construction and operating
agent. (See "The Plant Agreements" herein.)
Nuclear Coal-FireCoal-Fired Pumped Storage
-------------------------- --------------------------------------------------------- ---------------------------------- --------------
Plant Plant Plant Scherer Units Rocky
Hatch Vogtle Wansley No. 1 & No. 2 Mountain Total
------------ ------------ ------------ -------------------------- -------------- -------------- ---------------- -------------- -----
% MW(1) % MW(1) % MW(1) % MW(1) % MW(1) MW(1)
----- ----- ----- ----- ----- ----- -------- ----- ----------- ----- ----- -----
Oglethorpe ..Oglethorpe. 30.0 489 30.0 696 30.0 519 60.0(2) 982 74.61 633 3,319
GPC .........GPC........ 50.1 817 45.7 1,060 53.5 926 8.4 137 25.39 215 3,155
MEAG ........MEAG....... 17.7 288 22.7 527 15.1 261 30.2 494 -- -- 1,570
Dalton ......Dalton..... 2.2 36 1.6 37 1.4 24 1.4 23 -- -- 120
----- ----- ----- ----- ----- ----- -------- -------------------------- ------- ------- ------- ------- ------- ------ ----- -----
Total........------ ------
Total...... 100.0 1,630 100.0 2,320 100.0 1,730 100.0 1,636 100.00 848 8,164
----- ----- ----- ----- ----- ----- -------- ----- ------ ----- -----
----- ----- ----- ----- ----- ----- -------- ----- ------ ----- -----===== ===== ===== ===== ===== ===== ===== ===== ====== === =====
______________________- ----------
(1) Based on nameplate ratings.
(2) Oglethorpe leases its interest in Scherer Unit No. 2 pursuant to long-term
net leases.
GEORGIA POWER COMPANYGeorgia 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 three 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 Securities and Exchange Commission (the
"Commission").Commission. Copies of this material can be
obtained at prescribed rates from the Commission's Public Reference Section at
450 Fifth Street, N.W., Room 1024, Washington, D.C. 20549. Certain securities of
GPC are listed on the New York Stock Exchange, and reports and other information
concerning GPC can be inspected at the office of such Exchange.
MUNICIPAL ELECTRIC AUTHORITY OF GEORGIAMunicipal Electric Authority of Georgia
MEAG, an instrumentality of the State of Georgia, was created for the
purpose of providing electric capacity and energy to those political
subdivisions of the State of Georgia that owned and operated electric
distribution systems at that time. MEAG (who also markets under the name of 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 270,000 electric
customers.
2120
CITY OF DALTON, GEORGIACity 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 SCHERERThe Plant Agreements
Hatch, Wansley, Vogtle and Scherer
Oglethorpe's rights and obligations with respect to Plants Hatch,
Wansley, Vogtle and Scherer are contained in a number of contracts between
Oglethorpe and GPC and, in some instances, MEAG and Dalton. Oglethorpe is a
party to four Purchase and Ownership Participation Agreements ("Ownership
Agreements") under which it acquired from GPC a 30% undivided interest in each
of Plants Hatch, Wansley and Vogtle, a 60% undivided interest in Scherer Units
No. 1 and No. 2 and a 30% undivided interest in those facilities at Plant
Scherer intended to be used in common by Scherer Units No. 1, No. 2, No. 3 and
No. 4 (the "Scherer Common Facilities"). Oglethorpe has also entered into four
Operating Agreements ("Operating Agreements") relating to the operation and
maintenance of Plants Hatch, Wansley, Vogtle and Scherer, respectively. The
Operating Agreements and Ownership Agreements relating to Plants Hatch and
Wansley are two-party agreements between Oglethorpe and GPC. The other Operating
Agreements and Ownership Agreements are agreements among Oglethorpe, GPC, MEAG
and Dalton. The parties to each Ownership Agreement and each Operating Agreement
are referred to as "Participants" with respect to each such agreement.
In 1985, in four separate transactions, Oglethorpe sold its entire 60%
undivided ownership interest in Scherer Unit No. 2 to four separate owner trusts
established by four different institutional investors. (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. (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. 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.
Each Operating Agreement gives GPC, as agent, sole authority and
responsibility for the management, control, maintenance, operation, scheduling
and dispatching of the plant to which it relates. However, as provided in the
recent amendments to the Plant Scherer Ownership and Operating Agreements, Oglethorpe
is separately dispatching its ownership share of Scherer Units No. 1 and No. 2.
Similar amendments to the Plant Wansley Operating Agreement have recently been
negotiatedentered into and upon approval of RUS, Oglethorpe expects to dispatchbegin dispatching separately its
ownership share in Plant Wansley.Wansley in 1997. (See "THE POWER SUPPLY SYSTEM--Fuel"GENERATING FACILITIES--Fuel
Supply".) In 1990, the co-owners of Plants Hatch and Vogtle entered into the
NMBANuclear 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 NMBANuclear
Managing Board Agreement (the "Amended and Restated NMBA") which provides for a
managing board (the "Nuclear Managing Board") to coordinate the implementation
and administration of the Plant Hatch and Plant Vogtle Ownership and Operating
Agreements and provides for increased rights for the co-owners regarding certain
decisions and allowed GPC to contract with a
21
third party for the operation of the nuclear units. In connection with the
recent amendments to the Plant Scherer Ownership and Operating Agreements, the
co-owners of Plant Scherer entered into the Plant Scherer Managing Board
Agreement
22
which provides for a managing board (the "Plant Scherer Managing
Board") to coordinate the implementation and administration of the Plant Scherer
Ownership and Operating Agreements and provides for increased rights for the
co-owners regarding certain decisions, but does not alter GPC's role as agent
with respect to Plant Scherer.
The Operating Agreements provide that Oglethorpe is entitled to a
percentage of the net capacity and net energy output of each plant or unit equal
to its percentage undivided interest owned or leased in such plant or unit,
subject to its obligation to sell capacity and energy to GPC as described below.
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, once the proposed amendments to the
Plant Wansley Operating Agreement are effective,Oglethorpe begins separate dispatch there, 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.
(See "THE POWER Supply SYSTEM--Proposed Changes to Nuclear Plant
Operating Arrangements".)
TERMS.
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, 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 MOUNTAINProposed Changes to Nuclear Plant Operating Arrangements
In September 1992, GPC filed applications with the Nuclear Regulatory
Commission (the "NRC") to add SONOPCO to the operating license of each unit of
Plants Hatch and Vogtle and designate SONOPCO as the operator. The application
has been recently approved by the Atomic Safety and Licensing Board and became
effective in late March. SONOPCO, a subsidiary of The Southern Company
specializing in nuclear services, currently provides certain operating,
maintenance, and other services to GPC in accordance with the Amended and
Restated NMBA and the agreements referenced in the Amended and Restated NMBA.
The co-owners had previously agreed to a Nuclear Operating Agreement between GPC
and SONOPCO, which became operative on the effective date of the license
amendment.
Rocky Mountain
Oglethorpe's rights and obligations with respect to Rocky Mountain are
contained in several contracts between Oglethorpe and GPC, the co-owners of
Rocky Mountain. Pursuant to Rocky Mountain Pumped Storage Hydroelectric
Ownership Participation Agreement, by and between Oglethorpe and GPC (the
"Ownership Participation Agreement"), Oglethorpe initially acquired a 3%
undivided interest in Rocky Mountain which interest increased as Oglethorpe
expended funds to complete construction of Rocky Mountain. The final ownership
percentages for Rocky Mountain are Oglethorpe 74.61% and GPC 25.39%. In
connection with this
22
acquisition, Oglethorpe and GPC also entered into the Rocky Mountain Pumped
Storage Hydroelectric Project Operating Agreement (the "Rocky Mountain Operating
Agreement").
The Ownership Participation Agreement appoints Oglethorpe as agent with
sole authority and responsibility for, among other things, the planning,
licensing, design, construction, operation, maintenance and disposal of Rocky
Mountain. The Rocky Mountain 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 Ownership Participation Agreement.
Oglethorpe and GPC have each elected to schedule separately their respective
ownership interests. The Rocky Mountain Operating Agreement will terminate in
2035.
Oglethorpe completed, in two separate closings on December 31, 1996 and
January 3, 1997, lease transactions for its 74.61% undivided ownership interest
in Rocky Mountain. Under the terms of these transactions, Oglethorpe leased the
facility to three institutional investors for a term of 71 years, who in turn
leased it back to Oglethorpe for a term of 30 years. The transactions are
characterized as a sale and lease-back for income tax purposes, but not for
financial reporting purposes. Oglethorpe will continue to control and operate
the plant during the lease-back term, and it fully intends to repurchase tax
ownership and to retain all other rights of ownership with respect to the plant
at the end of the lease-back period. As a result of these transactions,
Oglethorpe received net proceeds of approximately $96 million which is being
recorded as a deferred credit and will be recognized in income over the term of
the lease-back. Approximately $91 million of the proceeds will be used for the
early retirement of FFB debt, with the remaining $5 million being used to pay
alternative minimum taxes on the transactions. The combination of the debt
prepayment and the amortized gain will result in an estimated $11 million in
annual savings. In connection with these transactions, Oglethorpe is obligated
to maintain liquidity from various sources of approximately $50 million.
23
AGREEMENTS RELATING TO THE INTEGRATED TRANSMISSION SYSTEMENVIRONMENTAL AND OTHER REGULATIONS
General
As is typical in the utility industry, Oglethorpe is subject to
Federal, State and GPC have enteredlocal air and water quality requirements which, among other
things, regulate emissions of pollutants, such as particulate matter ("PM"),
sulfur oxides and nitrogen oxides ("NOx") into the ITSAair and discharges of other
pollutants, including heat, into waters of the United States. Oglethorpe is also
subject to provide forFederal, State and local waste disposal requirements which regulate
the transmissionmanner of transportation, storage and distributiondisposal of solid and other waste. In
general, environmental requirements are becoming increasingly stringent, and
further or new requirements may substantially increase the cost of electric
energyservice by requiring changes in the design or operation of existing facilities
as well as changes or delays in the location, design, construction or operation
of new facilities. Failure to comply with these requirements could result in the
imposition of civil and criminal penalties as well as the complete shutdown of
individual generating units not in compliance. There is no assurance that the
units in operation will always remain subject to the regulations currently in
effect or will always be in compliance with future regulations.
Compliance with environmental standards or deadlines will continue to
be reflected in Oglethorpe's capital and operating costs. Oglethorpe's direct
capital costs to achieve compliance with environmental requirements are expected
to be an aggregate of approximately $250,000 for 1997, 1998 and 1999.
Clean Air Act
The Clean Air Act seeks to improve air quality throughout the United
States. The acid rain provisions of the Clean Air Act require the reduction of
sulfur dioxide ("SO2") and NOx emissions from affected units, including
coal-fired electric power facilities. The SO2 reductions required by the Clean
Air Act will be achieved in two phases. Phase I addresses specific generating
units named in the Clean Air Act. Both units of Plant Wansley are "affected
units" under Phase I. Scherer Units No. 1 and No. 2 are not "affected units"
under Phase I but are "affected units" under Phase II. Beginning in 1995, Phase
I affected units became subject to the SO2 emission allowance trading program.
Emission allowances are issued by the U.S. Environmental Protection Agency
("EPA"), based on statutory allocations in Phase I and on fossil fuel
consumption for affected units from 1985 through 1987 for Phase II. An
allowance, which gives the holder the authority to emit one ton of SO2 during a
calendar year, is transferable and can be bought, sold or banked for use in the
years following its issuance. Oglethorpe expects to comply with Phase I
requirements through the use of its allowances coupled with switching to lower
sulfur coal, a compliance strategy that has required some equipment upgrades at
Plant Wansley and may result in unused allowances that can be banked for future
use or sold.
For Phase II, which begins in the year 2000, when total U.S. emissions
of SO2 will be capped at 8.9 million tons, Oglethorpe could use a variety of
options for SO2 compliance, including use of emission allowances (allocated,
banked or purchased, if needed), fuel-switching or installation of flue gas
desulfurization equipment. Achieving compliance with Phase II has already
resulted in some equipment upgrades at Scherer Units No. 1 and No. 2.
Although some NOx regulations implementing the requirements of the
Clean Air Act have been finalized for some time, others have recently been
promulgated and there remains the possibility that further regulation of NOx
emissions from utility sources could be imposed. EPA recently issued a final
rule lowering the NOx emission standard for boiler types such as those found at
Scherer Units No. 1 and No. 2. These rules have been challenged, however, and
whether the new NOx emission standards will ultimately be imposed at Plant
Scherer Units No. 1 and
24
No. 2 is not known. Depending on the form those NOx rules take after the
associated litigation has ended, additional expenditures for pollution control
equipment may be incurred.
In general, compliance with the Clean Air Act will continue to require
expenditures for monitoring and permitting, and in some instances may involve
increased operating or maintenance expenses. Capital expenditures of Oglethorpe
through 1996 for pollution control equipment needed to comply with the Clean Air
Act at Plant Wansley have been approximately $7,200,000 and at Scherer Units No.
1 and No. 2 have been approximately $720,000. Although the estimated cost of any
additional improvements at Plant Wansley and Scherer Units No. 1 and No. 2
remains dependent upon the chosen compliance plan and may be affected by future
plan amendments and/or future regulation, Oglethorpe has budgeted approximately
$250,000 in capital expenditures for Clean Air Act and related projects over the
next three years. In addition, the final capital cost of improvements and any
effect on operating costs will be determined by the compliance plan as finally
implemented and any applicable regulatory changes.
Metropolitan Atlanta is classified as a "serious nonattainment area"
with regard to the ozone ambient air quality standards. The Clean Air Act, under
which these standards are promulgated, requires the State of Georgia other than in certain counties,to conduct
specific studies and for bulk power transactions, through useestablish new rules regulating sources of NOx and volatile
organic compounds ("VOC"), to achieve attainment of the ITS. The ITS, together with transmission system facilities acquired or
constructedstandards by MEAG and Dalton under agreements with GPC referred to below,
was established in order to obtain the benefits of a coordinated development
of the parties' transmission facilities1999 and to
make it unnecessarymaintain compliance thereafter. These studies could result in new rules for
any
party to construct duplicative facilities. The ITS consists of all
transmission facilities, including land, owned by the parties on the date the
ITSA became effective and those thereafter acquired, which are locatedpower plants in the State, of Georgiaincluding Plants Wansley and Scherer. Further, along
with 36 other thanstates in the excluded countieseastern half of the U.S., Georgia, as a member of
the Ozone Transport Assessment Group ("OTAG"), is performing extensive
photochemical grid modeling in an effort to reach a consensus among its member
states as to the strategies needed to reduce ozone and its precursors (including
NOx). Large, stationary sources of NOx have been a focus for OTAG. Originally,
each OTAG state was to have new emission reduction strategies in place by late
spring or early summer of 1997. However, EPA has stated its intention to specify
the overall amount of NOx and VOC emission reductions that must be achieved by
each OTAG state.
Plant Wansley is near the non-attainment area while Plant Scherer is
located further away. The results of these studies and new rules could require
NOx controls more stringent than those now required under the acid rain
provisions of the Clean Air Act for compliance. Portions of Subchapter I of the
Clean Air Act also require that several studies be conducted regarding the
health effects of power plant emissions of certain hazardous air pollutants. The
studies will be used in making decisions on whether additional controls of these
pollutants are necessary. The effect of any of these potential regulatory
changes under the Clean Air Act, including new rules under the amended
provisions, can not now be predicted.
The Clean Air Act also requires EPA to review all National Ambient Air
Quality Standards ("NAAQS") periodically, revising such standards as necessary.
Last year, EPA decided not to impose a new short-term standard for sulfur oxides
(measured as SO2). That decision has been appealed, however, so that it is still
possible that a new SO2 standard could be promulgated. If a new short-term NAAQS
for SO2 were imposed, it might require new emission controls at Plants Wansley
and Scherer, which could result in substantial costs to Oglethorpe.
EPA has also proposed to revise the NAAQS for both ozone and PM. Either
of these proposals, if finalized, could have a substantial effect on the types
of controls that might be needed at Plants Wansley or Scherer for compliance.
However, the final impacts (and any associated expenditures) at either plant can
not now be predicted with any certainty. In fact, the impact of any change in
these NAAQS can not now be determined, because the effect of any change would
depend in part on the final ambient standards developed.
Although Oglethorpe's management is currently unable to determine the
overall effect that compliance with requirements under the Clean Air Act will
have on its operations, it does not believe that any required increases in
capital or operating expenses would have a material effect on its results of
operations or its financial condition. Compliance with the requirements under
the Clean Air Act may also require increased capital or operating expenses on
the part of GPC. Any increases in GPC's capital or operating expenses may cause
an
25
increase in the cost of power purchased from GPC. (See "MEMBER REQUIREMENTS
AND POWER SUPPLY RESOURCES--Power Purchase and Sale Arrangements--Power
Purchases from GPC" in Item 1.)
Clean Water Act
For some time now, Congress has been considering reauthorization of the
Clean Water Act. If that occurs, Oglethorpe's operations could be affected.
However, the full impact of any reauthorization cannot now be determined and
will depend on the specific changes to the statute, as well as to any
implementing state or federal regulations that might be promulgated.
At the state level, EPA is under Federal court order to begin
development of Total Maximum Daily Loads ("TMDLs") for all of Georgia's stream
segments that do not yet meet established water quality standards. The order
calls for a strict schedule for the development of such TMDLs, beginning in the
summer of 1997. Oglethorpe cannot now predict what impact, if any, such
development will have on the operations of Plants Wansley, Scherer, Hatch or
Vogtle, because the effect will depend on the final TMDLs to be developed and
EPA's (and the state's) approach for revising National Pollutant Discharge
Elimination System permits to achieve the desired TMDLs and ultimately achieve
the required water quality standards.
Georgia Hazardous Site Response Act ("GHSRA")
GHSRA requires the compilation and listing of an inventory of all known
or suspected sites where "regulated substances" have been disposed of or
released in quantities deemed reportable by the state. In developing this list,
which includes hundreds of sites, one site co-owned by Oglethorpe was listed.
The site is located at Plant Wansley and consists of an ash pond. As the
operating agent of the plant, GPC will conduct the required remedial
investigation in late 1997 or early 1998, to determine if any clean-up
activities are usedrequired. At this time, it is uncertain whether any remediation
will be required and what the timing of any required remediation might be. If
remediation is required, Oglethorpe could incur up to an estimated $800,000 in
clean-up costs and $6 million in capital costs, associated with the
redevelopment of the ash pond. Additional sites may require investigation and
remediation expenses, a portion or usableall of which Oglethorpe may be liable for. At
this time, Oglethorpe does not believe that any capital or operating costs
associated with GHSRA clean-ups would have a material effect on its results of
operations or its financial condition.
Nuclear Regulation
Oglethorpe is subject to transmit powerthe provisions of the Atomic Energy Act of
1954, as amended (the "Atomic Energy Act"), which vests jurisdiction in the NRC
over the construction and operation of nuclear reactors, particularly with
regard to certain public health, safety and antitrust matters. The National
Environmental Policy Act has been construed to expand the jurisdiction of the
NRC to consider the environmental impact of a certain minimum voltage and to transform power
of a certain minimum voltage and a certain minimum capacity (the
"Transmission Facilities"). GPC has entered into agreements with MEAG and
Dalton that are substantially similar to the ITSA, and GPC may enter into
such agreements with other entities. The ITSA will remain in effect through
December 31, 2012 and, if not then terminated by five years' prior written
notice by either party, will continue until so terminated.
The ITSA is administered by a Joint Committee established by a Joint
Committee Agreement, summarized below. Each year, the Joint Committee
determines a four-year plan of additions to the Transmission Facilities that
will reflect the current and anticipated future transmission requirements of
the parties. Oglethorpe and GPC are each required to maintain an original
cost investment in the Transmission Facilities in proportion to their
respective Peak Loads (as defined in the ITSA).
Oglethorpe and GPC are parties to a Transmission Facilities Operation and
Maintenance Contract (the "Transmission Operation Contract"), under which GPC
provides System Operator Services (as defined in the Transmission Operation
Contract) for Oglethorpe. In addition, GPC is required to provide such
supervision, operation and maintenance supplies, spare parts, equipment and
labor for the operation, maintenance and construction as may be specified by
Oglethorpe. GPC is also required to perform certain emergency workfacility licensed under the Transmission Operation Contract. Oglethorpe is permitted, upon notice to
GPC, to perform, or contract with others for the performance of, certain
services performed by GPC. Absent termination or amendment of the
Transmission Operation Contract, however, GPC will continue to perform System
Operator Services for Oglethorpe. The term of the Transmission Operation
Contract will continue from year to year unless terminated by either party
upon four years' notice. Oglethorpe is required to pay its proportionate
share of the cost for the services provided by GPC.
THE JOINT COMMITTEE AGREEMENT
Oglethorpe, GPC, MEAG and Dalton are parties to a Joint Committee
Agreement. In the past, the Joint Committee coordinated the implementation
and administration of the various Ownership Agreements and Operating
Agreements, the various integrated transmission system agreements, and the
various integrated transmission system operation and maintenance agreements
among the parties. However, the Nuclear Managing Board has assumed such
responsibilities forAtomic
Energy Act. Plants Hatch and Vogtle are being operated under licenses issued by
the NRC. All aspects of the operation and maintenance of nuclear power plants
are regulated by the NRC. From time to time, new NRC regulations require changes
in the design, operation and maintenance of existing nuclear reactors. Operating
licenses issued by the NRC are subject to revocation, suspension or
modification, and the operation of a nuclear unit may be suspended if the NRC
determines that the public interest, health or safety so requires. (See
"CO-OWNERS OF THE PLANTS AND THE PLANT AGREEMENTS--The Plant
Scherer Managing
Board has assumed such responsibilities forAgreements--Proposed Changes to Nuclear Plant Scherer and an operating
committee will assume such responsibilities for Plant Wansley once the
proposed amendmentsOperating Arrangements".)
Pursuant to the Plant Wansley Operating Agreement are effective.
(See "The Plant Agreements--HATCH, WANSLEY, VOGTLE AND SCHERER" herein.) The
Joint Committee Agreement also makes allowanceNuclear Waste Policy Act of 1982, as amended, the
Federal government has the regulatory responsibility for the joint planningfinal disposition
of futurecommercially produced high-level radioactive waste materials, including
26
spent nuclear fuel. Such Act requires the owner of nuclear facilities to enter
into disposal contracts with DOE for such material. These contracts require each
such owner to pay a fee which is currently one dollar per MWh for the net
electricity generated and sold by each of its reactors. (See "GENERATING
FACILITIES--Fuel Supply".)
For information concerning nuclear insurance, see Note 8 of Notes to
Financial Statements in Item 8. For information regarding NRC's regulation
relating to decommissioning of nuclear facilities and regarding DOE's
assessments pursuant to the Energy Policy Act for decontamination and
decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to
Financial Statements in Item 8.
Other Environmental Regulation
In 1993, EPA issued a ruling confirming the non-hazardous status of
coal ash. That ruling may apply, however, only to situations where those wastes
are not co-managed, i.e. not mixed with other wastes. Pursuant to court order,
EPA has until 1998 to classify co-managed utility wastes as either hazardous or
non-hazardous. If the wastes are classified as hazardous, substantial additional
costs for the management of such wastes might be required, although the full
impact would depend on the subsequent development of requirements pertaining to
these wastes.
Oglethorpe is subject to other environmental statutes including, but
not limited to, the Toxic Substances Control Act ("TSCA"), the Resource
Conservation & Recovery Act ("RCRA"), the Endangered Species Act ("ESA"), the
Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"),
the Emergency Planning and Community Right to Know Act, and to the regulations
implementing these statutes. Oglethorpe does not believe that compliance with
these statutes and regulations will have a material impact on its operations.
Changes to any of these laws, however, could affect many areas of Oglethorpe's
operations. Congress is considering amending the ESA and reauthorizing CERCLA,
TSCA and perhaps RCRA. Although compliance with new environmental legislation
could have a significant impact on Oglethorpe, those impacts cannot be fully
determined at this time and would depend in part on the final legislation and
the development of implementing regulations.
The scientific community, regulatory agencies and the electric utility
industry are continuing to examine the issues of global warming and the possible
health effects of electromagnetic fields. While no definitive scientific
conclusions have been reached regarding these issues, it is possible that new
laws or regulations pertaining to these matters could increase the capital and
operating costs of electric utilities, including Oglethorpe or entities from
which Oglethorpe purchases power. In addition, the potential for liability
exists from lawsuits alleging damages from electromagnetic fields.
Energy Policy Act
The Energy Policy Act allows for increased competition among wholesale
electric suppliers and increased access to transmission and generation facilities.
24
ITEM 2. PROPERTIES
Information with respectservices by such
suppliers. It created a new class of utilities called Exempt Wholesale
Generators ("EWGs"), which are exempt from certain restrictions otherwise
imposed by the Public Utility Holding Company Act. The effect of this exemption
is to Oglethorpe's properties is set forthfacilitate the development of independent third-party generators
potentially available to satisfy utilities' needs for increased power supplies.
Unlike purchases from qualifying facilities under the caption "THEPURPA (see "MEMBER
REQUIREMENTS AND POWER SUPPLY SYSTEM" includedRESOURCES--Power Purchase and Sales
Arrangements--Other Power Purchases" in Item 1), utilities have no statutory
obligation to purchase power from EWGs. Furthermore, EWGs are precluded from
making direct sales to retail electricity customers.
The Energy Policy Act also broadened the authority of FERC to require a
utility to transmit power to or on behalf of other participants in the electric
utility industry, including EWGs and qualifying facilities, but FERC is
precluded from requiring a utility to transmit power from another entity
directly to a retail customer. In 1996,
27
FERC issued two final rules (Orders 888 and 889) and a notice of proposed
rulemaking regarding capacity reservation tariffs that would make significant
changes in the form of transmission services performed by public utilities
subject to FERC's jurisdiction. See "OGLETHORPE POWER CORPORATION--Relationship
with GTC" in Item 1 and is incorporated
herein by reference.
ITEMfor information regarding GTC's transmission tariff.
28
Item 3. LEGAL PROCEEDINGS
Oglethorpe is a party to various 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.
ITEMItem 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
2529
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Not applicable.
ITEM 6. SELECTED FINANCIAL DATA
...............................................................................................................
(dollars in thousands)
1996 1995 1994 1993 1992 1991
OPERATING REVENUES:Operating revenues:
Sales to Members ..................................... $ 1,023,094 $ 1,030,797 $ 930,875 $ 899,720 $ 816,000
$ 763,657
Sales to non-Members.............non-Members ................. 78,343 118,764 125,207 200,940 268,763
300,293
----------- ----------- ----------- ----------- ----------------------- ------------ ------------ ------------ ------------
Total operating revenues ..................... 1,101,437 1,149,561 1,056,082 1,100,660 1,084,763
1,063,950
----------- ----------- ----------- ----------- -----------
OPERATING EXPENSES:
Fuel.............................------------ ------------ ------------ ------------ ------------
Operating expenses:
Fuel ................................. 206,524 219,062 203,444 176,342 167,288
165,168
Production.......................Production .............................. 129,178 133,858 132,723 129,972 115,915
130,041
Purchased power..................power ......................... 229,089 264,844 227,477 271,970 230,510
229,898
Depreciation and
amortization....amortization ............................ 163,130 139,024 131,056 128,060 126,047
135,152
Taxes............................Taxes ................................... 30,262 27,561 24,741 25,148 19,634
42,422
Other operating expenses.........expenses ................ 60,505 56,535 49,234 44,876 50,578
49,373
----------- ----------- ----------- ----------- ----------------------- ------------ ------------ ------------ ------------
Total operating expenses.........expenses ................ 818,688 840,884 768,675 776,368 709,972
752,054
----------- ----------- ----------- ----------- -----------
OPERATING MARGIN...................------------ ------------ ------------ ------------ ------------
Operating margin ........................ 282,749 308,677 287,407 324,292 374,791
311,896
OTHER INCOME, NET..................Other income, net ....................... 65,334 33,710 40,795 38,741 45,928
113,441
NET INTEREST CHARGES...............Net interest charges .................... (326,331) (320,129) (305,120) (350,652) (393,247)
(396,892)
----------- ----------- ----------- ----------- -----------
MARGIN BEFORE CUMULATIVE EFFECT OF
CHANGE IN ACCOUNTING PRINCIPLE...Margin before cumulative effect of change
in accounting principle ............. 21,752 22,258 23,082 12,381 27,472
28,445
CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING FOR INCOME TAXES......Cumulative effect of change in accounting
for income taxes .................... -- -- -- 13,340 --
--
----------- ----------- ----------- ----------- -----------
NET MARGIN.........................------------ ------------ ------------ ------------ ------------
Net margin .............................. $ 21,752 $ 22,258 $ 23,082 $ 25,721 $ 27,472
============ ============ ============ ============ ============
Electric plant, net:
In service ........................... $ 28,445
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
ELECTRIC PLANT, NET:
In service.......................4,345,200 $ 4,436,009 $ 3,980,439 $ 4,054,956 $ 4,122,411
$ 4,196,966
Construction work in progress....progress ........... 31,181 35,753 538,789 450,965 322,628
178,980
----------- ----------- ----------- ----------- ----------------------- ------------ ------------ ------------ ------------
$ 4,376,381 $ 4,471,762 $ 4,519,228 $ 4,505,921 $ 4,445,039
============ ============ ============ ============ ============
Total assets ............................ $ 4,375,946
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
TOTAL ASSETS.......................5,362,175 $ 5,438,5365,438,496 $ 5,346,330 $ 5,323,890 $ 5,359,597
============ ============ ============ ============ ============
Capitalization:
Long-term debt ....................... $ 5,246,435
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
CAPITALIZATION:
Long-term debt...................4,052,470 $ 4,207,320 $ 4,128,080 $ 4,058,251 $ 4,095,796
$ 4,093,218
Obligation under capital leases..leases ......... 293,682 296,478 303,749 303,458 302,061
300,833Other obligations .................... 41,685 -- -- -- --
Patronage capital and membership fees............................fees 356,229 338,891 309,496 289,982 264,261
236,789
----------- ----------- ----------- ----------- ----------------------- ------------ ------------ ------------ ------------
$ 4,744,066 $ 4,842,689 $ 4,741,325 $ 4,651,691 $ 4,662,118
============ ============ ============ ============ ============
Property additions ...................... $ 4,630,840
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
PROPERTY ADDITIONS.................93,704 $ 138,921 $ 206,345 $ 235,285 $ 232,283
$ 225,021
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
ENERGY SUPPLY (MEGAWATT-HOURS)============ ============ ============ ============ ============
Energy supply (megawatt-hours):
Generated........................Generated ............................ 17,866,143 18,402,839 16,924,038 14,575,920 13,805,683
12,686,323
Purchased........................Purchased ............................... 6,606,931 5,738,634 4,381,087 7,620,815 6,233,262
6,915,758
----------- ----------- ----------- ----------- ----------------------- ------------ ------------ ------------ ------------
Available for sale...............sale ...................... 24,473,074 24,141,473 21,305,125 22,196,735 20,038,945
19,602,081
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
MEMBER REVENUE PER KWH SOLD........ 5.53CENTS 5.65CENTS 5.47CENTS 5.55CENTS 5.36CENTS
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------============ ============ ============ ============ ============
Member revenue per kWh sold ............. 5.11(cent) 5.53(cent) 5.65(cent) 5.47(cent) 5.55(cent)
============ ============ ============ ============ ============
26
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
GENERAL
MARGINS AND PATRONAGE CAPITALCorporate Restructuring
Oglethorpe and the Members completed a corporate restructuring (the
Corporate Restructuring) on March 11, 1997 (the Closing) pursuant to terms and
conditions set forth in the Second Amended and Restated Restructuring Agreement
(the Restructuring Agreement). Pursuant to the Corporate Restructuring,
Oglethorpe divided itself into three specialized operating companies to respond
to increasing competition and regulatory changes in the electric industry. As
part of the Corporate Restructuring, the transmission business is now owned and
operated by a newly formed Georgia electric membership corporation, Georgia
Transmission Corporation (An Electric Membership Corporation) (GTC), and the
system operations business is now owned and operated by a newly formed Georgia
nonprofit corporation, Georgia System Operations Corporation (GSOC). Oglethorpe
continues to own and operate the power supply business.
On October 1, 1996, Oglethorpe transferred to GSOC its system operations
assets, consisting of its system control center and related energy control and
revenue metering systems equipment. The purchase price of these assets totaled
approximately $9.4 million and was funded by GSOC's assumption of Oglethorpe's
obligations under an existing note held by the Rural Utilities Service (RUS), by
delivery of a purchase money note payable to Oglethorpe and by the assumption of
certain other liabilities of Oglethorpe. Since October 1, 1996, Oglethorpe has
been the sole member of GSOC. The Members and GTC became members of GSOC on the
Closing. GSOC will operate the system control center and provide system
operations services to the Members, Oglethorpe and GTC.
At the Closing, Oglethorpe transferred its transmission business and assets
to GTC. The purchase price for the transmission business was based on an
appraisal of the fair market value of such business, as determined by an
independent appraiser, and was approximately $708 million. The purchase price
was paid primarily by GTC's assumption of a portion (approximately 16.86%) of
Oglethorpe's long-term secured debt in an amount equal to approximately $686
million. Approximately $541 million of this debt (payable to RUS, Federal
Financing Bank (FFB) and CoBank, ACB (CoBank)) became the sole obligation of
GTC, and Oglethorpe was released from all liability with regard to this
indebtedness. The remaining debt assumed by GTC in connection with the Corporate
Restructuring, approximately $145 million, relates to Oglethorpe's pollution
control revenue bonds (PCBs). While GTC assumed and agreed to pay this $145
million of debt, Oglethorpe is not legally released from its liability for this
debt. The remainder of the purchase price was paid by GTC from cash obtained
through a borrowing from National Rural Utilities Cooperative Finance
Corporation (CFC) and the assumption of approximately $1 million of other
Oglethorpe liabilities. Oglethorpe also made a special patronage capital
distribution of approximately $49 million to the Members which was used by the
Members to establish equity in and to provide initial working capital to GTC.
Oglethorpe and the 39 Members are members of GTC. GTC now owns and operates the
transmission system and provides transmission services to the Members and
Oglethorpe. GTC has succeeded to all of Oglethorpe's rights and obligations with
respect to the Integrated Transmission System (ITS).
Oglethorpe continues to operate the power supply business. Oglethorpe
retained all of its owned and leased generation assets and has total assets of
approximately $4.7 billion and total long-term debt of approximately $3.9
billion. Oglethorpe also continues to administer its power purchase contracts
and provide marketing support functions to the Members.
In connection with the Corporate Restructuring, Oglethorpe, GTC, GSOC and
the Members entered into a Member Agreement (Member Agreement) which specifies
the form of the new wholesale power contracts (New Wholesale Power Contracts),
transmission agreements (Transmission Agreements) and system operations
contracts to be signed by the Members. The New Wholesale Power Contracts provide
that the Members are responsible, on a joint and several basis, for all of
Oglethorpe's obligations relating to its existing generation business. The
Transmission Agreements provide that the Members are responsible, on a joint and
several basis, for all of GTC's obligations with respect to its transmission
business.
Pursuant to the Member Agreement, in connection with the Closing, Oglethorpe
and each of the Members entered into New Wholesale Power Contracts which extend
through December 31, 2025. Under the New Wholesale Power Contracts, each Member
is assigned an agreed-upon fixed percentage capacity responsibility (PCR) for
all of Oglethorpe's existing resources. PCR responsibility for any future
resource will be assigned only to Members choosing to participate in that
resource. The New Wholesale Power Contracts permit each Member to take future
incremental power requirements either from Oglethorpe or other sources. Under
the New Wholesale Power Contracts, a Member is unconditionally obligated on an
express "take-or-pay" basis for a fixed allocation of Oglethorpe's costs for its
31
existing resources, as well as the costs with respect to any future resources in
which such Member elects to participate. The New Wholesale Power Contracts
specifically provide that the Member must make payments whether or not power is
delivered and whether or not a plant has been sold. Oglethorpe is obligated to
use its reasonable best efforts to operate, maintain and manage its resources in
accordance with prudent utility practices. The New Wholesale Power Contracts
provide that Oglethorpe will be responsible for power supply planning, resource
procurement and sales of capacity and energy for a Member unless the Member
notifies Oglethorpe that it does not want Oglethorpe to provide these services.
The New Wholesale Power Contracts provide that each Member will be jointly
and severally responsible for all costs and expenses of all existing resources
and any future resources (whether or not such Member has elected to participate
in such future resource) that have been approved by 75% of Oglethorpe's Board of
Directors and 75% of the Members. For resources so approved in which less than
all Members participate, costs of a defaulting Member are shared first among the
participating Members, and if all participating Members default, each
non-participating Member is expressly obligated to pay a proportionate share of
such default.
In connection with the implementation of new power marketer arrangements
with LG&E Power Marketing Inc. ("LPM"), Oglethorpe and each Member have entered
into supplemental agreements to the New Wholesale Power Contracts which relate
to certain provisions of the New Wholesale Power Contracts and apply during the
term of the power marketer arrangements. The supplemental agreements clarify the
application of the New Wholesale Power Contract rate schedule to the power
marketer agreements. The 75% requirement described above has been met with
respect to the LPM agreements. The supplemental agreement assures that all costs
incurred by Oglethorpe under the LPM agreement are recoverable under the New
Wholesale Power Contracts. As the expected additional power marketer
arrangements are finalized, additional supplemental agreements to the New
Wholesale Power Contracts will be entered into by Oglethorpe and the Members.
See "Results of Operations-Factors Affecting Future Financial Performance" for a
description of the power supply arrangements.
The rate set forth in the New Wholesale Power Contracts is intended to
recover all costs and expenses paid or incurred by Oglethorpe. The rate
expressly includes in the description of costs to be recovered all principal and
interest on indebtedness of Oglethorpe and all costs associated with
decommissioning or otherwise retiring any generating facility. The rate further
expressly provides for Oglethorpe to earn sufficient margins to satisfy the
requirements of the Master Indenture (defined below). The New Wholesale Power
Contracts contain covenants by the Member (i) to establish, maintain and collect
rates and charges for the service of its electric system and (ii) to conduct its
business in a manner that will produce revenues and receipts at least sufficient
to enable the Member to pay to Oglethorpe, when due, all amounts payable by the
Member under the New Wholesale Power Contracts and to pay any and all other
amounts payable from, or which might constitute a charge and a lien upon, the
revenues and receipts derived from its electric system, including all operation
and maintenance expenses and the principal of, premium (if any) and interest on
all indebtedness related to the Member's electric system.
The New Wholesale Power Contracts provide that a Member will not dissolve,
liquidate or otherwise wind up its affairs without Oglethorpe's approval. The
Member will not consolidate or merge with any person or reorganize or change the
form of its business organization from an electric membership corporation or
sell, transfer, lease or otherwise dispose of all of its assets to any person,
whether in a single transaction or series of transactions, unless either (i) the
transaction is approved by Oglethorpe or (ii) other specified conditions are
satisfied including, but not limited to, an assumption agreement by the
transferee, satisfactory to Oglethorpe, containing an assumption by the
transferee of the performance and observance of every covenant and condition of
the Member under the New Wholesale Power Contract, and certifications of
accountants as to certain specified financial requirements of the transferee
(taking into account the transfer).
Effective with the Corporate Restructuring, Oglethorpe amended its Bylaws to
implement a new governance structure with an 11-member board of directors
consisting of six directors elected from the Members, four independent outside
directors and Oglethorpe's President and Chief Executive Officer. This smaller
board replaced Oglethorpe's former 39-member board comprised of directors
nominated from and by each Member. The new directors will be nominated by
representatives from each Member on a weighted-voting method, based on the
number of retail customers served by such Member. However, each director will
continue to be elected by a vote of the Member representatives on a one-Member,
one-vote basis. Except for two of the four outside directors, all of
Oglethorpe's new directors have been elected and began their terms at the
Closing. The remaining two outside directors are expected to be elected on March
27, 1997.
Contemporaneously with the Corporate Restructuring, Oglethorpe replaced its
existing Consolidated Mortgage and Security Agreement, dated as of September 1,
1994, by and among Oglethorpe, as Mortgagor, the United States of
32
America, acting through the Administrator of the RUS and certain other
mortgagees (the RUS Mortgage) with the Indenture, dated as of March 1, 1997,
from Oglethorpe to SunTrust Bank, Atlanta, as trustee, (the Master Indenture)
providing for a lien on substantially all of the owned tangible and certain
intangible property of Oglethorpe. See "Rates and Financial Coverage
Requirements" below for a further description of the Master Indenture.
In conjunction with the Corporate Restructuring and as a part of its
continuing efforts to reduce costs, effective February 1, 1997, Oglethorpe
implemented a business alliance with Intellisource, Inc., a national provider of
outsourcing services. Pursuant to an agreement with Intellisource, approximately
150 support services division employees in the areas of accounting, auditing,
communications, human resources, facility management, purchasing,
telecommunications and information technology became employees of the
Intellisource organization. Oglethorpe, GTC and GSOC are key customers of
Intellisource and are being served on-site by the managers and employees of
Oglethorpe's former support services division.
Margins and Patronage Capital
Oglethorpe operates on a not-for-profit basis and, accordingly, seeks only
to generate revenues sufficient to recover its cost of service and to generate
margins sufficient to establish reasonable reserves and meet certain financial
coverage requirements. Revenues in excess of current period costs in any year
are designated in Oglethorpe's statements of revenues and expenses and patronage
capital as net margin. Retained net margins are designated on Oglethorpe's
balance sheets as patronage capital, which is allocated to each of the Members
on the basis of its electricity purchases from Oglethorpe. Since its formation
in 1974, Oglethorpe has generated a positive net margin in each year and had a
balance of $356 million in patronage capital as of December 31, 1996.
Oglethorpe's equity ratio (patronage capital and membership fees divided by
total capitalization) increased from 7.0% at December 31, 1995 had a balance
of $339 million in patronage capital.to 7.5% at
December 31, 1996.
Patronage capital constitutes the principal equity of Oglethorpe. Under
Oglethorpe's patronage capital retirement policy, margins are to be returned to
the Members 30 years after the year in which the margins are earned. Pursuant to
such policy, no patronage capital would be retired until 2010, at which time the
1979 patronage capital would be returned. (See "Proposed Restructuring"
below regarding a special patronage capital distribution contemplated in
connection with the proposed restructuring.) Any distributions of patronage capital
are subject to the discretion of the Board of Directors andDirectors. See "Corporate
Restructuring" above regarding a special patronage capital distribution made in
connection with the Corporate Restructuring.
Now that the Master Indenture has been substituted for the prior RUS
Mortgage, distributions of patronage capital are no longer subject to the
approval byof RUS, but are subject to certain restrictions set forth in the Rural Utilities Service (RUS), formerly known asMaster
Indenture. Under the Rural
Electrification Administration (REA).Master Indenture, Oglethorpe is prohibited from making any
distribution of patronage capital to the Members if, at the time thereof or
after giving effect thereto, (i) an event of default exists under the Master
Indenture, (ii) Oglethorpe's equity ratio (patronage capitalas of the end of the immediately preceding
fiscal quarter is less than 20% of Oglethorpe's total capitalization, or (iii)
the aggregate amount expended for distributions on or after the date on which
Oglethorpe's equity first reaches 20% of Oglethorpe's total capitalization
exceeds 35% of Oglethorpe's aggregate net margins earned after such date. This
last restriction, however, will not apply if, after giving effect of such
distribution, Oglethorpe's equity as of the end of the immediately preceding
fiscal quarter is not less than 30% of Oglethorpe's total capitalization.
Rates and membership fees divided
by total capitalization) increased from 6.5% at December 31, 1994 to 7.0% at
December 31, 1995.
RATES AND FINANCIAL COVERAGE REQUIREMENTS
Oglethorpe has entered into an "all-requirements" wholesale power
contract with each of its Members.Financial Coverage Requirements
Pursuant to such contracts,the New Wholesale Power Contract, Oglethorpe is required to
design capacity and energy rates that generate sufficient revenues to recover
all costs as described in such contracts, and to establish and maintain reasonable
margins.margins and to meet its financial coverage requirements. Oglethorpe reviews its
capacity rates at least annually to ensure that its fixed costs are being
adequately recovered and, if necessary, adjusts its rates to meet its net margin
goals. Oglethorpe's energy rate is set annually and adjusted at mid-yearestablished to recover actual fuel and
variable operations and maintenance costs. RateUnder the terms of Oglethorpe's prior
RUS Mortgage, rate revisions by Oglethorpe arewere subject to the approval of RUS.
Under the Master Indenture, Oglethorpe's rates are not subject to RUS and, to date, the RUS has
not reduced or delayed the effectiveness of any rate increase proposed by
Oglethorpe.approval
except in limited circumstances.
The capacity rate whichapplied by Oglethorpe used in 1993 and 1994 was based onutilized a proportional
allocation of fixed costs overbased on the previous year's billing demand for each
Member. Consequently, the 1994 rate produced capacity revenues (which included the recovery of margins) which were constant throughout the
year and were
virtually unaffected by current year factors. In 1995, Oglethorpe implemented
two additional capacity rate options in an effort to provide greater flexibility
to the Members. These options allocated fixed costs using billing determinants
of the current year. These rates produced differing monthly amounts of capacity
revenues throughout the year and introduced some variability and uncertainty as
to the level of revenues and margins to be received. Due to extreme weather
conditions and other factors, the new1995 rates options produced $2.5 million of
revenues in excess of budgeted amounts. Such excess amounts will bewere returned to the
Members in 1996.
Under an interima capacity rate mechanism effective from January 1, 1996 to April
30,throughout 1996, each Member haswas
responsible for
33
an assigned share of responsibility for fixed costs based on an agreed-upon allocation. Under this
approach, capacity costs will
bewere collected in equal monthly amounts. In connection with the approval on
March 29, 1996 of a Restructuring Agreement (discussed below under "Proposed
Restructuring"), Oglethorpe's Board extended theThis interim
rate mechanism has now been extended through the end of 1996, subject to rate changes that might be adopted in
connection with a new long-term power supply arrangement (discussed below
under "Results of Operations--FACTORS AFFECTING FUTURE FINANCIAL
PERFORMANCE"). The Restructuring Agreement contemplates that aMarch 31, 1997. A new rate schedule
would bewill become effective for 1997 which would implementunder the New Wholesale Power Contracts on April 1, 1997.
This new rate schedule implements on a long-term basis the assignment of
responsibility for fixed costscosts. The monthly charges for capacity and other
non-energy charges are based on historical
demand factors. In 1996, management expects a net increase inrate formula using the Oglethorpe 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 are based on actual energy costs. However, under the supplemental
agreements for the LPM agreements, each Member pays a fixed rate for energy,
plus certain adjustments, while LPM pays all energy costs, duewithin certain risk
bands. The new rate schedule also includes a prior period adjustment (PPA)
mechanism. The PPA serves to absorbing a full year's costsfacilitate the achievement of the Rocky Mountain pumped storage
hydroelectric facility (Rocky Mountain); however, becauseminimum 1.10 MFI
ratio, and it provides for the retention of anticipated
increasesmargins within a range from a 1.10
MFI ratio to a 1.20 MFI ratio. Amounts, if any, by which Oglethorpe fails to
achieve a minimum 1.10 MFI ratio would be accrued as of December 31 of the
applicable year and collected during the period April through December of the
following year. Amounts, if any, earned by Oglethorpe in energy salesexcess of a 1.20 MFI
ratio would be charged against revenues as of December 31 of the applicable year
and decreases in energy costs, average Member
revenues (measured in cents per kilowatt-hour (kWh)) should remain at or nearrefunded during the 1995 level.period April through December of the following year.
Under the prior RUS Mortgage, Oglethorpe utilizesutilized a Times Interest Earned
Ratio (TIER) as the basis for establishing its annual net margin goal. TIER is
determined by dividing the sum of Oglethorpe's net margin plus interest on
long-term debt (including interest charged to construction) by Oglethorpe's
interest on long-term debt (including interest charged to construction). The RUS
Mortgage requiresrequired Oglethorpe to implement rates that are designed to maintain an
annual TIER of not less than 1.05. Oglethorpe's Board of Directors set an annual
net margin goal to be the amount required to produce a TIER of 1.07 in 19931994
through 1995. The net margin goal for 1996 is also a 1.07 TIER.1996.
In addition to the TIER requirement under the RUS Mortgage, Oglethorpe iswas
also required under the RUS Mortgage to implement rates designed to maintain a
Debt Service Coverage Ratio (DSC) of not less than 1.0 and an Annual Debt
Service Coverage Ratio (ADSCR) of not less than 1.25. By paying in full or
defeasing certain outstanding pollution control revenue bonds (PCBs),
Oglethorpe could reduce the ADSCR requirement to 1.15. DSC is determined by
dividing the sum of Oglethorpe's net margin plus interest on long-term debt
(including interest charged to construction) plus depreciation and amortization
(excluding amortization of nuclear fuel and debt discount and expense) by
Oglethorpe's interest and principal payable on long-term debt
27
(including
interest charged to construction). ADSCR is determined by dividing the sum of
Oglethorpe's net margin plus interest on long-term debt (excluding interest
charged to construction) plus depreciation and amortization (excluding
amortization of nuclear fuel and debt discount and expense) by Oglethorpe's
interest and principal payable on long-term debt secured under the RUS Mortgage
(excluding interest charged to construction).
Oglethorpe has always met or exceeded the TIER, DSC and ADSCR requirements of
the RUS Mortgage. TIER, DSC and ADSCR for the years 19931994 through 19951996 were as
follows:
1995 1994 1993
---- ---- ----
TIER 1.07 1.07 1.07
DSC 1.21 1.19 1.23
ADSCR 1.27 1.25 1.26
Historically,- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
TIER 1.07 1.07 1.07
DSC 1.25 1.21 1.19
ADSCR 1.32 1.27 1.25
- --------------------------------------------------------------------------------
Under the Master Indenture, Oglethorpe is required to establish and collect
rates which are reasonably expected, together with other revenues of Oglethorpe,
to yield a Margins for Interest (MFI) for each fiscal year equal to at least
1.10 times total interest charges during such fiscal year on all indebtedness
secured under the Master Indenture (or by setting ratesa lien equal or prior to meet the TIER goals established by
Oglethorpe's Board, the DSC and ADSCR requirementslien of
the RUS Mortgage have
always been met or exceeded. BasedMaster Indenture), excluding indebtedness assumed by GTC. MFI is determined
by adding (i) Oglethorpe's net margins (after certain defined adjustments), (ii)
interest charges on Oglethorpe's current financial
projections, however, TIER levelsindebtedness secured under the current Board policy may not
produce rates sufficientMaster Indenture (or by lien
equal to meetor prior to the current ADSCRlien of the Master Indenture), and (iii) any amount
included in net margins for accruals for federal or state income taxes. The
definition of MFI takes into account any item of net margin, loss, gain or
expenditure of any affiliate or subsidiary of Oglethorpe only if Oglethorpe has
received such net margins or gains as a dividend or other distribution or if
Oglethorpe has made a payment with respect to such losses or expenditures.
The MFI ratio requirement inwent into effect upon the near
future. In that event, Oglethorpesubstitution of the
Master Indenture for the prior RUS Mortgage. For comparative purposes only, the
pro-forma MFI ratio for 1996 would have to set rates to meet the
current ADSCR requirement or take action to lower the ADSCR requirement by
prepaying or defeasing certain PCBs as described above.
MISCELLANEOUS
As with utilities generally, inflation has the effect of increasing the
cost of Oglethorpe's operations and construction program. Operating and
construction costs have been less affected by inflation over the last few
years because rates of inflation have been relatively low.1.09.
Miscellaneous
Currently, Oglethorpe is subject to the provisions of Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain Types of
Regulation". Oglethorpe has recorded regulatory assets and liabilities related
to its generation and transmission operations. In the event that Oglethorpe is
no longer subject to the provisions of Statement No. 71, Oglethorpe would be
required to write off related regulatory assets and liabilities. In addition,
Oglethorpe would be required to determine any impairment of other assets,
including utility plant, and
34
write down the plant assets, if impaired, to their fair value. See Note 1 of
Notes to Financial Statements for additional information.
The staff of the Securities and Exchange Commission has questioned certain
of the current accounting practices of the electric utility industry regarding
the recognition, measurement and classification of decommissioning costs for
nuclear generating facilities in financial statements of electric utilities. In
response to these questions, the Financial Accounting Standards Board has issued
an Exposure Draft of a proposed Statement on "Accounting for Certain Liabilities
Related to Closure or Removal of Long-Lived Assets". The proposed Statement
would require the recognition of the entire obligation for decommissioning at
its present value as a liability in the financial statements. Rate-regulated
utilities would also recognize a
regulatoryan offsetting asset for differences in the timing
of recognition of the costs of decommissioning for financial reporting and
rate-making purposes. Oglethorpe's management does not believe that this
proposed Statement would have an adverse effect on results of operations due to
its current and future ability to recover decommissioning costs through rates.
Beginning in years 2014 through 2029, it is expected that Plant Hatch and
Vogtle units will begin the decommissioning process. The expected timing of
payments for decommissioning costs will extend for a period of 9 to 14 years.
Oglethorpe's management does not expect such payments to have an adverse impact
on liquidity or capital resources.resources due to available amounts which have been set
aside in reserves for this purpose.
RESULTS OF OPERATIONS
HISTORICAL FACTORS AFFECTING FINANCIAL PERFORMANCEHistorical Factors Affecting Financial Performance
Over the past three years, Oglethorpe's Members have absorbed into rates
additional responsibility for the cost of its ownership interests in Plant
Scherer Unit No. 2 and Plant Vogtle Units No. 1 and No. 2. These generating units were placed in commercial
operation in 1984, 1987 and 1989, respectively. Oglethorpe has utilized both long-term
contractual arrangements with Georgia Power Company (GPC)GPC and margin and rates mechanismsa rate mechanism to allow for a gradual
absorption of costs over several years. In addition, Oglethorpe is utilizing margin and rates mechanismsutilized this
rate mechanism to mitigate the impact of absorbing the costs of the Rocky
Mountain Pumped Storage Hydroelectric Project (Rocky Mountain) which was placed
in service during June and July 1995.
Contractual arrangements with GPC provided that Oglethorpe sell to GPC
and GPC purchase from Oglethorpe a
declining percentage of Oglethorpe's entitlement to the capacity and energy of
certain co-owned generating plants during the initial seven to ten years of
operation of such units (GPC Sell-back). As of May 31, 1995, the GPC Sell-back
has expired for all units.
(See Note 1 of Notes to Financial Statements.) The historical ability of Oglethorpe to sell power
from new units to GPC under the GPC Sell-back enabled Oglethorpe to moderate the
effects of the higher costs associated with new generating units on Oglethorpe's
cost of service and, therefore, on the rates charged to Members. Furthermore,
the GPC Sell-back enabled Oglethorpe to obtain the generating capacity needed to
serve anticipated increases in Member loads while minimizing the risks and costs
of excess generating capacity.
Prior to the completion of the first unit of Plant Vogtle in 1987,
Oglethorpe's Board of Directors implemented policies that have resulted in the
gradual absorption of the costs of Plant Vogtle by the Members. In each of the
years 1985 through 1995, Oglethorpe exceeded its net margin goal. The Board
adopted resolutions in each of these years requiring that these excess margins
be retained and used to mitigate rate increases associated with Plant Vogtle
and, subsequently, with Rocky Mountain. In each year beginning with 1989, a
portion of these margins has beenwas returned to the Members through billing credits.
(See Note 1 of Notes to Financial Statements.) As of December 31, 1995, Oglethorpe held a balance of approximately $32 million
from deferred margins which will be utilized in 1996, forall
amounts previously retained have been returned to the Members and this rate
mitigation as
the annual costs of Rocky Mountain are absorbed.
28
OPERATING REVENUESmechanism ended.
Operating Revenues
Oglethorpe's operating revenues are derived from sales of electric services
to the Members and non-Members. Revenues from Members are collected pursuant to the
wholesale power contracts and are a function of the demand for power by the
Members' consumers and Oglethorpe's cost of service. Historically, most of
Oglethorpe's non-Member revenues have resulted from various plant operating
agreements with GPC as discussed below. However, in recent years, an increasing
amount of non-Member revenues has been derived by off-system sales to other
utilities and power marketers.
For the period 19931994 through 1995,1996, although total revenues have varied
slightly, the scheduled reduction of the GPC Sell-back has resulted in the
planned decrease of non-Member revenues from GPC of about $96$45 million. As
expected, the capacity and energy no longer being sold to GPC have been used by
Oglethorpe to meet increased Member requirements. In addition to increasing
sales to Members, Oglethorpe has increased revenues from energy
sales to other utilities and achieved reductions in fixed and operating costs in
order to mitigate the need to recover from the Members costs which were
previously recovered through sales to GPC. The refinancing transactions
discussed under "Financial Condition--REFINANCING TRANSACTIONS"Condition-Refinancing Transactions" below have
resulted in a reduction in gross interest charges from $367$330 million in 19931994 to
$318$308 million in 1995,1996, or a 13%7% decrease in that fixed cost component of the
capacity rates.
SALES TO MEMBERS.As a means of further reducing the cost of power provided to the Members,
Oglethorpe utilized short-term power supply arrangements during 1996. The
35
initial agreement was with Enron Power Marketing, Inc. (EPMI) and was in place
January through August. From September through December 1996, another power
supply arrangement was utilized with Duke/Louis Dreyfus L.L.C. (DLD). Under both
of the agreements, the power marketer was required to provide to Oglethorpe at a
favorable fixed rate all the energy needed to meet the Members' requirements and
Oglethorpe was required to provide to the power marketer at cost, subject to
certain limitations, upon request, all energy available from Oglethorpe's total
power resources. Under both agreements, Oglethorpe continued to operate the
power supply system and continued to dispatch the generating resources to ensure
system reliability.
Sales to Members. Revenues from sales to Members decreased by 0.7% in 1996
compared to 1995 and increased 10.7% in 1995 compared to 19941994. These changes
reflect both cost-related and increased 3.5% in 1994volume-related factors. The 1996 revenues
decreased compared to 1993. These increases
reflect two factors: (1) higher capacity revenues, offset by1995 due to the fact that the pass-through of savings in
energy costs (see the discussion of savings in purchased power under "Operating
Expenses" herein) more than offset higher capacity revenue requirements and the
effect of increased amounts of energy sold. The increase in revenues between
1995 and 1994 was due to the fact that higher capacity revenue requirements and
additional amounts of energy sold more than offset savings in energy costs (see
the discussion of savings in fuel and purchased power costs under "OPERATING EXPENSES""Operating
Expenses" herein), and (2) increased amounts of energy sold..
As non-Member revenues from GPC have declined, Oglethorpe's Member capacity
revenues are higher reflectinghave increased to reflect the recovery of the fixed costs which had
previously been recovered from GPC through the GPC Sell-back. (See the
discussion of this type of revenues under "Sales to non-Members" herein.) Member
capacity revenues in 1996 and 1995 were also affected by additional fixed costs
related to the commercial operation of Rocky Mountain beginning in June 1995.
Member energy revenues per kWhkilowatt-hour (kWh) declined 13.2% in 1996
compared to 1995 and declined 7.6% in 1995 compared to 1994 and
6.9%1994. The decrease in
1994 compared1996 resulted from savings of approximately $32 million in energy costs
(compared to 1993, reflectingbudget) achieved under the power supply arrangements. In 1995, the
decrease reflected savings in fuel and production costs. The 1995 decline in revenues per kWh also reflectscosts and lower average
purchased power costs. Actual energy costs are passed through to the Members
such that energy revenues equal energy costs.
The following table summarizes the amounts of kWh sold to Members during each of
the past three years:
(IN THOUSANDS) KILOWATT-HOURS
-------------------------------
1995 18,442,153
1994 16,285,127
1993 16,253,283
- --------------------------------------------------------------------------------
Kilowatt-hours
(in thousands)
- --------------------------------------------------------------------------------
1996 19,807,101
1995 18,442,153
1994 16,285,127
- --------------------------------------------------------------------------------
Member sales have been significantly affected by abnormal weather conditions
during two of the past three years. In 1995 and 1993, prolonged hot weather boosted sales,
while in 1994 record-breaking rainfall amounts statewide moderated Member sales.
Member sales increased 7.4% in 1996 despite a summer in which temperatures were
lower than 1995, due to continued growth in the Member systems' service
territories.
The net impact of the above capacity and energy rate factors, combined with
the spreading of fixed capacity costs over an increasing number of kWh sold each
year, have resulted in the following decreasing trend in average Member revenues:
CENTS PER KILOWATT-HOUR
-----------------------
1995 5.53 CENTS
1994 5.65
1993 5.47
SALES TO NON-MEMBERS.revenue
requirements:
- --------------------------------------------------------------------------------
Cents per Kilowatt-hour
- --------------------------------------------------------------------------------
1996 5.11(cent)
1995 5.53
1994 5.65
- --------------------------------------------------------------------------------
Sales to non-Members. Sales of electric services to non-Members are primarily
made pursuant to three different types of contractual arrangements with GPC and
from off-system sales to other non-Member utilities.
The following table summarizes the amounts of non-Member revenues from these
sources for the past three years:
(DOLLARS IN THOUSANDS) 1995 1994 1993
- -------------------------------------------------------------
Plant operating agreements $ 10,096 $ 45,392 $106,146
Power supply arrangements 43,226 26,280 44,904
Transmission agreements 12,614 10,974 15,763
Other utilities 52,828 42,561 34,127
-------- -------- --------
Total $118,764 $125,207 $200,940
- --------------------------------------------------------------------------------
1996 1995 1994
(dollars in thousands)
- --------------------------------------------------------------------------------
GPC-plant operating agreements $ -- $ 10,096 $ 45,392
GPC-power supply arrangements 13,703 43,226 26,280
ITS transmission agreements 9,789 12,614 10,974
Sales to power marketers 15,895 -- --
Sales to other utilities 38,956 52,828 42,561
------- -------- --------
Total $78,343 $118,764 $125,207
======= ======== ========
- --------------------------------------------------------------------------------
Revenues from sales to non-Members declined in 1996 compared to 1995 and in
1995 compared to 1994 and
in 1994 compared to 1993. These decreases1994. The first two types of non-Member revenues were primarily attributable to
scheduled reductions inderived
from contractual agreements with GPC. First, the elimination of the revenues
from the plant operating agreement revenues attributableagreements was due to the scheduled conclusion,
effective June 1, 1995, of the GPC Sell-back with respect to Plants Vogtle and Scherer.Plant Vogtle.
The second source of non-Member revenues is
36
power supply arrangements with GPC. These revenues are derived, for the most
part, from energy sales arising from dispatch situations whereby GPC causes
co-owned coal-fired generating resources to be operated when Oglethorpe's system
does not require all of its contractual entitlement to the generation. These
revenues essentially represent reimbursement of costs to Oglethorpe because,
under the operating agreements, Oglethorpe is responsible for its share of fuel
costs any time a unit operates. Revenues from sales of this type to GPC were
lower in 1996 compared to 1995 and were higher in 1995 compared to 1994 and lower1994. In
1996, the power marketers elected to retain more of the output from Plant
Wansley, whereas, in 1994 compared to 1993. In 1995, Oglethorpe retained less of its share of the output
from Plant Wansley units because the added cost associated with emission
allowances made those units less attractive than certain purchased resources.
The lower 1994 revenues were due toreflect the fact that Oglethorpe retained much of its share of
the output from the Plant Scherer and Plant Wansley units because the lower
average fuel costs made those units more attractive than certain purchased
resources. Emission allowances for Plant Wansley were not required in 1994. See
the discussion under "OPERATING EXPENSES""Operating Expenses" herein of the lower average fuel costs
of the coal-fired generating units in 19951996 and 1994.1995. Pursuant to the amendments
to the Plant Scherer ownership and operating agreements, Oglethorpe elected to
separately dispatch its ownership interest in Plant Scherer beginning May 1,
1994. Thereafter, Plant Scherer ceased to be a source of the above
"automatic"this type of sales
transaction; however, Oglethorpe did continuetransaction. Pursuant to make other sales to GPC from Plant Scherer in this
29
category. Once thesimilar amendments to the Plant Wansley operating
agreement, become effective, Oglethorpe will commence separate dispatch ofexpects to begin separately dispatching its ownership
interest in that Plant.Plant Wansley this year.
The third source of non-Member revenues is primarily payments from GPC for
use of the Integrated Transmission System (ITS)ITS and related transmission interfaces. GPC compensates Oglethorpe
to the extent that Oglethorpe's percentage of investment in the ITS exceeds its
percentage use of the system. In such case, Oglethorpe is entitled to
income as compensation for the use of its investment by the other ITS participants. The
change in revenues for 19951996 through 19931994 resulted from normal variations of
Oglethorpe's investment percentages and its use of the system.
RevenuesUnder the EPMI and DLD power supply agreements, sales to the power marketers
represented the net energy transmitted off-system on behalf of EPMI and DLD on a
daily basis from Oglethorpe's total resources. Such energy was sold to EPMI and
DLD at Oglethorpe's cost, subject to certain limitations. Sales to other
non-Member utilities increased substantially due to a
22% increasewere initiated by EPMI and DLD in kWh sales1996 while in 1995 as comparedand
1994 these sales were made by Oglethorpe directly with the non-Member utilities.
While Oglethorpe maintains the contractual relationship with these other
utilities and administers the transactions, all profits in 1996 on these sales
to 1994other utilities from Oglethorpe's total resources accrued to EPMI and a 28% increase in kWh
sales in 1994 as compared to 1993. Oglethorpe is continuing to aggressively
seek additional off-system sales opportunities as a means of reducing amounts
that must be recovered from Members.DLD.
See "FACTORS AFFECTING FUTURE FINANCIAL
PERFORMANCE""Factors Affecting Future Financial Performance" herein regarding
Oglethorpe's 1996 short-term power swap
arrangement which committed Oglethorpe's total power resources under a single
contractual arrangement, and regarding Oglethorpe's consideration of a similarnew long-term power supply swap arrangement for a longer term basis.
OPERATING EXPENSESarrangements.
Operating Expenses
Oglethorpe's operating expenses decreased 2.6% in 1996 compared to 1995 and
increased 9.4% in 1995 compared to 1994
and decreased 1.0%1994. The decrease in 1994operating expenses in
1996 compared to 1993.1995 was primarily attributable to energy cost savings achieved
under the short-term power supply arrangements offset somewhat by an increase in
depreciation and amortization. The increase in operating expenses in 1995
compared to 1994 was primarily attributable to a 13.0%13% increase in kWhkWhs sold to
Members and non-Members. In addition, depreciation and amortization, sales, and
administrative and general expenses were also higher.
The slight decrease in operating expensestotal fuel costs in 19941996 as compared to 1993
was largely due to the decline in purchased power expenses offset somewhat by
the increase in fuel expenses. The total kWh of energy supplied through
generation and purchased power in 1994 was 4% less than 1993.
Generally, over the years 1993 through 1995 the Members have received
the benefit of declining per unit fuel costs of Oglethorpe's generating
resources through the pass-through of lower energy costs. The per unit fuel
costs of Oglethorpe's nuclear and fossil generating resources for the last
three years are as follows:
CENTS PER KILOWATT-HOUR
-------------------------
NUCLEAR FOSSIL
---------- ----------
1995 0.59 CENTS 1.74 CENTS
1994 0.64 1.78
1993 0.61 1.96
Oglethorpe began receiving shipmentsresulted partly
from unplanned outages at Plant Scherer of lower-priced
coaland Plant Wansley Unit No. 1 and partly
from the mining regions ofpower marketer electing to dispatch the western United Statesfossil units less. These
factors resulted in the last quarter
of 1993.3.1% lower fossil generation in 1996 compared to 1995. The
increase in total fuel costs in 1995 versus 1994 resulted from 23% higher
generation at Plant Scherer. The continued use of lower-priced western coal
combined with a greater reliance on a favorable spot market for coal resulted in
a per unit fuel cost decrease for Plant Scherer of 13%5% in 1995 from 19931994 levels.
Because of the decline in fuel cost per kWh at Plant Scherer, the usage of the
units increased significantly. Output from Plant Scherer was 23% higher in 1995
compared to 1994 and 75% higher in 1994 compared to 1993. Oglethorpe retained significantly less of its
output from Plant Wansley in 1995 compared to 1994 primarily as a result of
relatively higher costs associated with the emission
allowances requirement. In 1994 compared to 1993, the per unit fuelPlant Scherer due to its emission allowance
requirement and due to cost reductions at Plant Wansley decreased by almost 10% and thus, Oglethorpe retained more of
its output. The decrease in per unit fuel costs resulted from a greater
reliance on a favorable spot market for coals.Scherer discussed above.
Purchased power cost decreased by 14% in 1996 compared to 1995 and increased
by 16% in 1995 compared to 19941994. Lower purchased power costs were achieved in
1996 despite the fact that energy purchases increased 15% in 1996 from 1995
levels. The 1996 cost reduction was due to (1) energy cost savings of $32
million realized from the short-term power supply arrangements and decreased 16%(2)
reductions in 1994 comparedpurchased power capacity costs due to 1993.(a) proceeds of $10.8
million from the settlement of a lawsuit with GPC and (b) savings resulting from
the elimination of a 250 MW Component Block (coal-fired units) of the Block
Power Sale Agreement (BPSA) effective September 1, 1996. In 1995, the 13% higher
kWh sales, including the increased Member sales and sales to GPC pursuant to
power supply arrangementarrangements (see the discussion under "OPERATING REVENUES""Operating Revenues" herein)
37
resulted in higher utilization of purchased power resources. Energy purchases
increased 31% in 1995 compared to 1994.
The significant increase in 1994 in coal-fired generation (prompted by
declining average fuel costs) as well as declining sales from these
coal-fired resources to GPC pursuant to power supply arrangement resulted in
substantially lower utilization of purchased power resources. Energy
purchases decreased by approximately 43% from 1993 levels.
Purchased power expense for 19931994 through 19951996 reflect the cost of capacity
and energy purchases under various long-term power purchase agreements. These
long-term agreements have, in some cases, take-or-pay minimum energy
requirements. For 19931994 through 1995,1996, Oglethorpe utilized its energy from these
purchase power agreements in excess of the take-or-pay requirements.
Oglethorpe's power purchases from these agreements amounted to approximately
$196 million in 1996, $207 million in 1995 $182and $183 million in 1994 and $192 million in
1993.1994. For a
discussion of the power purchase agreements, see Note 9 of Notes to Financial
Statements.
The increase in depreciation and amortization in 19951996 is partly due to thea
full year of depreciation on Rocky Mountain which began commercial operation in
June 1995 and due to $14 million of Rocky MountainBoard- approved accelerated amortization of
deferred charges of the discontinued Pickens County pumped storage hydroelectric
project. All remaining unamortized charges related to this project were expensed
in June.1996.
Sales, administrative and general expenses increased in 1995 as compared to
1994 primarily as
a result ofresulting from increased marketing efforts in support of Oglethorpe'sthe
Members.
OTHER INCOMEOther Income/Expense
Interest income increased in 1996 compared to 1995 and 1995 compared to
19941994. In 1996, interest income was higher due to higher earnings
fromaverage investment
balances. In 1995, interest income increased partly due to higher short-term
interest rates and due to higher investment returns in the decommissioning trust
fund.
In 1996, Oglethorpe utilized all remaining amounts available ($32 million)
under its deferred margin rate mechanism, and, as scheduled, this mechanism
ended. Likewise, deferred margins of $16 million and $18 million were amortized
as credits against Member revenue requirements in 1995 and 1994, interest income decreased
comparedrespectively,
to 1993 as a resultmitigate the rate impact of lower average investment balances.
Inincreased capacity costs related to Plant Vogtle
and Rocky Mountain. Also, in 1995 1994 and 1993,1994, Oglethorpe's Board of Directors
authorized the retention of approximately $14 million $9 million and $5$9 million,
respectively, in excess of the 1.07 TIER margin requirement as deferred margins. The remaining amount at December 31, 1995 of $32 million will be
available in 1996 to mitigate rate increases. Amortization of deferred
margins
for 1995 was $16 million, slightly less thanunder the amount utilized in
1994 but significantly more than the amount utilized in 1993.mechanism. (See Note 1 of Notes to Financial Statements for a
discussion of deferred margins and amortization of deferred margins.) The
decrease in 30
amortization of deferred gains in 1996 and 1995 as compared to 1994
resulted from the completion of amortization in September 1994 of a gain on the
sale of Plant Scherer common facilities. (Also see Note 1 of Notes of Financial
Statements for a discussion of the sale.)
INTEREST CHARGESInterest Charges
Net interest charges increased in 1996 compared to 1995 and in 1995 compared
to 1994 and decreased
significantly in 1994 compared to 1993.1994. The continued decrease in gross
interest on long-term debt and capital leases in 1995 and 1994 wasincreases were due to the refinancing efforts discussed under "Financial Condition--REFINANCING
TRANSACTIONS" below. Allowancefact that the allowances for debt and
equity funds used during construction (AFUDC) decreased in 1996 compared to 1995
and 1995 compared to 1994 as a result of the three units of Rocky Mountain
becoming commercially operable in June and July 1995. The continued decrease in
gross interest on long-term debt and capital leases in 1996 and 1995 was due to
the refinancing efforts discussed under "Financial Condition(Refinancing
Transactions" below. The change in other interest expense in 1995 compared to
1994 was due to gains received
on the sale of securities contained in the decommissioning trust fund,
whereas, the decrease in 1994 was primarily due to losses incurred on the
sale of securities containedhigher investment returns in the decommissioning trust fund.
(See Note 1 of Notes to Financial Statements for explanation of Oglethorpe's
accounting for decommissioning gains and losses.)
FACTORS AFFECTING FUTURE FINANCIAL PERFORMANCEFactors Affecting Future Member rates will be affected by such factors asFinancial Performance
Effective January 1, 1997, Oglethorpe entered into power supply agreements
with LPM for 50% of the annualized
fixed costs relatingload requirements of the Members. Under the agreements,
LPM is obligated to Rocky Mountaindeliver, and related transmission facilities,Oglethorpe is obligated to take, 50% of the
load requirements of the participating Members less the load requirements for
certain customer choice loads (900 kilowatt or greater), plus 50% of the
delivery obligations under Oglethorpe's existing firm power off-system sale
contracts. For customer choice loads of three megawatts or less, LPM is
obligated to deliver if Oglethorpe requests 50% of the associated load
requirements. Oglethorpe is obligated to sell and LPM is obligated to buy, 50%
of the output of each participating Member's PCR share of the "must run" units
(primarily nuclear units). Oglethorpe is also obligated to make available the
same share of all other resources, which LPM may schedule. LPM does not have the
right to the output of upgrades to these resources. LPM must pay Oglethorpe the
cost of addingfuel associated with the energy taken. There is a price adjustment if
the plant performance does not meet specified levels of availability and output.
Oglethorpe must pay LPM a contractually specified price for each MWh purchased.
Oglethorpe has the option of purchasing the energy requirements for customer
choice loads from another supplier.
Oglethorpe will cause GTC to Oglethorpe's existingprovide available transmission system, changesto deliver to
the border of the ITS any energy sold to LPM. Each Member will use its
Transmission Agreement for delivery of energy purchased from LPM and others.
Effective with the Corporate Restructuring and the execution of supplemental
agreements to the New Wholesale Power Contracts, the LPM agreement relating to
37 of the 39 Members has a term extending to 2011. With one years' notice,
Oglethorpe has the right to terminate the contract for any year beginning with
38
2002. LPM has the right to terminate the contract for any year beginning with
2005. The LPM agreement relating to the other two Members has a term extending
through the end of 1999.
Oglethorpe is now working to finalize a power supply agreement with Morgan
Stanley Capital Group (Morgan Stanley) that would supply the remaining 50% of
the Members' load requirements. The contract is expected to have a term of up to
eight years. Each Member is currently deciding individually whether to have
Oglethorpe obtain its remaining load requirements from Morgan Stanley. Any
Member that elects not to participate in fuel costs, fluctuating ratesthe Morgan Stanley agreement would have
other options available, including having Oglethorpe manage this portion of the
Member's load growth, environmentalrequirements. In the interim, Oglethorpe is supplying this portion
of its requirements from its own resources and other
governmental regulations applicableby off-system purchase and sales.
In the event Oglethorpe does not enter into power marketer agreements for the
remainder of its load, it can continue to operate effectively in this manner.
In order to complete the implementation of power marketer arrangements,
Oglethorpe and its suppliers andeach Member will enter into supplemental agreements to the completion in 1996New
Wholesale Power Contracts to implement the terms of each power marketing
arrangement under the amortization of deferred margins. Oglethorpe's
future rates will also be affected by its ability to forecast accurately its
future power resource needs and by its ability to obtain and manage its power
resources, including its purchases and construction of generating capacity
and its procurement of coal. Also, see "Proposed Restructuring" below for a
discussion of Oglethorpe's proposed restructuring.New Wholesale Power Contracts.
The electric utility industry in the United States is alsoundergoing fundamental
change and is becoming increasingly competitive
as a resultcompetitive. This change is promoted by the
Energy Policy Act of deregulation, competing energy suppliers, technologies1992 (the "Energy Policy Act"), recently adopted and
proposed policies from FERC regarding transmission access and pricing, increased
consolidation and mergers of electric utilities, the proliferation of
self-generators and independent power producers, surplus generation in certain
regional markets and other factors. The Energy Policy Act of 1992 allowsand FERC policies
allow for increased competition among wholesale electric suppliers and increased
access to transmission services by such suppliers. The new competitive
environment is subject to rapidly evolving regulatory policy at both the federal
and state levels which is based on a shift to a market-driven environment from a
regulated one. Significant legislative developments at the federal level and in
various state legislative bodies, and regulatory developments at the Federal
Energy Regulatory Commission (FERC) and in state commissions, are expected to
continue to clarify policy and the regulatory framework for increased
competition. All of these factors present an increasing challenge to Oglethorpe
and the Members to reduce costs, improve
the management ofmanage resources and respond to the changing
environment.
Inflation
As a meanswith utilities generally, inflation has the effect of reducingincreasing the cost
of power provided toOglethorpe's operations and construction program. Operating and construction
costs have been less affected by inflation over the Members, on
January 3, 1996, Oglethorpe entered into a power supply swap agreement with
Enron Power Marketing, Inc. (EPMI). The agreement, effective January 4, 1996
through April 30, 1996, requires EPMI to sell to Oglethorpe at a favorable
fixed cost all the energy needed to serve the Members (approximately 5.2
million MWh). Pursuant to the agreement, Oglethorpe is required to sell to
EPMI at cost, subject to certain limitations, all available energy from
Oglethorpe's total power resources. EPMI has the option to market any excess
energy that remains from Oglethorpe's total power resources.
On February 7, 1996, Oglethorpe issued a Request for Proposals (RFP) to
selected bidders for a long-term power supply arrangement. This RFP did not
seek a specific amountlast few years because rates
of power; instead, it requested proposals for meeting
the combined power needs of the Members with term options ranging from two to
15 years. Action is anticipated by Oglethorpe's Board of Directors during
April, with implementation of a new arrangement as soon thereafter as possible.inflation have been relatively low.
FINANCIAL CONDITION
GENERALGeneral
The principal changes in Oglethorpe's financial condition in 19951996 were
additions of $599$43 million to gross utility plant and a decrease in the cost of
capital achieved through the refinancing or prepayment of $336$106 million of long-term debt during 1995 and an additional $89 million in January 1996.debt. The
average interest rate on long-term debt decreased from 7.07%6.76% at December 31,
19941995 to 6.60%6.56% at JanuaryDecember 31, 1996.
CAPITAL REQUIREMENTSIn addition, Oglethorpe completed a long-term lease transaction on its share
of Rocky Mountain which produced approximately $96 million of net proceeds. (For
a further discussion of this transaction, see "Rocky Mountain Transactions"
below.)
Capital Requirements
As part of its ongoing capital planning, Oglethorpe forecasts expenditures
required for generation and transmission facilities and relatedother capital projects. The table below
details these expenditures for 1997 through 1999. Actual construction costs may
vary from the estimates listed below because of factors such as changes in
business conditions, fluctuating rates of load growth, environmental
requirements, design changes and rework required by regulatory bodies, delays in
obtaining necessary Federalfederal and other regulatory approvals, construction delays,
and cost of capital, equipment, material and labor.
The table below indicates
Oglethorpe's estimated capital expenditures through 1998:
CAPITAL EXPENDITURES
(DOLLARS IN THOUSANDS)
GENERAL
YEAR GENERATION(1) TRANSMISSION(2) PLANT AFUDC(3) TOTAL
- -----------------------------------------------------------------------
1996 $60,640 $ 44,795 $ 4,499 $3,466 $113,400
1997 60,682 39,004 4,000 2,428 106,114
1998 56,703 40,564 4.000 2,086 103,353
-------- --------- --------------------------------------------------------------------------------
Capital Expenditures(1)
(dollars in thousands)
- --------------------------------------------------------------------------------
Generating Nuclear General
Year Plant(2) Fuel Plant AFUDC(3) Total
1997 $14,753 $ 44,271 $ 3,715 $1,882 $ 64,621
1998 14,142 33,148 3,827 1,804 52,921
1999 11,250 35,549 3,941 1,435 52,175
------- ------ --------
Total $178,025 $124,363 $12,499 $7,980 $322,867
-------- -------- ------- ------ --------
-------- -------- ------- ------ --------
Total $40,145 $112,968 $11,483 $5,121 $169,717
======= ======== ======= ====== ========
(1) Not included in the above amounts are capital expenditures which became the
responsibility of GTC and GSOC as of the Closing of the Corporate Restructuring.
For the period 1997 through 1999, these expenditures total $135 million for GTC
and $1 million for GSOC.
(2) Consists of capital expenditures required for (i) replacements and additions to
facilities in service (ii)and compliance with environmental regulations, and (iii) nuclear fuel reloads.
(2) If the transmission assets are transferred to a new transmission
corporation, the new transmission corporation, and not Oglethorpe, would be
responsible for the transmission capital expenditures and related AFUDC. (See
"Proposed Restructuring" below)regulations..
(3) Allowance for funds used during construction of generation transmission
and general plant
facilities.
31
In 1988, Oglethorpe acquired from GPC an undivided ownership interest in
Rocky Mountain and assumed responsibility for its construction and operation.
By July 1995, all three units of Rocky Mountain were in-service and
Oglethorpe's investment in the project at December 31, 1995 was $565 million,
including related transmission facilities. Construction of Rocky Mountain's
recreational facilities is still in progress and should be completed in the
summer of 1996. Oglethorpe expects the final project cost to be
approximately $570 million, or more than $130 million under budget.
Oglethorpe financed its share of Rocky Mountain from the proceeds of an
RUS-guaranteed loan funded by the FFB. As of December 31, 1995, $555 million
had been advanced under this loan. Oglethorpe expects to draw the additional
$15 million to close out the project in 1996.- --------------------------------------------------------------------------------
Currently, Oglethorpe does not have any new generation facilities under
construction, and management does not anticipate the need for construction of
any new capacity well into the future. The System peaking capacity needs
through the early 2000 time frame are expected to be met through purchased
power alternatives. (See "Results of Operations-Factors
Affecting Future Financial Performance" for a discussion of the Member's futurelong-term power
supply options under "Proposed Restructuring" and Oglethorpe's current request for
proposals under "Results of Operations--FACTORS AFFECTING FUTURE FINANCIAL
PERFORMANCE".arrangements.)
Oglethorpe's investment in electric plant, net of depreciation, was
approximately $4.5$4.4 billion as of December 31, 1995.1996. Expenditures for property
additions during 19951996 amounted to $139$94 million, of which
$639
$91 million was provided from operations. These expenditures were primarily for
the
construction of Rocky Mountainadditions and replacements and additions to generation and transmission facilities.
In addition to the funds needed for capital expenditures, approximately $541$271
million will be required over the next fivethree years for sinking fund requirements
and maturities of long-term debt. Of this amount, $424$216 million, or 78%80%, relates
to the repayment of RUS and FFB debt. LIQUIDITY AND SOURCES OF CAPITALExcluded from these amounts is the amount
of debt assumed by GTC and GSOC as part of the Corporate Restructuring. (See
"General-Corporate Restructuring" and Note 5 of Notes to Financial Statements
for further discussion regarding long-term debt maturities.)
Liquidity and Sources of Capital
In the past, Oglethorpe, like most other G&Ts, has obtained the majority of
its long-term financing from RUS-guaranteed loans funded by the FFB. Oglethorpe has
also obtained a substantial portion of its long-term financing requirements from
tax-exempt PCBs.
In addition, Oglethorpe's operations have consistently provided a sizable
contribution to the funding of capital requirements, such that internally
generated funds have provided interim funding or long-term capital for nuclear
fuel reloads, new generation, transmission and general plant facilities,
replacements and additions to existing facilities, and retirement of long-term
debt. Oglethorpe anticipates that it will meet its future capital requirements
through 19981999 primarily with funds generated from operations and, if necessary,
with short-term borrowings.
To meet short term cash needs and contingencies,liquidity requirements, Oglethorpe had, as
of December 31, 1996, (i) approximately $201$133 million in cash and temporary cash
investments, plus $79(ii) $91 million in other short term investments available at the beginning of 1996.
The Corporation also hasand (iii)
available credit facilities as follows:
SHORT-TERM CREDIT FACILITIES AUTHORIZED
AMOUNT
- ---------------------------------------------------------
Commercial Paper.......................... $300,000,000
Committed lines of credit:
SunTrust Bank, Atlanta .................. 30,000,000
Uncommitted lines of credit:
CoBank, ACB.............................. 70,000,000
National Rural Utilities Cooperative
Finance Corporation (CFC)............... 50,000,000
- --------------------------------------------------------------------------------
Short-Term Credit Facilities Authorized Amount
- --------------------------------------------------------------------------------
Commercial Paper ..............................................$250,000,000
Committed lines of credit:
SunTrust Bank, Atlanta .......................................30,000,000
Uncommitted lines of credit:
National Rural Utilities Cooperative
Finance Corporation (CFC) ...............................50,000,000
- --------------------------------------------------------------------------------
Under its commercial paper program, Oglethorpe may issue commercial paper
not to exceed $300$250 million outstanding at any one time. The commercial paper which is
backed 100% by committed lines of credit provided by a group of banks for which
SunTrust Bank, Atlanta acts as agent. Proceeds from the issuance of commercial
paper may be used as a source of short-term fundsfor working capital requirements and is not designated
for any specific purpose. Historically, Oglethorpe has not relied on
commercial paper for short-term funding due to the availability of internally
generated funds and has never utilized the backup line of credit.general corporate
purposes.
The maximum amount that can be outstanding at any one time under the
commercial paper program and the lines of credit totals $370$250 million due to
certain restrictions contained in the SunTrust Bank and CFC line of credit
agreements. As of December 31, 1995,1996, no commercial paper was outstanding and
there was no outstanding balance on any line of credit. REFINANCING TRANSACTIONSIn March 1997,
Oglethorpe issued approximately $92 million of commercial paper to fund the
defeasance of certain PCBs in conjunction with the Corporate Restructuring. (See
"Refinancing Transactions" below for a further discussion of this defeasance.)
Refinancing Transactions
Over the past few years, Oglethorpe has implemented a program to reduce its
interest costs by refinancing or prepaying a sizable portion of its
high-interest rate PCB and FFB debt. Since the first transaction was completed
in June 1992, Oglethorpe has refinanced $1.1 billion in PCB debt and $1.2
billion in FFB debt and has prepaid another $105 million in FFB debt. Included
in these amounts are a January 19951996 refinancing of $285$89 million of FFB debt and
prepayment of an additional $30 million of FFB debt, and a December 1995October 1996 refinancing of $22$16 million of PCB debt. (See Note 5 of Notes to
Financial Statements.) The net result of the 19951996 transactions was to reduce the
average interest rate on total long-term debt from 7.07% at December 31, 1994 to 6.76% at December 31, 1995. The average interest rate was further reduced1995 to
6.60%
as of January6.56% at December 31, 1996 as a result of a $89 million FFB debt refinancing.1996. The refinancings completed since the program began
will resultresulted in total estimatedannual savings in 1996 of more than $90 million in gross
interest expense and $80 million in net interest expense (net of prepayment
penalties and transaction costs) in 1996..
Oglethorpe's use of financial derivatives areis for the purpose of mitigating
business risks and areis not used for speculative purposes. Derivatives have been
used on a very limited basis, as discussed below, and at December 31, 1995, the1996, any
credit risk for derivatives outstanding was not material.
To refinance high-interest rate PCBs, Oglethorpe entered into two interest
rate swap transactions with a swap counterparty, AIG
32
Financial Products Corp.
(AIG-FP), which were designed to create a contractual fixed rate of interest on
$322 million of variable rate PCBs. These transactions were entered into in
early 1993 on a forward basis, pursuant to which approximately $200 million of
variable rate PCBs were issued on November 30, 1993 and approximately $122
million of variable rate PCBs were issued on December 1, 1994. Oglethorpe is
obligated to pay the variable interest rate that accrues on these PCBs; however,
the swap agreements provide a mechanism for Oglethorpe to achieve a contractual
fixed rate which is lower than Oglethorpe would have obtained had it issued
fixed rate bonds.
Under the swap agreements, Oglethorpe is obligated to make periodic payments
to AIG-FP based on a notional principal amount equal to the aggregate principalprin-
40
cipal amount of the bonds outstanding during the period and a contractual fixed
rate (Fixed Rate), and AIG-FP is obligated to make periodic payments to
Oglethorpe on a notional principal amount equal to the aggregate principal
amount of the bonds outstanding during the period and a variable rate equal to
the variable rate of interest accruing on the bonds during the period (Variable
Rate). These payment obligations are netted, such that if the Variable Rate is
less than the Fixed Rate, Oglethorpe makes a net payment to AIG-FP. Likewise, if
the Variable Rate is higher than the Fixed Rate, Oglethorpe receives a net
payment from AIG-FP. Thus, although changes in the Variable Rate affects whether
Oglethorpe is obligated to make payments to AIG-FP or is entitled to receive
payments from AIG-FP, the effective interest rate Oglethorpe pays with respect
to the PCBs is not affected by changes in interest rates. The Fixed Rate for the
$200 million of variable rate bonds issued in 1993 is 5.67% and the Fixed Rate
for the $122 million of variable rate bonds issued in 1994 is 6.01%. For the
three years ended December 31, 1993, 1994, 1995 and 1995,1996, Oglethorpe has made in
connection with both interest rate swap arrangements combined net swap payments
to AIG-FP of $0.6 million,
$6.0 million, and $6.4 million respectively, totaling $13.0and $8.2 million, for such
three-year period.respectively.
The swap arrangements extend for the life of these PCBs. If the swap
arrangements were to be terminated while the PCBs wereare still outstanding,
Oglethorpe or AIG-FP may owe the other party a termination payment depending on
a number of factors, including whether the fixed rate then being offered under
comparable swap arrangements is higher or lower than the Fixed Rate. Under the
terms of the swap agreements, AIG-FP has limited rights to terminate the swaps
only upon the occurrence of specified events of default or a reduction in
ratings on Oglethorpe's PCBs, without credit enhancement, to a level that is
below investment grade. Oglethorpe estimates that its maximum aggregate
liability for termination payments under both swap arrangements had such
payments been due on December 31, 19951996 would have been approximately $52$34
million. (For additional information about the swap arrangements, see Note 2 of
Notes to Financial Statements.)
In connection with these interest rate swap agreements, Oglethorpe is
obligated to maintain minimum liquidity in an amount equal to 25% of the
principal amount of the variable rate refunding bonds outstanding. This minimum
liquidity requirement currently equals $81 million and will decrease
proportionately as such bonds are retired. The minimum liquidity must
consist of (a) any combination of (i) amounts available under committed lines
of credit and commercial paper programs to pay termination payments, if any,
due upon early termination of the interest rate swap transactions, (ii)
cash, (iii) United States government securities, and (iv) accounts receivable
due within 30 days, less (b) monetary obligations due within 30 days. As of
December 31, 1995, Oglethorpe had approximately $518 million of such
liquidity available to meet this requirement.
PROPOSED RESTRUCTURING
For some time, Oglethorpe and the Members have been discussing various
options to provide the Members greater flexibility for meeting their power
supply needs in an increasingly competitive utility environment. These
discussions led to a restructuring plan approved by Oglethorpe's Board of
Directors in December 1995 to divide Oglethorpe into three specialized
companies to respond to increasing competition in the electric industry
and to settle certain issues confronting Oglethorpe and the Members,
including several Members' previously stated intention to withdraw from
membership in Oglethorpe in order to gain more flexibility. The December
plan proposed the creation of a new transmission company and a new system
operations company and Oglethorpe's retention of the generation business.
Oglethorpe's Board believes there are significant potential benefits to the
Members of having the transmission business and the system operations
business operated in separate companies. Among the principal benefits is that
the Members' freedom to choose among power suppliers, including Oglethorpe,
for their future growth would be enhanced.
The current target date for full implementation of the
restructuring is January 1, 1997. As a preliminary step, Georgia
Transmission Corporation (An Electric Membership Corporation) (GTC) has been
incorporated for future use as the transmission company and Georgia System
Operations Corporation (GSOC) has been incorporatedretired as a Georgia non-profit
corporation for future use as the system operations company. On March 29,
1996, the Boardsresult of Oglethorpe, GTC and GSOC approved an agreement (the
Restructuring Agreement) which sets forth the terms and conditions on which the
restructuring and related changes would occur. The Restructuring Agreement
contemplates that Oglethorpe would operate primarily as a power supply
company, but initially would retain economic development, marketing and
service functions.
Oglethorpe would transfer its transmission business, including its existing
transmission assets, to GTC. GTC would thereafter own and operate the
transmission system and provide transmission services to the Members,
Oglethorpe and third parties. (See Note 6 of Notes to Financial Statements
for a summary of Oglethorpe's investments in electric plant, including
transmission and distribution plant.) The purchase price for the
transmission business would be equal to the sum of (1) the higher of: (a) the
appraised fair market value of such business as determined by an independent
appraiser, or (b) Oglethorpe's net book value for the transmission assets,
plus (2) the value of certain deferred charges. If the appraised value of
the transmission business exceeds Oglethorpe's net book value for the
transmission assets by more than 5%, GTC's Board would have to approve the
payment of any resulting purchase price. The purchase price would be paid by
GTC's assumption of a portion of
33
Oglethorpe's long-term secured debt and by cash obtained through third party
borrowing. Oglethorpe also would make a special patronage capital
distribution to the Members which could be used by the Members to
establish equity in and to provide initial working capital to GTC.
Oglethorpe would transfer its system operations business, consisting of
its operations center and related computer and dispatch equipment, to GSOC.
GSOC would thereafter own and operate the operations center and provide system
operation services to the Members, Oglethorpe, GTC and third parties.
Oglethorpe also plans to implement a new governance structure when: (a)
it receives a favorable ruling from the Internal Revenue Service that such
structure would not affect Oglethorpe's status for federal income tax purposes
as a corporation operating on a cooperative basis, and (b) a new rate
schedule which allocates to each Member responsibility for a specified
percentage of all costs of Oglethorpe's existing resources becomes legally
binding and effective. It is contemplated that the new governance structure
would become effective at the same time as the restructuring, although it is
possible that it could become effective independent of the restructuring.
The new governance structure provides for a board of directors consisting of
six directors elected from the Members, four independent outside directors and
Oglethorpe's President and Chief Executive Officer, rather than Oglethorpe's
current 39-member board which is comprised of directors nominated by each
Member. To be elected, the new directors must be nominated by a committee
composed of a representative from each Member whose vote would be weighted in
accordance with the number of retail customers served by such Member and then
elected by a vote of the Members on a one-member, one-vote basis.
In adopting the Restructuring Agreement, Oglethorpe's Board recommended to
the Members that they become members of GTC and GSOC and that they join with
Oglethorpe, GTC and GSOC in executing an agreement (the Member Agreement) as to
those matters contemplated in the Restructuring Agreement that directly involve
the Members in their capacities as separate corporations. The Member Agreement
will specify the form of transmission contracts and system operation contracts
to be signed by the Members. The Member Agreement will also provide, subject to
the approval of RUS, that Oglethorpe and each Member executing the Member
Agreement would execute a new wholesale power contract to govern the purchase
and sale of power between Oglethorpe and each such Member. Each Member signing
the new wholesale power contract would have a choice as to whether or not to
participate in future power supply projects sponsored by Oglethorpe. Such
Members would be free to own generation directly and to engage in purchases and
sales with other power suppliers. To the extent such Members choose to satisfy
their projected load growth from sources other than Oglethorpe, the growth in
Oglethorpe's revenues from the sale of power would decrease but the growth in
related expenses also would decrease.
Members agreeing to the new wholesale power contracts would have the
option to have energy and reserves priced on a pooled basis or to schedule
their capacity and associated energy separately at prices based on the cost
of production. GSOC would administer the new power pool contemplated by the
new wholesale power contracts and would implement the separate schedules for
Members electing that option. Under the power pool, Oglethorpe resources and
any Member-procured resources would be committed to economic dispatch (pooled)
for the benefit of all pool participants. The power pool arrangement also
would allow the participants to pool resource reserves.scheduled sinking fund
payments.
In connection with the restructuring,Corporate Restructuring, Oglethorpe plansdefeased
approximately $92 million in principal amount of Series 1992 PCBs. Initially
these bonds have been defeased through the issuance of commercial paper.
Oglethorpe may refinance the commercial paper issuance with medium-term notes at
some point in the future and expects to adopt specific
implementation procedures forrefinance the existing bylaw provision that grantscommercial paper or such
medium-term notes in late 2002 with PCBs.
Also, in connection with the Corporate Restructuring, Oglethorpe refinanced
approximately $217 million in principal amount of Series 1992A PCBs through the
issuance of refunding bonds having a Membernine-month maturity (the Series 1997A
bonds). Payment of principal and interest on the right to withdraw from membership in Oglethorpe upon satisfying
certain conditions. These conditions generally would require the withdrawing
Member either to affirm its obligations under its then-existing wholesale
power contract or to assign its rights and obligations under such wholesale
power contract to another party with a credit rating meeting certain
specified requirements. WithdrawalSeries 1997A bonds are insured
by a Member would continuemunicipal bond insurance policy issued by AMBAC Indemnity Corporation. In
connection with the AMBAC insurance, Oglethorpe is obligated to be
conditioned upon approval by RUS.maintain
liquidity in an amount at least equal to the principal amount of the Series
1997A bonds outstanding plus interest accrued thereon. The restructuringmaximum amount of
this liquidity requirement during the nine-month period equals approximately
$223 million. Oglethorpe currently expects to refinance the Series 1997A bonds
in the second half of 1997 with another series of PCBs.
Rocky Mountain Transactions
Oglethorpe completed, in two separate closings on December 31, 1996 and
January 3, 1997, lease transactions for its 74.61% undivided ownership interest
in Rocky Mountain. Under the terms of these transactions, Oglethorpe leased the
facility to three institutional investors for a term of 71 years, who in turn
leased it back to Oglethorpe for a term of 30 years. The transactions are
characterized as a sale and lease-back for income tax purposes, but not for
financial reporting purposes. Rocky Mountain is subject to a number of conditions, including (1)
implementation of Oglethorpe's new governance structure, (2) executionthe lien of the
Member Agreement byMaster Indenture. The leasehold interest transferred is subject and subordinate
to such lien. Oglethorpe will continue to control and operate the Members, executionplant during
the lease-back term, and it fully intends to repurchase tax ownership and to
retain all other rights of new wholesale power contracts
by Oglethorpe andownership with respect to the Members, and executionplant at the end of the
transmission contracts
and system operation contracts specified in the Member Agreement, (3) RUS
approval of new wholesale power contracts and the restructuring, (4)
governmental, lender and other third party consents, authorizations, waivers,
orders and approvals, (5) receipt by GTC and GSOC of certain capital
contributions by the Members and (6) assurances from rating agencies that the
ratings on Oglethorpe's outstanding fixed rate PCBs would not be lowered aslease-back period. As a result of these transactions, Oglethorpe received net
proceeds of approximately $96 million which is being recorded as a deferred
credit and will be recognized in income over the restructuring and that such rating agencies would assign to any
comparable bonds issued by GTC the same or better credit rating as assigned
to Oglethorpe's fixed rate PCBs. Most of these conditions may be waived by
Oglethorpe's Board, subject to RUS approval in certain instances.
The restructuring is expected to take the remainder of 1996 to complete,
although limited aspectsterm of the restructuring may become effective sooner if
specific conditions set forth in the Restructuring Agreement are met. In
lightlease-back.
Approximately $91 million of the significant conditions that mustproceeds will be satisfied, including RUS
and other governmental and third-party approvals and assurances and receiptused for the early retirement
of various agreements fromFFB debt, with the Members, Oglethorpe cannot predictremaining $5 million being used to pay alternative minimum
taxes on the actual
timing of or the ultimate likelihood of full implementationtransactions. The combination of the restructuring or governance changes. Until implementationdebt prepayment and the
amortized gain will result in an estimated $11 million in annual savings. In
connection with these transactions, Oglethorpe is obligated to maintain
liquidity of the
restructuring, Oglethorpe will continue its current operations, and until
satisfaction of the conditions applicable to the new governance
structure, Oglethorpe will continue under its existing governance structure.
34approximately $50 million.
41
ITEMItem 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO FINANCIAL STATEMENTS
PAGEIndex To Financial Statements
Page
----
Statements of Revenues and Expenses, For the Years Ended
December 31, 1996, 1995 1994 and 1993................................. 361994...................................... 43
Statements of Patronage Capital, For the Years Ended
December 31, 1996, 1995 1994 and 1993................................. 361994...................................... 43
Balance Sheets, As of December 31, 19951996 and 1994................... 371995......................... 44
Statements of Capitalization, As of December 31, 19951996 and 1994..... 391995........... 46
Statements of Cash Flows, For the Years Ended December 31, 1996,
1995 1994 and 1993.................................................... 401994......................................................... 47
Notes to Financial Statements...................................... 41Statements, including pro-forma financial
statements relating to the Corporate Restructuring.................... 48
Report of Management............................................... 51Management..................................................... 60
Reports of Independent Public Accountants.......................... 51
35Accountants................................ 60
42
STATEMENTS OF REVENUES AND EXPENSES
FOR THE YEARS ENDED DECEMBERFor the years ended December 31, 1996, 1995 and 1994 AND 1993
.........................................................................................................- ------------------------------------------------------------------------------------------------------
(dollars in thousands)
1996 1995 1994 1993
OPERATING REVENUES (NOTEOperating revenues (Note 1):
Sales to Members..................................... $1,030,797Members $ 1,023,094 $ 1,030,797 $ 930,875
$ 899,720
Sales to non-Members.................................non-Members 78,343 118,764 125,207
200,940
---------- ---------- ----------
TOTAL OPERATING REVENUES...............................----------- ----------- -----------
Total operating revenues 1,101,437 1,149,561 1,056,082
1,100,660
---------- ---------- ----------
OPERATING EXPENSES:
Fuel.................................................----------- ----------- -----------
Operating expenses:
Fuel 206,524 219,062 203,444
176,342
Production...........................................Production 129,178 133,858 132,723 129,972
Purchased power (Note 9)............................. 229,089 264,844 227,477
271,970
Power delivery.......................................delivery 18,216 17,520 16,965 14,286
Sales, administrative and general....................general 42,289 39,015 32,269
30,590
Depreciation and amortization........................amortization 163,130 139,024 131,056 128,060
Taxes other than income taxes........................taxes 30,262 27,561 24,741 23,328
Income taxes (Note 3)................................ -- -- 1,820
---------- ---------- ----------
TOTAL OPERATING EXPENSES...............................--
----------- ----------- -----------
Total operating expenses 818,688 840,884 768,675
776,368
---------- ---------- ----------
OPERATING MARGIN.......................................----------- ----------- -----------
Operating margin 282,749 308,677 287,407
324,292
---------- ---------- ----------
OTHER INCOME (EXPENSE)----------- ----------- -----------
Other income (expense):
Interest income......................................income 23,485 18,031 10,518 20,316
Amortization of deferred gains (Notes 1 and 4)....... 2,341 2,341 9,985
12,532
Amortization of proceeds fromnet benefit of sale of income
tax benefits (Note 1).................................. 8,054 8,043 8,102 8,102
Amortization of deferred margins (Note 1)............ 32,047 15,959 18,072 4,138
Deferred margins (Note 1)............................ -- (14,282) (9,287) (5,083)
Allowance for equity funds used during
construction (Note 1).............................. 238 1,715 2,907
2,278
Other................................................Other (831) 1,903 498
(3,542)
---------- ---------- ----------
TOTAL OTHER INCOME.....................................----------- ----------- -----------
Total other income 65,334 33,710 40,795
38,741
---------- ---------- ----------
INTEREST CHARGES:----------- ----------- -----------
Interest charges:
Interest on long-term debt and capital leases........leases 308,013 317,968 329,738
367,439
Other interest.......................................interest 10,006 12,979 3,856 8,539
Allowance for debt funds used during construction (Note 1)............................................ (2,576) (21,114) (36,113) (29,988)
Amortization of debt discount and expense............expense 10,888 10,296 7,639
4,662
---------- ---------- ----------
NET INTEREST CHARGES...................................----------- ----------- -----------
Net interest charges 326,331 320,129 305,120
350,652
---------- ---------- ----------
MARGIN BEFORE CUMULATIVE EFFECT OF CHANGE IN
ACCOUNTING PRINCIPLE.................................. 22,258 23,082 12,381
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR
INCOME TAXES ......................................... -- -- 13,340
---------- ---------- ----------
NET MARGIN ............................................----------- ----------- -----------
Net margin $ 21,752 $ 22,258 $ 23,082
$ 25,721
---------- ---------- ----------
---------- ---------- ----------=========== =========== ===========
STATEMENTS OF PATRONAGE CAPITAL
FOR THE YEARS ENDED DECEMBERFor the years ended December 31, 1996, 1995 and 1994 AND 1993
- ------------------------------------------------------------------------------------------------------
(dollars in thousands)
1996 1995 1994 1993
.........................................................................................................
Patronage capital and membership fees - beginning
of year (Note 1)..................................... $ 338,891 $ 309,496 $ 289,982
$ 264,261
Net margin.............................................margin 21,752 22,258 23,082 25,721
Change in unrealized gain (loss) on available-for-sale
securities, net of income taxes (Note 2)............. (4,414) 7,137 (3,568)
--
--------- --------- -------------------- ----------- -----------
Patronage capital and membership fees-end of year......year $ 356,229 $ 338,891 $ 309,496
$ 289,982
--------- --------- ---------
--------- --------- ---------=========== =========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
36The accompanying notes are an integral part of these financial statements.
43
BALANCE SHEETS
DECEMBERDecember 31, 1996 and 1995 AND 1994
........................................................................................- --------------------------------------------------------------------------------------------
(dollars in thousands)
ASSETSAssets 1996 1995 1994
ELECTRIC PLANT (NOTESElectric plant (Notes 1, 4 ANDand 6):
In service............................................service $ 5,699,2135,742,597 $ 5,100,2995,699,213
Less: Accumulated provision for depreciation..........depreciation (1,488,272) (1,362,431) (1,231,818)
----------- -----------
4,254,325 4,336,782 3,868,481
Nuclear fuel, at amortized cost.......................cost 86,722 94,013 105,683
Plant acquisition adjustments, at amortized cost......cost 4,153 5,214 6,275
Construction work in progress.........................progress 31,181 35,753 538,789
----------- -----------
4,376,381 4,471,762 4,519,228
----------- -----------
INVESTMENTS AND FUNDS (NOTESInvestments and funds (Notes 1 ANDand 2):
Bond, reserve and construction funds, at market.......market 53,955 56,511 64,163
Decommissioning fund, at market.......................market 86,269 74,492 59,164
Investment in associated organizations, at cost.......cost 15,379 15,853
17,371Deposit on Rocky Mountain transactions, at cost 41,685 --
----------- -----------
197,288 146,856 140,698
----------- -----------
CURRENT ASSETS:Current assets:
Cash and temporary cash investments, at cost (Note 1). 132,783 201,151 190,642
Other short-term investments, at market...............market 91,499 79,165
--
Receivables...........................................Receivables 113,289 99,559 88,873
Inventories, at average cost (Note 1)................. 89,825 82,949 95,076
Prepayments and other current assets..................assets 14,625 14,325 14,857
----------- -----------
442,021 477,149 389,448
----------- -----------
DEFERRED CHARGES:Deferred charges:
Premium and loss on reacquired debt, being amortized (Note 5)............................................. 201,007 200,794 161,889
Deferred amortization of Scherer leasehold (Note 4)... 90,717 87,134 80,132
Discontinued projects, being amortized (Note 1)....... 24,305 26,342
Deferred debt expense, being amortized................amortized 21,703 21,135
20,936
Other................................................. 9,361 7,657Other (Note 1) 33,058 33,666
----------- -----------
346,485 342,729 296,956
----------- -----------
$ 5,362,175 $ 5,438,496
$ 5,346,330
----------- -----------
----------- -----------=========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE BALANCE SHEETS.
37The accompanying notes are an integral part of these balance sheets.
44
........................................................................................- ------------------------------------------------------------------------------------------------
(dollars in thousands)
EQUITY AND LIABILITIESEquity and Liabilities 1996 1995 1994
CAPITALIZATION (SEE ACCOMPANYING STATEMENTS)Capitalization (see accompanying statements):
Patronage capital and membership fees (Note 1)....... $ 356,229 $ 338,891
$ 309,496
Long-term debt.......................................debt 4,052,470 4,207,320 4,128,080
Obligation under capital leases (Note 4)............. 293,682 296,478
303,749
----------- -----------Obligation under Rocky Mountain transactions (Note 1) 41,685 --
---------- ----------
4,744,066 4,842,689
4,741,325
----------- -----------
CURRENT LIABILITIES:---------- ----------
Current liabilities:
Long-term debt and capital leases due within one year................................................year 159,622 89,675
90,086
Deferred margins and Vogtle surcharge to be refunded within one year (Note 1)................... -- 32,047
19,279
Accounts payable.....................................payable 42,891 48,855
52,921
Accrued interest.....................................interest 15,931 91,096 100,010
Accrued and withheld taxes...........................taxes 4,940 1,785 1,566
Other current liabilities............................liabilities 14,022 18,007
18,177
----------- --------------------- ----------
237,406 281,465
282,039
----------- -----------
DEFERRED CREDITS AND OTHER LIABILITIES:---------- ----------
Deferred credits and other liabilities:
Gain on sale of plant, being amortized (Note 4)...... 58,527 60,868
63,209
SaleNet benefit of sale of income tax benefits, being amortized (Note 1)............................................ 42,049 50,194
58,236Net benefit of Rocky Mountain transactions, being amortized (Note 1) 70,701 --
Accumulated deferred income taxes (Note 3)........... 61,985 65,510 65,510
Deferred margins and Vogtle surcharge (Note 1)....... -- 17,765
Decommissioning reserve (Note 1)..................... 124,468 114,049
96,291
Other................................................Other 22,973 23,721
21,955
----------- --------------------- ----------
380,703 314,342
322,966
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTES---------- ----------
Commitments and Contingencies (Notes 4, 9 AND 10)and 11)
$5,362,175 $5,438,496
$5,346,330
----------- -----------
----------- -----------========== ==========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE BALANCE SHEETS.
3845
STATEMENTS OF CAPITALIZATION
DECEMBERDecember 31, 1996 and 1995 AND 1994
........................................................................................- ----------------------------------------------------------------------------------------------------------
(dollars in thousands)
1996 1995 1994
LONG-TERM DEBT (NOTE
Long-term debt (Note 5):
Mortgage notes payable to the Federal Financing Bank (FFB) at
interest rates varying from 5.67%5.27% to 10.78%9.51% (average rate of
7.19%6.95% at December 31, 1995)1996) due in quarterly installments
through 2023 .................................................................. $ 3,253,6363,172,851 $ 3,161,5503,253,636
Mortgage notes payable to the Rural Utilities Service (RUS) at
an interest rate of 5% due in monthly installments through 2021...........2021 .......... 22,475 22,983 23,467
Mortgage notes issued in conjunction with the sale by public authorities of
pollution control revenue bonds:
-o Series 1982
Serial bonds, 10.20% to 10.60%, due serially through 1997.........................................1997 .......................... 6,675 16,135
-6,675
o Series 1992
Term bonds, 7.50% to 8.00%, due 2003 to 2022..........2022 ............................. 92,130 92,130
-SeriesoSeries 1992A
Adjustable tender bonds, 3.25%3.40% to 3.95%3.70%, due 2025.....2025 ........................ 216,925 216,925
Serial bonds, 5.10%5.35% to 6.80%, due serially from 19971998 through 2012.........................................2012 ........ 124,690 129,760
139,240
-o Series 1993
Serial bonds, 3.30%3.55% to 5.25%, due serially from 19961997 through 2013.........................................2013 ........ 37,255 38,110
39,090
-o Series 1993A
Adjustable tender bonds, 5.15%4.00%, due 2016..............2016 ................................. 199,690 199,690
-o Series 1993B
Serial bonds, 3.55%3.75% to 5.05%, due serially from 1998 through 2008 ........ 126,935 136,745
o Series 1994
Serial bonds, 4.20% to 7.125%, due serially from 1997 through 2008......................................... 136,745 155,610
- Series 1994
Serial bonds, 4.90% to 7.125%, due serially from 1996
through 2015......................................... 10,6902015 ....... 10,365 10,690
Term bonds, 7.15% due 2021............................2021 ............................................... 11,550 11,550
-o Series 1994A
Adjustable tender bonds, 5.05%4.00%, due 2019..............2019 ................................. 122,740 122,740
-o Series 1994B
Serial bonds, 5.20%5.45% to 6.45%, due serially from 19971998 through 2005.........................................2005 ........ 11,140 12,475
13,720
-Unsecured notes issued in conjunction with the sale by public authorities of
pollution control revenue bonds:
o Series 1995
Adjustable rate bonds, 3.70% to June 1996, due in 2015.................................................2015 ................... -- 21,670
o Series 1996
Adjustable rate bonds, 3.88% to April 1997, due in 2017 .................. 37,885 --
CoBank, ACB notes payable:
-o Headquarters note payable: $5.2 million fixed at 6.85%6.60% through July 1996,April 1997,
due in quarterly installments through January 1, 2009 ................................................. 4,672 5,159
5,549
-o Transmission note payable: fixed at 6.85%6.50% through
July 1996;September 1997; due in bimonthly installments through November 1, 2018......................................2018 ... 2,237 2,261
2,279
-o Transmission note payable: fixed at 6.45%6.50% through November 1996;October 1997; due
in bimonthly installments through September 1, 2019.....................................2019 ...................... 8,556 8,637 8,697
----------- -----------
4,208,771 4,291,836 4,219,062
Less:Unamortized debt discount.........................discount ............................................. (766) (832) (896)
----------- -----------
Total long-term debt, net..............................net .................................................. 4,208,005 4,291,004
4,218,166
Less:Long termLong-term debt due within one year................year .................................... (155,535) (83,684) (90,086)
----------- -----------
TOTAL LONG-TERM DEBT, EXCLUDING AMOUNT DUE WITHIN
ONE YEAR...............................................Total long-term debt, excluding amount due within one year .................... 4,052,470 4,207,320
4,128,080
OBLIGATION UNDER CAPITAL LEASES, LONG TERM (NOTEObligation under capital leases, long-term (Note 4)..... ........................... 293,682 296,478
303,749
PATRONAGE CAPITAL AND MEMBERSHIP FEES (NOTEObligation under Rocky Mountain transactions, long-term (Note 1).......... .............. 41,685 --
Patronage capital and membership fees (Note 1) ................................ 356,229 338,891 309,496
----------- -----------
TOTAL CAPITALIZATION....................................Total capitalization .......................................................... $ 4,744,066 $ 4,842,689
$ 4,741,325
----------- -----------
----------- -----------=========== ===========
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
39The accompanying notes are an integral part of these financial statements.
46
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED DECEMBERFor the years ended December 31, 1996, 1995 and 1994 AND 1993
....................................................................................................................
(dollars in thousands)
1996 1995 1994
1993Cash flows from operating activities:
CASH FLOWS FROM OPERATING ACTIVITIES:
Net margin.......................................................margin ................................................... $ 21,752 $ 22,258 $ 23,082
$ 25,721
---------- ---------- ------------------- --------- ---------
Adjustments to reconcile net margin to net cash
provided by operating activities:
Cumulative effect of change in accounting for income taxes.... -- -- (13,340)
Depreciation and amortization.................................amortization ............................ 196,593 196,920 193,351
180,221Net benefit of Rocky Mountain transactions ............... 70,701 -- --
Interest on decommissioning reserve...........................reserve ...................... 7,167 9,951 1,291 7,356
Amortization of deferred gains .......................................................... (2,341) (2,341) (9,985) (12,532)
Deferred margins and amortization of deferred margins.........margins .... (32,047) (1,677) (8,785)
945
Amortization of proceeds fromnet benefit of sale of income tax benefits.....benefits (8,145) (8,043) (8,102) (8,102)
Allowance for equity funds used during construction...........construction ...... (238) (1,715) (2,907)
(2,278)
Deferred income taxes.........................................taxes .................................... (3,525) -- --
1,625Option payment on power swap agreement ................... (3,750) -- --
Other ............................................................................................................ (13) (13) (13)
Change in net current assets, excluding long-term
debt due within one year and deferred margins and
Vogtle surcharge to be refunded within one year:
Receivables...................................................Receivables ............................................ (13,731) (10,686) (18,055)
(24,990)
Inventories...................................................Inventories ............................................ (6,875) 12,127 (8,608) 7,172
Prepayments and other current assets..........................assets ................... (299) 532 (94)
2,369
Accounts payable..............................................payable ....................................... (5,964) (4,066) (10,569)
(2,349)
Accrued interest..............................................interest ....................................... (75,165) (8,914) (8,692) 49,379
Accrued and withheld taxes....................................taxes ............................. 3,155 219 (7,835)
5,741
Other current liabilities.....................................liabilities .............................. (3,985) (169) (24,124)
15,542
---------- ---------- ------------------- --------- ---------
Total adjustments................................................adjustments ............................................ 121,538 182,125 86,873
206,746
---------- ---------- ----------
NET CASH PROVIDED BY OPERATING ACTIVITIES..........................--------- --------- ---------
Net cash provided by operating activities ....................... 143,290 204,383 109,955
232,467
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES:--------- --------- ---------
Cash flows from investing activities:
Property additions...............................................additions ........................................... (93,704) (138,921) (206,345) (235,285)
Activity in decommissioning fund - Purchases.....................Purchases ................. (327,233) (410,597) (297,492)
--
- Proceeds......................Proceeds ........................ 316,542 399,077 293,990 --
Activity in bond, reserve and construction funds - Purchases.....Purchases . (107,890) (27,762) (498,052)
--
- Proceeds......Proceeds ........... 109,230 39,566 540,712 --
Activity in other short-term investments - Purchases.............Purchases ......... (15,532) (76,180) -- --
Increase in decommissioning fund................................. -- -- (8,990)
Net proceeds from bond, reserve and construction funds........... -- -- 53,574
Decrease in investment in associated organizations...............organizations ........... 474 1,518 1,752
786
Decrease (increase)--------- --------- ---------
Net cash used in other short-term investments.............. -- -- 66,165
Other............................................................ -- -- 158
---------- ---------- ----------
NET CASH USED IN INVESTING ACTIVITIES..............................investing activities ........................... (118,113) (213,299) (165,435)
(123,592)
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES:--------- --------- ---------
Cash flows from financing activities:
Debt proceeds, net...............................................net .......................................... 2,243 132,874 523,518
232,675
Debt payments....................................................payments ............................................... (95,367) (108,481) (517,530) (369,962)
Return of Vogtle surcharge.......................................surcharge .................................. -- (3,320) (2,031)
(1,600)
Other............................................................Other ....................................................... (421) (1,648) (2,008)
(1,439)
---------- ---------- ----------
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES................--------- --------- ---------
Net cash provided by (used in) financing activities ............. (93,545) 19,425 1,949
(140,326)
---------- ---------- ----------
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS.....--------- --------- ---------
Net increase (decrease) in cash and temporary cash investments .. (68,368) 10,509 (53,531)
(31,451)
CASH AND TEMPORARY CASH INVESTMENTS AT BEGINNING OF YEAR...........Cash and temporary cash investments at beginning of year ........ 201,151 190,642 244,173
275,624
---------- ---------- ----------
CASH AND TEMPORARY CASH INVESTMENTS AT END OF YEAR.................--------- --------- ---------
Cash and temporary cash investments at end of year .............. $ 132,783 $ 201,151 $ 190,642
$ 244,173
---------- ---------- ----------
---------- ---------- ----------
CASH PAID FOR:========= ========= =========
Cash paid for:
Interest (net of amounts capitalized)............................ ....................... $ 383,440 $ 308,797 $ 304,882
$ 289,255
Income taxes.....................................................taxes ................................................ -- -- 1,658--
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE FINANCIAL STATEMENTS.
40The accompanying notes are an integral part of these financial statements.
47
NOTES TO FINANCIAL STATEMENTS
FOR THE YEARS ENDED DECEMBERFor the years ended December 31, 1996, 1995 and 1994
AND 1993
..............................................................................
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. BUSINESS DESCRIPTIONSummary of significant accounting policies:
a. Business description
Oglethorpe Power Corporation (Oglethorpe) is an electric generation and
transmission (G&T) cooperative incorporated in 1974 and headquartered in
suburban Atlanta. Oglethorpe provides wholesale electric service, on a
not-for-
profitnot-for-profit basis, to 39 of Georgia's 42 Electric Membership Corporations
(EMCs). These 39 electric distribution cooperatives (Members) in turn distribute
energy on a retail basis to more than 2.6 million people across two-thirds of
the State. Oglethorpe is the nation's largest G&T in terms of operating
revenues, assets, kilowatt-hour sales and, through its Members, consumers
served.
Oglethorpe supplies energy to the Members from 3,335 megawatts (MW) of owned
or leased generating capacity and purchases the remainder from other power
suppliers. Oglethorpe also has access to over 16,000 miles of transmission line
through its ownership in the statewide Integrated Transmission System.
B. BASIS OF ACCOUNTINGOglethorpe and the Members completed on March 11, 1997, a corporate
restructuring. For a discussion of the corporate restructuring, see Note 11.
b. Basis of accounting
Oglethorpe follows generally accepted accounting principles and the practices
prescribed in the Uniform System of Accounts of the Federal Energy Regulatory
Commission (FERC) as modified and adopted by the Rural Utilities Service (RUS),
formerly known as the Rural Electrification Administration (REA).
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities as of December 31, 19951996 and 19941995 and the
reported amounts of revenues and expenses for each of the three years ending
December 31, 1995.1996. Actual results could differ from those estimates.
C. PATRONAGE CAPITAL AND MEMBERSHIP FEESc. Patronage capital and membership fees
Oglethorpe is organized and operates as a cooperative. The Members paid a
total of $195 in membership fees. Patronage capital is the retained net margin
of Oglethorpe. As provided in the bylaws, any excess of revenue over
expenditures from operations is treated as advances of capital by the Members
and is allocated to each of them on the basis of their electricity purchases
from Oglethorpe.
The margin andUnder Oglethorpe's patronage capital retirements policy, adopted bymargins are to be
returned to the Oglethorpe
Board of Directors in 1992 extended from 13 years toMembers 30 years after the period that
each year's net margin will be retained by Oglethorpe.year in which the margins are earned.
Pursuant to the previous
13-year patronage capital retirement schedule, 1978 patronage capital
assignments were retired in 1992. Under the new 30-year retirement schedule,such policy, no patronage capital would be returned to the Members
until 2010, at which time the 1979 patronage capital would be returned.
D. MARGIN POLICYSince the RUS Mortgage was replaced with the Master Indenture in connection
with Oglethorpe's corporate restructuring, patronage distributions also will be
restricted by the terms of the Master Indenture.
d. Margin policy
Under Oglethorpe's prior RUS mortgage, Oglethorpe's margin policy iswas based
on the provision of a Times Interest Earned Ratio (TIER) established annually by
the Oglethorpe Board of Directors. Pursuant to this policy, the annual net
margin goal for 1996, 1995 1994 and 19931994 was the amount required to produce a TIER of
1.07. The RUS Mortgage was replaced with the Master Indenture in connection with
Oglethorpe's corporate restructuring. Under the Master Indenture, Oglethorpe is
required to produce a Margins for Interest (MFI) Ratio of 1.10.
The Oglethorpe Board of Directors adopted resolutions annually requiring that
Oglethorpe's net margins for the years 1985 through 1995 in excess of its annual
margin goals be deferred and used to mitigate rate increases associated with
Plant Vogtle and Rocky Mountain. In addition, during 1986 and 1987, Oglethorpe's
wholesale electric rate to its Members provided for a one mill per kilowatt-hour
charge (Vogtle Surcharge), also to be used to mitigate the effect of Plant
Vogtle on rates.
Pursuant to rate actions by Oglethorpe's Board of Directors, specified
amounts of deferred margins and Vogtle Surcharge were returned in 1989 through
1995 and all remaining amounts will bewere returned in 1996. A summary of deferred
margins and Vogtle Surcharge as of December 31, 19951996 and 19941995 is as follows:
...................................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...................................................................................
DEFERRED MARGINS
1985-92 $ 165,552 $ 165,552
1993 5,083 5,083
1994 9,287 9,287
1995 14,282 --
--------- ---------
194,204 179,922
VOGTLE SURCHARGE
1986-87 36,613 36,613
--------- ---------
Subtotal 230,817 216,535
Less: Amounts returned in:
1989-92 (153,650) (153,650)
1993 (5,738) (5,738)
1994 (20,103) (20,103)
1995 (19,279) --
--------- ---------
32,047 37,044
Less: Current portion (32,047) (19,279)
--------- ---------
Long-term balance $ -- $ 17,765
--------- ---------
--------- ---------
...................................................................................
E. OPERATING REVENUES- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
- --------------------------------------------------------------------------------
Deferred margins
1985-92 $ 165,552 $ 165,552
1993 5,083 5,083
1994 9,287 9,287
1995 14,282 14,282
--------- ---------
194,204 194,204
Vogtle Surcharge
1986-87 36,613 36,613
--------- ---------
Subtotal 230,817 230,817
Less: Amounts returned in:
1989-93 (159,388) (159,388)
1994 (20,103) (20,103)
1995 (19,279) (19,279)
1996 (32,047) --
--------- ---------
-- 32,047
Less: Current portion -- (32,047)
--------- ---------
Long-term balance $ -- $ --
========= =========
- --------------------------------------------------------------------------------
48
e. Operating revenues
Operating revenues consist primarily of electricity sales pursuant to
long-term wholesale power contracts which Oglethorpe maintains with each of its
Members. These wholesale power contracts obligate each Member to pay Oglethorpe
for capacity and energy furnished in accordance with rates established by
Oglethorpe. Energy furnished is determined based on meter readings which are
conducted at the end of each month. Actual energy costs are compared, on a
monthly basis, to the billed energy costs, and an adjustment to revenues is made
such that energy revenues are equal to actual energy costs.
Revenues from Cobb EMC and Jackson EMC, two of Oglethorpe's Members,
accounted for 12.5% and 11.2% in 1996, 11.3% and 10.4% in 1995, and 11.0% and
10.5% in 1994, of
Oglethorpe's total operating
41
revenues. In 1993, Cobb EMC accounted for 10.3%respectively, of Oglethorpe's total operating revenues.
Sales to non-Members consist partly of revenues from energy sales to non-
Member utilities other than Georgia Power Company (GPC) and partly of capacity
and energy sales to GPC under terms of sell-back agreements entered into when
Oglethorpe purchased interests in certain of GPC's generation facilities.
Pursuant to these agreements, GPC purchased through 1995 from Oglethorpe a
declining fractional part of the capacity and energy during the first seven to
ten years of an applicable generating unit's commercial operation. The portion
of Oglethorpe's capacity and energy retained by GPC is shown as follows:
...................................................................................
Fractional Part of Capacity and Energy Retained
by GPC during Contract Year Ended May 31
Generating Unit 1996 1995 1994 1993
...................................................................................
Plant Scherer,
Unit No. 2 -- -- -- 6/60
Plant Vogtle,
Unit No. 1 -- -- 4/30 8/30
Plant Vogtle,
Unit No. 2 -- 4/30 8/30 11/30
...................................................................................
Pursuant to these sell-back agreements and to other contractual
arrangements with GPC, revenues from GPC accounted for approximately 6%, 8%,
and 15% of Oglethorpe's total operating revenues in 1995, 1994, and 1993,
respectively.
F. NUCLEAR FUEL COSTf. Nuclear fuel cost
The cost of nuclear fuel, including a provision for the disposal of spent
fuel, is being amortized to fuel expense based on usage. The total nuclear fuel
expense for 1996, 1995 1994 and 19931994 amounted to $49,298,000, $54,588,000 $55,229,000 and
$49,647,000,$55,229,000, respectively.
Contracts with the U.S. Department of Energy (DOE) have been executed to
provide for the permanent disposal of spent nuclear fuel for the life of Plant
Hatch and Plant Vogtle. The services to be provided by DOE arewere scheduled to
begin in 1998. However, the actual year that these services will begin is
uncertain. The Plant Hatch spent fuel storage is expected to be sufficient into
2003. The Plant Vogtle spent fuel storage is expected to be sufficient into
2009. If DOE does not begin receiving spent fuel from2008. Activities for adding dry cast storage capacity at Plant Hatch by as early
as 1999 are in 2003 or from Plant Vogtle in 2009, alternative spent fuel storage
will be needed.progress.
The Energy Policy Act of 1992 requiresrequired that utilities with nuclear plants be
assessed over the next 15 years,a 15-year period an amount which will be used by DOE for the
decontaminationdecon-tamination and decommissioning of its nuclear fuel enrichment facilities.
The amount of each utility's assessment iswas based on its past purchases of
nuclear fuel enrichment services from DOE. Based on its ownership in Plants
Hatch and Vogtle, Oglethorpe has a remaining nuclear fuel asset of approximately
$16,200,000,$14,900,000, which is being amortized to nuclear fuel expense over the next 1211
years. Oglethorpe has also recorded net of
sell-back, an obligation to DOE which approximated
$13,000,000$11,800,000 at December 31, 1995.
G. NUCLEAR DECOMMISSIONING1996.
g. Nuclear decommissioning
Oglethorpe's portion of the costs of decommissioning co-owned nuclear
facilities is estimated as follows:
...................................................................................
(DOLLARS IN THOUSANDS) Hatch Hatch Vogtle Vogtle
Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2
...................................................................................
Year of site study 1994 1994 1994 1994
Expected start date
of decommissioning 2014 2018 2027 2029
Decommissioning cost:
Discounted $ 92,000 $109,000 $ 82,000 $106,000
Undiscounted 223,000 299,000 302,000 419,000
...................................................................................
- --------------------------------------------------------------------------------
(dollars in thousands) Hatch Hatch Vogtle Vogtle
Unit No. 1 Unit No. 2 Unit No. 1 Unit No. 2
- --------------------------------------------------------------------------------
Year of site study 1994 1994 1994 1994
Expected start date
of decommissioning 2014 2018 2027 2029
Decommissioning cost:
Discounted $ 92,000 $ 109,000 $ 82,000 $ 106,000
Undiscounted 157,000 207,000 198,000 271,000
- --------------------------------------------------------------------------------
The decommissioning cost estimates are based on prompt dismantlement and
removal of the plant from service. The actual decommissioning costs may vary
from the above estimates because of changes in the assumed date of
decommissioning, changes in regulatory requirements, changes in technology, and
changes in costs of labor, materials and equipment.
The annual provision for decommissioning for 1996, 1995 and 1994 and 1993 was
$2,597,000, $4,156,000 $5,948,000 and $5,948,000, respectively. In developing the amount of
the annual provision for 19951996 and 1996,1997, the escalation rate was assumed to be
3.5%2.72% and return on trust assets was assumed to be 8%. Oglethorpe accounts for
this provision for decommissioning as depreciation expense with an offsetting
credit to a decommissioning reserve. Oglethorpe's management is of the opinion
that any changes in cost estimates of decommissioning will be fully recovered in
future rates.
In compliance with a Nuclear Regulatory Commission (NRC) regulation,
Oglethorpe maintains an external trust fund to provide for a portion of the cost
of decommissioning its nuclear facilities. The NRC regulation requires funding
levels based on average expected cost to decommission only the radioactive
portions of a typical nuclear facility. Oglethorpe's decommissioning reserve
reflects its obligation to decommission both the radioactive and most of the
non-radioactive portions of its nuclear facilities.
The amounts which will ultimately be used to
decommission the non-radioactive portions of Oglethorpe's nuclear plants are
classified as cash and temporary cash investments on the accompanying balance
sheets. With respect to these "internally" funded amounts, imputed interest
earnings are calculated based on average current investment rates and are
applied to the decommissioning reserve balance and charged to interest expense.
Similarly, realizedRealized investment earnings from the external trust fund, while increasing
the fund and interest income, also are applied to the decommissioning reserve
and charged to interest expense. Interest income earned from the external trust
fund and imputed on the internally funded amount is offset by the recognition of interest expense such that there is no
effect on Oglethorpe's net margin.
4249
H. DEPRECIATIONh. Depreciation
Depreciation is computed on additions when they are placed in service using
the composite straight-line method. Annual depreciation rates in effect in 1996,
1995 1994 and 19931994 were as follows:
...................................................................................
1995 1994 1993
...................................................................................
Steam production 2.13% 2.47% 2.66%
Nuclear production 2.78% 2.84% 2.83%
Hydro production 2.00% 2.00% 2.00%
Other production 3.75% 2.42% 1.09%
Transmission 2.75% 2.75% 2.75%
Distribution 2.88% 2.88% 2.88%
General 2.00-20.00% 2.00-20.00% 2.00-17.00%
...................................................................................
I. ELECTRIC PLANT- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Steam production 2.13% 2.13% 2.47%
Nuclear production 2.73% 2.78% 2.84%
Hydro production 2.00% 2.00% 2.00%
Other production 3.75% 3.75% 2.42%
Transmission 2.75% 2.75% 2.75%
Distribution 2.88% 2.88% 2.88%
General 2.00-20.00% 2.00-20.00% 2.00-20.00%
- --------------------------------------------------------------------------------
i. Electric plant
Electric plant is stated at original cost, which is the cost of the plant
when first dedicated to public service, plus the cost of any subsequent
additions. Cost includes an allowance for the cost of equity and debt funds used
during construction. The cost of equity and debt funds is calculated at the
embedded cost of all such funds. The plant acquisition adjustments represent the
excess of the cost of the plant to Oglethorpe over the original cost, less
accumulated depreciation at the time of acquisition, and are being amortized
over a ten-year period.
Maintenance and repairs of property and replacements and renewals of items
determined to be less than units of property are charged to expense.
Replacements and renewals of items considered to be units of property are
charged to the plant accounts. At the time properties are disposed of, the
original cost, plus cost of removal, less salvage of such property, is charged
to the accumulated provision for depreciation.
J. BOND, RESERVE AND CONSTRUCTION FUNDS:j. Bond, reserve and construction funds:
Bond, reserve and construction funds for pollution control bonds are
maintained as required by Oglethorpe's bond agreements. Bond funds serve as
payment clearing accounts, reserve funds maintain amounts equal to the maximum
annual debt service of each bond issue and construction funds hold bond proceeds
for which construction expenditures have not yet been made. As of December 31,
19951996 and 1994,1995, substantially all of the funds were invested in U.S. Government
securities.
K. CASH AND TEMPORARY CASH INVESTMENTSk. Cash and temporary cash investments
Oglethorpe considers all temporary cash investments purchased with a maturity
of three months or less to be cash equivalents. Temporary cash investments with
maturities of more than three months are classified as other short-term
investments.
L. INVENTORIESOf the amount reported as cash and temporary cash investments at December 31,
1996, approximately $65,600,000 is restricted by RUS for the purpose of
prepaying certain Federal Financing Bank (FFB) long-term debt on or before March
31, 1997.
l. Inventories
Oglethorpe maintains inventories of fossil fuels for its generation plant and
spare parts for certain of its generation and transmission plant. These
inventories are stated at weighted average cost on the accompanying balance
sheets.
At December 31, 19951996 and 1994,1995, fossil fuels inventories were $12,296,000$23,062,000 and
$24,225,000,$12,296,000, respectively. Inventories for spare parts at December 31, 1996 and
1995 were $66,763,000 and 1994 were $70,653,000, and $70,851,000, respectively.
M. ENERGY COST RECOVERY
Oglethorpe's wholesale power rate sets forth the manner in which energym. Deferred charges
Prior to 1996, Oglethorpe expensed nuclear refueling outage costs as
incurred. In 1996, Oglethorpe began accounting for these costs on a normalized
basis. Under this method of accounting, refueling outage costs are deferred and
subsequently amortized to be recovered from its Members. The rate in effect for 1995, 1994
and 1993 provided that an energy rate be determined based on projectedexpense over the 18-month operating cycle of each
unit. Deferred nuclear outage costs and kilowatt-hour sales and that the resulting rate be used to bill Members
for a six-month period. Actual energy costs are compared, on a monthly basis,
to the billed energy costs, and an adjustment to revenues is made such that
energy revenues are equal to actual energy costs. The offset to this
adjustment is included as an increase or decrease to the receivable from
Members. For 1995 and 1994, the rate provides that any cumulative
overcollection or undercollection for the previous six-month period be
utilized to adjust projected costs for the next six-month period. As ofat December 31, 1994, an overcollection of $2,125,000 existed and was utilized
to reduce Member billings in 1995. Due to the new power supply swap agreement
discussed in Note 10, in 1996 energy cost will be collected from Members on
a current basis. As of December 31, 1995, a cumulative undercollection of
$4,237,000 was owed Oglethorpe and will be collected from Members over the
next 12-month period.
N. DEFERRED CHARGES
Primarily as a result of its ownership of a majority interest in Rocky
Mountain, Oglethorpe determined that the Pickens County Pumped Storage
Hydroelectric Project was not needed within its present planning horizon.
Accordingly, Oglethorpe is amortizing the accumulated project costs in excess
of the value of the land purchased. The remaining unamortized project costs
of approximately $15,496,000 are reflected as deferred charges on the
accompanying balance sheets. Oglethorpe's Board of Directors has authorized
that these project costs be amortized and fully recovered through future
rates over a period of 15 years beginning in 1992.were $12,961,000.
As a result of the availability of long-term capacity purchases at similar
costs but with reduced risks to Oglethorpe and its Members, Oglethorpe
determined that the Smarr Combustion Turbine Project was not needed within the
present planning horizon. Therefore, Oglethorpe is amortizing the accumulated
project costs in excess of the current value of the land purchased. The
remaining project costs of $8,808,000$6,445,000 are reflected as deferred charges on the
accompanying balance sheets. In 1995, Oglethorpe's Board of Directors has authorized
that these project costs be amortized and fully recovered through future rates
over a period of 15 years beginning in 1995.
43
O. DEFERRED CREDITS
In April 1982, Oglethorpe sold to three purchasers certain of the income
tax benefits associated with Scherer Unit No.1 and related common facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act
of 1981. Oglethorpe received a total of approximately $110,000,000 from the
safe harbor lease transactions. Oglethorpe accounts for the proceeds as a
deferred credit, sale of income tax benefits, and is amortizing the amount
over the 20-year term of the leases.that year.
n. Deferred credits
In October 1989, Oglethorpe sold to GPCGeorgia Power Company (GPC) a 24.45%
ownership interest in the Plant Scherer common facilities as required under the
Plant Scherer Purchase and Ownership Agreement to adjust its ownership in the
Scherer units. Oglethorpe realized a gain on the sale of $50,600,000. RUS and
Oglethorpe's Board of Directors approved a plan whereby this gain was deferred
and was amortized over 60 months ending in September 1994.
P. REGULATORY ASSETS AND LIABILITIESIn April 1982, Oglethorpe sold to three purchasers certain of the income tax
benefits associated with Scherer Unit No.1 and related common facilities
pursuant to the safe harbor lease provisions of the Economic Recovery Tax Act of
1981. Oglethorpe received a total of approximately $110,000,000 from the safe
harbor lease transactions. Oglethorpe accounts for the net benefits as a
deferred credit and
50
is amortizing the amount over the 20-year term of the leases.
In December 1996, Oglethorpe entered into long-term lease transactions for a
portion of its 74.6% undivided ownership interest in the Rocky Mountain Pumped
Storage Hydroelectric Project (Rocky Mountain). The lease transactions are
characterized as a sale and lease-back for income tax purposes, but not for
financial reporting purposes. As a result of these leases, Oglethorpe recorded a
net benefit of $70,701,000 which was deferred and will be amortized to income
over the 30-year lease-back period. The lease transactions increased
Oglethorpe's Capitalization and Investments and funds by $41,685,000,
respectively (see Note 2 where discussed further).
In January 1997, Oglethorpe completed long-term lease transactions for the
remainder of its interest in Rocky Mountain resulting in a net benefit of
$24,859,000. The net benefit will be deferred and amortized to income over the
30-year term of the leases. Oglethorpe will increase Capitalization and
Investments and funds by $15,810,000, respectively.
o. Regulatory assets and liabilities
Oglethorpe is subject to the provisions of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation."
Regulatory assets represent probable future revenues to Oglethorpe associated
with certain costs which will be recovered from Members through the rate-making
process. Regulatory liabilities represent probable future reduction in revenues
associated with amounts that are to be credited to Members through the
rate-making process. The following regulatory assets and liabilities were
reflected on the accompanying balance sheets as of December 31, 1996 and 1995:
- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
- --------------------------------------------------------------------------------
Premium and 1994:
...............................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...............................................................................
Premium and loss on reacquired debt $200,794 $161,889
Deferred amortization of Scherer leasehold 87,134 80,132
Discontinued projects 24,305 26,342
Other regulatory assets 9,361 7,657
Sale of income tax benefits (50,194) (58,236)
Deferred margins and Vogtle Surcharge (32,047) (37,044)
Energy costs 4,237 (2,125)
-------- --------
$243,590 $178,615
-------- --------
-------- --------
...............................................................................
loss on reacquired debt $ 201,007 $ 200,794
Deferred amortization of Scherer leasehold 90,717 87,134
Other regulatory assets 29,308 33,666
Net benefit of sale of income tax benefits (42,049) (50,194)
Net benefit of Rocky Mountain transactions (70,701) --
Deferred margins -- (32,047)
Energy costs -- 4,237
--------- ---------
$ 208,282 $ 243,590
========= =========
- --------------------------------------------------------------------------------
In the event that Oglethorpe is no longer subject to the provisions of
Statement No. 71, Oglethorpe would be required to write off related regulatory
assets and liabilities. In addition, Oglethorpe would be required to determine
any impairment to other assets, including plant, and write down the assets, if
impaired, to their fair value.
Q. PRESENTATIONp. Presentation
Certain prior year amounts have been reclassified to conform with current
year presentation.
2. FAIR VALUE OF FINANCIAL INSTRUMENTS:Fair value of financial instruments:
A detail of the estimated fair values of Oglethorpe's financial instruments
as of December 31, 19951996 and 19941995 is as follows:
.....................................................................................
(DOLLARS IN THOUSANDS)- ------------------------------------------------------------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
1994
FAIR Fair COST VALUEFair
Cost Value .....................................................................................Cost Value
- ------------------------------------------------------------------------------------------------------------------------------------
CASH AND TEMPORARY
CASH INVESTMENTS:Cash and temporary cash investments:
Commercial paper $ 52,700 $ 52,700 $ 179,055 $ 179,055
$ 156,192 $ 156,192
Repurchase agreement -- -- 14,087 14,087
Certificates of deposit 20,000 20,00010,000 10,000 20,000 20,000
Cash and money market
securities 70,083 70,083 2,096 2,096 363 363
---------- ---------- ---------- ----------
TOTALTotal $ 132,783 $ 132,783 $ 201,151 $ 201,151
========== ========== ========== ==========
Other short term
investments:
Commingled
investment fund $ 190,64291,712 $ 190,64291,499 $ 76,180 $ 79,165
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
OTHER SHORT TERM INVESTMENTS:
Mutual fundsTotal $ 91,712 $ 91,499 $ 76,180 $ 79,165
$ -- $ --
---------- ---------- ---------- ----------
TOTAL $ 76,180 $ 79,165 $ -- $ --
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
BOND, RESERVE AND
CONSTRUCTION FUNDS:========== ========== ========== ==========
Bond, reserve and construction funds:
U. S. Government
securities $ 36,505 $ 35,873 $ 49,348 $ 49,932
$ 57,141 $ 53,573
Repurchase agreements 18,082 18,082 6,579 6,579 10,590 10,590
---------- ---------- ---------- ----------
TOTALTotal $ 54,587 $ 53,955 $ 55,927 $ 56,511
$ 67,731 $ 64,163
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
DECOMMISSIONING FUND:========== ========== ========== ==========
Decommissioning fund:
U. S. Government
securities $ 24,034 $ 23,950 $ 23,087 $ 23,568
$ 36,668 $ 35,513Foriegn government
securities 1,228 1,278 -- --
Commercial paper -- -- 4,036 4,036
-- --
Corporate bonds 11,953 11,868 5,875 6,073
4,548 4,388
Equity securities 30,339 34,073 19,514 21,271
8,605 8,707
Asset-backed securities 3,103 3,125 12,484 12,614
3,754 3,672Other bonds 5,445 5,453 -- --
Cash and money market
securities 6,522 6,522 6,937 6,930 6,884 6,884
---------- ---------- ---------- ----------
TOTALTotal $ 82,624 $ 86,269 $ 71,933 $ 74,492
$ 60,459 $ 59,164
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
LONG-TERM DEBT========== ========== ========== ==========
Long-term debt $4,118,117 $4,228,317 $4,207,320 $4,506,925
$4,128,080 $4,107,751
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
INTEREST RATE SWAP$========== ========== ========== ==========
Interest rate swap $ -- $ 33,938 $ -- $ 52,089
$ -- $ 6,148
---------- ---------- ---------- ----------
---------- ---------- ---------- ----------
.....................................................................................========== ========== ========== ==========
- ------------------------------------------------------------------------------------------------------------------------------------
The contractual maturities of debt securities available for sale at December
31, 19951996 and 1994,1995, regardless of their balance sheet classification, are as
follows:
.............................................................................................
(DOLLARS IN THOUSANDS) 1995 1994
FAIR Fair
COST VALUE Cost Value
.............................................................................................
Due within one year $ 21,050 $ 21,300 $ 32,292 $ 31,916
Due after one year through five years 37,172 37,452 48,810 47,065
Due after five years through ten years 27,628 27,966 21,940 19,367
Due after ten years 11,523 12,049 9,659 9,388
-------- -------- -------- --------
$ 97,373 $ 98,767 $112,701 $107,736
-------- -------- -------- --------
-------- -------- -------- --------
.............................................................................................
- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
Fair Fair
Cost Value Cost Value
- --------------------------------------------------------------------------------
Due within one year $33,944 $33,819 $21,050 $21,300
Due after one year through five years 17,439 17,266 37,172 37,452
Due after five years through ten years 27,912 27,302 27,628 27,966
Due after ten years 15,610 15,789 11,523 12,049
------- ------- ------- -------
$94,905 $94,176 $97,373 $98,767
======= ======= ======= =======
- --------------------------------------------------------------------------------
Oglethorpe uses the methods and assumptions described below to estimate the
fair value of each class of financial instruments. For cash and temporary cash
investments, the carrying amount approximates fair value because of the
short-term maturity of those
51
instruments. The fair value of Oglethorpe's long-term debt and the swap
arrangements is estimated based on the quoted market prices for the same or
similar issues or on the current rates offered to Oglethorpe for debt of similar
maturities.
Under the interest rate swap arrangements, Oglethorpe makes payments to the
counterparty based on the notional principal at a
44
contractually fixed rate and
the counterparty makes payments to Oglethorpe based on the notional principal at
the existing variable rate of the refunding bonds. The differential to be paid
or received is accrued as interest rates change and is recognized as an
adjustment to interest expense. Oglethorpe entered into the swap arrangements
for the purpose of securing a fixed rate lower than otherwise would have been
available to Oglethorpe had it issued fixed rate bonds. For the Series 1993A
notes, the notional principal was $199,690,000 and the fixed swap rate is 5.67%
(the variable rate at December 31, 1996 and 1995 was 4.00% and 1994 was 5.15% and 4.95%
respectively). With respect to the Series 1994A notes, the notional principal
was $122,740,000 and the fixed swap rate is 6.01% (the variable rate at December
31, 1996 and 1995 was 4.00% and 1994 was 5.05% and 4.95%, respectively). The notional principal
amount is used to measure the amount of the swap payments and does not represent
additional principal due to the counterparty. The swap arrangements extend for
the life of the refunding bonds, with reductions in the outstanding principal
amounts of the refunding bonds causing corresponding reductions in the notional
amounts of the swap payments. The estimated fair value of Oglethorpe's liability
under the swap arrangements at December 31, 1996 and 1995 was $33,938,000 and
1994 was $52,089,000, and $6,148,000, respectively. This amount represents payment Oglethorpe would pay
if the swap arrangements were terminated. Oglethorpe may be exposed to losses in
the event of nonperformance of the counterparty, but does not anticipate such
nonperformance.
Oglethorpe adopted Statement of Financial Accounting Standards No. 115,
"Accounting for Certain Investments in Debt and Equity Securities," as of
January 1, 1994. Under this Statement, investment securities held by Oglethorpe
are classified as either available-for-sale or held-to-maturity.
Available-for-sale securities are carried at market value with unrealized gains
and losses, net of any tax effect, added to or deducted from patronage capital.
Unrealized gains and losses from investment securities held in the
decommissioning fund, which are also classified as available-for-sale, are
directly added to or deducted from the decommissioning reserve. Held-to-maturity
securities are carried at cost. All realized and unrealized gains and losses are
determined using the specific identification method. Gross unrealized gains and
losses at December 31, 19951996 were $6,497,000$7,785,000 and $368,000,$4,985,000, respectively. Gross
unrealized gains and losses at December 31, 19941995 were $234,000$6,497,000 and $5,050,000,$368,000,
respectively. For 19951996 and 1994,1995, proceeds from sales of available-for-sale
securities totaled $425,772,000 and $438,643,000, respectively. Gross realized
gains and $834,702,000, losses from the 1996 sales were $6,410,000 and
$3,671,000,respectively. Gross realized gains and losses from the 1995 sales
were $5,098,000 and $1,308,000,respectively. Gross realized gains and
losses from the 1994 sales were $1,099,000 and $4,776,000, respectively.
Investments in associated organizations were as follows at December 31, 1996
and 1995:
- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
and 1994:
...........................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...........................................................................
National Rural Utilities
Cooperative Finance Corp. (CFC) $13,476 $13,476
CoBank, ACB 2,132 3,690
Other 245 205
------- -------
Total $15,853 $17,371
------- -------
------- -------
...........................................................................
- --------------------------------------------------------------------------------
National Rural Utilities
Cooperative Finance Corp. (CFC) $13,476 $13,476
CoBank, ACB 1,664 2,132
Other 239 245
------- -------
Total $15,379 $15,853
======= =======
- --------------------------------------------------------------------------------
The investments in these associated organizations are similar to compensating
bank balances in that they are required in order to maintain current financing
arrangements. Accordingly, there is no market for these investments.
The $41,685,000 deposit on the Rocky Mountain transactions (see Note 1 where
discussed) as of December 31, 1996 is invested in a guaranteed investment
contract which will be held to maturity (the end of the 30-year lease-back
period). At maturity, Oglethorpe fully intends to use the deposit to repurchase
tax ownership and to retain all other rights of ownership with respect to the
plant. The deposit is carried at cost.
In addition, from the proceeds of the Rocky Mountain transactions, Oglethorpe
paid $460,769,000 to a financial institution. In return, this financial
institution undertook to pay a portion of Oglethorpe's lease obligations. Both
Oglethorpe's interest in this payment undertaking agreement and the
corresponding lease obligations have been extinguished for financial reporting
purposes.
3. INCOME TAXESIncome taxes
Oglethorpe is a not-for-profit membership corporation subject to Federal State of Georgia and
State of Alabamastate income taxes. For years 1981 and prior,
Oglethorpe claimed tax-exempt status under Section 501(c)(12) of the Internal
Revenue Code of 1954, as amended (the Code). In 1982, Oglethorpe reported as
a taxable entity as a result of income received by it from GPC under the
capacity and energy sell-back agreement applicable to Scherer Unit No. 1. In
connection with its 1985 tax return, Oglethorpe made an election under
Section 168(j)(4)(E)(ii) of the Code to remain taxable from 1985 until at
least 2005 without regard to the amount of its income from GPC or other
non-Members. As a taxable electric cooperative, Oglethorpe has annually
allocated its income and deductions between Member and non-Member activities.
Any Member taxable income has been offset with a patronage exclusion.
As of January 1, 1993,exclusion and member
loss carryforwards.
Oglethorpe prospectively adopted the provisions ofaccounts for its income taxes pursuant to Statement of Financial
Accounting Standards (SFAS) No. 109, "Accounting for
Income Taxes." In adopting SFAS No. 109, Oglethorpe recorded a $13,340,000
reduction in accumulated deferred income taxes and an increase in income from
the cumulative effect of a change in accounting principle.109. SFAS No. 109 requires the recognition of
deferred tax assets and liabilities for the expected future tax consequences of
events that have been included in the financial statements or tax returns.
Deferred tax assets and liabilities are
determined based on the differences between the financial and tax bases using
enacted tax rates in effect for the year in which the differences are
expected to reverse.52
A detail of the provision for income taxes in 1996, 1995 1994 and 19931994 is shown as
follows:
...................................................................................
(DOLLARS IN THOUSANDS) 1995 1994 1993
...................................................................................
Current
Federal $ -- $ -- $ --
State -- -- 195
----- ----- -------
-- -- 195
----- ----- -------
Deferred
Federal -- -- 1,820
State -- -- (195)
----- ----- -------
-- -- 1,625
----- ----- -------
Income taxes charged
to operations $ -- $ -- $ 1,820
----- ----- -------
----- ----- -------
...................................................................................
45
- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995 1994
- --------------------------------------------------------------------------------
Current
Federal $ 3,525 $ -- $ --
State -- -- --
------- ------- -------
3,525 -- --
------- ------- -------
Deferred
Federal (3,525) -- --
State -- -- --
------- ------- -------
(3,525) -- --
------- ------- -------
Income taxes charged
to operations $ -- $ -- $ --
======= ======= =======
- --------------------------------------------------------------------------------
The difference between the statutory federal income tax rate on income before
income taxes and accounting changes and Oglethorpe's effective income tax rate is summarized as
follows:
...................................................................................
1995 1994 1993
...................................................................................
Statutory federal income tax rate 35.0% 35.0% 35.0%
Patronage exclusion (35.6%) (35.4%) (35.1%)
Other 0.6% 0.4% 0.1%
Effect of increase in statutory rate 0.0% 0.0% 12.8%
------ ------ ------
Effective income tax rate 0.0% 0.0% 12.8%
------ ------ ------
------ ------ ------
...................................................................................
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Patronage exclusion (35.7%) (35.6%) (35.4%)
Other 0.7% 0.6% 0.4%
------ ------ ------
Effective income tax rate 0.0% 0.0% 0.0%
====== ====== ======
- --------------------------------------------------------------------------------
The components of the net deferred tax liabilities as of December 31,
19951996 and 19941995 were as follows:
...........................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...........................................................................
DEFERRED TAX ASSETS
Net operating losses $ 538,067 $ 451,543
Member loss carryforwards 342,370 366,417
Tax credits 252,680 252,701
Accounting for safe harbor leases 86,599 98,746
Patronage exclusions available 0 80,190
Accrued nuclear decommissioning expense 45,042 38,644
Accounting for asset dispositions 33,496 34,448
Other 18,277 18,061
----------- -----------
1,316,531 1,340,750
Less: Valuation allowance (252,680) (252,701)
----------- -----------
1,063,851 1,088,049
----------- -----------
DEFERRED TAX LIABILITIES
Depreciation (1,034,153) (1,062,233)
Accounting for debt extinguishment (64,006) (61,003)
Other (31,202) (30,323)
----------- -----------
(1,129,361) (1,153,559)
----------- -----------
Net deferred tax liabilities $ (65,510) $ (65,510)
----------- -----------
----------- -----------
...........................................................................
- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
- --------------------------------------------------------------------------------
Deferred tax assets
Net operating losses $ 473,114 $ 538,067
Member loss carryforwards 328,912 342,370
Tax credits (alternative minimum tax
and other) 256,205 252,680
Accounting for Rocky Mountain
transactions 233,045 --
Accounting for sale of income tax benefits 77,429 86,599
Accrued nuclear decommissioning expense 49,127 45,042
Accounting for asset dispositions 32,545 33,496
Other 3,318 18,277
----------- -----------
1,453,695 1,316,531
Less: Valuation allowance (252,680) (252,680)
----------- -----------
1,201,015 1,063,851
----------- -----------
Deferred tax liabilities
Depreciation (1,008,714) (1,034,153)
Accounting for Rocky Mountain
transactions (156,557) --
Accounting for debt extinguishment (64,841) (64,006)
Other (32,888) (31,202)
----------- -----------
(1,263,000) (1,129,361)
----------- -----------
Net deferred tax liabilities $ (61,985) $ (65,510)
=========== ===========
- --------------------------------------------------------------------------------
As of December 31, 1995,1996, Oglethorpe has federal tax net operating loss
carryforwards (NOLs), alternative minimum tax credits (AMT) and unused general
business credits (consisting primarily of investment tax credits) as follows:
...........................................................................
(DOLLARS IN THOUSANDS)
...........................................................................
Expiration Date Tax Credits NOLs
1997 $ 11,197 $ --
1998 6,934 --
1999 37,206 --
2000 3,198 --
2001 7,264 --
2002 130,377 146,363
2003 652 253,665
2004 55,663 114,285
2005 189 213,080
2006 -- 209,009
2007 -- 86,779
2008 -- 94,927
2009 -- 96,394
2010 -- 77,967
---------- ----------
$ 252,680 $1,292,469
---------- ----------
---------- ----------
...........................................................................
- --------------------------------------------------------------------------------
(dollars in thousands)
- --------------------------------------------------------------------------------
Alternative
Minimum
Expiration Date Tax Credits Tax Credits NOLs
1997 $ -- $ 11,197 $ --
1998 -- 6,934 --
1999 -- 37,206 --
2000 -- 3,198 --
2001 -- 7,264 --
2002 -- 130,377 --
2003 -- 652 242,187
2004 -- 55,663 114,285
2005 -- 189 213,080
2006 -- -- 209,009
2007 -- -- 86,779
2008 -- -- 94,927
2009 -- -- 96,394
2010 -- -- 77,970
None 3,525 -- --
-------- ---------- ----------
$ 3,525 $ 252,680 $1,134,631
======== ========== ==========
- --------------------------------------------------------------------------------
Based on Oglethorpe's historical taxable transactions, the timing of the
reversal of existing temporary differences, future income, and tax planning
strategies, it is more likely than not that Oglethorpe's future taxable income
will be sufficient to realize the benefit of these NOLs before their respective
expiration dates. The NOLs expiration dates start in the year 2003 and end in
the year 2010. However, as reflected in the above valuation allowance, it is
more likely than not that the tax credits will not be utilized before
expiration. It is more likely than not that the AMT credit will be utilized.
53
4. CAPITAL LEASES:Capital leases:
In December 1985, Oglethorpe sold and subsequently leased back from four
purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The gain
from the sale is being amortized over the 36-year term of the leases. The
minimum lease payments under the capital leases together with the present value
of net minimum lease payments as of December 31, 19951996 are as follows:
...........................................................................
YEAR ENDING DECEMBER 31, (DOLLARS IN THOUSANDS)
...........................................................................
1996 $ 39,293
1997 35,239
1998 37,302
1999 37,890
2000 37,755
2001-2021 606,809
---------
Total minimum lease payments 794,288
Less: Amount representing interest (491,819)
---------
Present value of net minimum lease payments 302,469
Less: Current portion (5,991)
---------
Long term balance $ 296,478
---------
---------
...........................................................................
- --------------------------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
1997 $ 36,531
1998 37,302
1999 37,890
2000 37,755
2001 37,629
2002-2021 569,179
---------
Total minimum lease payments 756,286
Less: Amount representing interest (458,517)
---------
Present value of net minimum lease payments 297,769
Less: Current portion (4,087)
---------
Long-term balance $ 293,682
=========
- --------------------------------------------------------------------------------
The capital leases provide that Oglethorpe's rental payments vary to the
extent of interest rate changes associated with the debt used by the lessors to
finance their purchase of undivided ownership shares in Scherer Unit No. 2. The
debt of three of the lessors is financed at fixed interest rates averaging
9.64%9.70%. As of December 31, 1995,1996, the variable interest rates of the debt of the
remaining lessor ranged from 5.93%6.40% to 8.05% for an average rate of 6.99%6.83%.
Oglethorpe's future rental payments under its leases will vary from amounts
shown in the table above to the extent that the actual interest rates associated
with the fixed and variable rate debt of the lessors vary from the 11.05% debt
rate assumed in the table.
The Scherer Unit No. 2 lease meets the definitional criteria to be reported
on Oglethorpe's balance sheets as a capital lease. For rate-making purposes,
however, Oglethorpe treats this lease as an operating lease; that is, Oglethorpe
considers the actual rental payment on the leased asset in its cost of service.
Oglethorpe's accounting treatment for this capital lease has been modified,
therefore, to reflect its rate-making treatment. Interest expense is applied to
the obligation under the capital lease; then, amortization of the leasehold is
recognized, such that interest and amortization equal the actual rental payment.
Through 1994, the level of actual rental payments was such that amortization of
the Scherer Unit No. 2 leasehold calculated in this manner was less than zero.
Thereafter, the scheduled cash rental payments increase
46
such that positive
amortization of the leasehold occurs and the entire cost of the leased asset is
recovered through the rate-making process. The difference in the amortization
recognized in this manner on the statements of revenues and expenses and the
straight-line amortization of the leasehold is reflected on Oglethorpe's balance
sheets as a deferred charge.
In 1991 and 1992, all four of the lessors received Notices of Proposed
Adjustments from the IRS proposing adjustments to the tax benefits claimed by
these lessors in connection with their purchase and ownership of an undivided
interest in Scherer Unit No 2. In 1994, the IRS issued a revised Notice of
Proposed Adjustments to one of the lessors which reduced the proposed
adjustments. During 1995, this lessor advised Oglethorpe that it had settled
this issue on the basis of the revised Notice of Proposed Adjustments.
Oglethorpe subsequently made a lump sum indemnity payment of $362,000 to the
lessor in order to compensate for the reduction in the lessor's tax benefits
resulting from the sale and leaseback transaction. The IRS has indicated that it
will take consistent positions with the other three lessors. If the IRS's
current positions regarding the sale and leaseback transactions were ultimately
upheld, Oglethorpe would be required to indemnify the other three lessors.
Oglethorpe's indemnification liability to the three lessors is estimated to be
approximately $1,150,000$1,290,000 as of December 31, 1995.1996. This liability has been
reflected on the accompanying balance sheet as of this
date.sheet.
5. LONG-TERM DEBT:Long-term debt:
Long-term debt consists of mortgage notes payable to the United States of
America acting through the FFB and the RUS, mortgage notes issued in conjunction
with the sale by public authorities of pollution control revenue bonds, and
notes payable to CoBank. Oglethorpe's headquarters facility is pledged as
collateral for the CoBank headquarters note; substantially all of the owned
tangible and certain of the intangible assets of Oglethorpe are pledged as
collateral for the FFB and RUS notes, the remaining CoBank notes and the notes
issued in conjunction with the sale of pollution control revenue bonds. The
detail of the notes is included in the statements of capitalization.
Oglethorpe currently has ten RUS-guaranteed FFB notes of which $3,253,636,000$3,172,851,000
and $3,161,550,000$3,253,636,000 were outstanding at December 31, 19951996 and 1994,1995, respectively,
with rates ranging from 5.67%5.27% to 10.78%9.51%.
In January 1995, Oglethorpe prepaid two FFB advances totaling $29,940,000
of principal plus a premium equal to one year's interest of $3,163,000. The
premium will be reported as a deferred charge on the balance sheet and will
be amortized over 22 years, the remaining life of the prepaid advances.
In January 1995, Oglethorpe refinanced in a non-cash transaction
$284,759,000 of FFB advances.In connection with this refinancing, a premium
of $44,870,000 was incurred. This premium was financed by adding the amount
to the outstanding balances of the refinanced advances for a total refunding
debt of $329,629,000. Additionally, a fee of $1,122,000 was paid in cash for
the ability to finance the premium. The combined premium and fee of
$45,992,000 is reported as a deferred charge on the balance sheets and will
be amortized over the remaining life of the refinanced advances. Oglethorpe
has the option to set the maturities for each advance for a term as short as
three months. As of December 31, 1995, the remaining maturities on these
advances ranged from three months to 21 months.
In December 1995, Oglethorpe completed a current refunding transaction
whereby $21,670,000 of fixed rate pollution control revenue bonds were
issued. The proceeds of this transaction were used to retire $21,670,000 of
existing bonds. The unamortized transaction costs related to this transaction
total $287,000. This amount has been reported as a deferred charge on the
balance sheet and is being amortized over the life of the related bonds.
The proceeds from the December 1995, current refunding were held in debt
service reserve funds until the retirement of the bonds occurred in January
1996. At December 31, 1995, Oglethorpe accounted for the pending retirement
as an in-substance defeasance. Therefore, the cash held in debt service
reserve funds, bonds payable, and premium on reacquired debt are stated as
though the event of retiring the refunded bonds had occurred in 1995. In January 1996, Oglethorpe completed
note modifications pursuant to which it repriced $89,447,000 of FFB advances. In
connection with such modification, Oglethorpe paid a premium of $9,332,000.
These amounts will beare reported as deferred charges on the balance sheet, and will be
amortized over 22 years, the longest remaining life of the subject advances.
54
In October 1996, Oglethorpe completed a current refunding transaction whereby
$37,885,000 of fixed rate pollution control revenue bonds were issued. The
proceeds of this transaction were used to retire $37,885,000 of existing bonds.
The unamortized transaction costs related to this transaction have been reported
as a deferred charge on the balance sheet and are being amortized over the life
of the related bonds.
The annual interest requirement for 1996, based upon all debt outstanding
at December 31, 1995, will1997 is estimated to be approximately $290,000,000.$294,000,000.
Maturities for the long-term debt through 20002001 are as follows:
...................................................................................
(DOLLARS IN THOUSANDS) 1996 1997 1998 1999 2000
...................................................................................
FFB and RUS $ 82,026 $ 77,499 $ 82,744 $ 86,743 $ 94,897
CoBank 478 489 502 516 532
1982 Bonds -- 6,675 -- -- --
1992A Bonds -- 5,070 5,330 5,615 5,925
1992 Bonds -- -- 2,085 2,240 2,405
1993A Bonds -- -- 2,265 2,410 2,595
1993B Bonds -- 9,810 6,490 6,695 7,770
1993Bonds 855 875 900 935 1,135
1994A Bonds -- -- -- -- 2,240
1994B Bonds -- 1,335 550 1,465 1,540
1994 Bonds 325 330 350 370 385
Capital Leases 5,991 2,795 5,143 6,240 7,075
-------- -------- -------- -------- --------
Total $ 89,675 $104,878 $106,359 $113,229 $126,499
-------- -------- -------- -------- --------
-------- -------- -------- -------- --------
...................................................................................
- --------------------------------------------------------------------------------
(dollars in thousands) 1997 1998 1999 2000 2001
- --------------------------------------------------------------------------------
FFB and RUS $147,279 $ 86,894 $ 91,123 $ 98,867 $105,941
CoBank 376 502 516 532 550
PCB Bonds 7,880 17,970 19,730 23,995 26,260
Capital Leases 4,087 5,143 6,240 7,075 7,775
-------- -------- -------- -------- --------
Total $159,622 $110,509 $117,609 $130,469 $140,526
======== ======== ======== ======== ========
- --------------------------------------------------------------------------------
The estimated annual interest expense and the long-term debt maturities
described above do not take into account Oglethorpe's proposed corporate
restructuring, discussed in Note 11.
Oglethorpe has a commercial paper program under which it may issue commercial
paper not to exceed a $300,000,000$250,000,000 balance outstanding at any time. The
commercial paper may be used as a source of short-term fundsfor working capital requirements and is not
intended for any specific purpose.general
corporate purposes. Oglethorpe's commercial paper is backed 100% by committed
lines of credit provided by a group of banks.
As of December 31, 19951996 and 1994,1995, no commercial paper was outstanding.
Oglethorpe has arranged fora $50,000,000 uncommitted short-term linesline of
47
credit with CoBank and CFC
and a $30,000,000 committed line of credit with SunTrust Bank, Atlanta
(SunTrust). The CoBank line amounts to $70,000,000; the CFC line
amounts to $50,000,000; and the SunTrust line amounts to $30,000,000. The
maximum combined amount that can be outstanding under these
lines of credit and the commercial paper program at any one time totals
$370,000,000$250,000,000 due to certain restrictions contained in the CFC and SunTrust line
of credit agreements. No balance was outstanding on anyeither of these threetwo lines of
credit at either December 31, 19951996 or 1994.1995.
6. ELECTRIC PLANT AND RELATED AGREEMENTS:Electric plant and related agreements:
Oglethorpe and GPC have entered into agreements providing for the purchase
and subsequent joint operation of certain of GPC's electric generating plants
and transmission facilities. A summary of Oglethorpe's plant investments and
related accumulated depreciation as of December 31, 19951996 is as follows:
...................................................................................
(DOLLARS IN THOUSANDS) Accumulated
Plant Investment Depreciation
...................................................................................
In-service
Owned property
Vogtle Units No. 1 & No. 2
(NUCLEAR - 30% OWNERSHIP) $2,779,362 $ 594,553
Hatch Units No. 1 & No. 2
(NUCLEAR - 30% OWNERSHIP) 516,154 198,082
Wansley Units No. 1 & No. 2
(FOSSIL - 30% OWNERSHIP) 171,453 82,842
Scherer Unit No. 1
(FOSSIL - 60% OWNERSHIP) 429,553 184,513
Rocky Mountain Units No. 1,
No. 2 & No. 3
(HYDRO - 74.6% OWNERSHIP) 549,750 6,203
Tallassee (Harrison Dam)
(HYDRO - 100% OWNERSHIP) 9,282 1,641
Wansley (COMBUSTION TURBINE -
30% OWNERSHIP) 3,665 1,181
Transmission and distribution plant 823,087 176,553
Other 117,794 33,796
Property under capital lease
Scherer Unit No. 2
(FOSSIL - 60% LEASEHOLD) 299,113 83,067
---------- ----------
Total in-service $5,699,213 $1,362,431
---------- ----------
---------- ----------
Construction work in progress
Generation improvements $ 17,021
Transmission and distribution plant 18,258
Other 474
----------
Total construction work in progress $ 35,753
----------
----------
...................................................................................
- --------------------------------------------------------------------------------
(dollars in thousands)
Accumulated
Plant Investment Depreciation
- --------------------------------------------------------------------------------
In-service
Owned property
Vogtle Units No. 1 & No. 2
(Nuclear - 30% ownership) $2,781,446 $ 665,953
Hatch Units No. 1 & No. 2
(Nuclear - 30% ownership) 523,163 208,687
Wansley Units No. 1 & No. 2
(Fossil - 30% ownership) 173,192 84,388
Scherer Unit No. 1
(Fossil - 60% ownership) 429,299 193,129
Rocky Mountain Units No. 1,
No. 2 & No. 3
(Hydro - 74.6% ownership) 556,470 17,401
Tallassee (Harrison Dam)
(Hydro - 100% ownership) 9,270 1,797
Wansley (Combustion Turbine -
30% ownership) 3,718 1,319
Generation step-up substations 55,877 19,173
Transmission and distribution plant 815,929 179,960
Other 94,002 25,060
Property under capital lease
Scherer Unit No. 2
(Fossil - 60% leasehold) 300,231 91,405
---------- ----------
Total in-service $5,742,597 $1,488,272
========== ==========
Construction work in progress
Generation improvements $ 11,963
Transmission and distribution plant 18,715
Other 503
----------
Total construction work in progress $ 31,181
==========
- --------------------------------------------------------------------------------
In 1988, Oglethorpe acquired from GPC an undivided ownership interest in
the Rocky Mountain Project, a pumped storage hydroelectric facility (Rocky
Mountain).Mountain. Under the Rocky Mountain agreements, Oglethorpe assumed
responsibility for construction of the facility, which was commenced by GPC.
Under the agreements, GPC retained its current investment in Rocky Mountain with
the ultimate ownership interests of Oglethorpe and GPC in the facility based on
the ratio of each party's direct construction costs to total project direct
construction costs with certain adjustments.
On June 1, 1995, Unit 3 and the completed Unit Common facilities were
declared to be in commercial operation by Oglethorpe. Unit 2 and Unit 1 were
declared to be in commercial operation on June 19, 1995 and July 24, 1995,
respectively. In accordance with the Rocky Mountain agreements, the final
ownership interests of Oglethorpe and GPC in Rocky Mountain is 74.6% and 25.4%,
respectively. The final ownership interests in the project will be applied to
all future capital costs.
55
Oglethorpe is engaged in a continuous construction program and, as of
December 31, 1995,1996, estimates property additions (including capitalized interest)
to be approximately $113,000,000 in 1996, $106,000,000$108,000,000 in 1997, and
$103,000,000$98,000,000 in 1998 and $100,000,000
in 1999, primarily for replacements and additions to generation and transmission
facilities.
Oglethorpe's proportionate share of direct expenses of joint operation of the
above plants is included in the corresponding operating expense captions (e.g.,
fuel, production or depreciation) on the accompanying statements of revenues and
expenses.
7. EMPLOYEE BENEFIT PLANS:Employee benefit plans:
Oglethorpe has a noncontributory defined benefit pension plan covering
substantially all employees. Oglethorpe's pension cost was approximately
$1,388,000 in 1996, $1,954,000 in 1995 and $1,262,000 in 1994 and $1,038,000 in 1993.1994. For 1995, pension
cost increased by $912,000 related to termination benefits. The termination
benefits resulted from an early retirement program undertaken in the fourth
quarter of 1995. Plan benefits are based on years of service and the employee's
compensation during the last ten years of employment. Oglethorpe's funding
policy is to contribute annually an amount not less than the minimum required by
the Internal Revenue Code and not more than the maximum tax deductible amount.
The plan's pension cost recognized in 1996, 1995 and 1994 and 1993 iswas shown as
follows:
...................................................................................
(DOLLARS IN THOUSANDS) 1995 1994 1993
...................................................................................
Pension cost was comprised of the
following
Service cost - benefits earned
during the year $ 913 $ 1,084 $ 884
Interest cost on projected benefit
obligation 742 714 617
Actual return on plan assets (1,889) 387 (698)
Net amortization and deferral 1,288 (911) 247
Net gain from a plan curtailment (12) (12) (12)
------- ------- -------
Net pension cost $ 1,042 $ 1,262 $ 1,038
------- ------- -------
------- ------- -------
...................................................................................
48
- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995 1994
- --------------------------------------------------------------------------------
Pension cost was comprised of the
following
Service cost - benefits earned
during the year $ 1,149 $ 913 $ 1,084
Interest cost on projected benefit
obligation 872 742 714
Actual return on plan assets (984) (1,889) 387
Net amortization and deferral 351 1,288 (911)
Net gain from a plan curtailment -- (12) (12)
------- ------- -------
Net pension cost $ 1,388 $ 1,042 $ 1,262
======= ======= =======
- --------------------------------------------------------------------------------
The plan's funded status in Oglethorpe's financial statements as of December
31, 19951996 and 19941995 were as follows:
...........................................................................
(DOLLARS IN THOUSANDS) 1995 1994
...........................................................................
Actuarial present value of accumulated
plan benefits
Vested $ 6,868 $ 5,281
Nonvested 591 380
-------- --------
$ 7,459 $ 5,661
-------- --------
-------- --------
Projected benefit obligation $(12,326) $ (9,276)
Plan assets at fair value 7,760 7,282
-------- --------
Projected benefit obligation in excess of
plan assets (4,566) (1,994)
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions 223 (861)
Prior service cost not yet recognized
in net periodic pension cost 548 598
Unrecognized net asset at transition date
being recognized over 19 years (121) (133)
-------- --------
Pension accrual $ (3,916) $ (2,390)
-------- --------
-------- --------
...........................................................................
- --------------------------------------------------------------------------------
(dollars in thousands) 1996 1995
- --------------------------------------------------------------------------------
Actuarial present value of accumulated
plan benefits
Vested $ 7,554 $ 6,868
Nonvested 540 591
-------- --------
$ 8,094 $ 7,459
======== ========
Projected benefit obligation $(13,211) $(12,326)
Plan assets at fair value 9,218 7,760
-------- --------
Projected benefit obligation in excess of
plan assets (3,993) (4,566)
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions (880) 223
Prior service cost not yet recognized in net
periodic pension cost 498 548
Unrecognized net asset at transition date
being recognized over 19 years (109) (121)
-------- --------
Pension accrual $ (4,484) $ (3,916)
======== ========
- --------------------------------------------------------------------------------
The discount rate and rate of increase in future compensation levels used in
determining the actuarial present value of the projected benefit obligations
shown above were 7.50% and 5.0% in 1996, and 7.25% and 5.0% in 1995, and 8.5% and 5.0% in
1994,
respectively. The expected long-term rate of return on plan assets was 8.5% in
1996 and 1995, and 8% in 1994, and 1993, and the discount rate used in determining the
pension expense was 7.25% in 1996, 8.5% in 1995 and 7.5% in 1994 and 8.5% in
1993.1994.
Oglethorpe has a contributory employee thriftretirement savings plan covering
substantially all employees. Employee contributions to the plan may be invested
in one or more of threenine funds. The employee may contribute, subject to
IRS limitations,IRSlimitations, up to 16% of his annual compensation. Oglethorpe will match the
employee's contribution up to one-half of the first 6% of the employee's annual
compensation, as long as there is sufficient net margin to do so. Oglethorpe's
contributions to the plan were approximately $561,000 in 1996, $589,000 in 1995
and $565,000 in 1994 and $503,000 in 1993.1994.
8. NUCLEAR INSURANCE:Nuclear insurance:
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member
of Nuclear Mutual Limited (NML), a mutual insurer established to provide
property damage insurance coverage in an amount up to $500,000,000 for members'
nuclear generating facilities. In the event that losses exceed accumulated
reserve funds, the members are subject to retroactive assessments (in proportion
to their participation in the mutual insurer). The portion of the current
maximum annual assessment for GPC that would be payable by Oglethorpe, based on
ownership share, adjusted for sell-back, is limited to approximately $7,220,000$6,351,000 for each nuclear
incident.
56
GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is also a
member of Nuclear Electric Insurance Limited (NEIL), a mutual insurer, and
Oglethorpe has coverage under NEIL II, and NEIL III, which provideprovides insurance to cover
decontamination, debris removal and premature decommissioning as well as excess
property damage to nuclear generating facilities for an additional
$2,250,000,000 for losses in excess of the $500,000,000 NML coverage described
above. Under the NEIL policies, members are subject to retroactive assessments
in proportion to their participation if losses exceed the accumulated funds
available to the insurer under the policy. The portion of the current maximum
annual assessment for GPC that would be payable by Oglethorpe, based on
ownership share, adjusted for sell-back, is limited to approximately $13,980,000.$12,960,000.
For all on-site property damage insurance policies for commercial nuclear
power plants, the NRC requires that the proceeds of such policies issued or
annually renewed on or after April 2, 1991 shall be dedicated first for the sole
purpose of placing the reactor in a safe and stable condition after an accident.
Any remaining proceeds are next to be applied toward the costs of
decontamination and debris removal operations ordered by the NRC, and any
further remaining proceeds are to be paid either to the company or to its bond
trustees as may be appropriate under the policies and applicable trust
indentures.
The Price-Anderson Act, as amended in 1988, limits public liability claims
that could arise from a single nuclear incident to $8,900,000,000, which amount
is to be covered by private insurance and agreements of indemnity with the NRC.
Such private insurance (in the amount of $200,000,000 for each plant, the
maximum amount currently available) is carried by GPC for the benefit of all the
co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered
into by and between each of the co-owners and the NRC. In the event of a nuclear
incident involving any commercial nuclear facility in the country involving
total public liability in excess of $200,000,000, a licensee of a nuclear power
plant could be assessed a deferred premium of up to $79,275,000 per incident for
each licensed reactor operated by it, but not more than $10,000,000 per reactor
per incident to be paid in a calendar year. On the basis of its sell-back
adjusted ownership interest in four nuclear reactors, Oglethorpe could be
assessed a maximum of $95,130,000 per incident, but not more than $12,000,000 in
any one year.
Oglethorpe participates in an insurance program for nuclear workers that
provides coverage for worker tort claims filed for bodily injury caused at
commercial nuclear power plants. In the event that claims for this insurance
exceed the accumulated reserve funds, Oglethorpe could be subject to a total
maximum assessment of $3,360,000.$3,365,000.
All retrospective assessments, whether generated for liability or property,
may be subject to applicable state premium taxes.
9. POWER PURCHASE AND SALE AGREEMENTS:Power purchase and sale agreements:
Oglethorpe has entered into long-term power purchase agreements with GPC, Big
Rivers Electric Corporation (Big Rivers), and Entergy Power, Inc. (EPI). Under
the agreement with GPC, Oglethorpe will purchasepurchased on a take-or-pay basis 1,250
megawatts (MW) of capacity through the period ending August 31, 1996. Effective
September 1, 1996, Oglethorpe will purchase 1,000 MW of capacity through the
period ending 49
August 31, 1997. Effective September 1, 1997, Oglethorpe will
purchase 750 MW of capacity through the period ending August 31, 1998. Effective
September 1,1998, Oglethorpe will purchase 500 MW of capacity through the period
ending December 31, 2003,31,2004, subject to reductions or extension with proper notice.
The Big Rivers agreement commenced in August 1992 and is effective through July
2002. Oglethorpe is obligated under this agreement to purchase on a take-or-pay
basis 100 MW of firm capacity and certain minimum energy amounts associated with
that capacity. The EPI agreement commenced in July 1992, has a term of ten years
and represents a take-or-pay commitment by Oglethorpe to purchase 100 MW of
capacity.
Oglethorpe has a contract with Hartwell Energy Limited Partnership for the
purchase of approximately 300 MW of capacity for a 25-year period commencing in
April 1994.
Oglethorpe has entered into a short-term seasonal power purchase agreement
with Florida Power Corporation. Under the agreement, Oglethorpe will purchase 50
MW of capacity on a take-or-pay basis for the period June 1, 1997 through
September 30, 1997 and 275 MW for the period June 1, 1998 through September 30,
1998.
As of December 31, 1995,1996, Oglethorpe's minimum purchase commitments under the
above agreements, without regard to capacity reductions or adjustments for
changes in costs, for the next five years are as follows:
...........................................................................
Year Ending December 31, (dollars in thousands)
...........................................................................
1996 $ 149,835
1997 130,843
1998 119,948
1999 118,061
2000 121,179
...........................................................................
- --------------------------------------------------------------------------------
Year Ending December 31, (dollars in thousands)
- --------------------------------------------------------------------------------
1997 $ 130,457
1998 111,539
1999 92,873
2000 94,917
2001 97,116
- --------------------------------------------------------------------------------
Oglethorpe's power purchases from these agreements amounted to approximately
$190,760,000 in 1996, $206,641,000 in 1995 and $182,965,000 in 1994 and $192,059,000 in 1993.1994.
Oglethorpe has entered into an agreement with Alabama Electric Cooperative to
sell 100 MW of
57
capacity for the period June 1998 through December 2005.
10. SUBSEQUENT EVENT:
On January 3,As a means of reducing the cost of power provided to the Members, in 1996,
Oglethorpe entered into autilized short-term power supply swapagreements. The initial agreement
was with Enron Power Marketing, Inc. (EPMI). The agreement, effectiveand was in place from January 4, 1996
through April 30,August 31, 1996. From September 1, 1996 requires EPMIthrough December 31, 1996,
Oglethorpe utilized a short-term power supply transaction with Duke/Louis
Dreyfus L.L.C. Under both of the agreements, the power marketer was required to
sellprovide to Oglethorpe at a favorable fixed costrate all the energy needednecessary to servemeet
the Members (approximately 5.2 million
megawatt-hours). Per the agreement,Members' requirements and Oglethorpe iswas required to sellprovide to EPMIthe power
marketer at cost, subject to certain cost limitations, upon request all energy
available from Oglethorpe's total power resources. EPMI hasUnder both agreements,
Oglethorpe continued to operate the option to market any excess
energy that remains from Oglethorpe's total power resources. Oglethorpe is
considering a similar power supply swap for a longer term basis.
In order to provide its Members with greater flexibility for meeting their
power supply needs in an increasingly competitive utility environment, a plan
was approved by Oglethorpe's Board of Directors in December 1995 to divide
Oglethorpe into three specialized companies to respond to increasing
competition in the electric industry and related changes in law and
regulation. The December plan proposed the creation of a new transmission
company that would own and operate the transmission system and provides
servicescontinued to
dispatch the Members, and a new systems operations company that would own
and operate the systems operation services for the Members, Oglethorpe and
third parties. Oglethorpe would retain the generation business and would
operate as the power supplier for the Members. Oglethorpe is continuinggenerating resources to develop and refine the restructuring plan, and subject to receiving
governmental and other third party approvals, the current target date for
full implementation of the restructuring is January 1, 1997.
11. QUARTERLY FINANCIAL DATA (UNAUDITED)ensure system reliability.
10. Quarterly financial data (unaudited):
Summarized quarterly financial information for 19951996 and 19941995 is as follows:
...........................................................................
First Second Third Fourth
(DOLLARS IN THOUSANDS) Quarter Quarter Quarter Quarter
...........................................................................
1995
Operating revenues $257,547 $281,228 $317,536 $293,250
Operating margin 68,682 82,048 82,949 74,998
Net margin 8,462 20,292 10,656 (17,152)
1994
Operating revenues $267,618 $263,035 $266,818 $258,611
Operating margin 81,882 75,704 68,087 61,734
Net margin 20,184 13,511 4,386 (14,999)
...........................................................................
- --------------------------------------------------------------------------------
First Second Third Fourth
(dollars in thousands) Quarter Quarter Quarter Quarter
- --------------------------------------------------------------------------------
1996
Operating revenues $270,689 $275,228 $286,648 $ 268,872
Operating margin 73,568 72,514 75,009 61,658
Net margin 8,988 4,732 12,508 (4,476)
1995
Operating revenues $257,547 $281,228 $317,536 $ 293,250
Operating margin 68,682 82,048 82,949 74,998
Net margin 8,462 20,292 10,656 (17,152)
- --------------------------------------------------------------------------------
Oglethorpe's business is influenced by seasonal weather conditions. First
and thirdSecond
quarter 19951996 net margins weremargin was lower than the same periodsperiod of 1994.
Historically, most1995 primarily as a
result of Oglethorpe's annual net margin was earned by May 31 of
each year. This pattern of earning occurred because non-Member revenues
declined significantly on June 1 of each year through the end of such year
due to scheduled reductionsunbudgeted savings in capacity sell-back to GPC while monthly fixed
costs recovered from Members remained virtually unchanged throughout the
year. Member capacity revenues reflect recovery in nearly equal monthly
amounts of all budgeted fixed costs plus the annual net margin goal, less
fixed costs projected to be recovered from GPC pursuant to plant operating
agreements. The capacity sell-back arrangement with GPC expired on May 31,
1995. For a discussion of the GPC capacity sell-back arrangement, see Note 1.
The higher net margin for the second quarter 1995 compared to 1994
resulted from unbudgeted savings from the continued capitalization of costs
of Rocky Mountain due to the delay in commercial operation of the initial unit from
April 1995 to June 1995.
The negative net marginsmargin for the fourth quarter of 1996 is consistent with
expectations and reflects incurrence of certain nonrecurring expenses.
The negative net margin for the fourth quarter of 1995 and 1994 werewas primarily
attributable to the deferral of excess margins.margin. For a discussion of the amountsamount of
excess marginsmargin deferred, see Note 1.
5011. Subsequent events:
a. Power supply arrangements
Oglethorpe has entered into power supply agreements for approximately 50% of
its Members' load requirements with LG&E Power Marketing Inc. These agreements
commenced on January 1, 1997, initially on a short-term basis. These agreements
converted to a long-term arrangement upon the closing of the Corporate
Restructuring discussed below. Oglethorpe is now working to complete a long-term
contract for the remaining approximately 50% of its load.
b. Corporate restructuring
Oglethorpe and the Members completed on March 11, 1997, a corporate
restructuring (the Corporate Restructuring). Pursuant to the Corporate
Restructuring, Oglethorpe divided itself into three specialized companies to
respond to increasing competition and deregulation in the electric industry. As
part of the Corporate Restructuring, Oglethorpe transferred its transmission
business and assets to a newly formed Georgia electric membership corporation,
Georgia Transmission Corporation (An Electric Membership Corporation) (GTC), and
transferred its system operations business to a newly formed Georgia nonprofit
corporation, Georgia System Operations Corporation (GSOC). Oglethorpe retained
its generation business and owned and leased generation assets.
The following unaudited pro-forma balance sheet as of December 31, 1996
reflects the financial position of Oglethorpe as reported and as restated
reflecting the exclusion of the transmission business as though the Corporate
Restructuring had occurred at December 31, 1996.
The following unaudited pro-forma statement of revenues and expenses for the
year ended December 31, 1996 reflects the operations of Oglethorpe as reported
and as restated, reflecting the exclusion of the transmission business as though
the Corporate Restructuring had occurred at the beginning of 1996.
These unaudited pro-forma financial statements have been prepared based on
assumptions and estimates deemed appropriate and are presented for illustrative
purposes only and are not necessarily indicative of the financial position or
results of operations which would have actually been reported had the
transactions occurred in the period reported.
The columns titled Oglethorpe post-restructuring in the following unaudited
pro-forma financial statements have been restated reflecting the exclusion of
the system operations business as though the Corporate Restructuring had
occurred in the period reported. The system operations business is not shown
separately due to immateriality.
58
Pro-Forma Balance Sheet
(Unaudited)
As of December 31,1996
(dollars in thousands)
- ------------------------------------------------------------------------------------------------------------------------------------
Oglethorpe Transmission
Oglethorpe Pro-Forma Pro-Forma
(Pre- (Post- (Post-
Restructuring) Restructuring) Restructuring)
- ------------------------------------------------------------------------------------------------------------------------------------
Assets
Electric plant, at original cost:
In service $ 5,742,597 $ 4,908,752 $ 815,929
Less: Accumulated provision for depreciation (1,488,272) (1,299,328) (179,960)
----------- ----------- -----------
4,254,325 3,609,424 635,969
Nuclear Fuel, at amortized cost 86,722 86,722 --
Plant acquisition adjustments, at amortized cost 4,153 -- 8,780
Construction work in progress 31,181 12,466 18,715
----------- ----------- -----------
4,376,381 3,708,612 663,464
----------- ----------- -----------
Investments and funds 197,288 200,812 --
----------- ----------- -----------
Current assets:
Cash and temporary cash investments, at cost 224,282 245,424 --
Receivables 113,289 113,289 --
Inventories, at average cost 89,825 84,018 5,807
Prepayments and other current assets 14,625 14,264 361
----------- ----------- -----------
442,021 456,995 6,168
----------- ----------- -----------
Deferred charges:
Premium and loss on reacquired debt,
being amortized 201,007 169,081 31,926
Deferred debt expense, being amortized 21,703 18,256 3,447
Other 123,775 123,775 --
----------- ----------- -----------
346,485 311,112 35,373
----------- ----------- -----------
$ 5,362,175 $ 4,677,531 $ 705,005
=========== =========== ===========
Equities and Liabilities
Capitalization:
Patronage capital and membership fees $ 356,229 $ 356,229 $ --
Long-term debt 4,052,470 3,380,581 688,878
Obligations under capital leases 293,682 293,682 --
Obligations under Rocky Mountain
transactions 41,685 41,685 --
----------- ----------- -----------
4,744,066 4,072,177 688,878
----------- ----------- -----------
Current liabilities:
Long-term debt and capital leases due
within one year 159,622 144,565 15,057
Accounts payable 42,891 41,788 --
Accrued interest 15,931 15,931 --
Accrued and witheld taxes 4,940 4,940 --
Other current liabilities 14,022 12,799 1,070
----------- ----------- -----------
237,406 220,023 16,127
----------- ----------- -----------
Deferred credits and other liabilities 380,703 385,331 --
----------- ----------- -----------
$ 5,362,175 $ 4,677,531 $ 705,005
=========== =========== ===========
- ------------------------------------------------------------------------------------------------------------------------------------
Pro-Forma Statement of Revenues and Expenses
(Unaudited)
For the year ended December 31,1996
(dollars in thousands)
- ------------------------------------------------------------------------------------------------------------------------------------
Oglethorpe Transmission
Oglethorpe Pro-Forma Pro-Forma
(Pre- (Post- (Post-
Restructuring) Restructuring) Restructuring)
- ------------------------------------------------------------------------------------------------------------------------------------
Operating revenues:
Sales to Members $ 1,023,094 $ 927,156 $ 95,938
Sales to non-Members 78,343 68,554 9,789
----------- ----------- -----------
Total operating revenues 1,101,437 995,710 105,727
----------- ----------- -----------
Operating expenses:
Fuel 206,524 206,524 --
Production 129,178 129,178 --
Purchased power 229,089 229,089 --
Power delivery 18,216 -- 18,216
Depreciation and amortization 163,130 138,008 25,122
Taxes other than income taxes 30,262 22,728 7,534
Other operating expenses 42,289 33,307 8,982
----------- ----------- -----------
Total operating expenses 818,688 758,834 59,854
----------- ----------- -----------
Operating margin 282,749 236,876 45,873
----------- ----------- -----------
Other income (expense):
Interest income 23,485 20,129 3,356
Amortization of deferred margins 32,047 29,336 2,711
Allowance for equity funds used during
construction 238 114 124
Other 9,564 10,270 (706)
----------- ----------- -----------
Total other income 65,334 59,849 5,485
----------- ----------- -----------
Interest charges:
Interest on long-term debt and other obligations 328,907 279,542 49,365
Allowance for debt funds used during
construction (2,576) (1,231) (1,345)
----------- ----------- -----------
Net interest charges 326,331 278,311 48,020
----------- ----------- -----------
Net margin $ 21,752 $ 18,414 $ 3,338
=========== =========== ===========
- ------------------------------------------------------------------------------------------------------------------------------------
The above pro-forma balance sheet reflects the transfer of the transmission
and system operations businesses, and the related financing activities related
to the transfer based on the purchase price formula. In connection with the
Corporate Restructuring, Oglethorpe also made a special patronage capital
distribution to the Members totaling $48,863,000 which was used by the Members
to establish equity in and to provide initial working capital to GTC.
59
REPORT OF MANAGEMENT
The management of Oglethorpe Power Corporation has prepared this report and
is responsible for the financial statements and related information. These
statements were prepared in accordance with generally accepted accounting
principles appropriate in the circumstances and necessarily include amounts that
are based on best estimates and judgments of management. Financial information
throughout this annual report is consistent with the financial statements.
Oglethorpe maintains a system of internal accounting controls to provide
reasonable assurance that assets are safeguarded and that the books and records
reflect only authorized transactions. Limitations exist in any system of
internal control based upon the recognition that the cost of the system should
not exceed its benefits. Oglethorpe believes that its system of internal
accounting control, together with the internal auditing function, maintains
appropriate cost/benefit relations.
Oglethorpe's system of internal controls is evaluated on an ongoing basis by
its qualified internal audit staff. The Corporation's independent public
accountants (Coopers & Lybrand L.L.P.) also consider certain elements of the
internal control system in order to determine their auditing procedures for the
purpose of expressing an opinion on the financial statements.
Coopers & Lybrand L.L.P. also provides an objective assessment of how well
management meets its responsibility for fair financial reporting. Management
believes that its policies and procedures provide reasonable assurance that
Oglethorpe's operations are conducted with a high standard of business ethics.
In management's opinion, the financial statements present fairly, in all
material respects, the financial position, results of operations, and cash flows
of Oglethorpe Power Corporation.
T. D. Kilgore
President and Chief Executive Officer
Eugen Heckl
Senior Vice President and
Chief Financial Officer
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Oglethorpe Power Corporation:
We have audited the accompanying balance sheetsheets and statementstatements of
capitalization of Oglethorpe Power Corporation (a Georgia corporation) as of
December 31, 1996 and 1995 and the related statements of revenues and expenses,
patronage capital, and cash flows for the yearyears then ended. These financial
statements are the responsibility of Oglethorpe's management. Our
responsibility is to express an opinion on these financial statements based
on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to
obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Oglethorpe Power
Corporation as of December 31, 1995 and the results of its operations and its
cash flows for the year then ended in conformity with generally accepted
accounting principles.
Coopers & Lybrand L.L.P.
Atlanta, Georgia,
February 28, 1996.
51
REPORT OF INDEPENDENT
PUBLIC ACCOUNTANTS
To the Board of Directors of Oglethorpe Power Corporation:
We have audited the accompanying balance sheet and statement of
capitalization of Oglethorpe Power Corporation (a Georgia corporation) as of
December 31, 1994 and the related statements of revenues and expenses,
patronage capital, and cash flows for each of the two years in the period
ended December 31, 1994. These financial
statements are the responsibility of Oglethorpe's management. Our responsibility
is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Oglethorpe Power Corporation as
of December 31, 19941996 and 1995 and the results of its operations and its cash
flows for eachthe years then ended in conformity with generally accepted accounting
principles.
Coopers & Lybrand L.L.P.
Atlanta, Georgia,
February 21, 1997, except for Note 11, as to which the date is March 11,
1997.
60
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Board of Directors of Oglethorpe Power Corporation:
We have audited the two yearsstatement of revenues and expenses, patronage capital,
and cash flows of Oglethorpe Power Corporation (a Georgia corporation) for the
year ended December 31, 1994. These financial statements are the responsibility
of Oglethorpe's management. Our responsibility is to express an opinion on these
financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the periodfinancial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audit provides a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in
all material respects, the results of operations, changes in patronage capital,
and cash flows of Oglethorpe Power Corporation for the year ended December 31,
1994 in conformity with generally accepted accounting principles.
As explained in Note 2 of notes to financial statements, effective January 1,
1994, Oglethorpe Power Corporation changed its method of accounting for certain
investments in debt and equity securities.
As explained in Note 3 of
notes to financial statements, effective January 1, 1993, Oglethorpe changed
its method of accounting for income taxes.
Arthur Andersen LLP
Atlanta, Georgia,
February 24, 1995.
5261
ITEMItem 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
PART III
ITEMItem 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
(A) IDENTIFICATION OF DIRECTORS:(a) Identification of Directors:
As part of the Corporate Restructuring, Oglethorpe amended its Bylaws
to provide for an eleven member board of directors consisting of six directors
elected from the Members (the "Member Directors"), four independent outside
directors (the "Outside Directors") and Oglethorpe's President and Chief
Executive Officer. The Member Directors must be a director or general manager of
an Oglethorpe Member. Five of the six Member Directors must be located in one of
five geographical regions of the State of Georgia. The sixth Member Director is
governedelected statewide. The four Outside Directors must not be a director, officer or
employee of Oglethorpe or any Member. All eleven directors are nominated by
representatives from each Member whose weighted nomination is based on the
number of retail customers served by each Member. After nomination, the
directors are elected by a Boardmajority vote of 39each Member, voting on a one-Member,
one-vote basis.
All of the new directors have been elected with terms beginning on
March 11, 1997, except for two of the four Outside Directors 13which are expected
to be elected at the annual meeting of whom areMembers on March 27, 1997. The Bylaws
provide for staggering the terms of the directors by dividing the number of
directors into three groups. As noted below, some of the directors were elected
eachto an initial term of 1 year, some 2 years and some 3 years. As these initial
terms expire, directors will thereafter be elected for a three-year term. Eachterm of the 39 Members nominates one
Director who must also be on the Member's Board of Directors.three years.
The Directors
are then elected by the Members at their annual meeting. The Members also
elect Alternate Directors. Each Alternate Director must serve as the manager
of a Member to be eligible to serve as an Alternate Director. Under
Oglethorpe's Bylaws, Alternate Directors may attend all Board meetings, but
can be counted for quorum purposes and can exercise the powers and duties of
a Director only during the period when the directorship for whom he is the
alternate is vacant or at any meeting of the Board of Directors when the
Director for whom he is the alternate is absent. The Board of Directors
generally meets monthly. For a discussion of the proposed changes in
Oglethorpe's governance structure in connection with the proposed
restructuring, see "OGLETHORPE POWER CORPORATION-Proposed Restructuring" in
Item 1.
Six standing committees are appointed by the Chairman of the Board
and include both Directors and Alternate Directors. Special committees, as
deemed necessary, are also appointed by the Chairman of the Board or the
Board of Directors. Committee recommendations and management
recommendations, subject to the approval of the Board of Directors, determine
the policies and activities of Oglethorpe.
The Directors and Alternate Directors of Oglethorpe are as follows:
ALTAMAHA EMC
Jmon Warnock--Director,Larry N. Chadwick, age 70, is a farmer. He has served on the
Board of Directors of Oglethorpe since September 1974. His present term as a
Director will expire in March 1998. He is currently a member of the Finance
Committee of Oglethorpe. Mr. Warnock56, is the President of Altamaha EMC and aMember Director of GEMC.
James D. Musgrove--Alternate Director, age 49, isfrom the General
Manager of Altamaha EMC.Northwest
Region. He has served as an Alternate Director of
Oglethorpe since May 1989, with his present term to expire in March 1998.
Mr. Musgrove is a Director of Montgomery County Bankshares in Ailey, Georgia.
AMICALOLA EMC
Charles R. Fendley--Director, age 50, is a Vice President of Jasper
Yarn Processing, Inc., which processes yarn. He has served on the Board of
Directors of Oglethorpe since November 1993, with his present term to expire
in March 1998. Mr. Fendley is the President of Amicalola EMC. He is also a
Director of GEMC and a Director of Crescent Bank & Trust Co. in Jasper,
Georgia.
John S. Dean, Sr.--Alternate Director, age 56, has been General
Manager/Chief Executive Officer of Amicalola EMC since 1974. Prior to his
employment with Amicalola EMC, he was Controller of Pickens General Hospital.
He has served as an Alternate Director of Oglethorpe since 1975, with his
present term to expire in March 1998. He is currently a member of the
Finance Committee. Mr. Dean previously served on Oglethorpe's Operations
Review Committee and Executive Committee and served as Secretary-Treasurer of
Oglethorpe from March 1989 to March 1995. Currently, he is on the Board of
Directors of GRESCO, Southeastern Data Cooperative, Inc., Crescent Bank &
Trust Company, CoBank, and North Georgia Certified Development Corporation.
53
CANOOCHEE EMC
George C. Martin--Director, age 78, is the owner and operator of a
farm in Ellabell, Bryan County, Georgia where he raises beef cattle. He also
manages timberland in Bryan County, Georgia and rental properties in Savannah
and Pembroke, Georgia. Mr. Martin is President of Canoochee EMC. He has
served on the Board of Directors of Oglethorpe since March 1977, with his
present term to expire in March 1998. From March 1978 to March 1984, he
served as Vice President of Oglethorpe.
Donald F. Kennedy--Alternate Director, age 66, is the General
Manager of Canoochee EMC. He has served as an Alternate Director of
Oglethorpe since 1985, with his present term to expire in March 1998. Mr.
Kennedy is also a Director of the Tattnall Bank in Reidsville, Georgia.
CARROLL EMC
J. G. McCalmon--Director, age 78, is the owner of a farm in
Carrollton, Georgia, where he raises chickens and beef cattle. He has served
on the Board of Directors of Oglethorpe since September 1974, with his
present term to expire in March 1999. He currently serves as Vice Chairman
of the Human Resources Management Committee. He is Chairman of the Board of
Carroll EMC. Mr. McCalmon also serves on the Boards of Directors of GEMC,
the Farm Bureau, Carroll County Sales Barn, and the Carroll County Chamber
of Commerce.
Gary M. Bullock--Alternate Director. For a description of Mr.
Bullock's background and experience, see "Identification of Executive
Officers and Senior Executives" below.
CENTRAL GEORGIA EMC
D. A. Robinson, III--Director, age 55, is the owner and operator of
a dairy farm in Griffin, Georgia. He has served on the Board of Directors of
Oglethorpe since March 1984, and his present term will expire in March 1998.
He is a member of the Transmission Committee. Mr. Robinson serves as
Secretary-Treasurer of Central Georgia EMC.
George L. Weaver--Alternate Director, age 48, has been the
President of Central Georgia EMC since 1989. Prior to that time he was
General Manager, Manager of Accounting, and Financial Manager. He has served
as an Alternate Director of Oglethorpe since 1983, and his present term will
expire in March 1998. He is currently a member of the Finance Committee. He
is Vice President of the Board of Directors of Federated Rural Electric
Insurance Corporation in Shawnee Mission, Kansas and Chairman of the Board of
Directors of Southeastern Data Cooperative. Mr. Weaver is Chairman of the
Butts County Development Authority; Chairman of the Joint Development
Authority which encompasses Butts, Henry, Lamar, and Spalding Counties; and
Vice Chairman of the West Central Georgia Private Industry Council. He
serves on the Advisory Board of NationsBank of Georgia, N.A.
COASTAL EMC
James E. Estes--Director, age 60, has served on the Board of
Directors of Oglethorpe since March 1982, with his present term to expire in
March 1997. He currently serves as Chairman of the Wholesale Power Contract
Oversight Committee and is a member of the Executive Committee. He is also
Vice President of the Board of Directors of Coastal EMC. Mr. Estes operates
Estes Property Management, a commercial real estate management service in
Richmond Hill, Georgia; is President of Ways Company, Inc., a real estate
development company in Richmond Hill, Georgia; and is proprietor of Estes Tax
Service, an income tax service in Richmond Hill, Georgia.
Wayne Collins--Alternate Director, age 45, is the General Manager
of Coastal EMC and has served as an Alternate Director of Oglethorpe since
March 1977. His present term as an Alternate Director will expire in March
1997.
COBB EMC
Larry N. Chadwick--Director, age 55, is the owner of Chadwick's Hardware in Woodstock, Georgia. He has
served on the Board of Directors of Oglethorpe since July 1989, with his1989. His present term
towill expire in March 1998.
He is currently a member of the Generation Committee.1999. Mr. Chadwick is an engineer, with experience in the
design of hydrogen gas plants. He is Chairman of the Board of Cobb EMC.
54
Dwight Brown--AlternateBenny W. Denham, age 66, is the Vice Chairman of the Board and is the
Member Director age 50, is President and Chief
Executive Officer of Cobb EMC. He previously served as Vice President of
Engineering and Operations for Cobb EMC. Hefrom the Southwest Region. Mr. Denham has served as an Alternate
Directorexecutive
officer of Oglethorpe since October 1993, with his present term to expire in
March 1998. Mr. Brown currently serves on the Restructuring Advisory
Committee.
COLQUITT EMC
Simmie King--Director, age 52, is the owner and operator of a farm.1993. He has served on the Board of Directors
of Oglethorpe since March 1991, with
hisDecember 1988. His present term to expire in March 1999.
R. L. Gaston--Alternate Director, age 48, is the General Manager of
Colquitt EMC. From January 1985 to January 1990, he was Manager of
Engineering and Operations for Colquitt EMC. He has served as an Alternate
Director of Oglethorpe since February 1990, with his present term to expire
in March 1999. Mr. Gaston currently serves on the Restructuring Advisory
Committee.
COWETA-FAYETTE EMC
W. F. Farr--Director, age 83, is a banker. He has served on the
Board of Directors of Oglethorpe since March 1975, with his present term towill expire in March 1998.
He is currentlywas previously the Vice-Chairman of the Executive Committee and a member of
the Finance CommitteePower Planning and previously served as Chairman of the Human Resources Management Committee.
He has been President of Coweta-Fayette EMC since 1974. He previously served
as President of the Fayette State Bank in Peachtree City, Georgia and as a
Director and Consultant for Citizens and Southern National Bank, South Metro
Board in Atlanta, Georgia. Since June 1985, Mr. Farr has been the owner and
President of Pioneer Financial Associates, Inc. in Peachtree City, Georgia.
Michael C. Whiteside--Alternate Director, age 53, has been General
Manager of Coweta-Fayette EMC since August 1983. He previously served as
Administrative Assistant of Coweta-Fayette EMC. He currently serves on the
Marketing Committee and the RestructuringTechnical Advisory Committee. Mr. Whiteside
has served as an Alternate DirectorDenham is co-owner of
Oglethorpe since September 1983, with
his present term to expireDenham Farms in March 1998.
EXCELSIOR EMC
Vacant--Director
Gary T. Drake--Alternate Director, age 47, is the General Manager
of Excelsior EMC. He has served as an Alternate Director of Oglethorpe since
January 1979, with his present term to expire in March 1997. He was
Secretary-Treasurer of Oglethorpe from March 1984 through March 1989. He is
currently a member of the Generation Committee. Mr. Drake is also a Director
of GEMC.
FLINT EMC
Jeff S. Pierce, Jr.--Director, age 64, has served on the Board of
Directors of Oglethorpe since June 1992, with his present term to expire in
March 1997. He is a member of the Executive Committee. He has served as a
Director of Flint EMC since 1964. Mr. Pierce previously served 28 years as
Chief Executive Officer and as a Director for the First Federal Savings and
Loan Association in Warner Robins,Turner County, Georgia. He is also a Director of GEMC.
Harold B. Smith--Alternate Director, age 60, has been employed as
General Manager of Flint EMC since November 1978. He has served as an
Alternate Director of Oglethorpe since 1978, with his present term to expire
in March 1997. He is currently a member of the Transmission Committee.
55
GRADY EMC
Donald C. Cooper--Director, age 65, is the owner, operator and
President of Cooper Farms, Inc., a farm in Grady County, Georgia where he
grows row crops and raises cattle. He has served on the Board of Directors
of Oglethorpe since March 1975, with his present term to expire in March
1999. He is currently a member of the Generation Committee.
Thomas A. Rosser--Alternate Director, age 48, has been employed as
General Manager of Grady EMC since January 1992. He has served as an
Alternate Director of Oglethorpe since January 1992, with his present term to
expire in March 1999.
GREYSTONE POWER CORPORATION, AN EMC
J. Calvin Earwood--Director. For a description of Mr. Earwood's
background and experience, see "Identification of Executive Officers and
Senior Executives" below.
Tim B. Clower--Alternate Director, age 59, is President and Chief
Executive Officer of GreyStone Power Corporation, an EMC. He has served as
an Alternate Director of Oglethorpe since September 1974, with his present
term to expire in March 1998. He is currently a member of the Marketing
Committee. Mr. Clower serves on the Boards of Directors of Citizens &
Merchants State Bank and GEMC Workers' Compensation Fund.
HABERSHAM EMC
Ray Meaders--Director, age 72, is the owner and operator of a farm
in Cleveland, Georgia. He has served as Director of Oglethorpe since August
1995, with his present term to expire in March 1999. He is currently a
member of the Marketing Committee. Mr. Meaders is also a Director of
Habersham EMC.
William E. Canup--Alternate Director, age 60, is the General
Manager of Habersham EMC. Mr. Canup was Manager of Engineering/Operations of
Habersham EMC from 1979 to 1984 and served as Assistant Manager of Habersham
EMC from 1984 to 1986. He has served as an Alternate Director of Oglethorpe
since July 1986, with his present term to expire in March 1999.
HART EMC
Mac F. Oglesby--Director, age 63, served as Assistant
Secretary-Treasurer of Hart EMC from July 1986 through December 1987, when he
was appointed President. He has served as a Director of Oglethorpe since
February 1987, with his present term to expire in March 1997. He is
currently a member of the Marketing Committee and the Wholesale Power
Contract Oversight Committee. Mr. Oglesby was a U.S. Postal Service Rural
Carrier for 30 years.
Grooms Johnson--Alternate Director, age 66, has been the General
Manager of Hart EMC since March 1991. Prior to that time, he served as
Assistant Manager of Hart EMC. He has served as an Alternate Director of
Oglethorpe since March 1991, with his present term to expire in March 1997.
Mr. Johnson is also a Director of Bank of Hartwell in Hartwell, Georgia.
IRWIN EMC
Benny W. Denham--Director. For a description of Mr. Denham's
background and experience, see "Identification of Executive Officers and
Senior Executives" below.
Harold Randall Crenshaw--Alternate Director, age 44, has been the
General Manager of Irwin EMC since February 1988. He has served as an
Alternate Director of Oglethorpe since February 1988, with his present term
to expire in March 1998. He is Chairman and past Vice Chairman of the
Finance Committee and also serves on the Restructuring Advisory Committee.
Mr. Crenshaw was Office Manager of Irwin EMC from 1974 to 1988.
56
JACKSON EMC
E. L. McLocklin--Director, age 83, is a cattle farmer. He is also
Chairman of the Board of Directors of Jackson EMC. He has served as a
Director of Oglethorpe since October 1989, with his present term to expire in
March 1999. Mr. McLocklin is currently a member of the Marketing Committee.
Randall Pugh--Alternate Director, age 52, is President and Chief
Executive Officer of Jackson EMC. From August 1984 to January 1988 he was
General Manager of Jackson EMC. He was also General Manager of Walton EMC
from 1977 to August 1984. He has served as an Alternate Director of
Oglethorpe since 1977. His present term as Alternate Director will expire in
March 1999. He is currently a member of the Finance Committee and the
Restructuring Advisory Committee. Mr. Pugh is also a Director of the First
National Bank of Jackson County in Jefferson, Georgia.
JEFFERSON EMC
Sam Rabun--Director, age 64, is part owner of a livestock farm. He
has served as a Director of Oglethorpe since March 1993, with his present
term to expire in March 1999. He is currently a member of the Executive
Committee. Mr. Rabun is the President of Jefferson EMC.
Kenneth Cook--Alternate Director, age 49, is the Executive Vice
President and General Manager of Jefferson EMC. He has served as the Manager
of Engineering since joining Jefferson EMC in 1986. He was previously
self-employed as a row-crop and livestock farmer. Mr. Cook has served as a
Director of Oglethorpe since February 1996, with his present term to expire
in March 1999. He served on the BoardTurner County
Commission from 1980 to 1990, and was Chairman for six of Directors of Little Ocmulgee EMC
from 1979 to 1986 and on the Board of Directors of Oglethorpe from 1982 to
1986.
LAMAR EMC
E. J. Martin, Jr.--Director, age 68, is the owner of the Country
Kitchen restaurant in Barnesville, Georgia. Hethose years. Mr.
Denham is a retired tax assessor and
appraiser for Lamar County. He has served on the BoardDirector of Directors of
Oglethorpe since March 1982, with his present term to expireCommunity National Bank in March 1997.
He is currently a member of the Human Resources Management Committee. Mr.
Martin is the President of Lamar EMCAshburn, Georgia and a
Director of GEMC.Irwin EMC.
J. Raleigh Henry--Alternate Director,Calvin Earwood, age 45, is General Manager of
Lamar EMC. Prior to becoming General Manager, he served as Office Manager of
Lamar EMC. He has served as an Alternate Director of Oglethorpe since 1990,
with his present term to expire in March 1997.
LITTLE OCMULGEE EMC
Jim M. Knight--Director, age 60, is owner and manager of Knight
Farms. He has served on the Board of Directors of Oglethorpe since April
1994, with his present term to expire in March 1997. Mr. Knight is also a
Director of Little Ocmulgee EMC.
A. Arnold Horton--Alternate Director, age 49, is the General
Manager of Little Ocmulgee EMC. He previously served as Manager of
Engineering and Operations and has been with Little Ocmulgee EMC since 1983.
He has served as the Alternate Director of Oglethorpe since March 1993, with
his present term to expire in March 1997. Mr. Horton is a member of the
Transmission Committee.
MIDDLE GEORGIA EMC
Ronnie Fleeman--Director, age 61, is a self-employed land and
timber developer. He has served on the Board of Directors of Oglethorpe
since 1990, with his present term to expire in March 1998.
Charles Hugh Richardson--Alternate Director, age 42, has been
General Manager of Middle Georgia EMC since June 1983. From January 1983 to
June 1983, he was Acting General Manager of Middle Georgia EMC, and from
September 1976 to January 1983, he was Manager of Engineering at Middle
Georgia EMC. He has served as an Alternate Director of Oglethorpe since
1983, with his present term to expire in March 1998.
57
MITCHELL EMC
D. Lamar Cooper--Director, age 60, operates a dairy farm. He has
served on the Board of Directors of Oglethorpe since September 1974, with his
present term to expire in March 1999. He is currently a member of the
Generation Committee.
Edward A. Pritchett--Alternate Director, age 49, has served as
General Manager of Mitchell EMC since September 1995. Since that time he has
served as Alternate Director of Oglethorpe, with his present term to expire
in March 1999. Prior to that time, Mr. Pritchett served as Assistant General
Manager, Director of Finance and Administrative Services and Supervisor of
Data Processing for Mitchell EMC.
OCMULGEE EMC
Barry H. Martin--Director, age 47, is a farmer. He has served on
the Board of Directors of Oglethorpe since March 1983, with his present term
to expire in March 1997. Mr. Martin is the President of Ocmulgee EMC.
Dennis Grenade--Alternate Director, age 55, has been employed by
Ocmulgee EMC since December 1957. He has been General Manager since October
1987 and was previously Acting Manager and Manager of Operations. He has
served as an Alternate Director since October 1987, with his present term to
expire in March 1997. He is a member of the Transmission Committee.
OCONEE EMC
John B. Floyd, Jr.--Director, age 53, has served on the Board of
Directors of Oglethorpe since March 1980, with his present term to expire in
March 1999. He is currently a member of the Human Resources Management
Committee. Mr. Floyd is also the Vice Chairman of the Board of Oconee EMC.
Preston L. Johnson--Alternate Director, age 61, is President and
Chief Executive Officer of Oconee EMC. He has served as an Alternate
Director of Oglethorpe since September 1974, with his present term to expire
in March 1999. He was Secretary-Treasurer of Oglethorpe from September 1974
to March 1984.
OKEFENOKE RURAL EMC
Steve Rawl, Sr.--Director, age 49, has been President of Rawls,
Inc., a gift shop, since 1972. He has served as a Director of Oglethorpe
since September 1993, with his present term to expire in March 1997. He is
currently a member of the Finance Committee.
W. Don Holland--Alternate Director, age 45, is General Manager of
Okefenoke Rural EMC. He has served as an Alternate Director of Oglethorpe
since 1979, with his present term to expire in March 1997. He was formerly
General Manager of Little Ocmulgee EMC. He is currently Chairman of the
Transmission Committee and serves on the Restructuring Advisory Committee and
the Wholesale Power Contract Oversight Committee.
PATAULA EMC
James Grubbs--Director, age 73, is a farmer. He is involved with
fertilizer and chemical sales, and operates an air spray service and a peanut
purchasing plant. He has served on the Board of Directors of Oglethorpe
since March 1983, with his present term to expire in March 1999. Mr. Grubbs
is a member of the Transmission Committee.
Gary W. Wyatt--Alternate Director, age 43, is General Manager of
Pataula EMC. He has served as an Alternate Director of Oglethorpe since July
1986, with his present term to expire in March 1999. He currently serves as
Vice-Chairman of the Marketing Committee. Mr. Wyatt previously was
Operations Manager and Assistant Operations Superintendent of Coosa Valley
Electric Cooperative.
58
PLANTERS EMC
Sammy M. Jenkins--Director, age 69, is in the farm machinery
business and has been President of Jenkins Ford Tractor Co., Inc. since 1973.
He has served on the Board of Directors of Oglethorpe since March 1988, with
his present term to expire in March 1997. He was Vice Chairman of the Board
of Oglethorpe from March 1989 to March 1990. Mr. Jenkins currently serves as
Vice-Chairman of the Generation Committee and is a member of the Wholesale
Power Contract Oversight Committee.
Ellis H. Lovett--Alternate Director, age 60, is General Manager of
Planters EMC and has served as an Alternate Director of Oglethorpe since
1983. His present term as an Alternate Director will expire in March 1997.
He is currently a member of the Marketing Committee.
RAYLE EMC
J. M. Sherrer--Director, age 60, is the owner of a grocery,
hardware, gas and feed store. He has served on the Board of Directors of
Oglethorpe since September 1993, with his present term to expire in March
1997.
Wayne Poss--Alternate Director, age 50, has served as General
Manager of Rayle EMC since December 1992. Prior to that time, he served as
Manager of Engineering for Rayle EMC. He has served as an Alternate Director
of Oglethorpe since February 1993, with his present term to expire in March
1997. He is currently a member of the Generation Committee.
SATILLA RURAL EMC
Jack D. Vickers--Director, age 78, is the owner and operator of a
farm in Coffee County, Georgia. He has served on the Board of Directors of
Oglethorpe since March 1975, with his present term to expire in March 1997.
R. Lehman Lanier--Alternate Director, age 76, is President and
Chief Executive Officer of Satilla Rural EMC. He has served as an Alternate
Director of Oglethorpe since September 1974, with his present term to expire
in March 1997. He is currently a member of the Generation Committee. Mr.
Lanier is also a Director of Southeastern Data Cooperative, Inc.
SAWNEE EMC
C. W. Cox, Jr.--Director, age 68, is the owner of Cox Digging &
Grading, a general contracting sole proprietorship. He has served as a
member of the Board of Directors of Oglethorpe since February 1987, with his
present term to expire in March 1997. Mr. Cox is currently a member of the
Finance Committee.
Michael A. Goodroe--Alternate Director, age 39, is Executive Vice
President and General Manager of Sawnee EMC. He previously served as
Assistant General Manager of Sawnee EMC. He has served as an Alternate
Director of Oglethorpe since 1990, with his present term to expire in March
1997. He is a member of the Transmission Committee.
SLASH PINE EMC
Johnnie Crumbley--Director, age 73, is President of Slash Pine EMC.
He retired in 1982 from the Seaboard Coastline System. He has served as a
member of the Board of Directors of Oglethorpe since March 1978, with his
present term to expire in March 1999. He is also a Director of GEMC.
Edward Teston--Alternate Director, age 61, is Manager of Slash Pine
EMC. He has served as an Alternate Director of Oglethorpe since 1985, with
his present term to expire in March 1999.
SNAPPING SHOALS EMC
Jarnett W. Wigington--Director, age 63, is a self-employed
wallpapering contractor. He has served on the Board of Directors of
Oglethorpe since 1990, with his present term to expire in March 1997.
59
Randall G. Meadows--Alternate Director, age 51, is President/Chief
Executive Officer/Manager of Snapping Shoals EMC. He previously served as
Executive Vice President/Chief Operating Officer for Snapping Shoals EMC. He
has served as an Alternate Director of Oglethorpe since August 1995, with his
present term to expire in March 1997. Mr. Meadows currently serves on the
Restructuring Advisory Committee.
SUMTER EMC
Bob Jernigan--Director, age 68, has served as a Director of
Oglethorpe since March 1976, with his present term to expire in March 1999.
He served as Vice Chairman of the Board of Directors of Oglethorpe from March
1990 to March 1993. He is currently a member of the Transmission Committee.
Mr. Jernigan is the Chairman of the Board of Sumter EMC and ais the
Member Director of
GEMC.
James T. McMillan--Alternate Director, age 46, is President and
Chief Executive Officer of Sumter EMC. He was appointed General Manager of
Sumter EMC in 1984. The General Manager title was changed to President/CEO
in 1994. Prior to that time, he served as Manager of the Staff Services
Department of Sumter EMC, Manager of the Construction and Maintenance
Department of Sumter EMC, and Manager of the Office Services Department of
Sumter EMC. Heelected statewide. Mr. Earwood has served as an Alternate Director of Oglethorpe since 1984,
with his present term to expire in March 1999. Mr. McMillan currently serves
on the Generation Committee.
THREE NOTCH EMC
C. Willard Mims--Director, age 49, is a farmer. He has served on
the Board of Directors since 1991, with his present term to expire in March
1999. Mr. Mims is also a Director of GEMC.
Carlton O. Thomas--Alternate Director, age 48, has been General
Manager of Three Notch EMC since 1990. Prior to that time, he served as
Office Manager of Three Notch EMC. He has served as an Alternate Director of
Oglethorpe since 1990, with his present term to expire in March 1999. He
currently serves on the Transmission Committee. Mr. Thomas is also a
Director of First Federal Savings Bank of Southwest Georgia.
TRI-COUNTY EMC
Thomas Noles--Director, age 54, is a pharmacist. He has served on
the Board of Directors of Oglethorpe since September 1995, with his present
term to expire in March 1999.
Carol Robertson--Alternate Director, age 47, is the General Manager
of Tri-County EMC. She has served as an Alternate Director of Oglethorpe
since July 1988, with her present term to expire in March 1999. Ms. Robertson
currently serves on the Restructuring Advisory Committee.
TROUP EMC
Roy Tollerson, Jr.--Director, age 56, is the owner and operator of
Country Furniture. He has served on the Board of Directors of Oglethorpe
since March 1995, with his present term to expire in March 1998. Mr.
Tollerson is currently a member of the Marketing Committee.
Wayne Livingston--Alternate Director, age 44, has been the
Executive Vice President and General Manager of Troup EMC since August 1987.
Prior to that time, he was General Manager of Ocmulgee EMC. He has served as
an Alternate Director of Oglethorpe since 1978, with his present term to
expire in March 1998. Mr. Livingston currently serves on the Restructuring
Advisory Committee.
60
UPSON COUNTY EMC
Hubert Hancock--Director, age 79, has been President of the Upson
County EMC for the past 34 years. He has served as a Director of Oglethorpe
since September 1974, serving as Vice President from 1975 to 1978, as
President from March 1984 to July 1986, and as Chairman of the Board from
July 1986 to March 1989. His present term as Director expires in March 1998.
Mr. Hancock currently serves on the Executive Committee. Prior to his
involvement with Oglethorpe and Upson County EMC, he was a general farmer as
well as a peach farmer and cattle farmer. Mr. Hancock is also a Director of
West Central Georgia Bank in Thomaston, Georgia, and Chairman of Upson County
Hospital Authority.
John H. Brodnax--Alternate Director, age 48, was appointed General
Manager of Upson County EMC in 1995. Prior to that time he served as Office
Manager of Upson County EMC. Mr. Brodnax has served as Alternate Director of
Oglethorpe since 1995, with his present term to expire in 1998.
WALTON EMC
Hendrix B. Wiley, Jr.--Director, age 51, is a retired dairy farmer
and is currently self-employed in real estate. He has served on the Board of
Directors of Oglethorpe since August 1994, with his present term to expire in
March 1998. He currently serves on the Generation Committee. Mr. Wiley is
also a director of Walton EMC.
D. Ronnie Lee--Alternate Director, age 47, has been General Manager
of Walton EMC since August 1993. Prior to that time, he served as Manager of
Engineering and Operations from January 1979 to August 1993 for Walton EMC.
He has served as an Alternate Director of Oglethorpe since September 1993,
with his present term to expire in March 1998. Mr. Lee currently serves on
the Restructuring Advisory Committee.
WASHINGTON EMC
W. W. Archer--Director, age 64, is a self-employed insurance agent
and cattle farmer. He has served on Oglethorpe's Board of Directors since
September 1987, and his present term expires in March 1998. He is also a
Director of the Bank of Hancock County in Sparta, Georgia.
Robert S. Moore, Sr.--Alternate Director, age 66, has been General
Manager of Washington EMC since April 1982. Prior to that time, he was
Assistant General Manager of Washington EMC. He has served as an Alternate
Director of Oglethorpe since 1982, with his present term to expire in March
1998. He is currently a member of the Marketing Committee.
(B) IDENTIFICATION OF EXECUTIVE OFFICERS AND SENIOR EXECUTIVES:
Oglethorpe is managed and operated under the direction of a
President and Chief Executive Officer, who is appointed by the Board of
Directors. The executive officers of Oglethorpe and their principal
occupations are as follows:
J. Calvin Earwood, Chairman of the Board, age 54, has served as a
principal executive
officer of Oglethorpe since March 1984 (from March 1984 to July 1986, as Vice
President; from July 1986 to March 1989, as Vice Chairman of the Board; and
since March 1989, as Chairman of the Board). Mr. Earwood has served as a
Director of Oglethorpe since March 1981, with his1981. His present term towill expire in March
1998. He is currently the Chairman of the
Executive Committee and a member of the Human Resources Management Committee.2000. He was previously a member of the Operations Review Committee. From 1965
through
62
1982, Mr. Earwood was a salesman and part owner of Builders Equipment
Company. Since January 1983, he has been the owner and President of Sunbelt
Fasteners, Inc., which sells specialty tools and fasteners to the commercial
construction trade. He is also Vice Chairman of the Board of Directors of
Community Trust Bank in Hiram, Georgia and a Director of GreyStone Power
Corporation.
Benny W. Denham, Vice ChairmanSammy M. Jenkins, age 70, is the Member Director from the Southeast
Region. He is in the farm machinery business and has been President of the Board, age 65, has served as
a principal executive officer of OglethorpeJenkins
Ford Tractor Co., Inc. since March 1993.1973. He has served on the Board of Directors of
Oglethorpe since March 1988. His present term will expire in March 1999. He was
Vice Chairman of the Board of Oglethorpe from March 1989 to March 1990.
Mac F. Oglesby, age 64, is the Member Director from the Northeast
Region. He served as Assistant Secretary-Treasurer of Hart EMC from July 1986
through December 1988,1987, when he was appointed President. He has served as a
Director of Oglethorpe since February 1987. His present term will expire in
March 2000. Mr. Oglesby was a U.S. Postal Service Rural Carrier for 30 years.
J. Sam L. Rabun, age 65, is the Member Director from the Central
Region. He is the owner and operator of a farm in Jefferson County, Ga. He is
also a 50% owner of R&R Livestock Farms, Inc. He has served as a Director of
Oglethorpe since March 1993, with
61
his present term to expire in March 1998. He is currently the Vice-Chairman
of the Executive Committee and was previously a member of the Power Planning
and Technical Advisory Committee. Mr.
Denham is also a Director of Community
National Bank in Ashland, Georgia and a Director of Irwin EMC.
Gary M. Bullock, Secretary-Treasurer, age 54, hasRabun served as Secretary-Treasurerthe President of Oglethorpe since March 1995. He has served asJefferson EMC from 1993 to 1996.
Ashley C. Brown, age 51, is an Alternate Director of Oglethorpe since June 1978, with hisOutside Director. His present term towill
expire in March 1999. He is currently a memberExecutive Director of the Harvard Electricity Policy
Group at Harvard University's John F. Kennedy School of Government. He is Of
Counsel to the law firm of Verner, Liipfert, Bernhard, McPherson and Hand of
Washington, D.C. In addition, he is a Principal Consultant with the firm of
Hagler Bailly Consulting, Inc. From April 1983 through April 1993, Mr. Brown
served as Commissioner of the Public Utilities Commission of Ohio. Prior to his
appointment to the Ohio Commission, he was Coordinator and Counsel of the
Montgomery County, Ohio, Fair Housing Center. From 1979 to 1981, he was Managing
Attorney for the Legal Aid Society of Dayton (Ohio), Inc. From 1977 to 1979, he
was Legal Advisor of the Miami Valley Regional Planning Commission in Dayton,
Ohio. While practicing law, he specialized in litigation in federal and state
courts, as well as before administrative bodies. In addition, Mr. Brown has
extensive teaching experience in public schools and universities and has
published widely in the field of utility regulation. Mr. Brown has a law degree
from the University of Dayton School of Law, a Master of Administration degree
from the University of Cincinnati, and a Bachelor of Science degree from Bowling
Green State University.
Newton A. Campbell, age 68, is an Outside Director. His term will
expire in March 2000. He retired in January 1994 as Chairman and Chief Executive
CommitteeOfficer of Burns & McDonnell Engineering Company after serving 41 years with the
firm. Mr. Campbell directed the overall operations of Burns & McDonnell from
1982 until his retirement. From 1976 through 1982, he served as Vice President
and General Manager of the Restructuring Advisory CommitteePower Division, and was previouslyresponsible for directing the
company's work in the planning and design of fossil fueled power generation
facilities, high voltage transmission systems, and other power related
facilities. Mr. Campbell has been involved in feasibility, planning and
financial studies for numerous new and existing public and privately owned
electric utilities during various phases of their organization and development.
He also has considerable experience in conceptual studies, design, and project
management for large electric utility generation, transmission, substation and
distribution facilities throughout the United States. Mr. Campbell received a
memberMaster of Business Administration degree from the Operations Committee. Mr. BullockUniversity of Missouri at
Kansas City with a concentration in finance. He also holds a Bachelor of Science
degree in Electrical Engineering from the University of Illinois.
T. D. Kilgore, age 49, is the President and Chief Executive Officer of
Carroll EMC. Mr. Bullock is also the Secretary of Southeastern Data
Cooperative, Inc.Oglethorpe and serves on the Boards of Directors of the Georgia
Cooperative Council, the Federated Rural Electric Insurance Corporation, and
the Carrollton Federal Bank, F.S.B. in Carrollton, Georgia.
T. D. Kilgore, President and Chief Executive Officer, age 48, has served as an executive of Oglethorpe since July 1984 (from
July 1984 to July 1986, as Division Manager, Power Supply; July 1986 to July
1991, as Senior Vice President, Power Supply; and since July 1991, as President
and Chief Executive Officer). Mr. Kilgore servedHe also currently serves as Executive Vice President of GEMC
from December 1991 to June 1992. He has served asthe President and
Chief Executive Officer and as a director of GEMC from June 1992 until October 1995.both GTC and GSOC. Mr. Kilgore has
over 20 years of experience, including five years in senior management positions
with
63
Arkansas Power & Light Co. and seven years as a civilian employee with the
Department of the Army in positions ranging from reliability engineering to
construction management. Mr. Kilgore has served on various industry committees
including Electric Power Research Institute's Board of Directors and its
Advanced Power Systems Division and Coal System Division Advisory Committees. He
has also served on the Boards of Directors of the U.S. Committee for Energy
Awareness, the Advanced Reactor Corporation, on the Edison Electric Institute's
Power Plant Availability Improvement Task Force and the Nuclear Power Oversight
Committee. Mr. Kilgore currently serves on the Board of Directors of the Georgia
Chamber of Commerce and on the National Rural Electric Cooperative Association's
Power and Generation Committee. Mr. Kilgore has a BSBachelor of Science degree in
mechanical engineeringMechanical Engineering from the University of Alabama, where he has been
recognized as a Distinguished Engineering Fellow, and an MEMasters of Engineering
degree in industrial engineering from Texas A&M.
(b) Identification of Senior Executives:
Oglethorpe is managed and operated under the direction of a President
and Chief Executive Officer, who is appointed by the Board of Directors. The
senior executives assisting Mr. Kilgore, their areas of responsibility and a
brief summary of their experience are as follows:
Clarence D. Mitchell, Senior Vice President, and Group Executive, Generation,Power Supply, age 42,43, has
served as an executive of Oglethorpe since January 1995. Prior to that time, Mr.
Mitchell served as Assistant to the Senior Vice President for Generation from
February 1994 to December 1994; Manager of Corporate Planning from September
1992 to January 1994; Manager of Construction from January 1992 to August 1992;
Program Director of Technical Services (environmental, survey and mapping, land
acquisition and R&D) from January 1989 to December 1991; and from April 1981 to
December 1988 held various positions in the generation area, including
supervisor, project engineer and generation engineer. Before coming to
Oglethorpe, Mr. Mitchell spent four years as a field engineer with General
Electric Company and worked various installation and maintenance projects
related to coal, nuclear, gas and oil-fired generation. Mr. Mitchell has an MS
degree in Management from Georgia State University, a BSBachelor of Science degree
in Mechanical Engineering from Georgia Institute of Technology and a BSBachelor of
Science degree in Interdisciplinary Science from Morehouse College. Mr. Mitchell
is presently the Oglethorpe representative on both the Nuclear Managing Board
and the Plant Scherer Managing Board. For information about the Managing Boards
see "CO-OWNERS OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--The Plant Agreements" in
Item 1.
Wylie H. Sanders, Vice President and Group Executive, Transmission,
age 59, joined Oglethorpe in January 1994 after 35 years of utility
experience, including 20 years in management positions with Florida Power &
Light Company. Prior to coming to Oglethorpe, he served2. Mr. Mitchell also serves as Division
Commercial Manager from April 1973 to August 1983; as District General
Manager from August 1983 to July 1991; and as Director of Transmission from
July 1991 to September 1993 with Florida Power & Light. Mr. Sanders has a Bachelor's degree in Industrial Engineering from Georgia Institute of
Technology and has participated in Harvard University's postgraduate Program
for Management Development. Mr. Sanders is presently an Oglethorpe
representative on the Joint Committee. For information about the Joint
Committee, see "CO-OWNERS OF THE PLANTS AND THE PLANT AND
62
TRANSMISSION AGREEMENTS--The Joint Committee Agreement" in Item 1. Mr.
Sanders is a memberTrustee of the BoardFoundation of Trustees ofthe Southern
Tech Foundation, Inc.Polytechnic State University.
Nelson G. Hawk, Senior Vice President and Group Executive, Marketing,
age 46,47, has served as an executive at Oglethorpe since February 1994,
responsible for Market Planning, Economic Development, Commercial/Industrial
Marketing and Pricing, Commercial/Industrial Services, and Residential
Marketing. Prior to coming to Oglethorpe, Mr. Hawk spent almost 24 years with
the Florida Power & Light Company and related subsidiaries, serving as Director
of Regulatory Affairs from October 1993 to January 1994, Director of Market
Planning from July 1991 to September 1993, and as Director of Strategic Business
and President of FPL Enersys Services, Inc. (A utility subsidiary providing
energy services to commercial/industrial customers) from April 1989 to June
1991. Mr. Hawk has a wide range of utility management experience in energy
management, finance, strategic planning, marketing, system planning, quality
assurance, and distribution engineering. Mr. Hawk is a board member of the
Georgia Electrification Council, Inc. and the Georgia Partnership for Excellence
in Education, and served on the board of directors as well as President of the
National Association of Energy Services Companies (NAESCO), a national trade
association, during the late 1980s. Mr. Hawk is a registered Professional
Engineer in Florida and has a BSBachelor of Science degree in Electrical
Engineering from the Georgia Institute of Technology and an MBAa Master of Business
Administration degree from Florida International University.
W. Clayton Robbins, Senior Vice President and Group Executive,
Support Services, age 49, has served as an executive of Oglethorpe since
December 1991 (from December 1991 to February 1994, as Vice President,
Corporate Performance, and since February 1994, as Senior Vice President and
Group Executive, Support Services). Prior to that time, Mr. Robbins served as
Department Manager, Project Services, from September 1986 to November 1988;
as Program Director, Marketing Research and Analysis, from November 1988 to
December 1989; and as Vice President, Marketing Research and Analysis, from
December 1989 to December 1991. Before coming to Oglethorpe, Mr. Robbins
spent 17 years with the Stearns-Catalytic World Corporation and various
subsidiaries, including 13 years in management positions responsible for
Human Resources, Information Systems, Contracts, Insurance, Accounting, and
Project Controls. Mr. Robbins has a BA degree in Business Administration
from the University of North Carolina at Charlotte.
Eugen Heckl, Senior Vice President and Chief Financial Officer, age
61, has served as an executive of Oglethorpe since March 1975 (from March
1975 to July 1986, as senior finance and accounting executive; from July 1986
to February 1994 as Senior Vice President, Finance; and since February 1994,
as Senior Vice President and Chief Financial Officer). Mr. Heckl has over 30
years of experience, including ten years as a consultant and auditor to
electric utilities with Arthur Andersen & Co. and two years as
Secretary-Treasurer of Davis Brothers, Inc. Mr. Heckl is a Certified Public
Accountant in Georgia and has a BS degree in accounting from Samford
University and an MBA degree from Emory University. Mr. Heckl has served as
a Director of the GEMC Federal Credit Union since 1983, and as its Chief
Financial Officer since 1984. Mr. Heckl has elected to retire from
Oglethorpe under the provisions of an early retirement program, effective no
later than September 11, 1996. However, Mr. Heckl may continue to provide
services to Oglethorpe on a contract basis after that date at the discretion
of the President and Chief Executive Officer.
G. Stanley Hill, Senior Vice President, External Affairs, age 60,
has served as an executive of Oglethorpe since October 1975 (from October
1975 to November 1988, as Director of Planning, Director of Power Supply and
Planning, Division Manager, Power Supply and Engineering, Division Manager,
Engineering, Senior Vice President, Planning and System Operations; from
November 1988 to November 1991, as Senior Vice President, Administration;
from November 1991 to February 1994, as Senior Vice President, Marketing and
Customer Service and since February 1994, as Senior Vice President and Staff
Executive, External Affairs). Mr. Hill has approximately 37 years experience
with electric utilities, including four years in the Engineering Department
of the South Carolina Public Service Authority and 11 years as engineer and
senior engineer with Southern Engineering Company of Georgia, a consulting
engineering firm. Mr. Hill is a registered Professional Engineer and a
certified Cogeneration Professional in Georgia and has a BS degree in
electrical engineering from Clemson University and an MBA degree from Georgia
State University. Mr. Hill is presently an Oglethorpe representative on the
Joint Committee. For information about the Joint Committee, see "CO-OWNERS
OF THE PLANTS AND THE PLANT AND TRANSMISSION AGREEMENTS--The Joint Committee
Agreement" in Item 1. Mr. Hill has elected to retire from
63
Oglethorpe under the provisions of an early retirement program, effective no
later than September 11, 1996. However, Mr. Hill may continue to provide
services to Oglethorpe on a contract basis after that date at the discretion
of the President and Chief Executive Officer.
64
ITEMItem 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLESummary Compensation Table
The following table sets forth, for Oglethorpe's President and Chief
Executive Officer and the five most highly compensated senior executives, all
compensation paid or accrued for services rendered in all capacities during the
years ended December 31, 1996, 1995 1994 and 1993.1994. Amounts included in the table
under "Bonus" represent payments based on an incentive compensation policy. All
amounts paid under this policy are fully at risk each year and are earned based
upon the achievement of corporate goals and each individual's contribution to
achieving those goals. In conjunction with this policy, base salaries are
targeted below the market valuations for similar positions and remain fairly
stable unless the job content changes.
ANNUAL
COMPENSATION
NAME AND ------------------- ALL OTHER
PRINCIPAL POSITION YEAR SALARY BONUS(2) COMPENSATION
-Annual
Name and Compensation All Other
Principal Position Year Salary Bonus (2) Compensation
------------------ ---- -------- --------- ----------------------- ------------
T. D. Kilgore 1995 $235,000 $10,000 $6,012(1)1996 $265,627 $0 $6,246 (1)
President and Chief Executive Officer 1995 235,000 10,000 6,012
1994 224,997 0 6,758
1993 211,250 0 7,652
David L. SelfW. Clayton Robbins (3) 1995 145,896 13,410 48,024(1)(3)1996 144,460 17,112 5,425 (1)
Sr. Vice President, and 1994 147,833 10,476 9,117
Group Executive, System Operations 1993 135,000 12,143 8,229
Eugen Heckl 1995 142,114 13,174 7,651(1)
Sr. Vice President and Chief 1994 142,114 13,919 7,600
Financial Officer 1993 142,114 12,228 7,221
G. Stanley Hill 1995 140,000 11,088 7,204(1)
Sr. Vice President, External Affairs 1994 140,000 10,883 5,619
1993 140,000 12,580 7,001
W. Clayton Robbins 1995 142,310 10,631 4,716(1)
Sr. Vice President and4,716
Support Services 1994 140,366 11,946 4,986
Group Executive, Support Services 1993 128,000 12,461 4,582
Nelson G. Hawk (4)1996 142,535 16,530 5,246 (1)
Sr. Vice President, 1995 140,000 10,899 4,589(1)
Vice President and Group4,589
Marketing 1994 116,005 9,620 36,972(4)
Executive, Marketing 1993 N/A N/A N/A32,821
Clarence D. Mitchell 1996 133,369 17,112 3,887 (1)
Sr. Vice President, 1995 110,058 7,776 4,251
Power Supply 1994 91,705 5,765 3,354
Wiley H. Sanders (4) 1996 123,750 9,340 82,715 (1) (4)
Vice President, Transmission 1995 135,000 9,295 5,703
1994 119,785 12,737 25,178
Eugen Heckl (5) 1996 99,480 16,734 117,245 (1) (5)
Sr. Vice President, Finance 1995 142,114 13,174 7,651
1994 142,114 13,919 7,600
______________________- ----------
(1) Includes contributions made in 19951996 by Oglethorpe under the 401(k)
Retirement Savings Plan on behalf of Messrs. Kilgore, Self,Robbins, Hawk, Mitchell,
Sanders and Heckl Hill,
Robbinsof $4,750, $4,072, $4,446, $2,969, $3,654 and Hawk of $4,620, $3,034, $4,351, $3,975, $4,393 and $3,789,$2,958,
respectively; and insurance premiums paid on term life insurance on behalf of
Messrs. Kilgore, Self,Robbins, Hawk, Mitchell, Sanders and Heckl Hill, Robbinsof $1,496, $1,353,
$800, $918, $2,831 and Hawk of $1,392, $6,641,
$3,300, $3,229, $323 and $800,$2,200, respectively.
(2) All executives listed above, except Mr. Kilgore, is not a participantparticipate in thean incentive
compensation program. HisMr. Kilgore's compensation is governed solely by the Board
of Directors.
(3) In conjunction with the Corporate Restructuring, Mr. SelfRobbins ceased to be a
senior executive of Oglethorpe as of January 31, 1997. Mr. Robbins now serves as
Vice President of Intellisource's Southeast operations, including support
services to Oglethorpe, GTC and GSOC. See "OGLETHORPE POWER
CORPORATION--Relationship with Intellisource" in Item 1 for further discussion.
(4) Mr. Sanders retired from Oglethorpe as of November 30, 1996. Mr. Sanders'
1996 compensation includes accrued severance benefits of $59,114, payment of
accrued vacation and sick benefits of $4,998 and relocation costs of $12,118.
65
(5) Mr. Heckl elected to retire from Oglethorpe under the provisions of an early
retirement program effective December 22, 1995. His 1995as of September 11, 1996. Mr. Heckl's 1996 compensation
includes severance benefits of $30,254$65,258, retirement-related contributions to his
deferred compensation account of $34,938 and payment of accrued vacation and
sick benefits of $8,095.
(4) Mr. Hawk joined Oglethorpe in February 1994. Mr. Hawk's 1994
compensation includes a sign-on bonus of $5,000 and relocation costs of
$27,383.
65
PENSION PLAN TABLE$11,891.
Pension Plan Table
YEARS OF CREDITED SERVICE
---------------------------
AVERAGE COMPENSATION
Years of Credited Service
-----------------------------------------------
Average Compensation 15 20 25
- -------------------- ------- ------- -------
---------- --------- ---------
$ 50,000...................................... $12,823 $17,097 $21,371
75,000...................................... 20,323 27,097 33,871
100,000...................................... 27,823 37,097 46,371
125,000...................................... 35,323 47,097 58,871
150,000...................................... 42,823 57,097 71,371
175,000...................................... 50,323 67,097 83,871
200,000...................................... 57,823 77,097 96,371
225,000...................................... 65,323 87,097 108,871
250,000...................................... 72,823 97,097 120,00050,000.................................................. $12,684 $16,911 $21,139
75,000.................................................. 20,184 26,911 33,639
100,000.................................................. 27,684 36,911 46,139
125,000.................................................. 35,184 46,911 58,639
150,000.................................................. 42,684 56,911 71,139
175,000.................................................. 50,184 66,911 83,639
200,000.................................................. 57,684 76,911 96,139
225,000.................................................. 65,184 86,911 108,639
250,000.................................................. 72,684 96,911 121,139
275,000.................................................. 80,184 106,911 133,639
The preceding table shows estimated annual straight life annuity
benefits payable upon retirement to persons in specified compensation and
years-of-service classifications assuming such persons had attained age 65 and
retired during 1995.1996. For purposes of calculating pension benefits, compensation
is defined as total salary and bonus, as shown in the above Summary Compensation
Table. Because covered compensation changes each year, the estimated pension
benefits for the classifications above will also change in future years. The
above pension benefits are not subject to any deduction for Social Security or
other offset amounts.
As of December 31, 1995,1996, the years of credited service under the Pension
Plan for the individuals listed in the Summary Compensation Table are as
follows:
YEARS OF
NAME CREDITED SERVICE
---- ----------------
Mr. Kilgore.......................................... 10
Mr. Self............................................. 7
Mr. Heckl............................................ 19
Mr. Hill............................................. 19
Mr. Robbins.......................................... 9
Mr. Hawk............................................. 0.8
COMPENSATION OF DIRECTORSYears of
Name Credited Service
---- ----------------
Mr. Kilgore.......................................... 11
Mr. Robbins.......................................... 10
Mr. Hawk ............................................ 1
Mr. Mitchell......................................... 15
Mr. Sanders.......................................... 1
Mr. Heckl............................................ 20
Compensation of Directors
Under a proposed policy which is scheduled for approval at the March 27,
1997 Board meeting, Oglethorpe payswill pay its Outside Directors a per diem fee of
$200$5,500 per Board meeting for the first four meetings attendedin a year; a per diem of
$1,000 per Board meeting will be paid for the fifth and subsequent meetings in a
year. Outside Directors will also be paid $1,000 per day for attending committee
meetings, annual meetings of the Members or $50other official meetings of
Oglethorpe. Under the proposed policy, Member Directors will be paid a per diem
fee of $1,000 per Board meeting and a per diem of $300 per day for attending
committee meetings, conducted by conference call. Additionally,annual meetings of the Members or other official meetings of
Oglethorpe. In addition, Oglethorpe reimburses itswill reimburse all Directors for
66
out-of-pocket expenses incurred in attending a meeting. AlternateAll Directors serving aswill be
paid a Director at any
meeting receive neither the per diem payment nor the expense reimbursement to
which a Director is entitled. The Memberfee of which the Alternate Director is
the manager receives reimbursement for the Alternate Director's out-of-pocket
expenses.$50 per day when participating in meetings conducted by
conference call. The Chairman of the Board is alsowill be paid at least one day'san additional 20% of the
per diem of $200 each monthper Board meeting for time involved in carrying out his official duties in
addition topreparing for the regularly scheduled Board Meeting.
EMPLOYMENT CONTRACTSmeetings.
Employment Contracts
Effective January 1, 1996, Oglethorpe entered into an employment
agreement with its President and Chief Executive Officer. The term of the
agreement extends to December 31, 1998, with certain automatic annual extension
provisions beyond that date unless either party gives notice of termination 60
days prior to an extension. Pursuant to the agreement, Mr. Kilgore's base salary
and bonus will be determined by Oglethorpe's Board, with
66
annual base salary
being at least $240,000. Under the agreement, if Oglethorpe terminates Mr.
Kilgore's employment without cause, he will be entitled to all salary and
benefits he would have received between the date of termination to the end of
the agreement. In addition, if Oglethorpe terminates Mr. Kilgore's employment
without cause or meaningfully reduces his stated duties or prerogatives within
three months prior to or 24 months subsequent to a Change in Control of
Oglethorpe (as defined in the agreement), a severance payment will be paid in an
amount not less than two times Mr. Kilgore's annual base salary on the date of
termination or the date on which his duties or prerogatives are reduced,
whichever is applicable. If such reduction in duties occurs, Mr. Kilgore will be
entitled to severance regardless whether he is terminated or resigns. If Mr.
Kilgore voluntarily separates himself from Oglethorpe, he will be prohibited
from working with a competitor of Oglethorpe for a period of one year thereafter
and will be paid an amount equal to his then current salary, bonus and benefits
for such period.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATIONCompensation Committee Interlocks and Insider Participation
E. J. Martin, Jr., J. Calvin Earwood, John B. Floyd, Jr., and J. G.
McCalmon serveserved as members of the Oglethorpe Human Resources Management
Committee which functionsfunctioned as Oglethorpe's compensation committee.committee for 1996. J.
Calvin Earwood has served as an executive officer of Oglethorpe since 1984 and
has served as the Chairman of the Board since 1989.
ITEM67
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Not applicable.
ITEMItem 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
67T. D. Kilgore is the President and Chief Executive Officer and a
Director of Oglethorpe, GTC and GSOC. Oglethorpe plans to make payments to GSOC
for system operations services in 1997 of approximately $6.8 million, which is
55% of GSOC's budgeted revenues. (See "OGLETHORPE POWER CORPORATION--Corporate
Restructuring" in Item 1.)
68
PART IV
ITEMItem 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Page
(A) LIST OF DOCUMENTS FILED AS A PART OF THIS REPORT.----
List of Documents Filed as a Part of This Report.
(1) FINANCIAL STATEMENTSFinancial Statements (Included under "Item 8. Financial
Statements and Supplementary Data")
Statements of Revenues and Expenses, For the Years
Ended December 31, 1996, 1995 1994 and 1993........................ 361994.............................. 43
Statements of Patronage Capital, For the Years Ended
December 31, 1996, 1995 1994 and 1993.............................. 361994.................................... 43
Balance Sheets, As of December 31, 19951996 and 1994............... 371995...................... 44
Statements of Capitalization, As of December 31, 19951996
and 1994...................................................... 391995............................................................ 46
Statements of Cash Flows, For the Years Ended December 31,
1996, 1995 1994 and 1993........................................... 401994................................................. 47
Notes to Financial Statements.................................. 41Statements, including pro-forma financial
statements relating to the Corporate Restructuring.................. 48
Report of Management........................................... 51Management.................................................. 60
Reports of Independent Public Accountants...................... 51Accountants............................. 60
(2) FINANCIAL STATEMENT SCHEDULESFinancial Statement Schedules
None applicable.
(3) EXHIBITSExhibits
Exhibits marked with an asterisk (*) are hereby incorporated by
reference to exhibits previously filed by the Registrant as indicated in
parentheses following the description of the exhibit.
NUMBER DESCRIPTION
- ------ -----------
2.1 (1)Number Description
2.1(1) -- Second Amended and Restated Restructuring Agreement,
dated March 29, 1996,February 24, 1997, by and among Oglethorpe,
Georgia Transmission Corporation (An Electric Membership
Corporation) and Georgia System Operations Corporation.
2.2(1) -- Member Agreement, dated August 1, 1996, by and among
Oglethorpe, Georgia Transmission Corporation (An
Electric Membership Corporation), Georgia System
Operations Corporation and the Members of Oglethorpe.
*3(i)(a) -- Restated Articles of Incorporation of Oglethorpe, dated
as of July 26, 1988. (Filed as Exhibit 3.1 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1988, File No. 33-7591.)
*3(ii)3(i)(b) -- Amendment to Articles of Incorporation of Oglethorpe,
dated as of March 11, 1997.
69
3(ii) -- Bylaws of Oglethorpe, as amended November 8, 1993. (Filedon February 24, 1997,
and effective as Exhibit 3.2 to the Registrant's Form 10-Q for the quarterly period
ended September 30, 1993, File No. 33-7591.)of March 11, 1997.
*4.1 -- Serial Facility Bond (included in Collateral Trust
Indenture listed as Exhibit 4.2).
68
*4.2 -- Collateral Trust Indenture, dated as of October 15,
1986, between OPC Scherer Funding Corporation,
Oglethorpe and Trust Company Bank, a banking
corporation, as Trustee. (Filed as Exhibit 4.2 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.3 -- Refunding Lessor Notes. (Filed as Exhibit 4.3.1 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.4(a) -- Nonrecourse Promissory Secured Note, due June 30, 2011,
from Wilmington Trust Company and William J. Wade, as
Owner Trustees, to Columbia Bank for Cooperatives.
(Filed as Exhibit 4.3.4 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*4.4(b) -- First Amendment to Nonrecourse Promissory Secured Note,
dated as of June 30, 1987, by Wilmington Trust Company
and The Citizens and Southern National Bank, as Owner
Trustee under Trust Agreement No. 1 with IBM Credit
Financing Corporation, to Columbia Bank for
Cooperatives. (Filed as Exhibit 4.3.4(a) to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1987, File No. 33-7591.)
*4.5(a) -- Indenture of Trust, Deed to Secure Debt and Security
Agreement No. 2, dated December 30, 1985, between
Wilmington Trust Company and William J. Wade, as Owner
Trustees under Trust Agreement No. 2 dated December 30,
1985, with Ford Motor Credit Company and The First
National Bank of Atlanta, as Indenture Trustee, together
with a Schedule identifying three other substantially
identical Indentures of Trust, Deeds to Secure Debt and
Security Agreements. (Filed as Exhibit 4.4(b) to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.5(b) -- First Supplemental Indenture of Trust, Deed to Secure
Debt and Security Agreement No. 2 (included as Exhibit A
to the Supplemental Participation Agreement No. 2 listed
as 10.1.1(b)).
*4.5(c) -- First Supplemental Indenture of Trust, Deed to Secure
Debt and Security Agreement No. 1, dated as of June 30,
1987, between Wilmington Trust Company and The Citizens
and Southern National Bank, collectively as Owner
Trustee under Trust Agreement No. 1 with IBM Credit
Financing Corporation, and The First National Bank of
Atlanta, as Indenture Trustee. (Filed as Exhibit 4.4(c)
to the Registrant's Form 10-K for the fiscal year ended
December 31, 1987, File No. 33-7591.)
*4.6(a) -- Lease Agreement No. 2 dated December 30, 1985, between
Wilmington Trust Company and William J. Wade, as Owner
Trustees under Trust Agreement No. 2, dated December 30,
1985, with Ford Motor Credit Company, Lessor, and
Oglethorpe, Lessee, with a Schedule identifying three
other substantially identical Lease Agreements. (Filed
as Exhibit 4.5(b) to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
70
*4.6(b) -- First Supplement To Lease Agreement No. 2 (included as
Exhibit B to the Supplemental Participation Agreement
No. 2 listed as 10.1.1(b)).
*4.6(c) -- First Supplement to Lease Agreement No. 1, dated as of
June 30, 1987, between The Citizens and Southern
National Bank as Owner Trustee under Trust Agreement No.
1 with IBM Credit Financing Corporation, as Lessor, and
Oglethorpe, as Lessee. (Filed as Exhibit 4.5(c) to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1987, File No. 33-7591.)
69
*4.7(a)4.7 -- Amended and Consolidated Loan Contract, dated as of
JuneMarch 1, 19841997, between Oglethorpe and the United States
of America, as amended
and supplemented, together with elevenfour notes executed and
delivered pursuant thereto.
(Filed as Exhibit 4.6 to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*4.7(b)4.8.1 -- Amendments, dated October 17, 1986, and January 9, 1987, to
Amended and Consolidated Loan ContractIndenture, dated as of JuneMarch 1, 1984
between Oglethorpe and the United States of America. (Filed as
Exhibit 4.6(a) to the Registrant's Form 10-K for the fiscal year
ended December 31, 1986, File No. 33-7591.)
*4.7(c) -- Amendment, dated September 30, 1988, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(b) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1988, File No. 33-7591.)
*4.7(d) -- Amendment, dated March 20, 1990, to Amended and Consolidated Loan
Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(c) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1989, File No. 33-7591.)
*4.7(e) -- Amendment, dated July 1, 1991, to Amended and Consolidated Loan
Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(d) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1991, File No. 33-7591.)
*4.7(f) -- Amendment, dated April 6, 1992, to Amended and Consolidated Loan
Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(e) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1992, File No. 33-7591.)
*4.7(g) -- Amendment, dated June 12, 1992, to Amended and Consolidated Loan
Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(f) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1992, File No. 33-7591.)
*4.7(h) -- Amendment, dated October 20, 1992, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(g) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1992, File No. 33-7591.)
*4.7(i) -- Amendment, dated February 25, 1993, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.6(h) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1992, File No. 33-7591.)
*4.7(j) -- Amendment, dated August 26, 1993, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.7(j) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1993, File No. 33-7591.)
*4.7(k) -- Amendment, dated August 31, 1994, to Amended and Consolidated
Loan Contract dated as of June 1, 1984 between Oglethorpe and the
United States of America. (Filed as Exhibit 4.7(k) to the
Registrant's Form 10-K for the fiscal year ended December 31,
1994, File No. 33-7591.)
70
*4.8.1(a) -- Mortgage and Security Agreement1997, made by Oglethorpe
to United
States of America datedSunTrust Bank, Atlanta, as of January 8, 1975. (Filed as Exhibit
4.12(b) to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*4.8.1(b)trustee.
4.8.2 -- Supplemental Mortgage made by Oglethorpe to United States of
America dated as of January 6, 1977. (Filed as Exhibit 4.12(a)
to the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.8.2(a) -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America and Trust
Company Bank, as trustee under certain indentures identified
therein, Mortgagees, dated as of November 1, 1978. (Filed as
Exhibit 4.11(c) to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*4.8.2(b) -- Confirmation of Execution And Delivery of Notes And First
Amendment to Consolidated Mortgage and Security Agreement, dated as of January 11, 1979. (Filed as Exhibit 4.11(b) to the
Registrant's Form S-1 Registration Statement, File No. 33-7591,
filed on October 9, 1986.)
*4.8.2(c) -- Supplement and Second Amendment to Consolidated Mortgage and
Security AgreementMarch 1, 1997, made by
and among Oglethorpe Mortgagor, and
United States of America and Trust Companyto SunTrust Bank, Atlanta, as Trustee,
Mortgagees, dated April 30, 1980. (Filed as Exhibit 4.11(a) to
the Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*4.8.3 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America and Trust
Company Bank, as trustee under certain indentures identified
therein, Mortgagees, dated as of September 15, 1982. (Filed as
Exhibit 4.10 to the Registrant's Form S-1 Registration Statement,
File No. 33-7591, filed on October 9, 1986.)
*4.8.4 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, Columbia
Bank for Cooperatives, and Trust Company Bank, as trustee under
certain indentures identified therein, Mortgagees, dated as of
June 1, 1984. (Filed as Exhibit 4.9 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.8.5 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, Columbia
Bank for Cooperatives, and Trust Company Bank, as trustee under
certain indentures identified therein, Mortgagees, dated as of
December 1, 1984. (Filed as Exhibit 4.8 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.8.6(a) -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, Columbia
Bank for Cooperatives, and Trust Company Bank, as trustee under
certain indentures identified therein, Mortgagees, dated as of
October 15, 1985. (Filed as Exhibit 4.7 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*4.8.6(b) -- First Supplement and Amendment to Consolidated Mortgage and
Security Agreement made by and among Oglethorpe, Mortgagor, and
United States of America, Columbia Bank for Cooperatives, and
Trust Company Bank, as trustee under certain indentures
identified therein, Mortgagees, dated as of November 1, 1988.
(Filed as Exhibit 4.7(a) to the Registrant's Form 10-K for the
fiscal year ended December 31, 1988, File No. 33-7591.)
71
*4.8.7(a) -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, and Trust Company Bank, as trustee under
certain indentures identified therein, Mortgagees, dated as of
December 1, 1989. (Filed as Exhibit 4.19 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1989, File No.
33-7591.)
*4.8.7(b) -- Supplement to Consolidated Mortgage and Security Agreement made
by and among Oglethorpe, Mortgagor, and United States of
America, National Bank for Cooperatives, and Trust Company Bank,
as trustee under certain indentures identified therein,
Mortgagees, dated as of November 21, 1990. (Filed as Exhibit
4.19(a) to the Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*4.8.8 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, Credit Suisse, acting by and through its
New York branch, and Trust Company Bank, as trustee under certain
indentures identified therein, Mortgagees, dated as of April 1,
1992. (Filed as Exhibit 4.21 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1992, File No. 33-7591.)
*4.8.9 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, Credit Suisse, acting by and through its
New York branch, and Trust Company Bank, as trustee under certain
indentures identified therein, Mortgagees, dated as of October 1,
1992. (Filed as Exhibit 4.22 to the Registrant's Form 10-K for
the fiscal year ended December 31, 1992, File No. 33-7591.)
*4.8.10 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, Credit Suisse, acting by and through its
New York branch, and Trust Company Bank, as trustee under certain
indentures identified therein, Mortgagees, dated as of December
1, 1992. (Filed as Exhibit 4.23 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1992, File No. 33-7591.)
*4.8.11 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, Credit Suisse, acting by and through its
New York branch, and Trust Company Bank, as trustee under certain
indentures identified therein, Mortgagees, dated as of September
1, 1993. (Filed as Exhibit 4.8.11 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1993, File No. 33-7591.)
*4.8.12 -- Consolidated Mortgage and Security Agreement made by and among
Oglethorpe, Mortgagor, and United States of America, National
Bank for Cooperatives, Credit Suisse, acting by and through its
New York branch, and Trust Company Bank, as trustee under certain
indentures identified therein, Mortgagees, dated as of September
1, 1994. (Filed as Exhibit 4.8.12 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1994, File No. 33-7591.)
4.9.1 (3)trustee.
4.9.1(3) -- Loan Agreement, dated as of October 1, 1992, between
Development Authority of Monroe County and Oglethorpe
relating to Development Authority of Monroe County
Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Scherer Project), Series 1992A.
4.9.2 (3)4.9.2(3) -- Note, dated October 1, 1992, from Oglethorpe to Trust
Company Bank, as trustee acting pursuant to a Trust
Indenture, dated as of October 1, 1992, between
Development Authority of Monroe County and Trust Company
Bank.
4.9.3 (3)4.9.3(3) -- Trust Indenture, dated as of October 1, 1992, between
Development Authority of Monroe County and Trust Company
Bank, Trustee, relating to Development Authority of
Monroe 72
County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Scherer Project), Series
1992A.
4.10.1 (2) -- Loan Agreement, dated as of April 1, 1992, between Development
Authority of Burke County and Oglethorpe relating to Development
Authority of Burke County Adjustable Tender Pollution Control
Revenue Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1992A.
4.10.2 (2) -- Note, dated April 1, 1992, from Oglethorpe to Trust Company Bank,
as trustee acting pursuant to a Trust Indenture, dated as of
April 1, 1992, between Development Authority of Burke County and
Trust Company Bank.
4.10.3 (2) -- Trust Indenture, dated as of April 1, 1992, between Development
Authority of Burke County and Trust Company Bank, as trustee,
relating to Development Authority of Burke County Adjustable
Tender Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1992A.
4.10.4(a) -- First Amended and Restated Letter of Credit Reimbursement
(2) Agreement, dated as of June 1, 1992, between Credit Suisse and
Oglethorpe relating to an Irrevocable Letter of Credit issued in
connection with the Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe
Power Corporation Vogtle Project), Series 1992A.
4.10.4(b) -- First Amendment to First Amended and Restated Letter of Credit
(2) Reimbursement Agreement, dated September 15, 1993, between
Oglethorpe and Credit Suisse.
4.10.4(c) -- Second Amendment to First Amended and Restated Letter of Credit
(2) Reimbursement Agreement, dated August 1, 1994, between Oglethorpe
and Credit Suisse.
4.10.4(d) -- Third Amendment to First Amended and Restated Letter of Credit
(2) Reimbursement Agreement, dated April 15, 1995, between
Oglethorpe and Credit Suisse.
4.11.1 (4)4.10.1(4) -- Loan Agreement, dated as of December 1, 1992, between
Development Authority of Burke County and Oglethorpe
relating to Development Authority of Burke County
Adjustable Tender Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series
1993A.
4.11.2 (4)4.10.2(4) -- Note, dated December 1, 1992, from Oglethorpe to Trust
Company Bank, as trustee acting pursuant to a Trust
Indenture, dated as of December 1, 1992, between
Development Authority of Burke County and Trust Company
Bank.
4.11.3 (4)4.10.3(4) -- Trust Indenture, dated as of December 1, 1992, from
Development Authority of Burke County to Trust Company
Bank, as trustee, relating to Development Authority of
Burke County Adjustable Tender Pollution Control Revenue
Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A.
4.11.4 (4)4.10.4(4) -- Interest Rate Swap Agreement, dated as of December 1,
1992, by and between Oglethorpe and AIG Financial
Products Corp. relating to Development Authority of
Burke County Adjustable Tender Pollution Control Revenue
Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A.
4.11.5 (4)71
4.10.5(4) -- Liquidity Guaranty Agreement, dated as of December 1,
1992, by and between Oglethorpe and AIG Financial
Products Corp. relating to Development Authority of
Burke County Adjustable Tender Pollution Control Revenue
Bonds (Oglethorpe Power Corporation Vogtle Project),
Series 1993A.
73
4.11.6 (2)4.10.6(2) -- Standby Bond Purchase Agreement, dated as of December
14, 1995, between Oglethorpe and Canadian Imperial Bank
of Commerce, New York Agency, relating to Development
Authority of Burke County Adjustable Tender Pollution
Control Revenue Bonds (Oglethorpe Power Corporation
Vogtle Project), Series 1993A.
4.11.7 (2)4.10.7(2) -- Standby Bond Purchase Agreement, dated as of November
30, 1994, between Oglethorpe and Credit Local de France,
Acting through its New York Agency, relating to the
Development Authority of Burke County Adjustable Tender
Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1994A.
4.12.1 (4)4.11.1(4) -- Loan Agreement, dated as of DecemberOctober 1, 1995,1996, between
Development Authority of Burke County and Oglethorpe
relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1995.
4.12.2 (4)1996.
4.11.2(4) -- Note, dated October 1, 1996, from Oglethorpe to SunTrust
Bank, Atlanta, as trustee pursuant to an Indenture of
Trust, dated as of October 1, 1996, between Development
Authority of Burke County and SunTrust Bank, Atlanta.
4.11.3(4) -- Indenture of Trust, dated as of DecemberOctober 1, 1995,1996, between
Development Authority of Burke County and SunTrust Bank,
Atlanta, as trustee, relating to Development Authority
of Burke County Pollution Control Revenue Bonds
(Oglethorpe Power Corporation Vogtle Project), Series
1995.
*4.13.11996.
4.12.1(2) -- Loan Agreement, dated as of April 2, 1992, between the
Development Authority of Burke County and Oglethorpe, as
amended and supplemented by First Amendatory and
Supplemental Loan No. T-840901,Agreement, dated as of March 1, 1997,
relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1997A.
4.12.2(2) -- Note, dated March 1, 1997, from Oglethorpe to SunTrust
Bank, Atlanta, as trustee acting pursuant to a Trust
Indenture, dated as of April 1, 1992, between
Development Authority of Burke County and SunTrust Bank,
Atlanta, as supplemented by First Supplemental Trust
Indenture, dated as of March 1, 1997.
4.12.3(2) -- Trust Indenture, dated as of April 2, 1992, between
Development Authority of Burke County and SunTrust Bank,
Atlanta, as trustee, as supplemented by a First
Supplemental Trust Indenture, dated as of March 1, 1997,
relating to Development Authority of Burke County
Pollution Control Revenue Bonds (Oglethorpe Power
Corporation Vogtle Project), Series 1997A.
4.13.1 -- Indemnity Agreement, dated as of March 1, 1997, by and
between Oglethorpe and Columbia Bank for Cooperatives,Georgia Transmission Corporation
(An Electric Membership Corporation).
4.13.2 -- Indemnification Agreement, dated as of September 14, 1984.
(FiledMarch 11, 1997,
by Oglethorpe and Georgia Transmission Corporation (An
Electric Membership Corporation) for the benefit of the
United States of America.
72
4.14.1(2) -- Master Loan Agreement, dated as Exhibit 4.14.1of March 1, 1997,
between Oglethorpe and CoBank, ACB, MLA No. 0459.
4.14.2(2) -- Consolidating Supplement, dated as of March 1, 1997,
between Oglethorpe and CoBank, ACB, relating to the Registrant's Form S-1
Registration Statement, FileLoan No.
33-7591, filed on October 9,
1986.)
*4.13.2ML0459T1.
4.14.3(2) -- Promissory Note, Loan No. T-840901,dated March 1, 1997, in the original
principal amount of $8,995,000$7,102,740.26, from Oglethorpe to
Columbia Bank for
Cooperatives,CoBank, ACB, relating to Loan No. ML0459T1.
4.14.4(2) -- Consolidating Supplement, dated as of NovemberMarch 1, 1984. (Filed as Exhibit
4.14.2 to the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*4.14.1 -- Loan Agreement, Loan No. T-831222,1997,
between Oglethorpe and Columbia Bank for Cooperatives, dated as of December 30, 1983.
(Filed as Exhibit 4.16.1CoBank, ACB, relating to the Registrant's Form S-1
Registration Statement, FileLoan No.
33-7591, filed on October 9,
1986.)
*4.14.2ML0459T2.
4.14.5(2) -- Promissory Note, Loan No. T-831222,dated March 1, 1997, in the original
principal amount of $2,376,000 from$1,856,475.12, made by Oglethorpe to
Columbia Bank for
Cooperatives, dated as of June 1, 1984. (Filed as Exhibit 4.16.2CoBank, ACB, relating to the Registrant's Form S-1 Registration Statement, FileLoan No. 33-7591, filed on October 9, 1986.)ML0459T2.
*4.15.1 -- Loan Agreement, Loan No. T-830404, between Oglethorpe
and Columbia Bank for Cooperatives, dated as of April
29, 1983. (Filed as Exhibit 4.18.1 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed
on October 9, 1986.)
*4.15.2 -- Promissory Note, Loan No. T-830404-1, in the original
principal amount of $9,935,000, from Oglethorpe to
Columbia Bank for Cooperatives, dated as of April 29,
1983. (Filed as Exhibit 4.18.2 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*4.15.3 -- Security Deed and Security Agreement, dated April 29,
1983, between Oglethorpe and Columbia Bank for
Cooperatives. (Filed as Exhibit 4.18.3 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.1.1(a) -- Participation Agreement No. 2 among Oglethorpe as
Lessee, Wilmington Trust Company as Owner Trustee, The
First National Bank of Atlanta as Indenture Trustee,
Columbia Bank for Cooperatives as Loan Participant and
Ford Motor Credit Company as Owner Participant, 74
dated
December 30, 1985, together with a Schedule identifying
three other substantially identical Participation
Agreements. (Filed as Exhibit 10.1.1(b) to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.1.1(b)-- Supplemental Participation Agreement No. 2. (Filed as
Exhibit 10.1.1(a) to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.1.1(c)-- Supplemental Participation Agreement No. 1, dated as of
June 30, 1987, among Oglethorpe as Lessee, IBM Credit
Financing Corporation as Owner Participant, Wilmington
Trust Company and The Citizens and Southern National
Bank as Owner Trustee, The First National Bank of
Atlanta, as Indenture Trustee, and Columbia Bank for
Cooperatives, as Loan Participant. (Filed as Exhibit
10.1.1(c) to the Registrant's Form 10-K for the fiscal
year ended December 31, 1987, File No. 33-7591.)
*10.1.2 -- General Warranty Deed and Bill of Sale No. 2 between
Oglethorpe, Grantor, and Wilmington Trust Company and
William J. Wade, as Owner Trustees under Trust Agreement
No. 2, dated December 30, 1985, with Ford Motor Credit
Company, Grantee, together with a Schedule identifying
three substantially identical General Warranty Deeds
73
and Bills of Sale. (Filed as Exhibit 10.1.2 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.1.3(a)-- Supporting Assets Lease No. 2, dated December 30, 1985,
between Oglethorpe, Lessor, and Wilmington Trust Company
and William J. Wade, as Owner Trustees, under Trust
Agreement No. 2, dated December 30, 1985, with Ford
Motor Credit Company, Lessee, together with a Schedule
identifying three substantially identical Supporting
Assets Leases. (Filed as Exhibit 10.1.3 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.1.3(b)-- First Amendment to Supporting Assets Lease No. 2, dated
as of November 19, 1987, together with a Schedule
identifying three substantially identical First
Amendments to Supporting Assets Leases. (Filed as
Exhibit 10.1.3(a) to the Registrant's Form 10-K for the
fiscal year ended December 31, 1987, File No. 33-7591.)
*10.1.4(a)-- Supporting Assets Sublease No. 2, dated December 30,
1985, between Wilmington Trust Company and William J.
Wade, as Owner Trustees under Trust Agreement No. 2
dated December 30, 1985, with Ford Motor Credit Company,
Sublessor, and Oglethorpe, Sublessee, together with a
Schedule identifying three substantially identical
Supporting Assets Subleases. (Filed as Exhibit 10.1.4 to
the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*10.1.4(b)-- First Amendment to Supporting Assets Sublease No. 2,
dated as of November 19, 1987, together with a Schedule
identifying three substantially identical First
Amendments to Supporting Assets Subleases. (Filed as
Exhibit 10.1.4(a) to the Registrant's Form 10-K for the
fiscal year ended December 31, 1987, File No. 33-7591.)
*10.1.5 -- Tax Indemnification Agreement No. 2, dated December 30,
1985, between Ford Motor Credit Company, Owner
Participant, and Oglethorpe, Lessee, together with a
Schedule identifying three substantially identical Tax
Indemnification Agreements. (Filed as Exhibit 10.1.5 to
the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*10.1.6 -- Assignment of Interest in Ownership Agreement and
Operating Agreement No. 2, dated December 30, 1985,
between Oglethorpe, Assignor, and Wilmington Trust
Company and William J. Wade, as Owner Trustees under
Trust Agreement No. 2, dated December 30, 75
1985, with
Ford Motor Credit Company, Assignee, together with
Schedule identifying three substantially identical
Assignments of Interest in Ownership Agreement and
Operating Agreement. (Filed as Exhibit 10.1.6 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.1.7 -- Consent, Amendment and Assumption No. 2 dated December
30, 1985, among Georgia Power Company and Oglethorpe and
Municipal Electric Authority of Georgia and City of
Dalton, Georgia and Gulf Power Company and Wilmington
Trust Company and William J. Wade, as Owner Trustees
under Trust Agreement No. 2, dated December 30, 1985,
with Ford Motor Credit Company, together with a Schedule
identifying three substantially identical Consents,
Amendments and Assumptions. (Filed as Exhibit 10.1.9 to
the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*10.1.7(a)-- Amendment to Consent, Amendment and Assumption No. 2,
dated as of August 16, 1993, among Oglethorpe, Georgia
Power Company, Municipal Electric Authority of
74
Georgia, City of Dalton, Georgia, Gulf Power Company,
Jacksonville Electric Authority, Florida Power & Light
Company and Wilmington Trust Company and NationsBank of
Georgia, N.A., as Owner Trustees under Trust Agreement
No. 2, dated December 30, 1985, with Ford Motor Credit
Company, together with a Schedule identifying three
substantially identical Amendments to Consents,
Amendments and Assumptions. (Filed as Exhibit 10.1.9(a)
to the Registrant's Form 10-Q for the quarterly period
ended September 30, 1993, File No. 33-7591.)
*10.2.1 -- Section 168 Agreement and Election dated as of April 7,
1982, between Continental Telephone Corporation and
Oglethorpe. (Filed as Exhibit 10.2 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed
on October 9, 1986.)
*10.2.2 -- Section 168 Agreement and Election dated as of April 9,
1982, between National Service Industries, Inc. and
Oglethorpe. (Filed as Exhibit 10.3 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed
on October 9, 1986.)
*10.2.3 -- Section 168 Agreement and Election dated as of April 9,
1982, between Rollins, Inc. and Oglethorpe. (Filed as
Exhibit 10.4 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.2.4 -- Section 168 Agreement and Election dated as of December
13, 1982, between Selig Enterprises, Inc. and
Oglethorpe. (Filed as Exhibit 10.5 to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed
on October 9, 1986.)
*10.3.1(a)-- Plant Robert W. Scherer Units Numbers One and Two
Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia, dated
as of May 15, 1980. (Filed as Exhibit 10.6.1 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.3.1(b)-- Amendment to Plant Robert W. Scherer Units Numbers One
and Two Purchase and Ownership Participation Agreement
among Georgia Power Company, Oglethorpe, Municipal
Electric Authority of Georgia and City of Dalton,
Georgia, dated as of December 30, 1985. (Filed as
Exhibit 10.1.8 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.3.1(c)-- Amendment Number Two to the Plant Robert W. Scherer
Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and
City of Dalton, Georgia, dated as of 76
July 1, 1986.
(Filed as Exhibit 10.6.1(a) to the Registrant's Form
10-K for the fiscal year ended December 31, 1987, File
No. 33-7591.)
*10.3.1(d)-- Amendment Number Three to the Plant Robert W. Scherer
Units Numbers One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and
City of Dalton, Georgia, dated as of August 1, 1988.
(Filed as Exhibit 10.6.1(b) to the Registrant's Form
10-Q for the quarterly period ended September 30, 1993,
File No. 33-7591.)
*10.3.1(e)-- Amendment Number Four to the Plant Robert W. Scherer
Units Number One and Two Purchase and Ownership
Participation Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and
City of Dalton, Georgia, dated
75
as of December 31, 1990. (Filed as Exhibit 10.6.1(c) to
the Registrant's Form 10-Q for the quarterly period
ended September 30, 1993, File No. 33-7591.)
*10.3.2(a)-- Plant Robert W. Scherer Units Numbers One and Two
Operating Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and
City of Dalton, Georgia, dated as of May 15, 1980.
(Filed as Exhibit 10.6.2 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.3.2(b)-- Amendment to Plant Robert W. Scherer Units Numbers One
and Two Operating Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and
City of Dalton, Georgia, dated as of December 30, 1985.
(Filed as Exhibit 10.1.7 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.3.2(c)-- Amendment Number Two to the Plant Robert W. Scherer
Units Numbers One and Two Operating Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia, dated
as of December 31, 1990. (Filed as Exhibit 10.6.2(a) to
the Registrant's Form 10-Q for the quarterly period
ended September 30, 1993, File No. 33-7591.)
*10.3.3 -- Plant Scherer Managing Board Agreement among Georgia
Power Company, Oglethorpe, Municipal Electric Authority
of Georgia, City of Dalton, Georgia, Gulf Power Company,
Florida Power & Light Company and Jacksonville Electric
Authority, dated as of December 31, 1990. (Filed as
Exhibit 10.6.3 to the Registrant's Form 10-Q for the
quarterly period ended September 30, 1993, File No.
33-7591.)
*10.4.1(a)-- Alvin W. Vogtle Nuclear Units Numbers One and Two
Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia, dated
as of August 27, 1976. (Filed as Exhibit 10.7.1 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.4.1(b)-- Amendment Number One, dated January 18, 1977, to the
Alvin W. Vogtle Nuclear Units Numbers One and Two
Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia. (Filed
as Exhibit 10.7.3 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.1(c)-- Amendment Number Two, dated February 24, 1977, to the
Alvin W. Vogtle Nuclear Units Numbers One and Two
Purchase and Ownership Participation Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and City of Dalton, Georgia. (Filed
as Exhibit 10.7.4 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1986, File No. 33-7591.)
77
*10.4.2 -- Alvin W. Vogtle Nuclear Units Numbers One and Two
Operating Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and
City of Dalton, Georgia, dated as of August 27, 1976.
(Filed as Exhibit 10.7.2 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.5.1 -- Plant Hal Wansley Purchase and Ownership Participation
Agreement between Georgia Power Company and Oglethorpe,
dated as of March 26, 1976. (Filed as Exhibit 10.8.1 to
76
the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*10.5.2*10.5.2(a) -- Plant Hal Wansley Operating Agreement between Georgia
Power Company and Oglethorpe, dated as of March 26,
1976. (Filed as Exhibit 10.8.2 to the Registrant's Form
S-1 Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.5.2(b) -- Amendment, dated as of January 15, 1995, to the Plant
Hal Wansley Operating Agreements by and among Georgia
Power Company, Oglethorpe, Municipal Electric Authority
of Georgia and City of Dalton, Georgia. (Filed as
Exhibit 10.5.2(a) to the Registrant's Form 10-Q for the
quarterly period ended September 30, 1996, File No.
33-7591.)
*10.5.3 -- Plant Hal Wansley Combustion Turbine Agreement between
Georgia Power Company and Oglethorpe, dated as of August
2, 1982 and Amendment No. 1, dated October 20, 1982.
(Filed as Exhibit 10.18 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on
October 9, 1986.)
*10.6.1 -- Edwin I. Hatch Nuclear Plant Purchase and Ownership
Participation Agreement between Georgia Power Company
and Oglethorpe, dated as of January 6, 1975. (Filed as
Exhibit 10.9.1 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.6.2 -- Edwin I. Hatch Nuclear Plant Operating Agreement between
Georgia Power Company and Oglethorpe, dated as of
January 6, 1975. (Filed as Exhibit 10.9.2 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.7.1 -- Rocky Mountain Pumped Storage Hydroelectric Project
Ownership Participation Agreement, dated as of November
18, 1988, by and between Oglethorpe and Georgia Power
Company. (Filed as Exhibit 10.22.1 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1988,
File No. 33-7591.)
*10.7.2 -- Rocky Mountain Pumped Storage Hydroelectric Project
Operating Agreement, dated as of November 18, 1988, by
and between Oglethorpe and Georgia Power Company. (Filed
as Exhibit 10.22.2 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1988, File No. 33-7591.)
*10.8.1(a)10.8.1 -- Amended and Restated Wholesale Power Contract, dated September 5, 1974,as
of August 1, 1996, between Oglethorpe and PlantersAltamaha
Electric Membership Corporation and all schedules
thereto, the Supplemental Agreement dated September 5,
1974, between Oglethorpe and Planters Electric Membership
Corporation, relating to such Wholesale Power Contract, and
Amendment No. 1 to Wholesale Power Contract dated May 12, 1980,
between Oglethorpe and Planters Electric Membership Corporation, together with a Schedule identifying 37 other
substantially identical Amended and Restated Wholesale
Power Contracts, and an additional Amended and Restated
Wholesale Power Contract that is not substantially
identical (filed
herewith to reflect update to Schedule A to Wholesale Power
Contract). (Filed as Exhibit 10.10 to the Registrant's Form S-1
Registration Statement, File No. 33-7591, filed on October 9,
1986.)
*10.8.1(b)identical.
10.8.2 -- Amended and ConsolidatedRestated Supplemental Agreement, dated as of
August 1, 1996, by and between Oglethorpe, Altamaha
Electric Membership Corporation and the United States of
America, together with a Schedule identifying 38 other
substantially identical Amended and Restated
Supplemental Agreements.
10.8.3 -- Supplemental Agreement to the Amended Restated Wholesale
Power Contract, dated as of DecemberJanuary 1, 1988, between1997, by and
among Georgia Power Company, Oglethorpe and Planters Electric
Membership Corporation and all schedules thereto, and the
Amended and Consolidated Supplemental Agreement, dated
December 1, 1988, between Oglethorpe and PlantersAltamaha
Electric Membership Corporation, together with a
Schedule identifying 3738 other substantially identical
Supplemental Agreements.
77
10.8.4 -- Supplemental Agreement to the Amended Restated Wholesale
Power Contracts,Contract, dated as of March 1, 1997, by and
between Oglethorpe and Altamaha Electric Membership
Corporation, together with a Schedule identifying 36
other substantially identical Supplemental Agreements,
and an additional 78
Wholesale Power ContractSupplemental Agreement that is not
substantially identical.
(Filed as Exhibit 10.10(a)10.8.5 -- Supplemental Agreement to the Registrant's Form 10-K for
the fiscal year ended December 31, 1988, File No. 33-7591.)Amended Restated Wholesale
Power Contract, dated as of March 1, 1997, by and
between Oglethorpe and Coweta-Fayette Electric
Membership Corporation, together with a Schedule
identifying 1 other substantially identical Supplemental
Agreement.
*10.9 -- Transmission Facilities Operation and Maintenance
Contract between Georgia Power Company and Oglethorpe
dated as of June 9, 1986. (Filed as Exhibit 10.13 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.10(a) -- Joint Committee Agreement among Georgia Power Company,
Oglethorpe, Municipal Electric Authority of Georgia and
the City of Dalton, Georgia, dated as of August 27,
1976. (Filed as Exhibit 10.14(b) to the Registrant's
Form S-1 Registration Statement, File No. 33-7591, filed
on October 9, 1986.)
*10.10(b) -- First Amendment to Joint Committee Agreement among
Georgia Power Company, Oglethorpe, Municipal Electric
Authority of Georgia and the City of Dalton, Georgia,
dated as of June 19, 1978. (Filed as Exhibit 10.14(a) to
the Registrant's Form S-1 Registration Statement, File
No. 33-7591, filed on October 9, 1986.)
*10.11 -- Interconnection Agreement between Oglethorpe and Alabama
Electric Cooperative, Inc., dated as of November 12,
1990. (Filed as Exhibit 10.16(a) to the Registrant's
Form 10-K for the fiscal year ended December 31, 1990,
File No. 33-7591.)
*10.11(a) -- Amendment No. 1 to Interconnection Agreement between
Alabama Electric Cooperative, Inc. and Oglethorpe, dated
as of April 22, 1994. (Filed as Exhibit 10.11(a) to the
Registrant's Form 10-Q for the quarter ended June 30,
1994, File No. 33-7591.)
*10.11(b) -- Letter of Commitment (Firm Power Sale) Under Service
Schedule J - Negotiated Interchange Service between
Alabama Electric Cooperative, Inc. and Oglethorpe, dated
March 31, 1994. (Filed as Exhibit 10.11(b) to the
Registrant's Form 10-Q for the quarter ended June 30,
1994, File No. 33-7591.)
*10.12 -- Oglethorpe Deferred Compensation Plan for Key Employees,
as Amended and Restated January, 1987. (Filed as Exhibit
10.19 to the Registrant's Form 10-K for the fiscal year
ended December 31, 1986, File No. 33-7591.)
*10.13.1 -- Assignment of Power System Agreement and Settlement
Agreement, dated January 8, 1975, by Georgia Electric
Membership Corporation to Oglethorpe. (Filed as Exhibit
10.20.1 to the Registrant's Form S-1 Registration
Statement, File No. 33-7591, filed on October 9, 1986.)
*10.13.2 -- Power System Agreement, dated April 24, 1974, by and
between Georgia Electric Membership Corporation and
Georgia Power Company. (Filed as Exhibit 10.20.2 to the
78
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.13.3 -- Settlement Agreement, dated April 24, 1974, by and
between Georgia Power Company, Georgia Municipal
Association, Inc., City of Dalton, Georgia Electric
Membership Corporation and Crisp County Power
Commission. (Filed as Exhibit 10.20.3 to the
Registrant's Form S-1 Registration Statement, File No.
33-7591, filed on October 9, 1986.)
*10.14 -- Distribution Facilities Joint Use Agreement between
Oglethorpe and Georgia Power Company, dated as of May
12, 1986. (Filed as Exhibit 10.21 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1986,
File No. 33-7591.)
*10.15.1 -- Long Term Firm Power Purchase Agreement, dated as of
July 19, 1989, by and between Oglethorpe and Big Rivers
Electric Corporation. (Filed as Exhibit 10.24.1 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1989, File No. 33-7591.)
79
*10.15.2 -- Coordination Services Agreement, dated as of August 21,
1989, by and between Oglethorpe and Georgia Power
Company. (Filed as Exhibit 10.24.2 to the Registrant's
Form 10-K for the fiscal year ended December 31, 1989,
File No. 33-7591.)
*10.15.3 -- Long Term Firm Power Purchase Agreement between Big
Rivers Electric Corporation and Oglethorpe, dated as of
December 17, 1990. (Filed as Exhibit 10.24.3 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*10.15.4 -- Interchange Agreement between Oglethorpe and Big Rivers
Electric Corporation, dated as of November 12, 1990.
(Filed as Exhibit 10.24.4 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1990, File No.
33-7591.)
*10.16 -- Block Power Sale Agreement between Georgia Power Company
and Oglethorpe, dated as of November 12, 1990. (Filed as
Exhibit 10.25 to the Registrant's Form 8-K, filed
January 4, 1991, File No. 33-7591.)
*10.17 -- Coordination Services Agreement between Georgia Power
Company and Oglethorpe, dated as of November 12, 1990.
(Filed as Exhibit 10.26 to the Registrant's Form 8-K,
filed January 4, 1991, File No. 33-7591.)
*10.18 -- Revised and Restated Integrated Transmission System
Agreement between Oglethorpe and Georgia Power Company,
dated as of November 12, 1990. (Filed as Exhibit 10.27
to the Registrant's Form 8-K, filed January 4, 1991,
File No. 33-7591.)
*10.19 -- ITSA, Power Sale and Coordination Umbrella Agreement
between Oglethorpe and Georgia Power Company, dated as
of November 12, 1990. (Filed as Exhibit 10.28 to the
Registrant's Form 8-K, filed January 4, 1991, File No.
33-7591.)
*10.20 -- Amended and Restated Nuclear Managing Board Agreement
among Georgia Power Company, Oglethorpe Power
Corporation, Municipal Electric Authority of Georgia and
City of Dalton, Georgia dated as of July 1, 1993. (Filed
as Exhibit 10.36 to the Registrant's 10-Q for the
quarterly period ended September 30, 1993, File No.
33-7591.)
*10.21 -- Supplemental Agreement by and among Oglethorpe,
Tri-County Electric Membership Cooperation and Georgia
Power Company, dated as of November 12, 1990, together
with
79
a Schedule identifying 38 other substantially identical
Supplemental Agreements. (Filed as Exhibit 10.30 to the
Registrant's Form 8-K, filed January 4, 1991, File No.
33-7591.)
*10.22 -- Unit Capacity and Energy Purchase Agreement between
Oglethorpe and Entergy Power Incorporated, dated as of
October 11, 1990. (Filed as Exhibit 10.31 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*10.23 -- Interchange Agreement between Oglethorpe and Arkansas
Power & Light Company, Louisiana Power & Light Company,
Mississippi Power & Light Company, New Orleans Public
Service, Inc., Energy Services, Inc., dated as of
November 12, 1990. (Filed as Exhibit 10.32 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*10.24 -- Interchange Agreement between Oglethorpe and Seminole
Electric Cooperative, Inc., dated as of November 12,
1990. (Filed as Exhibit 10.33 to the Registrant's Form
10-K for the fiscal year ended December 31, 1990, File
No. 33-7591.)
80
*10.25.1 -- Excess Energy and Short-term Power Agreement between
Oglethorpe and Tennessee Valley Authority, effective as
of January 23, 1991. (Filed as Exhibit 10.34.1 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1990, File No. 33-7591.)
*10.25.2 -- Transmission Service Agreement between Oglethorpe and
Tennessee Valley Authority, effective as of January 23,
1991. (Filed as Exhibit 10.34.2 to the Registrant's Form
10-K for the fiscal year ended December 31, 1990, File
No. 33-7591.)
*10.26 -- Power Purchase Agreement between Oglethorpe and Hartwell
Energy Limited Partnership, dated as of June 12, 1992.
(Filed as Exhibit 10.35 to the Registrant's Form 10-K
for the fiscal year ended December 31, 1992, File No.
33-7591).
10.27 (5)*10.27(5) -- Master Power Purchase and Sale Agreement between Enron
Power Marketing, Inc. and Oglethorpe, dated as of
January 3, 1996. 10.28 (6)(Filed as Exhibit 10.27 to the
Registrant's Form 10-K for the fiscal year ended
December 31, 1995, File No. 33-7591.)
*10.27(a) (5) -- Extension and Modification Agreement between Enron Power
Marketing, Inc. and Oglethorpe, dated as of April 30,
1996. (Filed as Exhibit 10.27(a) to the Registrant's
Form 10-Q for the quarterly period ended March 31, 1996,
File No. 33-7591.)
*10.28(6) -- Employment Agreement between Oglethorpe and T. D.
Kilgore, dated as of December 20, 1995. 22.1(Filed as
Exhibit 10.28 to the Registrant's Form 10-K for the
fiscal year ended December 31, 1995, File No. 33-7591.)
*10.29(5) -- SubsidiaryMaster Power Purchase and Sale Agreement between
Duke/Louis Dreyfus L.L.C. and Oglethorpe, dated as of
August 31, 1996. (Filed as Exhibit 10.29 to the
Registrant's Form 10-Q for the quarterly period ended
September 30, 1996, File No. 33-7591.)
10.30(5) -- Power Purchase and Sale Agreement among LG&E Power
Marketing Inc., LG&E Energy Corp. and Oglethorpe, (not included becausedated
as of November 19, 1996.
10.31(5) -- Power Purchase and Sale Agreement among LG&E Power
Marketing Inc., LG&E Power Inc. and Oglethorpe, dated as
of January 1, 1997.
80
10.32.1 -- Participation Agreement (P1), dated as of December 30,
1996, among Oglethorpe, Rocky Mountain Leasing
Corporation, Fleet National Bank, as Owner Trustee,
SunTrust Bank, Atlanta, as Co-Trustee, the subsidiary
does not constituteOwner
Participant named therein and Utrecht-America Finance
Co., as Lender, together with a "significant subsidiary" under Rule 1-02(v)Schedule identifying
five other substantially identical Participation
Agreements.
10.32.2 -- Rocky Mountain Head Lease Agreement (P1), dated as of
Regulation S-X)December 30, 1996, between Oglethorpe and SunTrust Bank,
Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical Rocky
Mountain Head Lease Agreements.
10.32.3 -- Ground Lease Agreement (P1), dated as of December 30,
1996, between Oglethorpe and SunTrust Bank, Atlanta, as
Co-Trustee, together with a Schedule identifying five
other substantially identical Ground Lease Agreements.
10.32.4 -- Rocky Mountain Agreements Assignment and Assumption
Agreement (P1), dated as of December 30, 1996, between
Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other
substantially identical Rocky Mountain Agreements
Assignment and Assumption Agreements.
10.32.5 -- Facility Lease Agreement (P1), dated as of December 30,
1996, between SunTrust Bank, Atlanta, as Co-Trustee and
Rocky Mountain Leasing Corporation, together with a
Schedule identifying five other substantially identical
Facility Lease Agreements.
10.32.6 -- Ground Sublease Agreement (P1), dated as of December 30,
1996, between SunTrust Bank, Atlanta, as Co-Trustee and
Rocky Mountain Leasing Corporation, together with a
Schedule identifying five other substantially identical
Ground Sublease Agreements.
10.32.7 -- Rocky Mountain Agreements Re-assignment and Assumption
Agreement (P1), dated as of December 30, 1996, between
SunTrust and Rocky Mountain Leasing Corporation,
together with a Schedule identifying five other
substantially identical Rocky Mountain Agreements
Re-assignment and Assumption Agreements.
10.32.8 -- Facility Sublease Agreement (P1), dated as of December
30, 1996, between Oglethorpe and Rocky Mountain Leasing
Corporation, together with a Schedule identifying five
other substantially identical Facility Sublease
Agreements.
10.32.9 -- Ground Sub-sublease Agreement (P1), dated as of December
30, 1996, between Rocky Mountain Leasing Corporation and
Oglethorpe, together with a Schedule identifying five
other substantially identical Ground Sub-sublease
Agreements.
10.32.10 -- Rocky Mountain Agreements Second Re-assignment and
Assumption Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation and
Oglethorpe, together with a Schedule identifying five
other substantially identical Rocky Mountain Agreements
Second Re-assignment and Assumption Agreements.
10.32.11 -- Payment Undertaking Agreement (P1), dated as of December
30, 1996, between Rocky Mountain Leasing Corporation and
Cooperatieve Centrale Raiffeisen-Boerenleenbank B.A.,
New York Branch, as the Bank, together with a Schedule
identifying five other substantially identical Payment
Undertaking Agreements.
10.32.12 -- Payment Undertaking Pledge Agreement (P1), dated as of
December 30, 1996, between Rocky Mountain Leasing
Corporation, Fleet National Bank, as Owner Trustee, and
81
SunTrust Bank, Atlanta, as Co-Trustee, together with a
Schedule identifying five other substantially identical
Payment Undertaking Pledge Agreements.
10.32.13 -- Equity Funding Agreement (P1), dated as of December 30,
1996, between Rocky Mountain Leasing Corporation, AIG
Match Funding Corp., the Owner Participant named
therein, Fleet National Bank, as Owner Trustee, and
SunTrust Bank, Atlanta, as Co-Trustee, together with a
Schedule identifying five other substantially identical
Equity Funding Agreements.
10.32.14 -- Equity Funding Pledge Agreement (P1), dated as of
December 30, 1996, between Rocky Mountain Leasing
Corporation and SunTrust Bank, Atlanta, as Co-Trustee,
together with a Schedule identifying five other
substantially identical Equity Funding Pledge
Agreements.
10.32.15 -- Deed to Secure Debt, Assignment of Surety Bond and
Security Agreement (P1), dated as of December 30, 1996,
between Rocky Mountain Leasing Corporation, SunTrust
Bank, Atlanta, as Co-Trustee, together with a Schedule
identifying five other substantially identical
Collateral Assignment, Assignment of Surety Bond and
Security Agreements.
10.32.16 -- Subordinated Deed to Secure Debt and Security Agreement
(P1), dated as of December 30, 1996, among Oglethorpe,
AMBAC Indemnity Corporation and SunTrust Bank, Atlanta,
as Co-Trustee, together with a Schedule identifying five
other substantially identical Subordinated Deed to
Secure Debt and Security Agreements.
10.32.17 -- Tax Indemnification Agreement (P1), dated as of December
30, 1996, between Oglethorpe and the Owner Participant
named therein, together with a Schedule identifying five
other substantially identical Tax Indemnification
Agreements.
10.32.18 -- Consent No. 1, dated as of December 30, 1996, among
Georgia Power Company, Oglethorpe, SunTrust Bank,
Atlanta, as Co-Trustee, and Fleet National Bank, as
Owner Trustee, together with a Schedule identifying five
other substantially identical Consents.
10.32.19 -- OPC Intercreditor and Security Agreement No. 1, dated as
of December 30, 1996, among the United States of
America, acting through the Administrator of the Rural
Utilities Service, SunTrust Bank, Atlanta, Oglethorpe,
Rocky Mountain Leasing Corporation, SunTrust Bank,
Atlanta, as Co-Trustee, Fleet National Bank, as Owner
Trustee, Utrecht-America Finance Co., as Lender and
AMBAC Indemnity Corporation, together with a Schedule
identifying five other substantially identical
Intercreditor and Security Agreements.
10.33.1 -- Member Transmission Service Agreement, dated as of March
1, 1997, by and between Oglethorpe and Georgia
Transmission Corporation (An Electric Membership
Corporation).
10.33.2 -- Generation Services Agreement, dated as of March 1,
1997, by and between Oglethorpe and Georgia System
Operations Corporation.
10.33.3 -- Operation Services Agreement, dated as of March 1, 1997,
by and between Oglethorpe and Georgia System Operations
Corporation.
21.1 -- Rocky Mountain Leasing Corporation, a Delaware
corporation.
82
27.1 -- Financial Data Schedule (for SEC use only)
_________________- ----------
(1) Pursuant to 17 C.F.R. 229.601(b)(2), the schedules and exhibits to this
document are identified on a list of schedules and exhibits included
within this document and are not filed herewith; however the registrant
hereby agrees that such schedules and exhibits will be provided to the
Commission upon request.
(2) Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this document is not filed
herewith; however the registrant hereby agrees that such document will be
provided to the Commission upon request.
(3) For the reason stated in footnote (2), this document and eightfive other
substantially identical documents are not filed as exhibits to this
Registration Statement.
(4) For the reason stated in footnote (2), this document and another
substantially identical document are not filed as exhibits to this
Registration Statement.
(5) Certain portions of this document have been omitted as confidential and
filed separately with the Commission.
(6) Indicates a management contract or compensatory plan or arrangement
required to be filed as an exhibit to this form pursuant to Item 14(c) of
this report.
All other schedules and exhibits are omitted because of the absence of the
conditions under which they are required or because the required information is
included in the financial statements and related notes to financial statements.
(B) REPORTS ON FORM(b) Reports on Form 8-K.
No reports on Form 8-K were filed by Oglethorpe for the quarter ended
December 31, 1995.
811996.
83
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on the 1st26th day of
April 1996.March 1997.
OGLETHORPE POWER CORPORATION
(AN ELECTRIC MEMBERSHIP GENERATION &
TRANSMISSION CORPORATION)
By: /s/ J. CALVIN EARWOOD
--------------------------------------------------------------------------------------
J. Calvin EARWOOD, CHAIRMAN OF THE BOARD
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934,
THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE
REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
Signature Title Date
/s/ J. CALVIN EARWOOD ChairmanPursuant to the requirements of the Board, April 1, 1996
- -------------------------- Director (Principal Executive
J. CALVIN EARWOOD Officer)
/s/ T. D. KILGORE PresidentSecurities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
registrant and Chief Executive April 1, 1996
- -------------------------- Officer (Principal Executive
T. D. KILGORE Officer)
/s/ GARY M. BULLOCK Secretary-Treasurer (Principal April 1, 1996
- -------------------------- Financial Officer)
GARY M. BULLOCK
/s/ EUGEN HECKL Senior Vice Presidentin the capacities and Chief April 1, 1996
- -------------------------- Financial Officer (Principal
EUGEN HECKL Financial Officer)
/s/ LARRY N. BROWNLEE Controller April 1, 1996
- -------------------------- (Principal Accounting Officer)
LARRY N. BROWNLEE
/s/ JMON WARNOCK Director April 1, 1996
- --------------------------
JMON WARNOCK
/s/ CHARLES R. FENDLEY Director April 1, 1996
- --------------------------
CHARLES R. FENDLEY
/s/ GEORGE C. MARTIN Director April 1, 1996
- --------------------------
GEORGE C. MARTIN
/s/ J. G. MCCALMON Director April 1, 1996
- --------------------------
J. G. MCCALMON
82
/s/ D. A. ROBINSON, III Director April 1, 1996
- --------------------------
D. A. ROBINSON, III
/s/ JAMES E. ESTES Director April 1, 1996
- --------------------------
JAMES E. ESTES
/s/ LARRY N. CHADWICK Director April 1, 1996
- --------------------------
LARRY N. CHADWICK
/s/ SIMMIE KING Director April 1, 1996
- --------------------------
SIMMIE KING
/s/ W. F. FARR Director April 1, 1996
- --------------------------
W. F. FARR
/s/ GARY T. DRAKE Alternate Director April 1, 1996
- --------------------------
GARY T. DRAKE
/s/ JEFF S. PIERCE, JR. Director April 1, 1996
- --------------------------
JEFF S. PIERCE, JR.
/s/ DONALD C. COOPER Director April 1, 1996
- --------------------------
DONALD C. COOPER
/s/ RAY MEADERS Director April 1, 1996
- --------------------------
RAY MEADERS
/s/ MAC F. OGLESBY Director April 1, 1996
- --------------------------
MAC F. OGLESBY
/s/ BENNY W. DENHAM Director April 1, 1996
- --------------------------
BENNY W. DENHAM
/s/ E.on the dates indicated.
Signature Title Date
--------- ----- ----
/s/ J. CALVIN EARWOOD Chairman of the Board, March 26, 1997
- ------------------------------------- Director (Principal Executive
J. CALVIN EARWOOD Officer)
/s/ T. D. KILGORE President and Chief Executive March 26, 1997
- ------------------------------------- Officer (Principal Executive
T. D. KILGORE Officer)
/s/ VACANT (Principal Financial Officer) March 26, 1997
- -------------------------------------
VACANT
/s/ ROBERT D. STEELE Controller March 26, 1997
- ------------------------------------- (Principal Accounting Officer)
ROBERT D. STEELE
/s/ ASHLEY C. BROWN Director March 26, 1997
- -------------------------------------
ASHLEY C. BROWN
/s/ NEWTON A. CAMPBELL Director March 26, 1997
- -------------------------------------
NEWTON A. CAMPBELL
/s/ LARRY N. CHADWICK Director March 26, 1997
- -------------------------------------
LARRY N. CHADWICK
/s/ BENNY W. DENHAM Director March 26, 1997
- -------------------------------------
BENNY W. DENHAM
/s/ SAMMY M. JENKINS Director March 26, 1997
- -------------------------------------
SAMMY M. JENKINS
/s/ MAC F. OGLESBY Director March 26, 1997
- -------------------------------------
MAC F. OGLESBY
/s/ J. SAM L. RABUN Director March 26, 1997
- -------------------------------------
J. SAM L. MCLOCKLIN Director April 1, 1996
- --------------------------
E. L. MCLOCKLIN
/s/ SAM RABUN
Director April 1, 1996
- --------------------------
SAM RABUN
/s/ E. J. MARTIN, JR. Director April 1, 1996
- --------------------------
E. J. MARTIN, JR.
/s/ JIM M. KNIGHT Director April 1, 1996
- --------------------------
JIM M. KNIGHT
/s/ RONNIE FLEEMAN Director April 1, 1996
- --------------------------
RONNIE FLEEMAN
/s/ D. LAMAR COOPER Director April 1, 1996
- --------------------------
D. LAMAR COOPER
83
/s/ BARRY H. MARTIN Director April 1, 1996
- --------------------------
BARRY H. MARTIN
/s/ JOHN B. FLOYD, JR. Director April 1, 1996
- --------------------------
JOHN B. FLOYD, JR.
/s/ STEVE RAWL, SR. Director April 1, 1996
- --------------------------
STEVE RAWL, SR.
/s/ JAMES GRUBBS Director April 1, 1996
- --------------------------
JAMES GRUBBS
/s/ SAMMY M. JENKINS Director April 1, 1996
- --------------------------
SAMMY M. JENKINS
/s/ J. M. SHERRER Director April 1, 1996
- --------------------------
J. M. SHERRER
/s/ JACK D. VICKERS Director April 1, 1996
- --------------------------
JACK D. VICKERS
/s/ C. W. COX, JR. Director April 1, 1996
- --------------------------
C. W. COX, JR.
/s/ JOHNNIE CRUMBLEY Director April 1, 1996
- --------------------------
JOHNNIE CRUMBLEY
/s/ JARNETT W. WIGINGTON Director April 1, 1996
- --------------------------
JARNETT W. WIGINGTON
/s/ BOB JERNIGAN Director April 1, 1996
- --------------------------
BOB JERNIGAN
/s/ C. WILLARD MIMS Director April 1, 1996
- --------------------------
C. WILLARD MIMS
/s/ THOMAS NOLES Director April 1, 1996
- --------------------------
THOMAS NOLES
/s/ ROY TOLLERSON, JR. Director April 1, 1996
- --------------------------
ROY TOLLERSON, JR.
/s/ HUBERT HANCOCK Director April 1, 1996
- --------------------------
HUBERT HANCOCK
/s/ HENDRIX B. WILEY, JR. Director April 1, 1996
- --------------------------
HENDRIX B. WILEY, JR.
/s/ W. W. ARCHER Director April 1, 1996
- --------------------------
W. W. ARCHER
84
SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION
15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO
SECTION 12 OF THE ACT.
The registrant is a membership corporation and has no authorized or outstanding
equity securities. Proxies are not solicited from the holders of Oglethorpe's
public bonds. No annual report or proxy material has been sent to such
bondholders.
85