Filed Pursuant to Rule 424(b)(4)
Registration No. 333-68014
PROSPECTUS
[LOGO] Old Dominion Electric Cooperative
$215,000,000
Old Dominion Electric Cooperative
2001 Series A Bonds Due 2011

Old Dominion Electric Cooperative is offering $215,000,000 in principal
amount of its 2001 Series A Bonds Due 2011. The 2001 Series A Bonds will mature
on June 1, 2011, and will bear interest at 6.25% per annum. We will pay
interest on the 2001 Series A Bonds semi-annually on June 1 and December 1 of
each year beginning on December 1, 2001. We may redeem the 2001 Series A Bonds,
in whole or in part, prior to their stated maturity at the price set forth in
"DESCRIPTION OF THE BONDS--Make Whole Redemption." We may not otherwise
optionally or mandatorily redeem the bonds.

The 2001 Series A Bonds initially will be secured by a first lien on
substantially all of our tangible and some of our intangible properties,
equally and ratably with all other obligations issued under our Indenture of
Trust and Deed of Mortgage, dated as of May 1, 1992, as amended. The lien will
be released when all obligations issued by us under the indenture prior to the
2001 Series A Bonds cease to be outstanding or the holders of those obligations
consent to the release of the lien. After that time, the 2001 Series A Bonds
will be unsecured general obligations, ranking equally and ratably with our
other unsecured and unsubordinated obligations, subject to some exceptions. In
addition, we will be limited in our ability to secure obligations for borrowed
money or the deferred purchase price of property or services after that time
unless we equally and ratably secure the 2001 Series A Bonds. See "DESCRIPTION
OF THE BONDS."

Our timely payment of the regularly scheduled payments of the principal of,
and interest on, the 2001 Series A Bonds will be insured by a financial
guaranty insurance policy to be issued by Ambac Assurance Corporation
simultaneously with the delivery of the bonds. See "BOND INSURANCE."

[LOGO] Ambac

Underwriting
Price to Discounts and Proceeds to
Public Commissions Old Dominion
-------------------------------------------------

Per bond 100.126% 0.775% 99.351%
Total $215,270,900 $1,666,250 $213,604,650

The price to the public for the 2001 Series A Bonds includes accrued
interest, if any, from the date of issuance of the bonds. The proceeds to us do
not reflect the expenses we expect to pay in connection with the offering other
than underwriting discounts and commissions. We estimate these additional
expenses will be $3.85 million. We have agreed to indemnify the underwriters
for some obligations relating to this offering. See "UNDERWRITING."

The underwriters are offering the 2001 Series A Bonds subject to a number of
conditions and subject to prior sale by the underwriters. We expect that the
2001 Series A Bonds will be available for delivery in New York, New York in
book-entry form on or about September 28, 2001 through the facilities of The
Depository Trust Company against payment for the bonds in immediately available
funds.

Neither the Securities and Exchange Commission nor any state securities
commission has approved or disapproved of these securities or determined if
this prospectus is truthful and complete. Any representation to the contrary is
a criminal offense.

JPMorgan Banc of America Securities LLC

September 25, 2001

[INSIDE COVER DESCRIPTION OF ARTWORK. Old Dominion Electric Cooperative's
logo appears at the top of the page. At the mid-center of the page is a map of
portions of Virginia, Maryland, Delaware and West Virginia with the areas of
Old Dominion Electric Cooperatives member distribution cooperatives service
territories and neighboring utilities service territories highlighted in
different shades to distinguish those territories. In addition, the map
identifies the locations of the North Anna Nuclear Power Station, Clover Power
Station and each of the combustion turbine facilities known as Rock Springs,
Louisa and Marsh Run currently being developed.]

[MAP] Map of Service Territories and Generating Facilities

SUMMARY

The following summary contains information about our company, the offering
and the terms of the 2001 Series A Bonds that we believe is important. You
should read this entire prospectus, including the financial statements and the
accompanying notes, for a complete understanding of our company, the offering
and the bonds. This prospectus contains forward-looking statements based on our
current expectations, assumptions, estimates and projections about us and our
business and industry. These forward-looking statements involve risks and
uncertainties. Actual events or results could differ materially from those
described in these forward-looking statements as a result of a variety of
factors, some of which are more fully described elsewhere in this prospectus.
We undertake no obligation to update any forward-looking statements, even if
new information becomes available or other events occur in the future, except
as required by law.

The Offering

Old Dominion................ We are a not-for-profit power supply cooperative
based in Glen Allen, Virginia, principally
engaged in the business of providing wholesale
electric services to our members. Our members
include twelve customer-owned electric
distribution cooperatives that sell electric
services to customers in portions of Virginia,
Maryland, Delaware and West Virginia. We have one
other member, ODEC Power Trading, Inc. ("ODEC
Power Trading").

In this prospectus, the words "we," "us" and
"our" refer to Old Dominion Electric Cooperative
unless the context indicates otherwise.

Securities Offered.......... $215,000,000 principal amount of 6.25% 2001
Series A Bonds due June 1, 2011

Interest Payment Dates...... June 1 and December 1, commencing December 1,
2001

Redemption.................. We may redeem the 2001 Series A Bonds, in whole
or in part, prior to their stated maturity, at
our option. The redemption price for the bonds
will be equal to the greater of:

. 100% of the principal amount of the bonds being
redeemed plus accrued interest to the
redemption date; and

. the sum of the present values of the remaining
principal and interest payments on the bonds
being redeemed, discounted at a rate equal to
the sum of (1) the yield to maturity on the
U.S. Treasury security having a life equal to,
or the average yield to maturity on two U.S.
Treasury securities closely corresponding to,
the remaining life of the 2001 Series A Bonds
and trading in the secondary market at the
price closest to par and (2) twenty basis
points;

plus, in either case, without duplication,
interest due and payable but unpaid on the bonds
being redeemed.

We may not otherwise optionally or mandatorily
redeem the 2001 Series A Bonds. See "DESCRIPTION
OF THE BONDS--Make Whole Redemption."

Indenture................... We will issue the 2001 Series A Bonds under the
Indenture of Mortgage and Deed of Trust, dated
May 1, 1992, as amended, with Crestar Bank
(predecessor to SunTrust Bank), as trustee (the

"Existing Indenture"). We have entered into a
supplemental indenture to the Existing Indenture
which, when some provisions of it become
effective, will amend several provisions of the
Existing Indenture. The amendments include:

. modification of our rate covenant and
restrictions on the issuance of additional
bonds and distributions to members; and

. elimination of restrictions on investments and
short-term indebtedness and the obligation to
make depreciation deposits.

See "DESCRIPTION OF THE BONDS." These provisions
of the supplemental indenture will become
effective when the holders of a majority of the
obligations outstanding under the Existing
Indenture consent to the amendments (the
"Amendment Date"). In this prospectus, the
Existing Indenture as amended by these provisions
of the supplemental indenture on the Amendment
Date is referred to as the "Amended Indenture."

We also have entered into an Amended and Restated
Indenture which, when it becomes effective, will
amend and restate the Existing Indenture or the
Amended Indenture, as the case may be (the
"Restated Indenture"). The Restated Indenture
includes all of the amendments set forth in the
Amended Indenture and releases the lien of the
Existing Indenture or the Amended Indenture, as
the case may be. The Restated Indenture will
become effective when all obligations under the
Existing Indenture issued prior to the 2001
Series A Bonds cease to be outstanding or when
the holders of those obligations consent to the
release of the lien of the Existing Indenture or
the Amended Indenture, as the case may be (the
"Release Date"). The Release Date may occur
before the Amendment Date and, in that case, the
Amended Indenture will not become effective
because the Restated Indenture includes all of
the amendments set forth in the Amended
Indenture. See "DESCRIPTION OF THE BONDS--Release
and Substitution of Property Prior to Release
Date; Negative Pledge After Release Date."

When we refer to the "Indenture" in this
prospectus, we mean the Existing Indenture, the
Amended Indenture or the Restated Indenture,
whichever is in effect.

Security for the Bonds...... The 2001 Series A Bonds initially will be secured
by a first lien on substantially all of our
tangible and some of our intangible properties,
including our generating facilities, equally and
ratably with all other obligations issued under
the Existing Indenture, subject to permitted
liens and encumbrances. The first lien will be
released on the Release Date. We do not
anticipate that the Release Date will occur prior
to December, 2003.

On the Release Date, the 2001 Series A Bonds will
become unsecured general obligations and will
rank equally and ratably with all of our other
unsecured and unsubordinated obligations, subject
to some exceptions described below. See
"DESCRIPTION OF THE BONDS--

Security for Payment of the Obligations Prior to
Release Date; Conversion to Unsecured Obligations
on Release Date."

Under the Restated Indenture, we may not create
any lien or encumbrance securing borrowed money
or the deferred purchase price of property or
services on specified properties unless we
equally and ratably secure the 2001 Series A
Bonds and all other obligations issued under the
Restated Indenture. These specified properties
consist of substantially all of our real estate,
fixtures and tangible personal property primarily
used in connection with our generating
facilities. We may grant liens or other
encumbrances on these specified properties
securing borrowed money or the deferred purchase
price of property or services in an amount not to
exceed at any time the greater of 2% of our total
assets and $10 million.

The restrictions in the Restated Indenture on the
creation of a lien or encumbrance do not apply to
our three existing, or to any future, sale and
leaseback, lease and leaseback or similar
transactions or to liens or encumbrances relating
to commodities trading agreements entered into in
the ordinary course of business. See "POWER
SUPPLY RESOURCES--Clover" and "DESCRIPTION OF THE
BONDS--Release and Substitution of Property Prior
to Release Date; Negative Pledge After Release
Date."

Bond Insurance.............. The timely payments of the scheduled principal of
and interest on each of the 2001 Series A Bonds
will be insured by a financial guaranty insurance
policy issued by Ambac Assurance Corporation,
which will be issued at the same time the bonds
are delivered. As the insurer of the 2001 Series
A Bonds, Ambac Assurance Corporation (and not the
holders of 2001 Series A Bonds) will be
considered the holder of the 2001 Series A Bonds
for the following purposes:

. approving supplemental indentures or other
amendments to the Indenture;

. giving any other approval, consent or notice to
effect any waiver;

. exercising any remedies; and

. taking any other action that can be taken by
the holders of the 2001 Series A Bonds.

See "BOND INSURANCE" and "DESCRIPTION OF THE
BONDS--Rights of Insurer."

Use of Proceeds............. We expect the net proceeds of this offering to be
approximately $210 million after the payment of
underwriting discounts and offering expenses. We
will use the net proceeds of this offering to:

. make loans to our three wholly owned
subsidiaries that are developing three
combustion turbine facilities in Virginia and
Maryland to finance a portion of the
development and construction costs of the
facilities; and

. repay short-term borrowings under
construction-related lines of credit if we use
those lines of credit to finance previous loans
to the subsidiaries.

To the extent that we or the subsidiaries obtain
other funds to finance the development and
construction costs of the facilities, we will
apply the net proceeds of this offering to repay
existing indebtedness and, until so applied, to
fund other working capital needs. See "PLAN OF
FINANCE AND USE OF PROCEEDS."

Rate Covenant............... The Existing Indenture obligates us to establish
and collect rates that, subject to any necessary
regulatory approvals, are reasonably expected to
yield margins for interest equal to at least 1.20
times our total interest charges. Under the
Amended Indenture and the Restated Indenture, the
margins for interest requirement will change to
1.10 times total interest charges. In addition,
the calculations of margins for interest and
interest charges under the Amended Indenture and
the Restated Indenture differ in several respects
from the calculations under the Existing
Indenture. See "DESCRIPTION OF THE BONDS--Rate
Covenant."

Additional Obligations...... Prior to the Release Date, as long as we are in
compliance with financial tests relating to
margins for interest, we may issue additional
indebtedness or other obligations under the
Existing Indenture or the Amended Indenture. The
financial tests under the Amended Indenture are
different from the financial tests under the
Existing Indenture. The amount of obligations we
may issue is based on the cost of specified
property acquisitions we have made, the principal
amount of Indenture obligations we have retired
or defeased, and deposits of cash we have made
with the trustee. After the Release Date, we may
issue additional indebtedness or other
obligations without restriction. See "DESCRIPTION
OF THE BONDS--Additional Obligations."

Limitations on Distributions
to Members................ The Existing Indenture prohibits us from making
any distribution, including any dividend or
payment or retirement of patronage capital, to
our members if we are in default under the
Existing Indenture. Otherwise, we are permitted
to make a distribution to our members if, after
the distribution:

. our aggregate margins and equities as of the
end of the most recent fiscal quarter would be
equal to or greater than 20% of our total
long-term debt and equities and the aggregate
amount of all distributions after the date on
which our aggregate margins and equities first
reached 20% of our total long-term debt and
equities does not exceed 35% of our aggregate
net margins earned after that date; or

. our aggregate margins and equities as of the
end of the most recent fiscal quarter would be
equal to or greater than 30% of our total
long-term debt and equities.

At June 30, 2001, we could have distributed $29.8
million to our members under this formula. We
have not made any distributions to our members
since that date.

After the Amendment Date or the Release Date, we
may not make any distribution, including a
dividend or payment or retirement of patronage
capital, to our members if we are in default
under the Indenture. Otherwise, we will be
permitted to make a distribution if:

. after the distribution, our patronage capital
as of the end of the immediately preceding
fiscal quarter would be equal to or greater
than 20% of our total long-term debt and
patronage capital; or

. all of our distributions for the year in which
the distribution is to be made do not exceed 5%
of our patronage capital as of the end of the
immediately preceding fiscal year.

See "DESCRIPTION OF THE BONDS--Limitation on
Distributions to Members."

Reporting Obligations....... We do not intend to register the 2001 Series A
Bonds under the Securities Exchange Act of 1934,
as amended (the "Securities Exchange Act"). We
will, however, initially be subject to the
reporting requirements of Section 15(d) of the
Securities Exchange Act. The Indenture obligates
us to continue reporting under the Securities
Exchange Act so long as any of the 2001 Series A
Bonds are outstanding, even if we are not
required by law to do so.

Market for 2001 Series A
Bonds.................... We do not intend to list the 2001 Series A Bonds
on any securities exchange or have them quoted on
the National Association of Securities Dealers
Automated Quotation System. As a result, there
may not be a secondary market for the 2001 Series
A Bonds. The underwriters intend, but are not
obligated, to make a market in the 2001 Series A
Bonds. See "UNDERWRITING."

Old Dominion Electric Cooperative

Our Company................. We were formed in 1948 as a not-for-profit power
supply cooperative. We provide wholesale electric
services to our members. Through our member
distribution cooperatives, we provide retail
electric services to more than 436,000 electric
customers (meters) representing approximately 1.1
million people in portions of Virginia, Maryland,
Delaware and West Virginia. See "BACKGROUND" and
"BUSINESS."

We are exempt from federal income taxation
because we are an organization meeting the
requirements of Section 501(c)(12) of the
Internal Revenue Code of 1986, as amended. See
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Factors Affecting Results--Tax
Status" and "FEDERAL INCOME TAX MATTERS."

Our principal office is located at 4201 Dominion
Boulevard, Glen Allen, Virginia 23060. Our
telephone number is (804) 747-0592.

Power Supply Resources...... We supply power to our members through two
geographically divided power supply systems--a
mainland Virginia system and a Delmarva Peninsula
system. Our power supply resources consist of our
generating facilities, power purchase contracts
and forward, short-term and spot market
purchases. See "BACKGROUND" and "POWER SUPPLY
RESOURCES."

Our existing generating facilities consist of:

. an 11.6% interest in the North Anna Nuclear
Power Station, a two unit, 1,842 megawatt (net
capacity rating) nuclear power facility in
Louisa County, Virginia; and

. a 50% interest in the Clover Power Station, a
two unit, 882 megawatt (net capacity rating)
coal-fired generating facility located near
Clover, Virginia.

North Anna and Clover are operated by the
co-owner of the facilities, Virginia Electric
Power Company, a subsidiary of Dominion
Resources, Inc.

We also own diesel generators which we are
installing primarily to support the reliability
of power delivery to the member distribution
cooperatives.

We currently are restructuring our portfolio of
power supply resources to address changes in the
market and to meet our member distribution
cooperatives' growing power requirements. In
addition to amending several existing power
purchase contracts with third parties and
allowing others to expire, we have formed three
wholly owned subsidiaries to develop and own
three combustion turbine facilities in Cecil
County, Maryland and Louisa County and Fauquier
County, Virginia. The facilities are known as
"Rock Springs," "Louisa" and "Marsh Run,"
respectively. When the facilities become fully
operational, we anticipate that we will obtain
336, 504 and 672 megawatts of capacity from Rock
Springs, Louisa and Marsh Run, respectively. See
"BACKGROUND" and "POWER SUPPLY
RESOURCES--Combustion Turbine Facilities."

Members..................... We are owned by our members. We have two classes
of members. Our Class A members are twelve
customer-owned, electric distribution
cooperatives. The sole Class B member is ODEC
Power Trading. See "BUSINESS--Member Distribution
Cooperatives" and "--ODEC Power Trading."

Our member distribution cooperatives provide
electric services on a retail basis to
residential, commercial and industrial customers
in portions of Virginia, Maryland, Delaware and
West Virginia. The customers are located
predominately in suburban, rural and recreational
areas which require primarily residential
service. Approximately 50% of the member
distribution cooperatives' power sales are made
in the high growth, increasingly suburban area
between Washington, D.C. and Richmond, Virginia.
See

"BUSINESS--Member Distribution Cooperatives" and
"--Members' Service Territories and Customers."

As a result of recently enacted state electric
restructuring legislation, approximately 20% of
the customers of the member distribution
cooperatives currently can choose an alternate
power supplier. By 2004, virtually all customers
of the member distribution cooperatives will be
allowed to choose an alternate power supplier.
The member distribution cooperatives will remain
the exclusive providers of distribution services
and, at least initially, the default power
supplier to their customers within their service
territories. See "BUSINESS--Retail Competition."

Our only member that is not a member distribution
cooperative is ODEC Power Trading. Formed in
2001, ODEC Power Trading is a corporation owned
by our member distribution cooperatives to sell
power in the market, manage the member
distribution cooperatives' exposure to changes in
fuel prices and take advantage of other
power-related trading opportunities which may
become available in the market.

Wholesale Power Contracts... The member distribution cooperatives are the
primary purchasers of the power we supply. The
member distribution cooperatives purchase power
from us pursuant to "all-requirements" wholesale
power contracts which extend at least through
2028. The contracts require the member
distribution cooperatives to buy all of their
power requirements from us, to the extent that we
have the power to supply to them, with limited
exceptions. We also will enter into a wholesale
power contract with ODEC Power Trading whereby
ODEC Power Trading will purchase power from us
for resale in the market. See "BUSINESS--Member
Distribution Cooperatives--Wholesale Power
Contracts" and "--ODEC Power Trading."

Cooperative Status.......... We are organized as a cooperative. A cooperative
is a business organization owned by its members,
which also are its customers. Cooperatives are
created to provide goods or services to their
members on a cost-effective basis.

Because we are a cooperative, we use different
accounting terminology than investor-owned,
for-profit corporations. In this prospectus, when
we refer to net margins for a period, we mean our
revenues in excess of our costs for that period.
When we refer to patronage capital, we mean our
aggregate net margins that we have not
distributed to our members. Patronage capital
constitutes our principal equity and currently is
assigned to each member on the basis of its class
of membership and purchases from us.

SUMMARY FINANCIAL DATA

The summary financial data below present selected historical information
relating to our financial condition and results of operations. The financial
data for the five years ended December 31, 2000, are derived from our audited
consolidated financial statements. The financial data for the six-month periods
ended June 30, 2001 and 2000 are derived from our unaudited condensed
consolidated financial statements. The unaudited financial statements include
all adjustments, consisting of normal recurring adjustments, which we consider
necessary for a fair presentation of our financial position and results of
operations for these periods. You should read the information contained in this
table together with our financial statements, the related notes to the
financial statements and the discussion of this information in "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"
included in this prospectus.

Six Months Ended
June 30, Years Ended December 31,
---------------------- ----------------------------------------------------------
2001 2000 2000 1999 1998 1997 1996
---------- ---------- ---------- ---------- ---------- ---------- ----------
(in thousands, except ratios)

Operating revenues................ $ 234,221 $ 200,234 $ 422,031 $ 390,060 $ 364,221 $ 358,505 $ 366,909
Operating expenses................ (213,185) (176,603) (377,335) (336,735) (298,026) (286,169) (299,129)
Operating margin.................. 21,036 23,631 44,696 53,325 66,195 72,336 67,780
Net margin........................ 3,896 4,254 8,229 9,839 12,094 12,799 12,240

Net electric plant................ $ 649,041 $ 661,419 $ 648,898 $ 699,531 $ 766,966 $ 811,084 $ 835,561
Total assets...................... 1,032,951 1,034,605 1,010,572 1,050,512 1,126,544 1,130,256 1,156,346
Patronage capital................. 220,994 220,623 224,598 216,369 206,530 197,552 184,753
Long-term debt.................... 447,564 477,869 449,823 509,606 584,630 605,878 664,490
Total capitalization.............. 669,200 696,341 674,165 723,659 791,857 803,774 849,243

Ratio of earnings to fixed charges 1.15 1.16 1.16 1.16 1.17 1.17 1.12
Margins for interest ratio........ 1.20 1.20 1.20 1.20 1.20 1.20 1.20

BACKGROUND

As a power supply cooperative, we were organized for the purpose of
supplying the power our member distribution cooperatives require to serve their
customers. We supply that power through long-term "all-requirements" wholesale
power contracts. As used in this prospectus, power consists of capacity and
energy. Energy is the physical electricity delivered through transmission and
distribution facilities to a customer. Because energy cannot be stored, a
utility must have adequate capacity to serve its customers reliably during
periods of high energy consumption. Capacity is the right to a specified amount
of energy dispatched from an electric generating facility. Capacity typically
is obtained through the ownership of an electric generating facility or is
purchased from another power producer.

We supply our member distribution cooperatives' capacity and energy
requirements through a portfolio of power supply resources. These resources
include:

. our interests in two generating facilities, consisting of an 11.6%
interest in the North Anna Nuclear Power Station ("North Anna"), and a 50%
interest in the Clover Power Station ("Clover");

. power purchase contracts with other power producers; and

. forward, short-term and spot market purchases of energy.

Our power supply resources also include ten diesel generators which we are
installing throughout the member distribution cooperatives' service
territories. See "POWER SUPPLY RESOURCES."

We arrange for the supply of our member distribution cooperatives' power
requirements through two geographically separate transmission systems which are
limited in their capability to transmit power between each other. One system is
located in mainland Virginia and the other is located on the Delmarva
Peninsula. The Delmarva Peninsula is the peninsula formed by Delaware and the
portions of Maryland and Virginia east of the Chesapeake Bay.

Restructuring of Portfolio of Power Supply Resources

As a power supply cooperative, we strive to meet our member distribution
cooperatives' capacity and energy requirements with the most economical power
supply resources. Over the years, our power supply strategy has evolved as the
electric utility industry has changed. Since the commercial operation of Clover
in 1996, North Anna and Clover have satisfied approximately half of our
capacity and three-fourths of our energy requirements in mainland Virginia. In
1996, we satisfied the remainder of our member distribution cooperatives'
capacity and energy needs in mainland Virginia and all of the member
distribution cooperatives' capacity and energy requirements on the Delmarva
Peninsula through long-term power purchase contracts with neighboring
utilities. Under these power purchase contracts, we purchased capacity and
energy at a price determined by the supplying utility's average system cost.

In the late 1990's, we began reviewing whether our existing portfolio of
power supply resources best served the member distribution cooperatives' power
requirements for several reasons. First, the electric utility industry began
changing dramatically. In 1998, federal regulations ordered most utilities to
permit open access to their transmission facilities. In the same year,
Virginia, Maryland and Delaware began considering (and eventually adopted)
electric restructuring legislation to permit competition for retail electric
services customers, including those of our member distribution cooperatives.
See "BUSINESS--Retail Competition." Second, our projections of the future
market price of capacity and energy were less than the price of capacity and
energy we were paying under several power purchase contracts. Third, we
forecasted steady growth in our member distribution cooperatives' power
requirements which created the need for additional sources of capacity and
energy. See "BUSINESS--Members' Service Territories and Customers."

Based on our review of these factors, we took several actions. We began
restructuring our existing long-term power purchase contracts to reduce the
term, provide for market-based pricing of capacity or energy, reduce

the amount of the capacity or energy we purchased under the contract or a
combination of these changes. At the same time, we entered into new power
purchase contracts to acquire capacity or energy or both at fixed or market
prices as opposed to prices based on the supplying utility's average system
cost. In addition, we started purchasing increasing amounts of energy in the
forward, short-term and spot markets by exercising our contractual rights to
forego energy purchases under existing long-term power purchase contracts. See
"POWER SUPPLY RESOURCES--Other Power Supply Resources--Power Purchase
Contracts" and "--Market Energy Purchases."

In 1999, we issued a request for bids to provide all or a portion of our
capacity and energy requirements for the foreseeable future. We simultaneously
evaluated the cost of constructing and owning additional generating facilities,
including base load, intermediate and combustion turbine facilities, with the
goal of securing the most economical power supply resources. As a result of
these actions, we determined that the construction of Rock Springs, Louisa and
Marsh Run as combustion turbine facilities, coupled with additional forward,
short-term and spot market energy purchases, was the most economical approach
to satisfy our power requirements.

When the combustion turbine facilities become fully operational, we
currently expect that all of our capacity requirements in mainland Virginia
will be supplied by North Anna, Clover, Louisa and Marsh Run. We also currently
expect Rock Springs to satisfy substantially all of our capacity requirements
on the Delmarva Peninsula. We are evaluating how best to satisfy the remaining
portion of our capacity requirements on the Delmarva Peninsula. We most likely
will satisfy this capacity through the construction of a new unit or by
contract with a third party or both. In addition, we are considering how to
meet growth in our capacity and energy needs after the time the combustion
turbine facilities become operational.

Reliance on Energy Purchases

While the combustion turbine facilities will provide most of our capacity
requirements above those met by Clover and North Anna, they will not satisfy a
significant portion of our energy requirements. Combustion turbine facilities
are most economical to operate when the market price of energy is relatively
high. By operating the combustion turbine facilities during those times, we
reduce our exposure to market energy price volatility risk but use the market
to supply energy during other times. Currently, we expect in 2005 the
combustion turbine facilities will supply approximately 10% of our energy
requirements, the market will supply approximately 40% of our energy
requirements and North Anna and Clover will supply the remaining approximate
50% of our energy requirements.

Because we have and will rely heavily on market purchases of energy, we have
taken two primary steps to reduce our exposure to future price fluctuations in
the energy market. First, in 2000, we began purchasing in the market blocks of
short-term energy and options to purchase energy for significant periods into
the future. Currently, we have secured through market purchases or energy
contracts the majority of our energy requirements not supplied by our
generating facilities or the combustion turbine facilities through the end of
2003. We plan to continue purchasing energy for significant periods into the
future by utilizing option contracts for the purchase of energy, and forward,
short-term and spot market purchases. In addition, we plan to use similar
efforts to manage our exposure to market changes in the price of fuel,
especially changes in the price of natural gas.

Second, in March, 2001, we engaged Alliance for Cooperative Electricity
Services Power Marketing LLC ("APM"), an energy trading and risk management
company, to assist us in executing trades to purchase energy, developing a
strategy of when to operate the combustion turbine facilities or purchase
energy, modeling our power requirements, and analyzing our power purchase
contracts and credit risks of counterparties. See "QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK."

We continue to review our power supply resource options and future
requirements. As we have done in the past, we expect to adjust our portfolio of
power supply resources to reflect our projected power requirements and changes
in the market.

PLAN OF FINANCE AND USE OF PROCEEDS

The development and construction of Rock Springs, Louisa and Marsh Run will
require significant capital expenditures over several years. We currently
expect the yearly cost to develop and construct the facilities, including
capitalized interest, to be as follows:

Actual Projected
------ ----------------------------------------
Facility
Facility 2000 2001 2002 2003 2004 2005 Total
-------- ------ ----- ------ ------ ----- ----- --------
(in millions)

Rock Springs.... $10.9 $46.2 $ 68.7 $ 18.0 $ - $ - $143.8
Louisa.......... 18.4 35.6 124.6 34.8 - - 213.4
Marsh Run....... 12.3 6.6 53.7 123.5 37.3 47.0 280.4
----- ----- ------ ------ ----- ----- ------
Yearly Total. $41.6 $88.4 $247.0 $176.3 $37.3 $47.0 $637.6
===== ===== ====== ====== ===== ===== ======

A separate wholly owned subsidiary owns, is developing and will construct
each combustion turbine facility. To date, we have financed the development and
pre-construction costs of the facilities through loans to the subsidiaries from
our internally generated funds. As of June 30, 2001, we had loaned to the three
subsidiaries an aggregate of $65.2 million. See "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Liquidity and
Capital Resources." We expect the financing for the remaining $572.4 million
required to develop and construct the facilities will be obtained through one
or more of several possible sources. These sources include:

. our internally generated funds,

. the net proceeds of this offering, estimated to be approximately $210
million after payment of underwriting discounts and offering expenses,

. borrowings under construction-related lines of credit,

. loans to the subsidiaries guaranteed by the United States Department of
Agriculture Rural Utilities Service ("RUS"), and

. the net proceeds of future offerings of indebtedness under the Indenture.

Internal Funds, Net Proceeds and Lines of Credit

We intend to use internally generated funds, the net proceeds of this
offering and borrowings under construction-related lines of credit to provide
the funding necessary for the combustion turbine facilities while RUS is
considering the subsidiaries' loan guarantee applications or, if the
applications are not approved, until alternative long-term financing has been
secured. As of June 30, 2001, we had loaned the subsidiaries the funds
necessary to pay the costs incurred as of that date for development of the
facilities. We funded these loans with internally generated cash.

By the end of the third quarter of 2001, our internally generated funds may
no longer be sufficient to fund the necessary loans to the subsidiaries to
finance the continued development and construction of the combustion turbine
facilities. When this occurs, we intend to fund loans to the subsidiaries
through the use of the net proceeds of this offering and, if necessary,
borrowings under committed short-term variable rate lines of credit entered
into primarily for the purpose of funding construction of the combustion
turbine facilities. The commitments under these lines of credit total $115
million. While the Existing Indenture limits our ability to issue short-term
indebtedness, we expect that those restrictions will not limit our ability to
borrow the entire $115 million if necessary after this offering, as long as not
more than approximately $17.6 million is outstanding under our
non-construction-related working capital lines of credit. We currently do not
expect to borrow any amounts under these non-construction-related working
capital lines of credit. See "MANAGEMENT'S DISCUSSION AND

ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Liquidity and
Capital Resources" and "DESCRIPTION OF THE BONDS--Limitations on Issuance of
Short-Term Debt."

If we have borrowed amounts under the construction-related lines of credit
prior to our receipt of the net proceeds of this offering, we anticipate that
we will repay those borrowings with the net proceeds of this offering. The
amount repaid will be available for future borrowings. We will use the
remaining net proceeds of this offering to fund capital expenditures relating
to the development and construction of the combustion turbine facilities as
necessary or, until so used, for working capital purposes.

Each subsidiary will repay our loans to it in an amount equal to the excess
of (1) the proceeds of any RUS-guaranteed loan and amounts we previously loaned
to it, over (2) the cost to develop and construct its facility. We will in turn
loan those amounts to another subsidiary which has not fully funded the cost of
the development and construction of its combustion turbine facility with
RUS-guaranteed loans. To the extent the net proceeds of this offering and
RUS-guaranteed loans to all of the subsidiaries exceed the cost of all three
combustion turbine facilities or otherwise are not required for development and
the construction of these facilities, we intend to use the excess net proceeds
to reduce our outstanding indebtedness and, until so used, for other working
capital purposes.

RUS-Guaranteed Loans

Through our three subsidiaries, we are seeking long-term financing through
RUS for the cost of developing and constructing the facilities. We formed the
subsidiaries specifically to facilitate the approval by RUS of the loan
guarantee applications. The subsidiaries have submitted applications to RUS for
loan guarantees to finance the entire cost of all three facilities.

If a subsidiary obtains RUS financing, we will enter into a power purchase
contract with that subsidiary. Each power purchase contract will require us,
among other things, to take or pay for all capacity and energy of the facility
owned by the subsidiary even if that energy is not available, delivered or
taken and pay for all costs associated with the facility or the subsidiary,
including all scheduled debt service payments on the RUS-guaranteed loan. Each
subsidiary obtaining financing through RUS-guaranteed loans will grant RUS a
mortgage and security interest in substantially all of its tangible and
intangible assets, including the combustion turbine facility owned by it.

We do not expect a decision from RUS about the loan guarantee applications
before late 2001 or early 2002. We cannot predict whether any subsidiary will
obtain an RUS-guaranteed loan, and if so, the amount and timing of the loan. If
any subsidiary does not obtain RUS financing for the development and
construction of the facility owned by it, we anticipate dissolving the
subsidiary and distributing its property to us. We would then continue to
develop and construct the facility.

Other Sources of Financing

We will secure other long-term sources of financing for the construction of
the facilities to the extent RUS-guaranteed loans are not obtained and the net
proceeds of this offering have been consumed. In that case, we anticipate that
we will issue additional indebtedness under the Indenture. See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Liquidity and Capital Resources--Uses."

SELECTED FINANCIAL DATA

The selected financial data below present selected historical information
relating to our financial condition and results of operations. The financial
data for the five years ended December 31, 2000 are derived from our audited
consolidated financial statements. The financial data for the six-month periods
ended June 30, 2001 and 2000 are derived from our unaudited condensed
consolidated financial statements. The unaudited financial statements include
all adjustments, consisting of normal recurring adjustments, which we consider
necessary for a fair presentation of our financial position and results of
operations for these periods. You should read the information contained in this
table together with our financial statements, the related notes to the
financial statements and the discussion of this information in "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS"
included in this prospectus.

Statements of Operations Data:
Operating revenues:
Member revenues........................ $ 231,239 $ 193,743 $ 414,937 $ 388,968 $ 363,432 $ 358,122 $ 366,515
Nonmember revenues..................... 2,982 6,491 7,094 1,092 789 383 394
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues.............. 234,221 200,234 422,031 390,060 364,221 358,505 366,909
Operating expenses....................... (213,185) (176,603) (377,335) (336,735) (298,026) (286,169) (299,129)
Other income (expenses), net............. 682 (713) 323 (152) 1,301 528 (4,848)
Investment income........................ 1,467 2,452 4,091 5,552 4,640 3,532 6,475
Interest charges, net.................... (19,289) (21,116) (40,881) (48,886) (60,042) (63,597) (57,167)
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net margin............................. $ 3,896 $ 4,254 $ 8,229 $ 9,839 $ 12,094 $ 12,799 $ 12,240
========== ========== ========== ========== ========== ========== ==========
Balance Sheet Data:
Assets:
Electric plant:
In service, net....................... $ 568,652 $ 652,349 $ 601,300 $ 686,508 $ 753,375 $ 798,383 $ 824,455
Construction work in progress......... 80,389 9,070 47,598 13,023 13,591 12,701 11,106
---------- ---------- ---------- ---------- ---------- ---------- ----------
Net electric plant................... 649,041 661,419 648,898 699,531 766,966 811,084 835,561
Investments............................ 250,673 267,772 246,730 262,024 211,044 191,611 183,429
Other assets........................... 133,237 105,414 114,944 88,957 148,534 127,561 137,356
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total assets.......................... $1,032,951 $1,034,605 $1,010,572 $1,050,512 $1,126,544 $1,130,256 $1,156,346
========== ========== ========== ========== ========== ========== ==========
Capitalization and Liabilities:
Capitalization:
Patronage capital..................... $ 220,994 $ 220,623 $ 224,598 $ 216,369 $ 206,530 $ 197,552 $ 184,753
Accumulated other comprehensive
income (expense)..................... 642 (2,151) (256) (2,316) 697 344 --
Long-term debt........................ 447,564 477,869 449,823 509,606 584,630 605,878 664,490
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total capitalization................. 669,200 696,341 674,165 723,659 791,857 803,774 849,243
Liabilities............................ 363,751 338,264 336,407 326,853 334,687 326,482 307,103
---------- ---------- ---------- ---------- ---------- ---------- ----------
Total capitalization and liabilities.. $1,032,951 $1,034,605 $1,010,572 $1,050,512 $1,126,544 $1,130,256 $1,156,346
========== ========== ========== ========== ========== ========== ==========
Other Data:
Ratio of earnings to fixed charges(1).... 1.15 1.16 1.16 1.16 1.17 1.17 1.12
Margins for interest ratio(2)............ 1.20 1.20 1.20 1.20 1.20 1.20 1.20
Equity ratio(3).......................... 33.1% 31.6% 33.3% 29.8% 26.1% 24.6% 21.8%

(1)We do not take the ratio of earnings to fixed charges into account in
setting our rates. Our ratio of earnings to fixed charges is less than that
of many utilities because we operate on a not-for-profit basis and establish
rates to collect sufficient revenue to pay expenses plus required reserves.
See "Management's Discussion and Analysis of Financial Condition and Results
of Operations--Factors Affecting Results--Formulary Rate."
(2)This ratio is determined by dividing our margins for interest by our
interest charges. See "Description of Bonds--Rate Covenant" for a
description of the calculation of margins for interest and interest charges
under the Indenture.
(3)The equity ratio equals our patronage capital (net margins we have not
distributed) divided by the sum of our long-term debt and patronage capital.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

Caution Regarding Forward Looking Statements

Management's Discussion and Analysis of Financial Condition and Results of
Operations contains forward-looking statements regarding matters that could
have an impact on our business, financial condition and future operations.
These statements, based on our expectations and estimates, are not guarantees
of future performance and are subject to risks, uncertainties, and other
factors that could cause actual events or results to differ materially from
those expressed in the forward-looking statements. These risks, uncertainties,
and other factors include, but are not limited to, general business conditions,
increased competition in the electric utility industry, changes in our tax
status, demand for power, federal and state legislative and regulatory actions
and legal and administrative proceedings, changes in and compliance with
environmental laws and policies, weather conditions, the cost of commodities
used in our industry and unanticipated changes in operating expenses and
capital expenditures. Any forward-looking statement speaks only as of the date
on which the statement is made, and we undertake no obligation to update any
forward-looking statement or statements to reflect events or circumstances
after the date on which the statement is made even if new information becomes
available or other events occur in the future.

Factors Affecting Results

Margins

We operate on a not-for-profit basis and, accordingly, seek to generate
revenues sufficient to recover our cost of service and produce margins
sufficient to establish reasonable reserves, meet financial coverage
requirements and accumulate additional equity required by our board of
directors. Revenues in excess of expenses in any year are designated as net
margins in our Consolidated Statements of Revenues, Expenses and Patronage
Capital. We designate retained net margins in our Consolidated Balance Sheets
as patronage capital, which we assign to each of our members on the basis of
its class of membership and business with us. Any distributions of patronage
capital are subject to the discretion of our board of directors and
restrictions contained in the Indenture. See "DESCRIPTION OF THE
BONDS--Limitation on Distributions to Members."

Formulary Rate

Components. Under a formulary rate accepted by the Federal Energy Regulatory
Commission ("FERC"), we develop rates for sales of power to our member
distribution cooperatives intended to permit collection of revenues which will
equal the sum of:

. all of our costs and expenses,

. 20% of our total interest charges, and

. additional equity contributions approved by our board of directors.

The formulary rate has three components: a demand rate, a base energy rate
and a fuel factor adjustment. The demand rate is designed to recover all of our
capacity-related costs, which are primarily fixed costs, such as depreciation
expense, interest expense, administrative and general expenses, capacity costs
under power purchase contracts with third parties, capacity-related
transmission costs and our margin requirements. The base energy rate recovers
energy costs, which are primarily variable costs, such as nuclear and coal fuel
costs and the energy costs under our power purchase contracts with third
parties. To the extent the base energy rate over or under collects all of our
energy costs, we refund or collect the difference through a fuel factor
adjustment. Of these components, only the base energy rate is a fixed rate that
requires FERC approval prior to adjustment.

The formulary rate identifies the costs that we can collect through the
demand rate and the fuel factor adjustment, but not the actual amounts to be
collected. Our costs to be collected under the components of the

formulary rate typically change each year. Specifically, the demand rate is
revised automatically to recover the costs contained in our annual budget and
any revisions made by the board to the annual budget. In addition, we review
our energy costs at least every six months to determine whether the base energy
rate and the fuel factor adjustment adequately recover our energy costs. We
revise the fuel factor adjustment accordingly.

Existing Indenture. Subject to any necessary regulatory approvals, the
Existing Indenture requires us to establish and collect rates for the use or
the sale of the output, capacity or service of our electric generation,
transmission and distribution system which are reasonably expected to yield
margins for interest for the 12-month period commencing with the effective date
of the rates equal to at least 1.20 times total interest charges during that
12-month period.

Margins for interest under the Existing Indenture equal the total of net
margins plus total interest charges and income tax accruals for the applicable
period less:

. the amount, if any, by which non-operating margins (other than interest
earnings on investments held by the trustee or on investments held by any
trustee for the purpose of decommissioning or dismantling any of our
assets) included in our net margins exceeds 60% of net margins for that
period; and

. the net earnings or losses of property with a fair value in excess of
$25,000 released from the lien of the Existing Indenture during the period
or thereafter.

Our margins for interest requirement and the calculations of margins for
interest and interest charges will change under the Amended Indenture and the
Restated Indenture. See "DESCRIPTION OF THE BONDS--Rate Covenant" for a
description of the calculations of margins for interest and interest charges
under the Indenture.

Since 1992, when the Existing Indenture became effective, our non-operating
margins have not exceeded 60% of our net margins in any year. We do not
anticipate that our non-operating margins (after the above-described
exclusions) will exceed 60% of net margins in the foreseeable future and
believe that our formulary rate, and the rates and charges established under
the wholesale power contracts with our member distribution cooperatives, will
enable us to achieve the required margins for interest. Since 1992, we have
always achieved a margins for interest ratio under the Existing Indenture of at
least 1.20.

Margin Stabilization Plan

Our board of directors established a Margin Stabilization Plan in 1984. This
plan allows us to review our actual cost of service and power sales as of year
end and adjust revenues from our member distribution cooperatives to meet our
financial coverage requirements. Our formulary rate allows us to recover and
refund amounts under the Margin Stabilization Plan. We record all adjustments,
whether increases or decreases, in the year affected and allocate any
adjustments to our member distribution cooperatives based on power sales during
that year. We collect these increases from our member distribution
cooperatives, or offset decreases against amounts owed by our member
distribution cooperatives to us, in the succeeding year. See "BUSINESS--Member
Distribution Cooperatives--Wholesale Power Contracts."

Strategic Plan Initiative

In the late 1990's, some of the same factors which caused us to review how
we served the member distribution cooperatives' power requirements--the
possibility of retail competition and projected lower market power rates--also
caused us to focus on reducing our costs. See "BACKGROUND." Specifically, we
sought to lower our costs so that our member distribution cooperatives could
set rates for power at or below market rates for power by the time competition
for retail customers began in Virginia in 2004. See "BUSINESS--Retail
Competition." Our efforts to meet this objective became known as the "Strategic
Plan Initiative." Because our estimates of future market rates for power
constantly change, we monitor and periodically reevaluate our methods and
progress in achieving the goal of the Strategic Plan Initiative to identify and
implement any appropriate changes.

Our actions to reduce costs pursuant to the Strategic Plan Initiative have
included:

. restructuring our power purchase contracts with neighboring utilities to
reduce the term of the contracts or reduce the price or the amount of the
capacity or energy or both purchased under the contracts;

. accelerating amortization of regulatory assets relating to North Anna and
other items;

. accelerating depreciation of our generating facilities; and

. reducing our indebtedness by purchasing our bonds issued under the
Indenture in the market.

See also "BACKGROUND" and "POWER SUPPLY RESOURCES--Other Power Supply
Resources--Power Purchase Contracts." The recovery of accelerated amortization
and depreciation through our formulary rate generated cash. See "Formulary
Rate." We have used a portion of this cash to purchase bonds issued under the
Indenture. As a result, we have reduced our costs in future years in three
ways: (1) we will incur less amortization and depreciation expense in the
future, (2) our interest expense will be lower in the future as a result of
less indebtedness outstanding under the Indenture, and (3) lower interest
expense will require a lower level of margins for interest. See "DESCRIPTION OF
THE BONDS--Rate Covenant."

Our projections of future market prices of power are key factors in
determining our progress in meeting the Strategic Plan Initiative's objective.
Beginning in 1999, our projections of market prices for power began to rise
significantly. Based on current market projections, we believe that the $160.3
million accumulated through the Strategic Plan Initiative since 1998 and held
as cash or investments, or already applied to reduce our indebtedness, is
sufficient to reduce our costs to a level which would enable the member
distribution cooperatives' rates for power to their customers to be at or below
projected market rates by January 1, 2004. As a result, we ceased recording
accelerated depreciation of our generating facilities effective June 1, 2001.

Based on our projections and today's market price for power, we currently do
not anticipate the need to collect any additional funds under the Strategic
Plan Initiative. Market prices for power can change significantly, however, due
to several factors that we cannot control or predict. These factors include,
among others, the price of fuel (including natural gas), the implementation of
restructuring legislation, the amount of new generating capacity constructed by
competitors and the availability of transmission capacity into the service
territories of our member distribution cooperatives. For these reasons, we
cannot predict whether the member distribution cooperatives' rates for power to
their customers actually will be at or below market rates by January 1, 2004.
We will continue to evaluate the various factors that impact our costs and the
projected market prices of power in 2004 and take additional actions as
appropriate in our efforts to meet the objective of the Strategic Plan
Initiative.

Tax Status

To maintain our tax-exempt status under the Internal Revenue Code of 1986,
as amended (the "Internal Revenue Code"), we must receive at least 85% of our
gross receipts from our members. The major components of our non-member
receipts include:

. investment interest;

. income on the decommissioning fund for North Anna;

. interest from deposits associated with two long-term lease transactions
related to Clover; and

. sales of excess energy to non-members.

See "POWER SUPPLY RESOURCES--North Anna" and "--Clover."

If, in any given year, our member receipts are less than 85% of gross
receipts, we would become a taxable entity in that year, and the potential tax
liability could be significant. Our ability to maintain our tax-exempt status
is dependent upon many factors, several of which are outside of our control,
such as weather-related power

sales and interest rates. Additionally, a decrease in member revenues resulting
from the effect of retail competition could also cause us to lose our
tax-exempt status. See "BUSINESS--Retail Competition." We regularly monitor the
level of our non-member gross receipts to assist us in making adjustments to
preserve our tax-exempt status. Our member receipts in each year have been in
excess of 85% of total gross receipts.

Results of Operations

Operating Revenues

Sales to Members. Our operating revenues are derived from power sales to our
members and to non-members. Revenues from sales to members are a function of
our member distribution cooperatives' customers' requirements for power and our
formulary rate for sales of power to our member distribution cooperatives. Our
formulary rate is based on our cost of service in meeting these requirements.
See "Factors Affecting Results--Formulary Rate." Our member revenues by
formulary rate component, energy sales to our members and average member cost
per megawatt-hour for the six-month periods ended June 30, 2001 and 2000, and
for the past three years were as follows:

Six Months Ended June 30, Years Ended December 31,
------------------------ ------------------------------------
2001 2000 2000 1999 1998
----------- ----------- ----------- ----------- -----------

Member revenues (in thousands)
Demand................................ $ 106,097 $ 119,003 $ 250,817 $ 244,907 $ 238,426
Energy................................ 81,449 77,079 160,530 150,454 141,690
Fuel factor adjustment................ 43,693 (2,339) 3,590 (6,393) (16,684)
----------- ----------- ----------- ----------- -----------
Total member revenues............... $ 231,239 $ 193,743 $ 414,937 $ 388,968 $ 363,432
=========== =========== =========== =========== ===========
Energy sales (in megawatt-hours)....... 4,526,199 4,314,945 8,986,840 8,424,048 7,933,881
Average member cost (per megawatt-hour) $ 51.09 $ 44.90 $ 46.17 $ 46.17 $ 45.81

Three factors significantly affect our member distribution cooperatives'
customers' demand for power:

. growth in the number of customers;

. growth in customers' requirements for power; and

. seasonal weather fluctuations.

From 1995 through 2000, our member distribution cooperatives experienced an
average annual compound growth rate of 2.8% in the number of customers and an
average annual compound growth rate of 4.0% in energy sales. In the future, the
ability of the member distribution cooperatives' customers to select their
power provider may affect this growth. See "BUSINESS--Retail Competition."

Weather affects the demand for electricity. Although the exact amount of
sales attributable to weather conditions cannot be quantified, extreme
temperatures tend to increase demand for energy to use heating and air
conditioning systems. Mild weather generally reduces demand because heating and
air conditioning systems are operated less. Other factors affecting our member
distribution cooperatives' customers' demand for energy include the amount,
size and usage of electronics and machinery, and expansion of operations among
their commercial and industrial customers.

Changes in our member revenues attributable to growth in sales volume and
changes in our average rates for demand and energy (base energy rate and fuel
factor adjustment), for the first six months of 2001 as compared with the first
six months of 2000, and for the years 2000 and 1999 as compared with the prior
years, were as follows:

Six Months Ended Year Ended December 31,
Changes in Member June 30, 2001 --------------------------
Revenues Resulting from Compared 2000 Compared 1999 Compared
Changes in: to 2000 to 1999 to 1998
----------------------- ---------------- ------------- -------------
(in thousands)

Demand sales volume................ $ 3,004 $ 17,595 $16,465
Energy sales volume................ 3,659 9,624 7,723
-------- -------- -------
Total sales volume.............. $ 6,663 $ 27,219 $24,188
-------- -------- -------
Demand rate........................ (15,910) (11,684) (9,984)
Energy rate........................ 46,743 10,434 11,332
-------- -------- -------
Total rates..................... $ 30,833 $ (1,250) $ 1,348
-------- -------- -------
Total change in member revenues. $ 37,496 $ 25,969 $25,536
======== ======== =======

First Six Months of 2001 Compared to First Six Months of 2000. Member
revenues increased by $37.5 million, or 19.4%, for the six month period ended
June 30, 2001 over the same period in 2000 as a result of an increase in the
amount of power we sold to our member distribution cooperatives and an increase
in our average energy rate. Our sales of energy were 4.9% higher for the first
six months of 2001 as compared to the first six months of 2000 due in part to
an approximate 3.1% increase in the number of customers served by our member
distribution cooperatives.

Our average energy rate (including the base energy rate and the fuel factor
adjustment) increased 59.6% between the two periods because of changes in the
fuel factor adjustment. (The base energy rate is a fixed rate in our formulary
rate and did not change. See "Factors Affecting Results--Formulary Rate.") We
increased the fuel factor adjustment for two reasons. First, our energy costs
had been higher than we projected and we needed to recover energy costs that we
previously incurred but did not fully recover under the base energy rate and
existing fuel factor adjustment. Second, we increased the fuel factor
adjustment to a level that, combined with the base energy rate, we anticipated
would adequately recover future energy costs that we expect to be in excess of
the amounts we originally budgeted. These higher energy costs relate to, among
other items, coal purchases and short-term power purchases.

The increase in our energy costs was partially offset by a 13.0% decrease in
the average demand rate for the six month period ended June 30, 2001 compared
to 2000, which resulted from three separate reductions in the demand rate.
First, we reduced the demand rate by approximately 1.3% effective January 1,
2001, as a result of the elimination of the gross receipts tax which had
applied to providers of electricity in Virginia. Second, we reduced the demand
rate approximately 20.0% effective April 1, 2001 to recover evenly the
remaining amounts then anticipated to be collected under the Strategic Plan
Initiative. Finally, in response to new projected power prices we stopped
recording accelerated depreciation under the Strategic Plan Initiative
effective June 1, 2001, which had the effect of amending our budget and
automatically reducing our demand rate by the terms of the formulary rate and
the wholesale power contracts with the member distribution cooperatives. See
"Factors Affecting Results--Strategic Plan Initiative," and "BUSINESS--Member
Distribution Cooperatives--Wholesale Power Contracts." At the same time, we
adopted a revenue deferral plan for the period June 1, 2001, through December
31, 2002. Under this plan, we estimate that we will collect as deferred revenue
approximately $9.1 million through the demand rate in 2001. We will use this
additional amount to reduce the increase in the demand rate we expect will be
required in 2002. The net effect of these two actions was a decrease in our
demand rate of approximately 5.0% effective June 1, 2001.

2000 Compared to 1999. Member revenues increased by $26.0 million, or 6.7%,
from 1999 to 2000 as a result of an increase in the amount of power we sold to
our member distribution cooperatives to meet the power

requirement of their customers. The number of customers buying power from our
member distribution cooperatives grew by 3.1% while the average amount of power
purchased by these customers increased by 3.3%.

Our average member cost per megawatt-hour did not change from 1999 to 2000.
Our average energy rate (including the base energy rate and the fuel factor
adjustment) increased 6.8% in 2000, however, this increase was offset by a
reduction in our demand rate of approximately 4% that became effective April 1,
2000.

1999 Compared to 1998. Member revenues increased by $25.5 million, or 7.0%,
from 1998 to 1999 primarily as a result of an increase in the amount of power
we sold to our member distribution cooperatives. The number of customers buying
power from our member distribution cooperatives grew by 2.9% during this period
while the average amount of power purchased by these customers remained
relatively flat.

Average member cost per megawatt-hour remained relatively constant from 1998
to 1999. The fuel factor adjustment was increased in 1999 to recover higher
energy costs, but the effect of this was mitigated by an approximate 4%
reduction in our demand rate.

Sales to Non-Members. Sales to non-members represent sales of excess
purchased energy and sales of excess generated energy from Clover. In addition,
we sold excess purchased energy to the Pennsylvania-New Jersey-Maryland
Interconnection LLC ("PJM") power pool. We sell excess energy from Clover to
Virginia Electric and Power Company ("Virginia Power") pursuant to the
requirements of the operating agreement for Clover. See "POWER SUPPLY
RESOURCES--Other Power Supply Resources--Power Purchase Contracts."

Non-member revenues in the first six months of 2001 decreased $3.5 million
over the first six months of 2000 primarily as a result of lower sales of
energy to PJM. During the first six months of 2001, we purchased the majority
of the energy for our member distribution cooperatives located on the Delmarva
Peninsula under an energy contract that matched those members' need for power.
During the same period in 2000, we purchased blocks of power to meet our peak
needs and sold the amounts not needed by those members to PJM.

The $6.0 million increase in non-member revenues in 2000 as compared to 1999
resulted from the sale of excess purchased energy to PJM. In 2000, we purchased
sufficient blocks of power to meet our peak needs on the Delmarva Peninsula.
During non-peak periods, the portions of these purchases not needed to meet the
energy needs of our member distribution cooperatives were sold to PJM. During
1999, we purchased most of our energy under contracts that supplied varying
amount of energy to meet our needs. The majority of our non-member revenues in
1999 were sales to Virginia Power of excess energy generated from Clover.

Operating Expenses

Generating facilities, particularly nuclear generating facilities such as
North Anna, generally have relatively high fixed costs. Nuclear facilities
operate with relatively low variable costs due to lower fuel costs and
technological efficiencies. Owners of nuclear and other generating facilities,
incur the embedded fixed costs of these facilities whether or not the units
operate.

When either North Anna or Clover is off-line, we must purchase replacement
energy either from Virginia Power, which is more costly, or from the market,
which may be more or less costly. As a result, our operating expenses, and
consequently our rates to our member distribution cooperatives, are
significantly affected by the operations of North Anna and Clover. The output
of North Anna and Clover for the first six months of 2001 and 2000 and the past
three years as a percentage of the maximum dependable capacity rating of the
facilities was as follows:

North Anna
-----------------------------------
Six Months Ended Years Ended
June 30, December 31,
--------------- ------------------
2001 2000 2000 1999 1998
----- ----- ----- ----- ----

Unit 1... 100.8% 79.4% 92.0% 103.8% 92.3%
Unit 2... 76.7 101.2 101.8 91.4 90.2
Combined. 88.8 90.3 96.9 97.6 91.3

Clover
-----------------------------------
Six Months Ended Years Ended
June 30, December 31,
--------------- ------------------
2001 2000 2000 1999 1998
----- ----- ----- ----- ----

Unit 1... 83.0% 83.6% 88.4% 82.3% 85.7%
Unit 2... 83.8 87.2 90.3 84.7 72.5
Combined. 83.4 85.4 89.4 83.5 79.1

North Anna. As of June 30, 2001, North Anna Unit 1 had been on-line for 415
consecutive days. Prior to that, North Anna Unit 1 had run for 522 consecutive
days before it began a scheduled refueling outage on March 12, 2000. Unit 1 was
returned to service on April 8, 2000.

North Anna Unit 2 began a scheduled refueling outage on March 11, 2001 after
340 days of being on-line, and was returned to service on April 10, 2001. North
Anna Unit 2 experienced only minor unscheduled outages during the year 2000.
There were no significant unplanned outages at North Anna during 1999 or 1998.

Clover. During the first six months of 2001, Clover Unit 1 was off-line 13
days for a scheduled maintenance outage and had been on-line for 276 days prior
to that. Clover Unit 1 experienced minor outages during the year 2000 including
15 days in April 2000 for a scheduled maintenance outage.

Clover Unit 2 was off-line for 15 days during the first half of 2001 for a
scheduled maintenance outage after being on-line for 241 consecutive days.
Clover Unit 2 experienced minor outages during the year 2000.

During the summer of 1999, both Clover units experienced very low water flow
due to lengthy drought conditions in Virginia. As a result, the units operated
to meet peak capacity requirements during the day, but beginning on August 7,
1999, the power generated at night was reduced on each unit to 150 megawatts in
order to conserve water. On August 27, 1999, the units were authorized to
resume full operations.

During 1998, Clover Unit 2 was off-line for 60 days to replace the chimney
liner.

The major components of our operating expenses for the six months ended June
30, 2001 and 2000, and the years ended December 31, 2000, 1999 and 1998 were as
follows:

Six Months
Ended June 30, Years Ended December 31,
----------------- --------------------------
2001 2000 2000 1999 1998
-------- -------- -------- -------- --------
(in thousands)

Fuel.......................................... $ 27,753 $ 23,317 $ 49,578 $ 46,045 $ 46,747
Purchased power............................... 123,428 80,976 170,428 162,242 149,409
Operations and maintenance.................... 17,304 17,594 34,855 34,096 33,020
Administrative and general.................... 11,455 9,394 19,602 18,659 15,071
Depreciation, amortization and decommissioning 31,658 40,826 94,257 68,015 46,421
Taxes, other than income taxes................ 1,587 4,496 8,615 7,678 7,358
-------- -------- -------- -------- --------
Total operating expenses................... $213,185 $176,603 $377,335 $336,735 $298,026
======== ======== ======== ======== ========

First Six Months of 2001 Compared to First Six Months of 2000. Our aggregate
operating expenses increased by $36.6 million, or 20.7%, in the first six
months of 2001 because of a 4.9% increase in the amount of energy sold and an
increase in energy costs. Primarily as a result of rising energy prices, our
average cost of purchased power rose 37.7% in the first six months of 2001 as
compared to the same period for 2000. We have secured the majority of our
energy needs for 2002 and 2003 at fixed prices that are below those that we
paid during the first half of 2001. The average cost of fuel increased 21.3% in
the first six months of 2001 as compared to the first six months of 2000
because of the higher price of coal and a fuel inventory adjustment.

Administrative and general expenses increased in the first six months of
2001 by $2.1 million, or 21.9%, primarily because of an increase in engineering
consulting and legal fees related to pre-construction activities for the
combustion turbine facilities.

The increases in our operating expenses generally caused by higher energy
costs were partially offset by decreases in two cost components of our demand
rate. First, depreciation, amortization and decommissioning decreased $9.2
million, or 22.5%, in the first six months of 2001 as compared to the same
period in 2000, primarily due to a $7.7 million decrease in the amount of
accelerated depreciation recorded on generating facilities in accordance with
our Strategic Plan Initiative. See "Factors Affecting Results--Strategic Plan
Initiative." Accelerated depreciation for the six months ended June 30, 2001,
and 2000, was $18.5 million and $26.2 million, respectively. Second, taxes,
other than income taxes, dropped $2.9 million, or 64.7%, between the two six
month periods because we are no longer subject to Virginia gross receipts tax
as of January 1, 2001.

Included in depreciation, amortization and decommissioning for the first six
months of 2001 is $1.3 million collected under a revenue deferral plan which we
implemented on June 1, 2001. See "Results of Operations--Operating
Revenues--First Six Months of 2001 Compared to First Six Months of 2000."

2000 Compared to 1999. Our aggregate operating expenses increased by $40.6
million, or 12.1%, in 2000, as a result of a 6.7% increase in our energy sales
and as a result of a $21.3 million, or 48.7%, increase in the amount of
accelerated depreciation recorded under our Strategic Plan Initiative. At
December 31, 2000, we had recorded $65.0 million of accelerated depreciation as
compared to $43.7 million in 1999.

Administrative and general expenses increased in 2000 by $943,000, or 5.1%,
primarily because of an increase in engineering consulting and legal fees
related to pre-construction activities for the combustion turbine facilities.

1999 Compared to 1998. Our aggregate operating expenses increased by $38.7
million, or 13.0%, in 1999 as a result of a 6.2% increase in our energy sales
and a $21.6 million, or 46.5%, increase in depreciation, amortization and
decommissioning. In 1999, we recorded $43.7 million of accelerated depreciation
on our generating facilities in accordance with our Strategic Plan Initiative.
In 1998, we accelerated the amortization of certain other assets also in
accordance with the Strategic Plan Initiative, which increased amortization
expenses by $20.7 million.

Administrative and general expenses increased in 1999 by $3.6 million, or
23.8%, primarily because of an increase in engineering consulting and legal
fees related to the siting and permitting of the combustion turbine facilities.

Other Items

Investment Income. Investment income decreased in the first six months of
2001 by $1.0 million, or 40.2%, as compared to the same period in 2000
primarily because of a decrease in our investments and a reduction in the
interest rate on our investments. Our investments declined primarily as a
result of aggregate payments of $62.4 million made on combustion turbine
generators over the past year, of which $22.9 million was paid in the first six
months of 2001. The combustion turbine generator payments were funded with
liquidated investments and cash and cash equivalents, which were included in
other assets.

Investment income decreased in 2000 by $1.5 million, or 26.3%, as compared
to 1999 because of a decrease in investments and invested cash and cash
equivalents resulting from the purchase of $33.3 million and $49.3 million of
outstanding debt in 2000 and 1999, respectively, and $39.5 million in payments
with respect to the generators for the combustion turbine facilities.
Additionally, on average, we earned less interest on our investments in 2000.
Investment income increased $1 million, or 19.7%, from 1998 to 1999 primarily
because of an increase in investments resulting from amounts collected pursuant
to the Strategic Plan Initiative.

Interest. The primary factors affecting our interest expense are scheduled
payments of principal on our indebtedness and prepayments relating to the
implementation of the Strategic Plan Initiative. See "Factors Affecting
Results--Strategic Plan Initiative" and "Liquidity and Capital
Resources--Uses--Financing Activities."

Interest charges, net, decreased by $1.8 million, or 8.7%, in the first six
months of 2001 as compared to the first six months of 2000 because of the
purchase of $33.3 million of outstanding debt and $28.5 million in debt
principal payments in 2000.

Interest charges, net, decreased in 2000 by $8.0 million, or 16.4%, as
compared to 1999 primarily because we purchased $49.3 million of our
outstanding debt in 1999 and made scheduled debt principal payments of $28.5
million. Additionally, we purchased $33.3 million of our outstanding debt in
2000.

Interest charges, net, decreased in 1999 by $11.2 million, or 18.6%, as
compared to 1998 because of scheduled debt principal payments of $28.5 million
in 1998 and accelerated amortization of $8.1 million of debt prepayment
premiums, both of which occurred in late 1998, and the purchase of $49.3
million of outstanding debt in 1999. The decrease was partially offset by an
additional $1.7 million of accelerated amortization of a debt prepayment
premium in 1999.

Net margin. Net margin for the first six months of 2001 and 2000 was $3.9
million and $4.3 million, respectively. Net margin for the years 2000, 1999 and
1998 was $8.2 million, $9.8 million and $12.1 million, respectively. Our margin
requirement, which is a function of our interest charges, decreased over the
last three years because we reduced our interest charges through scheduled
principal payments and the purchase of outstanding indebtedness under the
Existing Indenture in accordance with the Strategic Plan Initiative. See
"Factors Affecting Results--Strategic Plan Initiative."

Financial Condition

The principal changes in our financial condition from December 31, 1999,
through June 30, 2001, were caused by accelerated depreciation recorded on our
generating facilities and a reduction in long-term indebtedness. Accelerated
depreciation recorded on our generating facilities was $18.5 million and $65.0
million for the six month period ended June 30, 2001, and for the year ended
December 31, 2000, respectively. The additional depreciation was recorded as
part of the Strategic Plan Initiative. See "Factors Affecting
Results--Strategic Plan Initiative."

The reduction in long-term indebtedness was achieved through the purchase of
$36.9 million of our outstanding indebtedness from January, 2000, through June,
2001 and annual principal payments of $28.5 million in 2000. The purchases also
were part of our Strategic Plan Initiative.

Our deferred energy balance changed from a $3.3 million credit, a liability,
at December 31, 1999, to a $21.1 million debit, an other asset, at June 30,
2001, because the base energy rate and the fuel factor adjustment of our
formulary rate inadequately recovered increased energy costs over the period.
The fuel factor adjustment was increased April 1, 2001 to collect these energy
costs and to attempt to reduce the deferred energy debit to zero over the
subsequent 12 month period. See "Results of Operations--Operating
Revenues--First Six Months of 2001 Compared to First Six Months of 2000." From
December 31, 1999, to June 30, 2001, our investments decreased $11.4 million,
primarily due to payments made on the combustion turbines, offset by (1)
amounts

collected pursuant to the Strategic Plan Initiative, (2) deposits to and
increases in the value of the decommissioning fund, and (3) increases in lease
deposits. See "POWER SUPPLY RESOURCES--Clover."

Liquidity and Capital Resources

Sources

Cash generated by our operations, issuances of indebtedness and,
periodically, borrowings under available lines of credit provide our sources of
liquidity and capital.

Operations. Historically, our operating cash flows have been sufficient to
meet our short and long-term capital expenditures relating to the operation of
North Anna and Clover, our debt service requirements and our ordinary business
operations. Our operating activities provided cash flows of $51.9 million and
$45.4 million for the first six months of 2001 and 2000, respectively, and
$79.5 million, $75.5 million and $71.8 million for the years ended December 31,
2000, 1999 and 1998, respectively. As of June 30, 2001, our cash on hand was
approximately $32.0 million. In the past three years and the six months ended
June 30, 2001, our operating cash has been sufficient to meet all of our cash
requirements, including, more recently, all costs related to the development
and construction of the combustion turbine facilities.

Lines of Credit. In addition to liquidity from our operating activities, we
maintain committed lines of credit to cover short-term funding needs.
Currently, we have short-term committed variable rate lines of credit in an
aggregate amount of $210 million. Of this amount, $95 million is available for
general working capital purposes and $115 million is available only for capital
expenditures related to the development and construction of the combustion
turbine facilities or other generating facilities. The following table
describes the amount, lender, permitted use of proceeds and expiration date of
each line of credit:

Amount Lender Use of Proceeds Expiration Date
------ ------ --------------- ---------------

$30 million Bank of America Working capital September 30, 2001

$25 million Branch Banking and Trust Company of Virginia Working capital March 30, 2002

$20 million National Rural Utilities Cooperative Finance Working capital December 31, 2001
Corporation

$20 million CoBank, ACB Working capital December 31, 2001

$40 million Morgan Guaranty Trust Company of New York Construction of May 14, 2002
generating facilities

$20 million Bank of America Construction of June 30, 2002
generating facilities

$55 million National Rural Utilities Cooperative Finance Construction of July 15, 2002
Corporation generating facilities

The Existing Indenture limits our ability to borrow amounts under these
facilities. Under the Existing Indenture, our short-term indebtedness may not
exceed the greater of $100 million and 15% of our total long-term debt and
equities. See "DESCRIPTION OF THE BONDS--Limitations on Issuance of Short-Term
Debt." As of June 30, 2001, this covenant would limit the aggregate amount we
could have drawn under these lines of credit to approximately $100 million.
Because the sale of the 2001 Series A Bonds will increase our long-term debt,
the amount of short-term indebtedness we will be permitted to have outstanding
under the Existing Indenture will increase to approximately $132.6 million
following this offering. As of June 30, 2001, no amounts were outstanding under
any line of credit.

We expect the working capital lines of credit to be renewed as they expire.
We expect the construction-related lines of credit to be renewed until no
longer necessary for the development and construction of the combustion turbine
facilities.

Financings. We fund the portion of our capital expenditures that we are not
able to supply from operations through financings in the market. Since 1983,
these capital expenditures have consisted primarily of the costs related the
acquisition of our interest in North Anna, our share of the costs to construct
Clover and other capital improvements and additions to North Anna and Clover.

We had minimal financing activities during the first six months of 2001. As
of the three year period ended December 31, 2000, our principal financing
activities related to a loan to us from the proceeds of pollution control bonds
issued by a municipality on our behalf. Between 1998 and 2000, we refinanced
$3.4 million of our First Mortgage Bonds, 1992 Series C, due 1998 through 2000.

In December, 1998, a municipality issued tax-exempt bonds to finance the
expansion of the solid waste facilities at Clover. The municipality loaned $5
million of the proceeds of that offering to us in consideration for the
issuance of $5 million of our First Mortgage Bonds, 1998 Series B due 2002. As
of June 30, 2001, we have not used the proceeds of the loan to us because the
existing solid waste facilities at Clover have remained adequate and, as a
result, we have not yet been required to expend moneys to expand the
facilities.

Uses

Our uses of liquidity and capital relate to funding our working capital
needs, investment activities and financing activities. Substantially all of our
investment activities relate to capital expenditures in connection with our
generating facilities. We expect that cash flows from our operations, the net
proceeds of this offering and existing lines of credit will be sufficient to
meet our operational and capital requirements until the third quarter of 2002.

Capital Expenditures. We regularly forecast our capital expenditures as part
of our long-term business planning activities. We review these projections
frequently in order to update our calculations to reflect changes in our future
plans, construction costs, market factors and other items affecting our
forecasts. Our actual capital expenditures could vary significantly from these
projections because of, among other things, unforeseen construction or other
problems relating to the combustion turbine facilities. The following
summarizes our actual and current projected capital expenditures, including
capitalized interest, for 1998 through 2005:

Actual Projected
--------------- --------------------------------
1998 1999 2000 2001 2002 2003 2004 2005
---- ---- ----- ------ ------ ------ ----- -----
(in millions)

Clover....................... $0.2 $0.6 $ 2.4 $ 1.9 $ 2.6 $ 1.5 $ 0.8 $ 0.8
North Anna................... 8.5 6.6 6.8 11.6 9.2 6.5 10.5 7.7
Combustion turbine facilities - - 41.6 88.4 247.0 176.3 37.3 47.0
Diesel generators............ - - - 6.5 - - - -
Other........................ 0.2 0.5 0.7 2.4 0.8 0.8 0.8 0.8
---- ---- ----- ------ ------ ------ ----- -----
Total..................... $8.9 $7.7 $51.5 $110.8 $259.6 $185.1 $49.4 $56.3
==== ==== ===== ====== ====== ====== ===== =====

Nearly all of our capital expenditures consist of additions to our
electrical plant and equipment. In addition to loans to our subsidiaries for
the development and construction of the combustion turbine facilities, our
future capital requirements include our portion of the cost of the nuclear fuel
purchased for North Anna and additions to the solid waste facilities at Clover.
See "REGULATION AND LEGAL PROCEEDINGS--Environmental Matters." We also expect
to spend approximately $6.5 million in 2001 in connection with the installation
of ten diesel generators. Other capital expenditures include the purchase and
development of computer software. We intend to use our cash from operations and
the currently invested net proceeds of the tax-exempt bonds loaned to us to
fund all of our capital requirements not related to the development and
construction of the combustion turbine facilities through 2005.

Through the fourth quarter of 2005, we currently expect that development and
construction of the combustion turbine facilities will require an aggregate of
$637.6 million, including amounts we have already

loaned to the subsidiaries. Of the $88.4 million estimated to be required for
this purpose in 2001, we have recorded expenditures of and funded $23.8 million
of this amount as of June 30, 2001, with cash from operations. In the future,
however, funds in addition to cash generated from our operations will be
required to finance the combustion turbine facilities. We expect these other
sources of funds to be the proceeds of this offering, loans to our subsidiaries
guaranteed by RUS, borrowings under our construction-related lines of credit or
issuances of additional indebtedness in the market or a combination of these
sources. See "PLAN OF FINANCE AND USE OF PROCEEDS."

We do not expect a decision from RUS with respect to any of the
subsidiaries' loan guarantee applications before late 2001 or early 2002. We
cannot predict whether any subsidiary will obtain an RUS-guaranteed loan and,
if so, the amount and timing of the loan. While we are waiting for RUS's review
of the loan guarantee applications or, if the applications are not approved, we
plan to finance the loans to the subsidiaries for the construction of the
combustion turbine facilities in part with the net proceeds of this offering.
In addition, we currently estimate that we will be able to borrow $115 million
under the construction-related lines of credit as long as not more than
approximately $17.6 million is outstanding under our other working capital
lines of credit. As a result, we project that we will have sufficient capital
to fund construction activities for the combustion turbine facilities through
the third quarter of 2002 even if no RUS-guaranteed loans are made to a
subsidiary. To the extent amounts are financed under lines of credit, we
anticipate those amounts would be repaid with the proceeds of an RUS-guaranteed
loan or the offering of additional long-term indebtedness under the Indenture.
See "PLAN OF FINANCE AND USE OF PROCEEDS."

Other Investments. In March 2001, we purchased a one-sixth interest in APM
for $750,000. See "BACKGROUND--Reliance on Energy Purchases." As part of our
investment, we extended a loan to APM in the amount of $500,000. Repayment of
the loan is due on or prior to February 15, 2002. In addition, APM has the
right to require us to contribute an additional $750,000 to APM as part of a
required capital contribution of all investors in APM.

On June 12, 2001, we invested $7.5 million in ODEC Power Trading in exchange
for all of its capital stock. We distributed the stock of ODEC Power Trading as
a patronage distribution to our member distribution cooperatives on the same
date. In addition, to facilitate ODEC Power Trading's ability to sell power in
the market, we have agreed to guarantee a maximum of $42.5 million of ODEC
Power Trading's delivery and payment obligations associated with its energy
trades. See "BUSINESS--ODEC Power Trading." Our guarantee of ODEC Power
Trading's obligations will enable it to maintain sufficient credit support to
meet its delivery and payment obligations associated with its energy trades.

In the future, we anticipate that we will guarantee the obligations of the
subsidiaries developing the combustion turbine facilities as they enter into
agreements relating to the development and construction of the facilities, such
as engineering, procurement and construction contracts. These guarantees will
support capital expenditures by our subsidiaries already reflected in our
estimates of our capital expenditures. As of June 30, 2001, we had not provided
any guarantees on behalf of these subsidiaries.

Financing Activities. Pursuant to the Strategic Plan Initiative, we
accumulated approximately $160.3 million to reduce our outstanding
indebtedness. See "Factors Affecting Results--Strategic Plan Initiative." Of
this amount, we have spent $89.2 million (including premiums and discounts) to
purchase indebtedness outstanding under the Indenture. These debt purchases
resulted in principal retirements of $3.6 million during the first six months
of 2001, and $33.3 million and $49.3 million in 2000 and 1999, respectively. We
intend to use the remaining $71.1 million to purchase additional indebtedness
under the Indenture before 2004 in the most economical method from time to
time.

Future Issues

Reliance on Energy Purchases

As part of the restructuring of our power supply resources, we intend to
continue to rely on forward, short-term and spot market purchases of energy to
meet a significant portion of our members' requirements. While we actively
manage the risks associated with this reliance on the market, our results of
operations are subject to changes in prices in the energy markets. See
"BACKGROUND" and "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS."

Changes in the Electric Utility Industry

The electric utility industry is becoming increasingly competitive as a
result of deregulation of the supply of power, competing energy suppliers, new
technology and other factors. The Energy Policy Act of 1992 amended the Federal
Power Act and the Public Utilities Holding Company Act of 1935 to allow for
increased competition among wholesale electricity suppliers and increased
access to transmission services by suppliers of energy. A number of other
significant factors are affecting the operations of electric utilities,
including:

. state electric restructuring legislation permitting retail customers to
choose their power suppliers;

. the adequacy of transmission system capabilities;

. the availability and cost of fuel for the generation of electric energy;

. the use of alternative fuel sources for space and water heating and
household appliances;

. fluctuating rates of growth in capacity requirements;

. compliance with environmental and other governmental regulations;

. licensing and other factors affecting the construction, operation, and
cost of new and existing facilities; and

. the effects of conservation, energy management, and other governmental
regulations on the use of electric energy.

These factors present an increasing challenge to companies in the electric
utility industry to reduce costs, increase efficiency and innovation, and
improve management of resources. See "BUSINESS--Retail Competition" for a
discussion of the recently enacted electric restructuring legislation in
Virginia, Maryland and Delaware.

As a result of these factors, many member distribution cooperatives are
providing or considering providing non-traditional products and services such
as satellite television, propane and natural gas, and internet and other
services. Depending on the impact of competition, there could be reasons for
the member distribution cooperatives to restructure their current businesses to
operate more effectively under retail competition.

In addition, these factors may cause our member distribution cooperatives to
desire greater flexibility in their power supply options in the future, which
may require an amendment to their wholesale power contracts. See
"BUSINESS--Member Distribution Cooperatives--Wholesale Power Contracts."

Recently Issued Accounting Standards

In June, 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133 "Accounting for
Derivative Instruments and Hedging Activities." In June, 2000, the FASB issued
SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities--An Amendment to FASB Statement No. 133," which further
clarifies certain SFAS No. 133 implementation issues. SFAS No. 133, which
applies to all of our financial statements beginning January 1, 2001, requires
that all derivative instruments, including those embedded in other contracts,
be recorded as either

assets or liabilities at fair value. Any changes in value should be reported
currently in earnings, unless the derivative instrument is specifically
designated as a hedge and meets certain accounting criteria required for such
designation. Effective January 1, 2001, we adopted SFAS 133, as amended by SFAS
138. The adoption of these accounting standards did not have a significant
effect on our financial statements.

On August 15, 2001, the FASB issued SFAS No. 143 "Accounting for Asset
Retirement Obligations" which will be effective with respect to us beginning in
2003. The new rules will change our current accounting and reporting relative
to our decommissioning costs. The standard requires entities to record at fair
value an asset retirement obligation in the period in which it is incurred.
When the liability is initially recorded, the entity capitalizes the costs by
increasing the carrying amount of the related long-lived asset. Over time, the
liability is accreted to its present value each period, and the capitalized
asset is depreciated over the useful life of the related long-lived asset. We
do not believe that this statement will have a material adverse effect on
results of our operations due to our current and future ability to recover
decommissioning costs through rate adjustments.

Extension of North Anna Licenses

We expect that North Anna will begin decommissioning in 2018 if its
operational licenses are not extended. If both units are decommissioned, we
expect the timing of payments for decommissioning costs would extend for 32
years. We do not expect these payments to have a material adverse impact on our
liquidity or capital resources because we have set aside appropriate reserves
for this purpose. In June, 2001, Virginia Power filed applications with the
Nuclear Regulatory Commission (the "NRC") to renew the operating licenses for
both North Anna units. If granted, the renewal licenses would permit operation
of the facility for another 20 years, until 2038 for Unit 1 and 2040 for Unit
2. We cannot predict whether the NRC will grant the renewal licenses.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to various market risks, including changes in interest rates
and equity and market prices. Interest rate risk is generally associated with
our outstanding indebtedness and securities issued under the Indenture. We also
are subject to interest rate risk, as well as equity price risk, as a result of
our nuclear decommissioning trust investments in debt and equity securities.

Interest Rate Risk

We use both fixed and variable rate debt as sources of financing. As of June
30, 2001, all of our outstanding long-term indebtedness accrued interest at
fixed rates, except for two series of bonds with variable interest rates that
are periodically re-priced which were issued to municipalities in connection
with their issuance of tax-exempt bonds to finance the purchase of load
management software and equipment and pollution control facilities. The
following table illustrates financial instruments sensitive to interest rate
changes that we held or were issued by us at June 30, 2001:

Expected Maturity Value /(1)/

Fair
Liability 2001 2002 2003 2004 2005 Thereafter Total Value
--------- ----- ----- ----- ----- ----- ---------- ------ ------
(in millions, except percentages)

Fixed rate taxable bonds...... $28.2 $28.2 $20.7 $20.6 $20.6 $367.0 $485.3 $503.5
Average interest rate....... 8.2% 8.2% 8.2% 8.2% 8.0% 8.0%
Tax-exempt bonds............ $ 1.3 $10.7 $ 1.4 $ 1.5 $ 1.6 $ 48.7 $ 65.2 $ 66.3
Average interest rate....... 6.2% 6.2% 6.4% 6.4% 6.7% 6.7%
Variable rate tax-exempt bonds $ 1.1 -- -- -- -- $ 6.7 $ 7.8 $ 7.8
Average interest rate....... 2.7% -- -- -- -- 2.9% -- --

(1)The maturities of the bonds reflect mandatory redemption obligations, if
any.

As of June 30, 2001, any impact on our earnings as a result of a change in
interest rates on our variable rate tax exempt bonds due in 2001 and our
short-term credit facilities would have been immaterial.

If we borrowed amounts under our short-term credit lines (which are not
included in the above table) to the extent permitted under the Existing
Indenture, approximately $132.6 million after this offering, we estimate a 10%
increase in market interest rates would increase our annual interest costs by
less than $1 million. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--Liquidity and Capital Resources."

Equity Price Risk

We are exposed to price fluctuations in equity markets with respect to some
of our nuclear decommissioning investments. At June 30, 2001, these equity
investments totaled approximately $36.6 million. We believe our exposure to
fluctuations in equity prices will not have a material impact on our financial
results.

We accrue decommissioning costs over the expected service life of North Anna
and make periodic deposits to a trust fund so that the fund balance will equal
the estimated cost to decommission North Anna at the time of decommissioning.
At June 30, 2001, these funds were invested primarily in equity securities and
corporate obligations. These equity securities expose us to price fluctuations
in equity markets. To minimize the risk of price fluctuations, we actively
monitor our portfolio by measuring the performance of our investments against
market indexes and by maintaining and reviewing established target allocation
percentages of assets in our trust to various investment options. Unrealized
gains and losses on investments in the trust are deferred as an adjustment to
the reserve until realized.

Market Price Risk

Because our member distribution cooperatives' power requirements are greater
than our owned or contractual power supply resources, we must secure additional
energy resources by entering into forward, short-term and spot-purchase
contracts to meet our total energy requirements. See "BACKGROUND" and "POWER
SUPPLY RESOURCES--Other Power Supply Resources." These contracts are sensitive
to changes in the prices of electricity, coal and natural gas. We currently are
not party to any derivative commodity instruments.

Through our relationship with APM, we expect to formulate policies and
procedures to manage the risks associated with these price fluctuations and use
various commodity instruments, such as hedges, futures and options, to reduce
our risk exposure by creating offsetting market positions. We intend to use APM
to assist us in managing our market price risks by:

. designing a portfolio model that identifies our power producing resources
(including fuel supply, our power purchase contract positions and our
generating capacity) and analyzing the optimal use of these resources in
light of costs and market risks associated with using these resources;

. modeling our power obligations and assisting us with analyzing
alternatives to meet our member distribution cooperatives' power
requirements;

. selling power as our agent and the agent of ODEC Power Trading, including
excess power produced by the combustion turbine facilities; and

. executing hedge trades to stabilize the cost of fuel requirements,
primarily natural gas, used to operate the three combustion turbine
facilities and to limit our exposure under power purchase contracts with
variable rates based on natural gas prices.

We continually review various options to acquire low cost power and are
developing the combustion turbine facilities as a means of maintaining stable
power costs. See "BACKGROUND."

BUSINESS

General

We are a not-for-profit power supply cooperative engaged in the business of
providing wholesale electric services to our members. We were organized for the
purpose of securing adequate reliable sources of capacity and energy for our
member distribution cooperatives on a cost-effective basis. We provide this
power pursuant to long-term, all-requirements wholesale power contracts. Our
wholesale power contracts with the member distribution cooperatives obligate us
to supply, and our member distribution cooperatives to purchase, all of their
capacity and energy requirements through 2028, with limited exceptions. See
"Member Distribution Cooperatives--Wholesale Power Contracts." We also will
sell power to our other member, ODEC Power Trading, which in turn will sell the
power in the market. See "ODEC Power Trading."

We supply the member distribution cooperatives' capacity and energy
requirements through a portfolio of power supply resources consisting of
generating facilities, power purchase contracts and forward, short-term and
spot market energy purchases. Our generating facilities consist of an 11.6%
undivided interest in North Anna, a two-unit 1,842 megawatt (net capacity
rating) nuclear generating facility, and a 50% undivided interest in Clover, a
two-unit 882 megawatt (net capacity rating) coal-fired electric generating
facility. See "POWER SUPPLY RESOURCES--North Anna" and "--Clover."

Currently, we purchase a portion of our capacity and energy under power
purchase contracts that expire before 2005. Since the late 1990's, we have
restructured these power purchase contracts to increase our reliance on market
purchases of energy to take advantage of our projections of relatively lower
future market energy prices. See "BACKGROUND," "BUSINESS--Retail Competition"
and "POWER SUPPLY RESOURCES."

As part of our restructured approach to meet our member distribution
cooperatives' future power requirements, we are developing Rock Springs, Louisa
and Marsh Run through our subsidiaries. We expect Rock Springs, Louisa and
Marsh Run to supply 336, 504 and 672 megawatts of capacity, respectively, to
us. Rock Springs will be developed jointly with one or more third parties. Our
subsidiaries are seeking approvals and permits to begin construction of these
facilities. We expect construction of Rock Springs to begin in the third
quarter of 2001 and construction of Louisa and Marsh Run to begin in 2002. See
"POWER SUPPLY RESOURCES--Combustion Turbine Facilities."

Our member distribution cooperatives serve primarily suburban, rural and
recreational areas. The areas predominantly reflect stable residential capacity
requirements both in terms of power sales and number of customers. See
"Members' Service Territories and Customers." Under recently enacted state
restructuring legislation, between 2001 and 2004, nearly all customers of our
member distribution cooperatives will be able to select their power suppliers.
The member distribution cooperatives will continue to be the exclusive
providers of distribution services and, at least initially, the default
providers of power to their customers in their service territories. See "Retail
Competition."

We do not have collective bargaining agreements. We had 65 employees as of
June 30, 2001. We believe that our relations with our employees are good.

Cooperative Structure

In general, a cooperative is a business organization owned by its members,
which are also either the cooperative's wholesale or retail customers.
Cooperatives are designed to give groups the opportunity to satisfy their needs
in a particular area of business more effectively than if the members acted
independently. As not-for-profit organizations, cooperatives are intended to
provide services to their members on a cost-effective basis, in part by
eliminating the need to produce profits or a return on equity in excess of
required margins. Margins not distributed to members constitute patronage
capital, a cooperative's principal equity. Patronage capital is held for the
accounts of the members without interest and returned when the board of
directors of the cooperative deems it appropriate to do so.

We are a power supply cooperative. Electric distribution cooperatives form
power supply cooperatives to acquire power supply resources, typically through
the construction of generating facilities or the development of other power
purchase arrangements, at a lower cost than if they were acquiring those
resources alone.

Our Class A members are electric distribution cooperatives. Electric
distribution cooperatives own and maintain nearly half of the distribution
lines in the United States and serve three-quarters of the United States' land
mass. There are currently approximately 870 electric distribution cooperatives
in the United States. Historically, the primary purpose of an electric
distribution cooperative was to own and operate a distribution system and to
supply the power requirements of its retail customers. With the advent of
retail competition and regional transmission organizations in many areas,
distribution cooperatives must adjust to changes in the distribution business,
which typically remain regulated monopolies, and the power supply business
which is rapidly becoming competitive. See "Retail Competition."

Member Distribution Cooperatives

General

Our member distribution cooperatives provide electric services, consisting
of power supply, transmission services and distribution services (including
metering and billing) to, residential, commercial and industrial customers in
70 counties in Virginia, Maryland, Delaware and West Virginia. The member
distribution cooperatives' distribution business involves the operation of
substations, transformers and electric lines that deliver power to customers.
Three of our member distribution cooperatives provide electric services on the
Delmarva Peninsula: A&N Electric Cooperative in Virginia, Choptank Electric
Cooperative in Maryland, and Delaware Electric Cooperative in Delaware. The
remaining nine member distribution cooperatives provide electric services in
mainland Virginia. These members are: BARC Electric Cooperative, Community
Electric Cooperative, Mecklenburg Electric Cooperative, Northern Neck Electric
Cooperative, Northern Virginia Electric Cooperative, Prince George Electric
Cooperative, Rappahannock Electric Cooperative, Shenandoah Valley Electric
Cooperative and Southside Electric Cooperative.

Historically, the member distribution cooperatives have been the exclusive
providers of power to customers within their service territories. Recent
restructuring legislation will permit nearly all of the member distribution
cooperatives' customers to select their power suppliers by 2004. The member
distribution cooperatives will remain the exclusive provider of distribution
services and, at least initially, the default provider of power within their
service territories. See "Retail Competition."

The member distribution cooperatives are not our subsidiaries, but rather
our owners. We have no interest in the properties, liabilities, equity,
revenues or margins of the member distribution cooperatives. Financial and
statistical information relating to the member distribution cooperatives is set
forth in Appendix A to this prospectus.

Wholesale Power Contracts

We sell power to our member distribution cooperatives under
"all-requirements" wholesale power contracts. Each contract obligates us to
sell and deliver to the member distribution cooperative, and the member
distribution cooperative to purchase and receive from us, all power that it
requires for the operation of its system, with limited exceptions, to the
extent that we have the power and facilities available to do so. Each of these
wholesale power contracts is effective through 2028 and continues in effect
until we or the member distribution cooperative gives the other at least three
years notice of termination.

There are two principal exceptions to the "all-requirements" obligations of
the parties. First, each mainland Virginia member distribution cooperative may
purchase power allocated to it from the Southeastern Power

Administration. In 2000, the total allocation of power from the Southeastern
Power Administration to the member distribution cooperatives was 84 megawatts
plus associated energy, representing approximately 4.6% of our total member
distribution cooperatives' peak capacity requirements and approximately 1.5% of
our total member distribution cooperatives' energy requirements. Second, if
pursuant to the Public Utility Regulatory Policies Act ("PURPA") or other laws,
a member distribution cooperative is required to purchase electric power from a
facility, the member distribution cooperative must make the required purchases.
Any required purchases made by the member distribution cooperative will be at a
rate no more than our avoided cost, as established by us. At our option, the
member distribution cooperative will sell that power to us at a price no more
than that rate. The member distribution cooperative may appoint us to act as
its agent in all dealings with the owner of any of these facilities. Purchases
of power generated by qualifying facilities constituted less than 1.0% of our
member distribution cooperatives' capacity and energy requirements in 2000. In
addition to these exceptions, one member distribution cooperative is permitted
to supply a small portion of its requirements on two islands located in the
Chesapeake Bay with two back-up generators located on the islands.

Each member distribution cooperative is required to pay us monthly for power
furnished under its wholesale power contract in accordance with our formulary
rate. The formulary rate is intended to allow us to meet all of our costs and
expenses from the ownership, operation, maintenance, termination, retirement
and decommissioning of and repairs, improvements, modifications to our
generating plants, transmission system or related facilities and associated
costs and expenses. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--Factors Affecting Results--Formulary
Rate." In addition, the formulary rate includes our costs and expenses relating
to the acquisition and sale of power or related services that we provide to our
member distribution cooperatives under the wholesale power contracts,
including:

. payments of principal of and premium, if any, and interest on all
indebtedness issued by us (other than payments resulting from the
acceleration of the maturity of the indebtedness);

. the cost of any power purchased for resale by us under the wholesale power
contracts and the costs of transmission, scheduling, dispatching and
controlling services for delivery of electric power;

. any additional cost or expense, imposed or permitted by any regulatory
agency or which is paid or incurred by us relating to our generating
plants, transmission system or related facilities or relating to the
services we provide to our member distribution cooperatives that is not
otherwise included in any of the costs specified in the wholesale power
contracts;

. additional amounts required to meet the requirement of any rate covenant
with respect to coverage of principal of and interest on our indebtedness
contained in any indenture or contract with holders of our indebtedness;
and

. any additional amounts which our board of directors deems advisable in the
marketing of our indebtedness.

The rates established under the wholesale power contracts are designed to
enable us to comply with our mortgage, indenture, regulatory and governmental
requirements which apply to us from time to time.

We may revise our budget at any time to the extent that our current budget
does not accurately reflect our costs and expenses or estimates of our sales of
power. Increases or decreases in our annual budget automatically amend the
demand component of our formulary rate. Also, the wholesale power contracts
permit us to adjust the amounts to be collected from the member distribution
cooperatives to equal our actual costs. We make these adjustments under the
Margin Stabilization Plan. These adjustments are treated as due, owing,
incurred and accrued for the year to which the increase or decrease relates.
The member distribution cooperatives pay any amounts owed as a result of this
adjustment in the following year. If at any time our board of directors
determines that the formula does not meet all of our costs and expenses, it may
adopt a new formula to meet those costs and expenses, subject to any necessary
regulatory review and approval. See "MANAGEMENT'S

DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Factors Affecting Results--Margin Stabilization Plan."

During the term of each wholesale power contract, each member distribution
cooperative will not, without obtaining our written consent, take or permit to
be taken any steps for reorganization or dissolution, consolidation with or
merger into any corporation, or the sale, lease or transfer all or a
substantial portion of its assets. We will not, however, unreasonably withhold
our consent to any reorganization, dissolution, consolidation, merger or sale,
lease or transfer of assets. In addition, we will not withhold or condition our
consent if the transaction would not (1) increase rates to our other members,
(2) impair our ability to repay our indebtedness or any other obligation, or
(3) affect our system performance in any material way. Despite these
restrictions, a member distribution cooperative may reorganize or dissolve,
consolidate with or merge into any corporation, or sell, lease or transfer a
substantial portion of its assets without our consent if it:

. pays the portion of our indebtedness or other obligations as we determine,
and

. complies with reasonable terms and conditions that we may require to
eliminate any adverse effects on the rates of our other members, or
provide assurance that we will have the ability to repay our indebtedness
and abide by our other obligations.

As a result of deregulation and changes in the electric industry, we
recognize that it may be necessary or desirable to modify the relationship
between us and our member distribution cooperatives in the future. In
particular, we recognize that our member distribution cooperatives may desire
greater flexibility in their power supply options in the future, which may
require an amendment to their wholesale power contracts. Currently, we are
negotiating with one member distribution cooperative, Northern Virginia
Electric Cooperative, possible amendments to its wholesale power contract with
us. The negotiations center around changing the nature of the contract from an
all-requirements contract to a contract under which Northern Virginia Electric
Cooperative would take a percentage of the output of North Anna, Clover and the
planned combustion turbine facilities and pay its share of our costs relating
to these resources and the provision of services under the amended contract.
Any amendments to our wholesale power contract with Northern Virginia Electric
Cooperative would need to be approved by our board of directors before becoming
effective. If approved, similar terms for the provision of power would be
offered to all of our other member distribution cooperatives. In May 2001, our
board of directors adopted a resolution stating that it would not approve any
amendments to the wholesale power contract with a member distribution
cooperative that could materially adversely affect our financial condition or
cause us to fail to maintain our existing credit ratings.

Northern Virginia Electric Cooperative has told us that if the negotiation
of an amendment to its wholesale power contract is not successful, it may bring
an action before FERC or the Virginia State Corporation Commission (the
"Virginia Commission") seeking a reformation of the contract along the lines
being negotiated. Northern Virginia Electric Cooperative would base its
requested reformation on changes in circumstances since the execution of the
wholesale power contract. It has acknowledged that it would not seek to be
relieved of its obligation to buy power from us equal to its share of North
Anna, Clover and the combustion turbine facilities. Nor would it seek to be
relieved of its obligation to pay its share of the costs of those generating
facilities, including debt service, lease rentals, operation and maintenance
expenses, coverage and other costs and expenses related to the facilities or
properly allocable to the services provided by us to it. For these purposes,
its share would be determined with reference to the ratio of its requirements
to the requirements of all our member distribution cooperatives. We do not
believe any reformation of our wholesale power contract with Northern Virginia
Electric Cooperative is justified if the parties do not agree to an amendment.

ODEC Power Trading

Changes in the electric utility industry and our development of the
combustion turbine facilities have made it more important for us to manage our
activities in power-related markets. For instance, to obtain an economical
power supply, we have purchased power in excess of our member distribution
cooperatives' needs. We also

intend to purchase natural gas or futures contracts to limit our exposure to
fluctuating natural gas prices. In response to these changes, we formed ODEC
Power Trading in 2001 for the primary purpose of purchasing power from us to
sell in the market, acquiring natural gas to supply the combustion turbine
facilities and taking advantage of other power-related trading opportunities in
the market which will help lower our member distribution cooperatives' costs.
ODEC Power Trading was not formed to engage in speculative trading.

We will enter into a wholesale power contract with ODEC Power Trading
whereby ODEC Power Trading will purchase power from us. ODEC Power Trading will
then sell this power to the market. To comply with FERC regulations relating to
the sale of power, on August 7, 2001, ODEC Power Trading filed an application
with FERC seeking approval to sell power at market-based rates. The application
included a generic rate schedule which permits sales of power at negotiated
rates. ODEC Power Trading expects to receive approval of the application by the
end of 2001. We also intend to enter into an agreement with ODEC Power Trading
under which it would assist us in procuring natural gas.

We expect that ODEC Power Trading will engage APM to provide ODEC Power
Trading with contract monitoring and compliance, credit analysis and
monitoring, energy credit negotiations, portfolio modeling and structuring,
reporting, trading controls and settlement services.

We initially capitalized ODEC Power Trading with a $7.5 million capital
investment for all of its capital stock. We distributed all of ODEC Power
Trading's stock as a patronage capital distribution to our member distribution
cooperatives. ODEC Power Trading is our only Class B member and will be
entitled to patronage from us. Its patronage will be based on our allocation of
patronage to Class B members and its business with us.

We have entered into an agreement with ODEC Power Trading whereby we agree
to provide accounting, billing, reporting and other administrative services to
ODEC Power Trading. We will provide these services on an arm's-length basis. To
fully participate in power-related markets, ODEC Power Trading will be required
to maintain credit support sufficient to meet delivery and payment obligations
associated with power trades. To assist ODEC Power Trading in providing this
credit support, we have agreed to guarantee up to $42.5 million of ODEC Power
Trading's delivery and payment obligations associated with its power trades.

Members' Service Territories and Customers

Historically, our member distribution cooperatives have had the exclusive
right to provide electric services to customers within their exclusive service
territories certified by their respective state public service commissions.
Under this structure, the member distribution cooperatives, like other
incumbent utilities, charged their customers a bundled rate for electric
services which included charges for power, transmission services and
distribution (including metering and billing) services.

Virginia, Maryland and Delaware have enacted legislation granting retail
customers the right to choose their power supplier. This legislation maintains
the exclusive right of the incumbent electric utilities, including our member
distribution cooperatives, to continue to provide transmission and distribution
services and, at least initially, to be the default providers of power to their
customers in their service territories. See "Retail Competition."

The territories served by the member distribution cooperatives cover large
portions of Virginia, Maryland and Delaware. One of our member distribution
cooperatives also serves a small area of West Virginia. These service
territories range from the suburban metropolitan Washington, D.C. area in
northern Virginia, to the Atlantic shore of Delaware, Maryland and Virginia, to
the Appalachian Mountains and the North Carolina border. The service
territories of member distribution cooperatives serving the high growth,
increasingly suburban area between Washington, D.C. and Richmond, Virginia
account for approximately half of our capacity requirements. While our member
distribution cooperatives do not serve any major cities, several portions of
their service territories are in close proximity to urban areas. These areas
are experiencing growth due to the expansion

of suburban communities into neighboring rural areas and the continuing
development of resort and vacation communities within their service
territories.

Our member distribution cooperatives' service territories are diverse and
encompass primarily suburban, rural and recreational areas. These territories
predominantly reflect historically stable residential capacity requirements
both in terms of power sales and number of customers. The major industries
served by our member distribution cooperatives include manufacturing,
fisheries, agriculture, forestry and wood products, paper, travel and trade.

Sales of energy by our member distribution cooperatives in 2000 totaled
approximately 8,533,135 megawatt-hours. Our member distribution cooperatives'
sales of energy were divided by type as follows:

Percentage of Percentage of
Customer Class Megawatt-hour Sales Customers
-------------- ------------------- -------------

Residential.................. 63.0% 92.8%
Commercial and industrial.... 35.9% 6.7%
Other........................ 1.1% 0.5%

Our revenues from the following member distribution cooperatives equaled or
exceeded 10% of our total revenues in 2000:

Percentage
of Total
Member Distribution Cooperative Revenues Revenues
------------------------------- ------------- ----------
(in millions)

Northern Virginia Electric Cooperative.... $110.5 26.2%
Rappahannock Electric Cooperative......... 89.0 21.1%
Delaware Electric Cooperative............. 44.1 10.4%

These three members have experienced substantial residential growth in their
capacity requirements due to the suburbanization of a significant portion of
their respective service territories. In each case, in excess of 92% of its
customers are residential.

The member distribution cooperatives' average number of customers per mile
of energized line has increased approximately 5% since 1995 to over 8.9
customers per mile in 2000. System densities of our member distribution
cooperatives in 2000 ranged from 5.9 customers per mile in the service
territory of BARC Electric Cooperative to over 19 customers per mile in the
service territory of Northern Virginia Electric Cooperative. In 1999, the
average service density for all distribution electric cooperatives was
approximately 6.8 customers per mile.

Retail Competition

Restructuring Legislation

Virginia, Maryland and Delaware have enacted legislation that restructures
the electricity utility industry and changes the manner in which electricity
may be sold to customers. The individual restructuring plans adopted by
Virginia, Maryland and Delaware contain similar components.

Retail Choice for Power. The restructuring laws of Virginia, Maryland and
Delaware generally deregulate the power component of electric service,
permitting all retail customers to purchase power from the supplier of

their choice. In other words, the utility with the historically exclusive
territory, the incumbent electric utility, no longer has the exclusive right to
provide power to customers located in its certificated service territory. Each
of these states has implemented a schedule by which each incumbent electric
utility will provide its customers with the opportunity to purchase power from
licensed power suppliers. Transmission and distribution of power will remain
regulated services.

Stranded Costs. One consequence of the transition to competition for
customers is that electric utilities may incur stranded costs. Stranded costs
are generally described as the difference between what an electric utility
would have recovered under regulated cost of service rates and what that
electric utility will recover under competitive market rates. See "--Stranded
Costs" below. The new legislation in all three jurisdictions generally allow
the incumbent electric utilities an opportunity to recover stranded costs.

Capped Rates. To address stranded costs and to facilitate the implementation
of retail competition, the new legislation in all three states requires the
incumbent utility to cap the bundled rates that it can charge customers in its
certificated service territory during a specified transition period. These
capped rates are then unbundled, or itemized, into power, transmission and
distribution components and, in some cases, a competitive transition charge.

Default Service Provider. A customer who is either unable or has not
selected an alternative power supplier will receive power from its "default"
provider. The restructuring laws of Virginia, Maryland and Delaware each
designate each of the member distribution cooperatives, at least initially, to
be the default provider of power for all customers located in its certificated
service territory who do not affirmatively select a competitive power supplier.

All of the customers of our Delaware and Maryland member distribution
cooperatives are now free to choose an alternative power supplier. These
customers accounted for 20.6% of our capacity requirements in 2000. By January
1, 2004, customers accounting for approximately 99.7% of our capacity
requirements in 2000 will be free to choose an alternative power supplier. No
timetable currently exists for permitting customers to select their provider of
power in West Virginia. The West Virginia customers of our member distribution
cooperative providing power in the state accounted for approximately 0.3% of
our capacity requirements in 2000.

Distribution Service Provider. Generally, the new legislation in each state
also provides that each incumbent electric utility including, our member
distribution cooperatives, still has the exclusive right to provide
distribution services in its certificated territory. Member distribution
cooperatives in Virginia, Maryland and Delaware also may exclusively provide
metering and most billing services to all customers located in their
certificated service territories.

Virginia

Retail Choice for Power. The Virginia restructuring legislation provides for
retail choice for power services to be phased in between January 1, 2002 and
January 1, 2004 in accordance with a schedule developed by the Virginia
Commission. The member distribution cooperatives in Virginia may each set their
own schedule for the phase-in of competition between January 1, 2002 and
January 1, 2004. Our Virginia member distribution cooperatives, which accounted
for 79.1% of our capacity requirements in 2000, are in the process of preparing
their schedule for the phase-in of retail competition.

Capped Rates. The Virginia restructuring legislation caps rates for power
from January 1, 2001 to July 1, 2007. The rates of our Virginia member
distribution cooperatives are capped at the levels that were in effect on July
1, 1999 in the absence of a petition to the Virginia Commission for an increase
in rates prior to January 1, 2001. The requests of three of our member
distribution cooperatives for increases in their rates under this provision are
pending before the Virginia Commission. The Virginia Commission may adjust
capped rates to permit our member distribution cooperatives to recover their
fuel costs. We expect our recent increases in the

fuel factor adjustment to recover additional energy costs will be recovered by
our Virginia member distribution cooperatives as increased fuel costs. See
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL RESULTS AND RESULTS OF
OPERATIONS--Results of Operations--Operating Revenues--First Six Months of 2001
Compared to the First Six Months of 2000." Upon petition by a utility, the
Virginia Commission may terminate the utility's capped rates at any time after
2003 if it determines that an effectively competitive market for power exists
within that utility's service territory. If capped rates continue in the
service territories of our member distribution cooperatives after 2003, each of
our member distribution cooperatives may request a one-time change in the
distribution component of its capped rate. Additionally, the member
distribution cooperatives may seek increases in their capped rates at any time
if they are in financial distress beyond their control.

Stranded Costs. Between January 1, 2001, and January 1, 2007, the member
distribution cooperatives may collect stranded costs through a competitive
transition charge that will be collected from all customers that choose an
alternative power supplier. To establish the competitive transition charge, the
Virginia Commission currently is conducting regulatory proceedings to (1)
determine the unbundled rate components of power, transmission and
distribution, by rate class, for each of our Virginia member distribution
cooperatives, and (2) determine the projected market price for power. Once the
projected market price for power is determined and allocated to each rate
class, the Virginia Commission will subtract it from the power component of the
capped rate to determine the applicable competitive transition charge. Our
Virginia member distribution cooperatives are then permitted to collect the
competitive transition charge from their customers that choose an alternative
power supplier during the capped rate period. The competitive transition charge
will be adjusted by the Virginia Commission not more than once a year.

Default Service Provider. Under the restructuring legislation, each of our
Virginia member distribution cooperatives will be the default provider of power
unless (1) it seeks to become the default service provider in the certificated
service territory of another utility, or (2) after July 1, 2004, if the
Virginia Commission determines that a sufficient degree of competition exists
in the service territory and elimination of default service is not contrary to
the public interest. The legislation provides that our member distribution
cooperatives' rates for default service will be the same as the capped rates
described above for the period from January 1, 2001, to July 1, 2007. After
July 1, 2007, the default rates will be based on the member distribution
cooperative's prudently incurred costs of power.

Distribution Service Provider. Each of our Virginia member distribution
cooperatives will remain the exclusive provider of distribution services in its
certificated service territory. Our Virginia member distribution cooperatives
also will be the exclusive providers of metering and most billing services to
all customers located in their certificated service territory.

Maryland

Retail Choice for Power. The Maryland restructuring legislation required our
member distribution cooperative in Maryland, Choptank Electric Cooperative
("Choptank"), to present to the Maryland Public Service Commission ("Maryland
PSC") a plan granting all of its cooperative customers a choice in their
selection of a power supplier by July 1, 2003. Pursuant to a settlement with
the Maryland PSC, Choptank, which accounted for 9.2% of our capacity
requirements in 2000, volunteered to offer all of its customers a right to
choose their power suppliers on July 1, 2001. In order for a competitive
supplier to provide power to Choptank's customers, the supplier must be
qualified by the Maryland PSC and registered with Choptank. As of July 1, 2001,
approximately 30 entities had obtained permission from the Maryland PSC to
provide power in Maryland but to date no alternative power supplier has
registered to serve the customers of Choptank.

Capped Rates and Stranded Costs. Pursuant to its settlement with the
Maryland PSC, Choptank's rates are capped for a period of four years beginning
on July 1, 2001, and ending June 30, 2005. Choptank's capped rates were
developed using a forecast of its cost (including our forecasted rates) for the
capped rate period.

Under the settlement, Choptank's capped rates were unbundled into components
for power, transmission, distribution and a competitive transition charge. The
power component of Choptank's capped rate was determined using forecasts
developed in 1998. The Maryland PSC settlement recognized our efforts to
mitigate stranded costs under the Strategic Plan Initiative. As part of the
settlement, the Maryland PSC approved the collection of a competitive
transition charge based on an amount equal to Choptank's share of our
above-market costs as determined under the Strategic Plan Initiative (and other
transition costs). The competitive transition charges can be collected during
the capped rate period from all of its customers, until we have successfully
concluded the Strategic Plan Initiative. See "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Factors Affecting
Results--Strategic Plan Initiative."

On July 14, 2001, Choptank filed a proposal with the Maryland PSC to
increase the power component of its rate by the amount of the competitive
transition charge that would otherwise be eliminated from the total capped rate
because we have ceased collecting amounts pursuant to the Strategic Plan
Initiative. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS--Factors Affecting Results--Strategic Plan
Initiative." On August 15, 2001, the Maryland PSC approved Choptank's proposal.

Beginning in 1999, market prices for power rose significantly from the
projections made in our 1998 study, causing an increase in our forecasted
energy costs. As a result, the amounts recovered under the power component of
Choptank's capped rate may be less than the amounts we charge Choptank for
power. The settlement with the Maryland PSC does not allow Choptank to
automatically recover these increased energy costs. The settlement does allow
Choptank to petition the Maryland PSC to change the capped rates if there are
extraordinary circumstances or Choptank is under financial distress. Choptank
is having discussions with the Maryland PSC regarding its ability to recover
these increased costs.

Choptank's capped rate does not impair our ability to charge our costs to
Choptank under our wholesale power contract with Choptank. If Choptank's costs
are greater than the rate capped by the Maryland PSC, Choptank must absorb any
deficiency. If Choptank's costs are less than the rate capped by the Maryland
PSC, Choptank is allowed to retain the surplus. We believe that Choptank will
be able to make its payments to us through a combination of revenues derived
from the capped rate, revenues from other sources, reductions in its other
costs and its equity.

Default Service Provider. Under the settlement with the Maryland PSC,
Choptank will be the default provider of power services in the territory
through 2010. Through June 30, 2005, Choptank will provide default services at
the capped rate. Afterwards, Choptank will provide default services for power
at a rate no greater than our annualized rates (including transmission
charges).

Distribution Service Provider. Choptank will remain the exclusive provider
of distribution services in its certificated service territory. Choptank also
will be the exclusive provider of metering and most billing services to all
customers located in its certificated service territory.

Delaware

Retail Choice for Power. The Delaware restructuring legislation required a
phase-in of retail competition beginning April 1, 2000, and ending April 1,
2001, for customers of Delaware Electric Cooperative ("DEC"), our Delaware
member. The customers of DEC that were given the option to select their power
supplier during 2000 accounted for less than 1.0% of our capacity requirements
in 2000. As of April 1, 2001, all customers of DEC, representing approximately
11.4% of the capacity that we sold to our member distribution cooperatives in
2000, have the option to choose their power supplier. To date, none of these
customers has changed to an alternative power supplier.

Capped Rates. Pursuant to the Delaware restructuring legislation, during the
period from April 1, 2000, to March 31, 2005, rates for DEC's customers are
capped at the rates in effect on April 1, 2000, as adjusted by a

one-time fuel adjustment. The power component of DEC's capped rate was
determined using a forecast that we developed in 1998. Market prices for power
rose significantly, however, beginning in 1999. As a result, the amounts
recovered under the power component of DEC's capped rate may be less than the
amounts we charge DEC for power. The Delaware restructuring legislation does
not allow DEC to automatically recover increased fuel costs. The Delaware
Public Service Commission ("Delaware PSC") may change the capped rates in
connection with any extraordinary costs that the Delaware PSC approves.

DEC's capped rate does not impact our ability to charge our costs to DEC
under our wholesale power contract with DEC. If DEC's costs are greater than
the rate capped by the Delaware PSC, DEC must absorb any deficiency. If DEC's
costs are less than the rate capped by the Delaware PSC, DEC is allowed to
retain the surplus. We believe that DEC will be able to make its payments to us
through a combination of revenues derived from the capped rate, revenues from
other sources, reductions in its other costs and its equity.

Stranded Costs. The restructuring legislation required the Delaware PSC to
approve a restructuring and rate unbundling plan, including any proposed
collection of stranded costs for each incumbent utility. DEC filed the required
plan in September, 1999. On April 25, 2000, the Delaware PSC issued a final
order determining that DEC did not have stranded costs and that DEC is not
permitted to collect a competitive transition charge from those customers that
choose an alternative power supplier during the specified transition period.

Default Service Provider. Under the new law, DEC will remain the default
power provider to its current customers through March 31, 2005. After that
date, DEC may continue as a default service provider unless the Delaware PSC
determines that DEC is unable to provide default service or its current service
is not adequate to meet the requirements of public necessity and convenience.
The Delaware PSC has determined that DEC's rates for default service will be
the same as the capped rates described above for the period from April 1, 2001,
to March 31, 2005. After March 31, 2005, the default service rate will be set
by the Delaware PSC.

Distribution Service Provider. DEC will remain the exclusive provider of
distribution services in its certificated service territory. DEC also will be
the exclusive provider of metering and most billing services to all customers
located in its certificated service territory.

West Virginia

On March 11, 2000, the West Virginia legislature adopted a restructuring
plan that implemented customer choice on January 1, 2001, or a later date
established by the state public service commission. Passage of a second
resolution during the 2001 legislative session was necessary for the
deregulation plan to proceed. During the 2001 legislative session, however,
lawmakers did not pass the resolution necessary for the introduction of retail
competition for power services. As a result, the legislation did not become
effective and no timetable currently exists for the introduction of retail
competition for electric services in West Virginia.

Stranded Costs

In a competitive environment, generating utilities are no longer assured the
recovery of prudently incurred costs. Costs that are not recovered are commonly
known as stranded costs. Generating utilities with costs that exceed market
prices could suffer significant losses from stranded costs. Additionally, the
loss of customers as a result of retail competition also could have a
significant impact on a utility's results of operations.

We are allowed to recover all of our costs through the formulary rate we
charge the member distribution cooperatives for power under our wholesale power
contracts with them. See "Member Distribution Cooperatives--Wholesale Power
Contracts." Because nearly all of the member distribution cooperatives'
customers will be permitted to select their power suppliers by 2004, the member
distribution cooperatives may have stranded costs to the extent they are
required to purchase power from us at a price that causes their customers to
select another power supplier, and the competitive transition charges approved
by their respective

state public service commissions are insufficient to recover stranded costs.
The member distribution cooperatives' exposure to potentially stranded costs
most likely would result from:

. power purchase contracts that regularly require us to purchase capacity or
energy in excess of market prices; and

. the inability of our generating facilities to operate economically in a
deregulated market.

The loss of a significant portion of the power purchased by the member
distribution cooperatives' customers could cause a reduction in our revenues
and cash flows. The resulting decrease in our member revenues also could cause
us to lose our tax-exempt status. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Factors Affecting Results--Tax
Status."

Over the past years, we have taken several steps to (1) prepare for and
adapt to the fundamental changes which have occurred or are likely to occur in
the electric utility industry, (2) improve our member distribution
cooperatives' competitive positions, and (3) reduce the possibility that they
will incur stranded costs. Most importantly, we have implemented the Strategic
Plan Initiative. The objective of the Strategic Plan Initiative is to ensure
that our member distribution cooperatives' rates for power will be equal to or
less than the market price of power by January 1, 2004. Based on our most
recent study, we believe that we have reduced our indebtedness and future costs
and acquired enough cash to further reduce our indebtedness in the future so
that our costs under our formulary rate will be at or below our current
projections of the price of power on January 1, 2004. Because several factors
affect this determination, we continue to evaluate the events that could impact
this calculation. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS--Factors Affecting Results--Strategic Plan
Initiative."

POWER SUPPLY RESOURCES

General

We provide power to our members through a combination of our interests in
North Anna and Clover, power purchase contracts and forward, short-term and
spot purchases of power in the open market. Our power supply resources for the
past three years have been as follows:

Years Ended December 31,
--------------------------------------------------
2000 1999 1998
---------------- ---------------- ----------------
Generated: (in megawatt-hours and percentages)

Clover................... 3,428,357 36.7% 3,198,062 36.7% 3,028,740 37.0%
North Anna............... 1,767,053 18.9% 1,775,915 20.3% 1,659,167 20.2%
--------- ------ --------- ------ --------- ------
Total generated........ 5,195,410 55.6% 4,973,977 57.0% 4,687,907 57.2%
--------- ------ --------- ------ --------- ------
Purchased:
Virginia Power........... 1,942,575 20.8% 1,694,685 19.4% 1,599,006 19.5%
Delmarva Peninsula....... 1,198,195 12.8% 1,436,079 16.5% 1,624,444 19.9%
Other.................... 1,002,435 10.8% 623,015 7.1% 280,420 3.4%
--------- ------ --------- ------ --------- ------
Total purchased........ 4,143,205 44.4% 3,753,779 43.0% 3,503,870 42.8%
--------- ------ --------- ------ --------- ------
Total available energy. 9,338,615 100.0% 8,727,756 100.0% 8,191,777 100.0%
========= ====== ========= ====== ========= ======

Our system is geographically divided into two separate and distinctive
transmission and distribution systems with limited capability to transmit power
between the two systems--a mainland Virginia system and a Delmarva Peninsula
system. The two systems have similar customer usage characteristics and
distribution of sales by customer classification. Typically, however, the
mainland Virginia system's capacity requirements peak in the winter months,
while the Delmarva Peninsula system's capacity requirements peak in the summer
months. While there is little variance between our summer and winter peak
capacity requirements, we typically have experienced a slightly higher peak
demand for capacity in the winter months. This peak is due to the winter
heating requirements of the member distribution cooperatives' customers, which
reflects the large residential component of our total capacity requirements.

The mainland Virginia system represented approximately 80% of our member
distribution cooperatives' 2000 peak capacity requirements, which occurred in
January. North Anna and Clover satisfied approximately 45% of our current
capacity requirements and 72% of our energy requirements in the mainland
Virginia system in 2000. We obtain the remainder of our mainland Virginia
system and all of our Delmarva Peninsula system requirements, both capacity and
energy, from several suppliers, including the market. Generally, power purchase
contracts allow us to meet these requirements by purchasing fixed-priced firm
capacity and energy at market prices.

Between 2001 and 2005, most of these contracts will expire. Through our
subsidiaries, we are developing the combustion turbine facilities to satisfy
substantially all of the capacity and a portion of the energy currently
supplied by the contracts. See "BACKGROUND." The timing and size of each
combustion turbine facility was planned to meet our projected capacity
requirements, which are a function of expiring power purchase contracts and our
member distribution cooperatives' capacity requirements growth projections. In
addition, we are installing ten diesel generators across our member
distribution cooperatives' service territories primarily to enhance our
systems' reliability.

North Anna

In 1983, we acquired an 11.6% undivided ownership interest in North Anna,
including nuclear fuel and common facilities at the power station, and a
portion of spare parts inventory and other support facilities. North

Anna is a two unit, 1,842 megawatt (net capacity rating) facility located in
Louisa County, Virginia, approximately 60 miles northwest of Richmond,
Virginia. During 2000, North Anna provided approximately 18.9% of our energy
requirements. North Anna Unit 1 commenced commercial operation in June, 1978,
and Unit 2 commenced commercial operation in December, 1980. Virginia Power,
the co-owner of North Anna, operates the facility. Virginia Power also has the
authority and responsibility to procure nuclear fuel for North Anna. See "Fuel
Supply--Nuclear."

Under the Amended and Restated Interconnection and Operating Agreement with
Virginia Power ("I&O Agreement"), we are entitled to 11.6% of the power from
North Anna. In addition, we can purchase from Virginia Power supplemental or
peaking power or both through 2003. See "Other Power Supply Resources--Power
Purchase Contracts--Virginia Power" for a description of the type and amount of
power we may purchase under the contract. We intend to purchase our reserve
capacity requirements for North Anna from Virginia Power for the term of the
I&O Agreement, which expires on the earlier of the date on which all facilities
at North Anna have been retired or decommissioned and the date we have no
interest in North Anna.

Under the I&O Agreement, we are responsible for 11.6% of all
post-acquisition date additions and operating costs associated with North Anna,
as well as a pro-rata portion of Virginia Power's administrative and general
expenses directly attributable to North Anna. We are obligated to provide our
own financing for these items. In addition, we separately fund our pro rata
portion of the decommissioning costs of North Anna. We and Virginia Power also
bear pro rata any liabilities arising from ownership of North Anna, except for
liabilities resulting from the gross negligence of the other.

Like other nuclear facilities, North Anna is subject to unanticipated or
extended outages for repairs, replacements or modifications of equipment or to
comply with regulatory requirements. These outages may involve significant
expenditures not previously budgeted, including replacement energy costs. See
"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL RESULTS OF
OPERATIONS--Results of Operations--Operating Expenses" for a discussion of
recent operating history of North Anna.

Clover

We have a 50% undivided interest in Units 1 and 2 of Clover, a coal-fired
generating facility jointly owned with Virginia Power. Clover has a net
capacity rating of 882 megawatts and is located near Clover in Halifax County,
Virginia, approximately 100 miles southwest of Richmond, Virginia. Clover Units
1 and 2 began commercial operations in October 1995 and March 1996,
respectively.

Pursuant to the terms of the Clover operating agreement, Virginia Power, as
the co-owner of Clover, is responsible for operating Clover and procuring and
arranging for the transportation of the fuel required to operate Clover. See
"Fuel Supply--Coal." We are responsible for half of all additions and operating
costs associated with Clover, as well as half of Virginia Power's
administrative and general expenses for Clover. We must provide our own
financing for these expenses.

Under the terms of the Clover operating agreement, we and Virginia Power
each are required to take half of the power produced by Clover. During 2000,
our share of Clover provided approximately 36.7% of our energy requirements. In
those hours when we are not able to use our share of the energy produced by
Clover, we are required to sell and Virginia Power is required to purchase our
excess energy. In addition, if Virginia Power makes off-system sales from
Clover, we will share in the net proceeds of those sales. In light of recent
deregulation legislation enacted in Virginia, we and Virginia Power have agreed
that the operating agreement for Clover will be restructured prior to January
1, 2002, to permit us to sell our excess energy from Clover to other power
purchasers as well as to Virginia Power on changed terms and to schedule
dispatch from the facility after that date. We expect to execute an amendment
to the I&O Agreement to grant us these rights prior to 2002.

We have entered into a sale and leaseback of our undivided ownership
interest in pollution control assets at Clover Units 1 and 2. In 1994, we sold
these pollution control assets to an investor, subject to the lien of the
Existing Indenture, and leased them back for a term extending until December
30, 2012. After the Release Date, the lessor's interest in these assets will no
longer be subject to the lien of the Indenture. See "DESCRIPTION OF THE
BONDS--Release and Substitution of Property Prior to Release Date; Negative
Pledge After Release Date." We have an option to purchase the undivided
interest in the pollution control assets sold to the investor on December 30,
2004 for a fixed purchase price. Our obligation to make periodic payments of
basic rent and the fixed purchased option price payable in 2004 have been fully
assumed and the payments are being made by a third party. We have been released
from these payment obligations. The lessor's interest in the undivided interest
in the assets subject to the lease is subject to a lien in favor of us securing
our purchase options under this lease. We have covenanted to exercise our
option to purchase the assets subject to the lease on December 30, 2004.

We also have entered into separate lease and leaseback agreements of our
undivided ownership interest in each Clover unit and related common facilities,
including the pollution control assets at the facilities. In March, 1996, we
entered into a lease with an owner trust for the benefit of an investor in
which we leased our interest in Clover Unit 1, subject to the lien of the
Existing Indenture, for a term extendable by the lessor up to the full
productive life of Clover Unit 1, and simultaneously entered into an
approximately 22-year lease of the interest back to us. After the Release Date,
the interest of the owner trust in Clover Unit 1 will no longer be subject and
subordinate to the lien of the Indenture. See "DESCRIPTION OF THE
BONDS--Release and Substitution of Property Prior to Release Date; Negative
Pledge After Release Date." The lease back to us includes a fixed price
purchase option at the end of its term. We have provided for all of our
periodic basic rent payments under the lease by investing in obligations issued
or insured by entities, the claims paying ability or senior debt obligations of
which are rated "AAA." These obligations will mature at a time and in an amount
sufficient to fully fund the fixed purchase option price in the lease to us.
The lease to us contains events of default which, if they occur, could result
in termination of the lease, and, consequently, our loss of possession and
right to the output of Clover Unit 1.

In July, 1996, we entered into another lease subject to the lien of the
Existing Indenture with an owner trust for the benefit of a different investor
of our interest in Clover Unit 2 for a term extendable by the lessor up to the
full productive life of Clover Unit 2. We simultaneously entered into an
approximately 23-year lease of the interest back to us. After the Release Date,
the interest of the owner trust will no longer be subject and subordinate to
the lien of the Indenture. See "DESCRIPTION OF THE BONDS--Release and
Substitution Property Prior to Release Date; Negative Pledge After Release
Date." The lease back to us includes a fixed price purchase option at the end
of its term. We have provided for all of our periodic basic rent payments under
the lease by investing in obligations issued or insured by entities, the claims
paying ability or senior debt obligations of which are rated "AAA." These
obligations will mature at a time and in an amount sufficient to fully fund the
fixed purchase option price in the lease to us. In addition, we granted a
subordinated lien and security interest in Clover Unit 2 to secure our
obligations under the lease and our reimbursement obligation to an insurer for
its payments under a surety bond securing some of our payment obligations under
the lease. This subordinated lien and security interest will be required to be
released prior to the Release Date unless the holders of obligations issued
under the Existing Indenture or the Amended Indenture are equally and ratably
secured with respect to the assets subject to the lease. As with the Clover
Unit 1 lease, the lease back to us of Clover Unit 2 contains events of default
which could result in termination of the lease and loss of possession and right
to the output of the unit.

Combustion Turbine Facilities

Through our subsidiaries, we are developing Rock Spring, Louisa and Marsh
Run to enable us to continue to serve our member distribution cooperatives'
power requirements. Upon completion of the facilities, our total system
capacity from facilities owned by us or our subsidiaries will increase from 655
to 2167 megawatts. We estimate that the combustion turbine facilities will
provide approximately 58% of our capacity requirements by the end of 2005. See
"BACKGROUND."

The sites selected for Rock Springs, Louisa and Marsh Run contain the
attributes required to support a combustion turbine facility. These sites have
access to electric transmission lines, natural gas pipelines, and the other
major infrastructure required to support a combustion turbine facility. We are
currently negotiating to acquire the necessary easements and agreements
required for an adequate supply of water to the facilities.

While Rock Springs is in the advanced stages of development and we expect
construction of it to commence in the third quarter of 2001, Louisa and Marsh
Run are in less advanced stages of development. These facilities require
several governmental approvals, including certificates of public convenience
and necessity, prior to the start of construction. For this and other reasons,
how and when the facilities will be developed and constructed may change in the
future and we cannot predict what those changes may be. We will purchase
replacement capacity and energy through forward, short-term or market purchases
or under new power purchase contracts in the event of a delay in the
development and construction of the combustion turbine facilities.

Rock Springs

The Rock Springs facility is being developed by our subsidiary together with
one or two other participants. Rock Springs will meet a substantial portion of
the capacity requirements of our member distribution cooperatives on the
Delmarva Peninsula and provide power to the other participants. Located in the
community of Rock Springs, Cecil County, Maryland, the facility is currently
expected to consist of six 168 megawatt (net capacity rating) combustion
turbines, for a total of 1,008 megawatts. Power from the facility will be
transmitted to our member distribution cooperatives over PJM's transmission
facilities under its open access transmission tariff.

At this time, there is one other party developing Rock Springs with our
subsidiary. We anticipate that another participant will join the project in the
future. We expect that each of the three participants, including our
subsidiary, will own two units with a total capability of 336 megawatts and a
one-third undivided interest in the common facilities. Our subsidiary will be
responsible for all costs associated with the development, construction,
additions and operating costs and administrative and general expenses relating
to its two units and a proportional share (depending on the number of
participants in Rock Springs) of the costs relating to the common facilities
for Rock Springs. We estimate that the development and construction costs that
our subsidiary will be responsible for are $143.8 million. See "PLAN OF FINANCE
AND USE OF PROCEEDS."

The Maryland PSC has issued a certificate of convenience and necessity for
the construction and operation of the facility. All major environmental permits
from the State of Maryland have been obtained, subject to compliance with
customary conditions set forth in the certificate, and we have purchased the
necessary nitrogen oxide ("NO\\x\\") emissions credits required prior to the
start of construction of the facility. See "REGULATION AND LEGAL
PROCEEDINGS--Environmental Matters."

We have entered into a fixed-price contract with General Electric Company to
purchase three General Electric 7FA combustion turbines, two of which will be
installed at Rock Springs and the other at Louisa. The turbines will be fueled
by natural gas and have dry low-NO\\x\\ burners which currently exceed Best
Available Control Technology and meet the Lowest Achievable Emission Rate
standards established by the Environmental Protection Agency (the "EPA"). We
intend to assign our rights in the contract with respect to the two turbines to
be installed at Rock Springs to our subsidiary developing the facility.

We expect to be appointed as construction agent on behalf of our subsidiary
and the other participant or participants in Rock Springs to administer and
supervise the development and construction of the facility. We entered into a
contract with Fru-Con Construction Corp. for engineering, procurement and
construction services relating to Rock Springs. We expect that construction
will begin in the third quarter of 2001 and that commercial operation of the
first unit will occur in 2002. The other party currently participating in Rock
Springs will own the first unit but will sell the output from that unit to us
for one year. We expect the two units owned by our subsidiary will begin
commercial operation in 2003.

Louisa

The Louisa facility will be located near Gordonsville, in Louisa County,
Virginia. The facility is currently expected to consist of five combustion
turbines totaling 504 megawatts. We have entered into a fixed-price contract
with General Electric Company to purchase four 84 megawatt (net capacity
rating) General Electric combustion turbines in addition to one 168 megawatt
(net capacity rating) General Electric 7FA combustion turbine purchased with
the two turbines for Rock Springs. The combustion turbines are expected to be
fueled by natural gas and, if necessary, No. 2 distillate fuel oil. We intend
to assign our interest in the contracts relating to the turbines to be
installed at the facility to our subsidiary developing Louisa. The estimated
cost to develop and construct Louisa is $213.4 million. See "PLAN OF FINANCE
AND USE OF PROCEEDS." We expect we will have to guarantee our subsidiaries
obligations under the engineering, procurement and construction contract for
the facility. As with Rock Springs, we expect that we will act as construction
agent on behalf of our subsidiary.

In March, 2000, the Louisa County Board of Supervisors approved our
subsidiary's zoning application and a conditional use permit for the facility.
These approvals are being contested in a lawsuit by adjacent landowners. See
"REGULATION AND LEGAL PROCEEDINGS--Legal Proceedings." In May 2001, the
subsidiary applied to the Virginia Commission for a certificate of public
convenience and necessity and to the Virginia Department of Environmental
Quality for all major environmental permits. A hearing on the application is
scheduled for November 14, 2001. We expect construction of the facility to
begin in the first quarter of 2002 and the units to be available for commercial
operation in 2003. Power from Louisa will be transmitted to our member
distribution cooperatives over the transmission facilities of Virginia Power
under its open access tariff.

Marsh Run

The Marsh Run facility will be located near Remington in Fauquier County,
Virginia, and is currently expected to consist of four 168 megawatt (net
capacity rating) combustion turbines, for a total of 672 megawatts. We have
entered into a fixed-price contract with General Electric Company to purchase
three General Electric 7FA combustion turbines to be installed at Marsh Run. We
intend to assign the contract to the subsidiary developing Marsh Run. The
combustion turbines are expected to be fueled by natural gas and, if necessary,
No. 2 distillate fuel oil. We have not determined how the fourth combustion
turbine will be obtained. The estimated cost to develop and construct Marsh
Run, including the fourth combustion turbine, is $280.4 million. See "PLAN OF
FINANCE AND USE OF PROCEEDS."

Our subsidiary owning the project is in the process of obtaining all
necessary permits and regulatory approvals required for the construction of the
facility. It has received a recommendation for approval by the Fauquier County
Planning Commission and the Board of Supervisors considered that recommendation
at a meeting on August 24, 2001. We expect that construction of the facility
will begin in 2002 and three units will be available for commercial operation
in 2004. We expect to guarantee our subsidiary's engineering, procurement and
construction contract for the facility and that we will act as construction
agent on behalf of our subsidiary. Power from Marsh Run will be transmitted to
our member distribution cooperatives over the transmission facilities of
Virginia Power under its open access tariff.

Other Power Supply Resources

In 2000, we purchased approximately 44.4% of our total energy requirements.
These energy requirements are in excess of our generating assets and were
provided principally by neighboring utilities through power purchase contracts
and purchases of energy in the forward, short-term and the spot market.

Power Purchase Contracts

Historically, we satisfied our capacity and energy requirements not supplied
by North Anna and Clover through power purchase contracts with Virginia Power,
Allegheny Power Resources ("Allegheny"), American Electric Power Virginia
("AEP-Virginia") and Delaware Power & Light, predecessor to Conectiv Energy
("Conectiv"). Under these contracts, we purchased capacity and energy at a
price determined by the seller's average system cost. In the late 1990's, we
sought to take advantage of projected lower market prices of power by (1)
restructuring or reducing the term of these contracts, (2) reducing the amount
of capacity or energy or both we purchased under these contracts, and (3)
entering into new contracts which contained market-based pricing provisions. As
a result, we entered into power purchase contracts with Public Service Electric
& Gas Company ("PSE&G"), Conectiv and Pennsylvania Power and Light ("PP&L"),
and Williams Marketing and Trading Company ("Williams"). See "BACKGROUND." Most
of these contracts expire as the combustion turbine facilities become
operational. See "Combustion Turbine Facilities."

Virginia Power. Under the terms of the I&O Agreement, Virginia Power sells
us reserve capacity and energy for North Anna and Clover. We plan to purchase
our reserve capacity requirements for North Anna and Clover from Virginia Power
for the term of the I&O Agreement, which expires on the earlier of the date on
which all facilities at North Anna have been retired or decommissioned and the
date we have no interest in North Anna. Through 2001, Virginia Power has the
obligation to provide us with all of the monthly supplemental and peaking
demand and energy requirements to meet the needs of our mainland Virginia
members not met from our portion of the output of North Anna and Clover. Under
the I&O Agreement, we will purchase from Virginia Power half of these
supplemental capacity requirements in 2002 and none in 2003. We will continue
to purchase our peaking requirements from Virginia Power through 2003.

Beginning January 1, 2000, energy pricing for the peaking portion of
Virginia Power purchases changed from the Virginia Power system average cost to
a charge that reflects Virginia Power's owned combustion turbine costs. We have
the contractual right to elect not to purchase energy under the I&O Agreement
if we can purchase more economical energy from other sources.

Additionally, under the terms of the I&O Agreement, Virginia Power has
unbundled the services it provides us and no longer provides transmission and
ancillary services to us under the contract. These services are now provided
under Virginia Power's open access transmission tariff. Specific terms for the
provision of those services are provided in a Service Agreement for Network
Integration Transmission Service and a Network Operating Agreement with
Virginia Power, both of which became effective as of January 1, 1998.

PSE&G. We have entered into an agreement with PSE&G to purchase 150
megawatts of capacity, consisting of 75 megawatts of intermediate or peaking
capacity and 75 megawatts of base load capacity, as well as reserves and
associated energy, through 2004. The agreement with PSE&G contains fixed
capacity charges for the base, intermediate, and peaking capacity to be
provided under the agreement. However, either party can apply to FERC in some
circumstances to recover changes in specified costs of providing services. If a
change in rate occurs, the party adversely affected may terminate the agreement
on one year's notice. We may purchase the energy associated with the PSE&G
capacity from PSE&G or other power suppliers. If purchased from PSE&G, the
energy cost is based on PSE&G's incremental cost above its own capacity
requirements, taking into account PJM pool energy transactions. If purchased
from other power suppliers, we pay a negotiated energy rate.

In October 1997, we filed with FERC a Section 206 complaint against PSE&G
asserting that our agreement with PSE&G should be modified to conform to the
restructuring of PJM. Under the PJM structure, we pay for the transmission of
PSE&G power through the zonal rate it currently pays Conectiv. On May 14, 1998,
FERC ruled in our favor, ordering PSE&G to remove any transmission costs from
its rates for capacity and associated energy sold to us. PSE&G has complied
with the FERC order by virtue of a compliance filing submitted to FERC on June
15, 1998. On November 30, 2000, PSE&G filed with the United States Court of
Appeals for the District of Columbia Circuit a petition for review of FERC's
orders in this matter. PSE&G's appeal is still pending before that court.

Conectiv and PP&L. We had a contract with Conectiv to provide 220 megawatts
of capacity through August 31, 2001, to satisfy our capacity requirements for
our member distribution cooperatives providing service on the Delmarva
Peninsula. There was no commitment to provide energy under the contract, and we
utilized forward and short-term energy contracts and spot market purchases to
supply the energy requirements related to the capacity.

Additionally, we have a contract with a joint venture of Conectiv and PP&L
to purchase 60 megawatts of firm system capacity through December, 2001. We do
not purchase energy under the contract.

AEP-Virginia. We purchase power from AEP-Virginia pursuant to three
agreements. Combined, the agreements permit us to purchase up to 108 megawatts
a year from AEP-Virginia. Charges for power purchased under these contracts are
determined according to AEP-Virginia's wholesale rate tariff filed with FERC.
Each of the agreements remains in effect until November, 2003.

Allegheny. We have a fixed price contract with Allegheny to supply all of
our energy requirements at three delivery points through 2001. In 2000, we
purchased 85,000 megawatt-hours from Allegheny. Transmission service relating
to the contract is supplied under Allegheny's open access transmission tariff.

Williams. Because we will not be able to construct the combustion turbine
facilities before some of our power purchase contracts expire, we have entered
into two contracts with Williams. To satisfy our Delmarva Peninsula system
member distribution cooperatives' capacity requirements, we will purchase 200
megawatts of capacity from Williams for the last four months of 2001 and 285
megawatts of capacity for the first four months of 2002. To satisfy our
Virginia mainland member distribution cooperatives' capacity requirements, we
will purchase 245 megawatts of capacity in 2002 and 490 megawatts of capacity
for the first five months of 2003. The contract provides capacity requirements
and energy at predetermined prices. All transmission arrangements have been
secured for delivery of the energy purchased under this contract to both PJM
and the Virginia mainland.

We also entered into a contract with Williams beginning on January 1, 2001,
and ending on August 31, 2001, for the purchase of our full energy requirements
for the three member distribution cooperatives operating on the Delmarva
Peninsula system whose energy requirements are served by the PJM. Under this
contract, Williams met the hourly energy needs of these members at
predetermined monthly prices.

Market Energy Purchases

We purchase in the market the portion of our energy requirements not
provided by North Anna or Clover or purchased pursuant to long-term power
purchase contracts. Market energy purchases are comprised of a changing
portfolio of forward and short-term contracts and spot market purchases.
Sometimes we exercise our right not to purchase energy under a power purchase
contract and instead buy more economical power in the market. We continually
evaluate the short-term capacity and energy markets as compared to power
purchase contracts for our power supply needs.

Relying on purchasing energy in the market subjects us to some risk. We may
be required to purchase energy at market prices that are higher than the cost
of operating the combustion turbine facilities for a significant period because
the combustion turbine facilities cannot be operated for extended periods of
time. To mitigate our energy market risk, we attempt to match our energy
purchases with our energy needs and purchase energy in advance. Additionally,
we have developed policies and procedures to manage the risks in our changing
business environment and have engaged APM to assist us in executing trades to
purchase energy, modeling our power obligations and analyzing our power
purchase contracts and the credit risks of counterparties. See
"BACKGROUND--Reliance on Energy Purchases" and "QUANTITATIVE AND QUALITATIVE
DISCLOSURES ABOUT MARKET RISK."

Diesel Generators

We currently are installing ten Caterpillar 3516B utility-grade diesel
generators throughout our member distribution cooperatives' service
territories. Each generator has a capacity of approximately two megawatts. We
are installing the generators primarily to enhance our system's reliability if
other power supply resources are unavailable.

Transmission

We do not own any significant energized transmission or distribution
facilities. We have entered into agreements with Virginia Power, PJM,
AEP-Virginia and Allegheny which provide us with access to their transmission
facilities as necessary to deliver energy to our members.

Virginia Power

Under the operating agreements for both North Anna and Clover, Virginia
Power makes available to us its transmission and distribution systems, as
needed, to transmit our power from North Anna and Clover, as well as power
purchased from other suppliers, to our member distribution cooperatives'
delivery points. Under the I&O Agreement, Virginia Power supplies all
transmission services under its open access transmission tariff. Terms for
transmission and related services are described in our Service Agreement for
Network Integration Transmission Service and the Network Operating Agreement
with Virginia Power. Because Virginia Power has stated an intention to
participate in the Alliance regional transmission organization, we will obtain
transmission service from that organization when it becomes operational, which
we expect to occur on January 15, 2002. See "--RTOs."

PJM

We are a member of PJM to serve our member distribution cooperatives located
on the Delmarva Peninsula. PJM is an independent system operator of
transmission facilities serving all of Delaware and New Jersey and parts of
Pennsylvania, Maryland and Virginia.

PJM continually balances its participants power requirements with the power
resources available to supply those requirements. Based on this evaluation of
supply and demand, PJM schedules available resources to meet the demand for
power in the most efficient and cost effective manner. When available resources
cannot be dispatched due to transmission constraints, more expensive generating
facilities not subject to the transmission constraints must be dispatched to
meet the requested power requirements. PJM participants whose power
requirements cause the redispatch are obligated to pay those costs. Our PJM
power requirements are located on the Delmarva Peninsula, which has been
subject to significant congestion costs over the last two years. In 2000, we
paid approximately $12.8 million in congestion charges to PJM. In the first six
months of 2001, we paid approximately $4.6 million in congestion charges.

We attempt to mitigate the effects of congestion at PJM's delivery points
through the use of fixed transmission rights. Through fixed transmission rights
we receive or pay the difference between the cost of energy delivered to our
delivery points and the cost of energy delivery to other specified delivery
points on the PJM system (which generally is less expensive than the cost we
incur at our delivery points). As a result, fixed transmission rights generally
reduce congestion charges resulting from having to purchase more expensive
power if the energy we purchased for delivery is unable to be delivered because
of transmission congestion. PJM allocates to us a specified number of fixed
transmission rights, and we purchase additional rights from other members of
PJM if economical.

Conectiv has been performing system upgrades to meet reliability criteria
and to interconnect a new generating facility located in the portion of
Virginia on the Delmarva Peninsula. Conectiv expects that congestion will be
reduced significantly once these upgrades are complete. In addition, we have
agreed to pay for direct

connection facilities and transmission network upgrades to the PJM in order to
serve our member distribution cooperatives on the Delmarva Peninsula more
reliably.

Other Transmission Systems

Allegheny, in its power purchase contract with us, has agreed to transmit
power pursuant to Allegheny's open access transmission tariff. In addition, our
power purchase contracts with AEP-Virginia require AEP-Virginia to transmit
power purchased under our contracts with it. These transmission arrangements
may change as these companies become part of an independent system operator as
directed by FERC.

RTOs

In December 1999, FERC issued Order No. 2000 amending its regulations under
the Federal Power Act to advance the formation of regional transmission
organizations ("RTOs"). One of the major objectives of Order No. 2000 is to
eliminate "pancaked" transmission rates (incurring charges from multiple
transmission owners due to transmission across several systems). By paying a
single transmission rate to access all the transmission facilities under the
control of the RTO, the RTO will expand access to markets that were previously
uneconomical due to having to pay each utility a transmission charge. FERC will
regulate the rates established by the RTOs. The regulations require that each
public utility that owns, operates or controls facilities for the transmission
of electric energy in interstate commerce make required filings with respect to
forming and participating in an RTO. Because we do not own any significant
jurisdictional transmission or distribution facilities, our participation in
any RTO would be as a market participant and not as a transmission owner. We
will be impacted by Order No. 2000 because our members have power requirements
for which we have the responsibility of providing transmission service. We will
benefit from Order No. 2000 if, as intended, it increases competition and
consequently reduces our transmission costs.

FERC noted in Order No. 2000, and on rehearing in Order No. 2000-A, that
existing state and federal laws applicable to cooperatives may inhibit their
participation in RTOs. These laws include tax laws that restrict the level of
business a cooperative can conduct with non-members and still maintain its
tax-exempt status. FERC obligated investor-owned utilities under Order No. 2000
to consider the constraints imposed on cooperatives and work with them to
foster their participation in RTOs.

On July 12, 2001, FERC issued a series of orders in which it determined that
it is necessary that the three independent system operators in the Northeastern
United States, which includes the PJM, combine to form one RTO. Similarly, FERC
concluded that it is necessary that the transmission owners in the Southeastern
United States, including Virginia Power, combine to form one RTO. Accordingly,
FERC initiated expedited mediation proceedings for the purpose of facilitating
the formation of a single RTO for the Northeastern United States and one for
the Southeastern United States. We currently are evaluating the effect of the
orders on us.

Fuel Supply

Nuclear

Under the Purchase, Construction and Ownership Agreement for North Anna, the
I&O Agreement, and the Nuclear Fuel Agreement, Virginia Power, as operating
agent, has the authority and responsibility to procure nuclear fuel for North
Anna. Virginia Power employs both spot purchases and long-term contracts to
satisfy North Anna's nuclear fuel requirements. Virginia Power continually
evaluates worldwide market conditions in order to ensure a range of supply
options at reasonable prices. Virginia Power reports that current agreements,
inventories, and spot market availability will support current and planned fuel
cycles. Beyond that period, additional fuel will be purchased as required to
ensure optimum cost and inventory levels.

Coal

Under the Clover operating agreement, Virginia Power, as operating agent,
has the authority and responsibility to procure sufficient coal for the
operation of Clover. Virginia Power employs both spot purchases and long-term
contracts to acquire the low sulfur bituminous coal used to fuel the facility.
We anticipate that sufficient supplies of coal will be available in the future
at reasonable prices, but market prices and price volatility both may be higher
than we currently anticipate.

Gas

Natural gas has become the preferred fuel for new electric generating
facilities, causing an increase in competition for natural gas capacity. The
combustion turbine facilities are located adjacent to natural gas transmission
lines. We anticipate that these natural gas transmission lines generally will
have the capacity to meet the natural gas needs of the combustion turbine
facilities. We are developing a fuel supply plan that will provide an
economical and reliable supply of gas to the combustion turbine facilities. To
develop this plan, we are evaluating purchases of firm gas (delivery of which
may not be interrupted even during periods of high demand for gas) and
interruptible gas, and designing Louisa and Marsh Run to operate for a limited
period of time on fuel oil reserves. Through APM and ODEC Power Trading, we and
the subsidiaries plan to utilize long-term contracts and spot purchases to
support the natural gas needs of the combustion turbine facilities and enter
into hedging instruments to minimize price volatility. We presently anticipate
that sufficient supplies of natural gas will be available in the future at
reasonable prices, but significant price volatility may occur, especially
during the winter. See "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK" and "BUSINESS--ODEC Power Trading."

REGULATION AND LEGAL PROCEEDINGS

Regulation and Rates

We are subject to regulation by FERC and, to a limited extent, state public
service commissions. Some of our operations also are subject to regulation by
the Virginia Department of Environmental Quality, the Department of Energy
("DOE"), the NRC and other federal, state, and local authorities. Compliance
with future laws or regulations may increase our operating and capital costs by
requiring, among other things, changes in the design and operation of the
generating facilities in which we have an interest or the combustion turbine
facilities.

FERC regulates our rates for transmission services and the wholesale sale of
power in interstate commerce. We establish our rates for power furnished to our
member distribution cooperatives pursuant to our comprehensive formulary rate
which has been accepted by FERC. The formulary rate is intended to permit us to
collect revenues which, together with revenues from all other sources, are
equal to all of our costs and expenses, plus an additional 20% of our total
interest charges, plus additional equity contributions as approved by our board
of directors. The formula is comprised of three components: a demand rate, a
base energy rate and a fuel factor adjustment. See "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Factors Affecting
Results--Formulary Rate." Of these components, only changes in the base energy
rate must be accepted by FERC.

The formulary rate provides for periodic adjustment of rates to recover
actual, prudently incurred costs, whether they increase or decrease, without
further application to or acceptance by FERC. FERC also may review our rates
upon its own initiative or upon complaint and order a reduction of any rates
determined to be unjust, unreasonable, or otherwise unlawful and order a refund
for amounts collected during such proceedings in excess of the just,
reasonable, and lawful rates. Our rates to ODEC Power Trading will be
established under our market-based sales tariff filed with FERC.

In addition to its jurisdiction over our rates, FERC also regulates the
issuance of securities and assumption of liabilities by us, as well as mergers,
consolidations, the acquisition of securities of other utilities, and the
disposition of property other than generating facilities. Under FERC
regulations, we are prohibited from selling, leasing, or otherwise disposing of
the whole of our transmission facilities (which constitute minor switching
assets), or any part of those facilities having a value in excess of $50,000,
without FERC approval. FERC also will regulate the sale of power by our
subsidiaries unless RUS has guaranteed loans to the subsidiaries. The
subsidiaries intend to seek approval from FERC as exempt wholesale generators.

Because we are regulated by FERC, the Virginia Commission, the Delaware PSC
and the Maryland PSC do not have jurisdiction over our rates and services. The
state public service commissions, however, do have oversight over the siting of
our utility facilities in their respective jurisdictions. They also regulate
the rates and services offered by our member distribution cooperatives. See
"BUSINESS--Retail Competition."

In November, 2000, the Maryland PSC issued to us a certificate of public
convenience and necessity to build and operate Rock Springs. In the second
quarter of 2001, we filed an application with the Virginia Commission seeking a
certificate of public convenience and necessity to build and operate Louisa. A
hearing on the application is scheduled on November 14, 2001. We anticipate
filing an application with the Virginia Commission in the fall of 2001 seeking
a certificate of public convenience and necessity to build and operate Marsh
Run.

On behalf of our member distribution cooperatives, we have developed and
published a competitive bidding program for use in long-term purchases of
capacity and energy from power suppliers. This program represents a system-wide
election to use a centrally administered competitive bidding process for all
member distribution cooperatives to satisfy the requirements of PURPA and the
rules of the respective state public service commissions having regulatory
authority over the member distribution cooperatives.

Environmental Matters

We are currently subject to regulation by the EPA and other federal, state,
and local authorities regarding the emission, discharge, or release of
materials into the environment. As with all electric utilities, the operation
of our generating units could be affected by future environmental regulations.
Capital expenditures and increased operating costs required to comply with any
future regulations could be significant. Expenditures necessary to ensure
compliance with environmental standards or deadlines will continue to be
reflected in our capital and operating costs.

We are subject to the Clean Air Act. The Clean Air Act requires utilities
owning fossil fuel fired power stations to, among other things, limit emissions
of sulfur dioxide and NO\\x\\, one of the precursors of ground-level ozone, or
obtain allowances for these emissions. Through the use of pollution control
facilities, Clover is designed and licensed to operate at full capacity below
the current limitations for sulfur dioxide emissions levels and nitrogen oxides
emissions. Pollution control facilities at Clover include wet limestone
scrubbers, low NO\\x\\ burners, and fly ash collection facilities. Virginia
Power, as operator of North Anna and Clover, is responsible for environmental
compliance and reporting for the facilities. If, however, liabilities arise as
a result of a failure of environmental compliance at North Anna or Clover, our
respective responsibility for those liabilities is governed by the operating
agreement for the facilities. See "POWER SUPPLY RESOURCES--North Anna" and
"--Clover."

In 1998, the EPA issued a rule addressing regional transport of ground-level
ozone through reductions in NO\\x.\\ The rule is commonly known as the NO\\x\\
State Implementation Plan ("SIP") call. The NO\\x\\ SIP call affects 22 states,
including Maryland, Virginia and the District of Columbia, and required those
states to develop a plan by October 30, 2000, to reduce NO\\x\\ emissions. The
NO\\x\\ SIP call also required emissions reduction to be implemented by May 1,
2004. On December 26, 2000, the EPA found that several states, including
Virginia, failed to submit a plan satisfying the rules. If a state fails to
make the required submittal, which the EPA determines is complete, within 18
months of the findings, a emissions offset sanction will apply. This sanction
requires new or modified sources of emissions to obtain allowances to emit two
tons of NO\\x\\ for every one ton of NO\\x\\ emitted from the source, subject
to the Clean Air Act new source review program for NO\\x\\. The EPA will lift
the sanctions when it finds that the state has made a complete filing under the
SIP call. The EPA also can promulgate a federal implementation plan as late as
two years after the initial findings, unless the affected state has submitted a
complete plan by that time. In a federal plan, the EPA rather than the states
would determine the specific sources that must reduce NO\\x\\ emissions. We
anticipate that fossil fuel electric generating facilities greater than 250
mmBtu/hour will be required to reduce their NO\\x\\ emissions or obtain NO\\x\\
emissions credits from another source. We and Virginia Power are currently
evaluating options in meeting the NO\\x\\ SIP call as applicable to Clover.
These options include installing additional NO\\x\\ controls at Clover and
purchasing emissions allowances or a combination of both. At this time, we and
Virginia Power continue to evaluate NO\\x\\ controls to determine the best
alternatives for Clover.

North Anna is not impacted by the SIP call because it does not have
significant NO\\x\\ emissions. Louisa and Marsh Run will be required to obtain
allowances to emit one ton of NO\\x\\ for every ton of NO\\x\\ emitted from the
facility. Rock Springs is in an ozone non-attainment area and will be required
to obtain allowances to emit one ton of NO\\x\\ emissions for every ton of
NO\\x\\ emitted as well as 1.3 NO\\x\\ emissions reduction credits for every
ton of potential NO\\x\\ emissions. NO\\x\\ emission reduction credits are
required to be obtained prior to the construction of the facility. We will
purchase in the market the allowances and have purchased credits required for
the operation of the combustion turbine facilities. We project that we will be
able to obtain sufficient quantities of allowances in the future at
commercially reasonable prices but increased NO\\x\\ emissions or increased
restrictions could cause the price of allowances to be higher than we expect.

In addition to the NO\\x\\ SIP call, several Northeast utilities filed
petitions under Section 126 of the Clean Air Act requesting that the EPA take
action to mitigate interstate transportation of NO\\x\\. In December 1999, the
EPA established NO\\x\\ allocations for 392 generating facilities, including
Clover, and many industrial facilities. Additionally, the EPA established a
trading program to help those companies meet the required reductions in NO\\x\\
by May 3, 2003.

The EPA has promulgated a new regional haze rule, which affects any source
that emits NO\\x\\ or sulfur dioxide and that may contribute to the degradation
of visibility in national parks and wilderness areas. Currently, we do not know
what controls, if any, may have to be installed at Clover to comply with this
rule.

Each state regulates the discharge of process wastewater and some storm
water discharges into its waters under the National Pollutant Discharge
Elimination System program. This program was established as part of the Federal
Clean Water Act. We are also subject to permit limitations for surface water
discharges and for the operation of a waste landfill at Clover for disposal of
ash and scrubber sludge. Permits required by the Clean Water Act and state laws
have been issued to us. These permits are subject to reissuance and continued
review. We and Virginia Power are evaluating relocating the future landfill
discharge to the Roanoke River which contains a larger flow and provides more
dilution.

Clover has a Virginia water protection permit that regulates the amount of
water allowed to be withdrawn from the Roanoke River. Clover has a 34-day
on-site water supply reservoir to supply the facility during times of low flow
when the Roanoke River is below the withdrawal level allowed in the permit.

Our direct capital expenditures for environmental control facilities at
Clover and North Anna, excluding capitalized interest, were approximately $2.5
million and $36,000, respectively, in 2000. Based on information provided by
Virginia Power, our portion of direct capital expenditures for environmental
control facilities planned for Clover and North Anna over the next three years
is estimated to be approximately $2.2 million and $1.3 million, respectively.
These expenditures, which include amounts related to the above referenced
NO\\x\\ emissions reduction plans, are included in our energy costs which are
passed through to our member distribution cooperatives. See "MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS--Factors Affecting Results--Formulary Rate."

The scientific community, regulatory agencies, and the electric utility
industry are examining the issues of global warming and acidic deposition, and
the possible health effects of electric and magnetic fields. While no
definitive scientific conclusions have been reached regarding these issues, it
is possible that new regulations pertaining to these matters could further
increase the capital and operating costs of electric utilities.

In December 2000, the EPA announced that it will regulate emissions of
mercury and other air toxins from coal and oil-fired electric utility steam
generating units to reduce the health risk of mercury exposure. Clover would be
subject to such regulation but because existing pollution control systems on
these units currently reduce mercury emissions, we do not anticipate
installation of additional equipment will be required at this time. The EPA
currently intends to propose regulations with respect to mercury emissions by
December 15, 2003, and issue final regulations by December 15, 2004.

Finally, several studies required by the Clean Air Act examined the health
effects of power plant emissions of various hazardous air pollutants. Emissions
of other hazardous air pollutants, such as nickel and cadmium, also may become
regulated. The EPA expects to follow a rulemaking schedule to establish limits
on these emissions that would require compliance by 2007 to 2008. Depending on
the outcome of this rulemaking, significant capital expenditures may be
incurred at Clover.

Nuclear

North Anna is subject to regulation by the NRC. 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. From time to time, new NRC
regulations require changes in the design, operation, and maintenance of
existing nuclear reactors. The operating licenses for North Anna Unit 1 and
North Anna Unit 2 are scheduled to terminate in 2018 and 2020, respectively.
Virginia Power, as operator of the facility, applied to the NRC to extend the
operating licenses for both North Anna units for an additional 20 years. See
"POWER SUPPLY RESOURCES--North Anna."

Under the Nuclear Waste Policy Act, the DOE is required to provide for the
permanent disposal of spent nuclear fuel produced by nuclear facilities, such
as North Anna, in accordance with contracts executed with the DOE. However,
since the DOE did not begin accepting spent fuel in 1998 as specified in its
contracts, Virginia Power is providing on-site spent nuclear fuel storage at
North Anna. These facilities are expected to be adequate until the DOE begins
accepting the spent nuclear fuel.

Legal Proceedings

From time to time we are alleged to be in violation or in default under
orders, statutes, rules or regulations relating to the environment, compliance
plans imposed upon or agreed to by us, or permits issued by various local,
state and federal agencies for the construction or operation of facilities.
From time to time, there may be pending administrative proceedings on these
matters. In addition, we may be involved in legal proceedings arising in the
ordinary course of business. We believe that the ultimate resolution of these
proceedings will not have a material adverse impact on the results of our
operations, liquidity or financial condition.

On April 6, 2000, landowners adjacent to the proposed combustion turbine
facility in Louisa County filed a Bill of Complaint for Declaratory Judgment
seeking a determination that the Louisa County Board of Supervisor's decision
to rezone the 92 acres on which that facility is to be located to allow for the
construction and operation of an electric generating facility was inconsistent
with Louisa County's Comprehensive Plan concerning land use. On July 23 and 24,
2001, the Circuit Court for Louisa County heard testimony on the complaint.
Final arguments are scheduled for September 24, 2001.

In October 1997, we filed a claim against PSE&G with FERC requesting
modification of our power purchase agreement in connection with the
restructuring of PJM. FERC ruled in our favor and PSE&G appealed. See "POWER
SUPPLY RESOURCES--Other Power Supply Resources--Power Purchase
Contracts--PSE&G."

There is no other material litigation pending against us.

MANAGEMENT

We operate under the direction of a board of 25 directors that consists of
two representatives from each of our member distribution cooperatives and one
representative from our Class B member, ODEC Power Trading. Each of our 12
member distribution cooperatives nominate two directors, at least one of whom
must be a director of that member in good standing. One director currently
serves as a director on behalf of a Class A member and the Class B member. The
candidates are then elected to our board of directors by voting delegates from
each of our members, elected by each member distribution cooperative's board of
directors and authorized to represent the member at our annual meeting. Our
board of directors establishes company policy and provides direction to our
President and Chief Executive Officer. Our President and Chief Executive
Officer administers our day-to-day business and affairs. The ages and positions
of our executive officers and directors are as follows:

Name Age Position
---- --- --------

Jackson E. Reasor....... 48 President and Chief Executive Officer
Daniel M. Walker........ 56 Senior Vice President of Accounting and Finance
Konstantinos N. Kappatos 58 Senior Vice President of Engineering and Operations
Gregory W. White........ 49 Senior Vice President of Retail and Alliance Management
William M. Alphin....... 71 Class A Director
E. Paul Bienvenue....... 61 Class A Director
Frank W. Blake.......... 82 Class A Director
John E. Bonfadini....... 62 Class A Director
Dick D. Bowman.......... 73 Class A Director
M. Johnson Bowman....... 55 Class A Director
M Dale Bradshaw......... 48 Class A Director
Vernon N. Brinkley...... 54 Class A and Class B Director
Calvin P. Carter........ 76 Class A Director
Glenn F. Chappell....... 58 Class A Director
Carl R. Eason........... 64 Class A Director
Stanley C. Feuerberg.... 49 Class A Director
Hunter R. Greenlaw, Jr.. 57 Class A Director
Bruce A. Henry.......... 55 Class A Director
Frederick L. Hubbard.... 60 Class A Director
David J. Jones.......... 52 Class A Director
William M. Leech, Jr.... 74 Class A Director
M. Larry Longshore...... 60 Class A Director
James M. Reynolds....... 54 Class A Director
Charles R. Rice, Jr..... 60 Class A Director
Cecil E. Viverette...... 60 Class A Director
Richard L. Weaver....... 55 Class A Director
Carl R. Widdowson....... 63 Class A Director
C. Douglas Wine......... 59 Class A Director

Executive Officers of Old Dominion

Jackson E. Reasor. Mr. Reasor has served as our President and Chief
Executive Officer and in the same capacities for the Virginia, Maryland and
Delaware Association of Electric Cooperatives ("VMDA"), an electric cooperative
association which provides services to our members and other electric
cooperatives, since 1998. He also served as Vice President of First Virginia
Bank from 1997 until 1998, President and Chief Executive Officer of Premier
Trust Company from 1995 until 1997, and a Virginia State Senator from 1992
until 1998.

Daniel M. Walker. Mr. Walker is our Senior Vice President of Accounting and
Finance and has acted in this or similar capacity for us since 1984. Since
December, 1986, Mr. Walker has also acted as Assistant

Treasurer for each of Dominion Power Control, Ltd. ("DPL") and Regional
Headquarters, Inc. ("RHI") and holds the additional position of director and
President of CSC Services, Inc. ("CSC") since April, 1998.

Konstantinos N. Kappatos. Mr. Kappatos is our Senior Vice President of
Engineering and Operations and has served in this or a similar capacity for us
since 1984.

Gregory W. White. Mr. White has served as our Senior Vice President of
Alliance Management since 1999. Mr. White also served as Vice President of VMDA
from 1996 until 1999.

Classes

Our bylaws establish three classes of members, designated as Class A, Class
B and Class C. Class A members consist of the member distribution cooperatives.
Each Class A member is required to purchase from or through us all electric
energy used by it to operate its system, subject to its wholesale power
contract with us. Each Class A member is entitled to seat two directors on our
board of directors. Currently, we have twelve Class A members.

Class B members consist of other wholesale customers admitted to membership
that purchase electric capacity or energy or both, at wholesale from or through
us pursuant to a full or partial requirements contract. Class B members
collectively are entitled to seat one director on our board of directors.
Currently, ODEC Power Trading is our only Class B member.

Class C members consist of any other customers admitted to membership that
purchase energy, or any other products or services that we are permitted by law
to offer for sale, from or through us pursuant to any other contract,
arrangement or agreement. Class C members collectively are entitled to seat one
director on our board of directors. Currently, we do not have any Class C
members.

Our Directors

Information concerning our directors, including their principal occupations
and employment during the past five years and directorships in public
corporations, if any, are listed below.

William M. Alphin. Mr. Alphin has been a director on our board since
September, 1980. In addition, he has served as secretary of RHI since July,
1998, treasurer of RHI from May, 1987 until July, 1998 and an insurance advisor
with Virginia Farm Bureau Insurance Company since October, 1975. In addition,
he has been a self-employed farmer since June, 1996.

E. Paul Bienvenue. Mr. Bienvenue has been a member of our board of directors
since September, 1981 and was Chairman of our board of directors from July,
1995 until September, 1998. In addition, he served as President of DPC from
July, 1995 until September, 1998, President of DEC since September, 1998,
General Manager of Delaware Electric Cooperative from September, 1981 until
September, 1998, and Executive Vice President and General Manager of Rural
Electric TV, Inc. from May, 1989 through March, 2001.

Frank W. Blake. Mr. Blake has been a member of our board of directors since
July, 1977. Mr. Blake was a self-employed buyer and seller of real estate from
1943 until 1998 and serves as a Methodist minister.

John E. Bonfadini. Mr. Bonfadini has been a member of our board of directors
since July, 1977. Mr. Bonfadini has also served as a professor at George Mason
University since July, 1980.

Dick D. Bowman. Mr. Bowman has been a member of our board of directors since
July, 1993. He has also served as President of Bowman Brothers, Inc., a farm
equipment retailer, since November, 1976.

M. Johnson Bowman. Mr. Bowman has been a member of our board of directors
since July, 1974. Mr. Bowman has also served as President and Chief Executive
Officer of Mecklenburg Electric Cooperative since January, 1980 and Executive
Vice President and General Manager of Mecklenburg Communications Services, Inc.
since January, 1999.

M Dale Bradshaw. Mr. Bradshaw has been a member of our board of directors
since January, 1995 and Secretary of our board of directors since July, 1999.
He also has served as Chief Executive Officer of Prince George Electric
Cooperative since January, 1995 and Secretary/Treasurer of DPC since July,
1999.

Vernon N. Brinkley. Mr. Brinkley has served as Chairman of our board of
directors since July, 2001, and prior to that served as Vice Chairman from
July, 1999 to July, 2001 and Secretary/Treasurer from July, 1998 to July, 1999,
and July, 1992 to July, 1997. He has been a member of our board of directors
since October, 1982. He has also served as Vice President of DPC since July,
1999, Secretary/Treasurer of DPC from July, 1998 until July, 1999, and
President and General Manager of A&N Electric Cooperative since October, 1995.

Calvin P. Carter. Mr. Carter has been a member of our board of directors
since May, 1991. Mr. Carter has been self employed as the owner of Carter's
Store since April, 1960, the owner of Carter Stone Co., a stone quarry, since
June, 1965 and a member of the Campbell County Board of Supervisors since
November, 1979.

Glenn F. Chappell. Mr. Chappell has been a member of our board of directors
since December, 1995. Mr. Chappell has also been a self-employed farmer since
1962.

Carl R. Eason. Mr. Eason has been a member of our board of directors since
2000. Mr. Eason has been retired since August 5, 1997 and prior to his
retirement was an electrical supervisor with International Paper from June,
1972 through his retirement.

Stanley C. Feuerberg. Mr. Feuerberg has served as the Vice Chairman of our
board of directors since July, 2001. He has been a member of our board of
directors since July, 1992. Mr. Feuerberg has also served as treasurer of RHS
since July, 1998 and President and Chief Executive Officer of Northern Virginia
Electric Cooperative since January, 1992.

Hunter R. Greenlaw, Jr. Mr. Greenlaw has been a member of our board of
directors since November, 1991. Mr. Greenlaw has also served as the President
of Greenlaw Properties, Ltd., a real estate development and general contracting
company, since August, 1974.

Bruce A. Henry. Mr. Henry has been a member of our board of directors since
November, 1993. Mr. Henry has also served as the owner and Secretary/Treasurer
of Delmarva Builders, Inc. since January, 1981.

Frederick L. Hubbard. Mr. Hubbard has been a member of our board of
directors since November, 1991. In addition, he has served as President and
Chief Executive Officer of Choptank Electric Cooperative since June, 2001, and
prior to that was Senior Executive Vice President of Choptank from May, 1991
until June, 2001. He has been a director of Peoples Bank of Maryland since
June, 1996.

David J. Jones. Mr. Jones has been a member of our board of directors since
July, 1986. In addition, he has served as Vice President of Exchange Warehouse,
Inc. since April, 1996. Mr. Jones has also served as the owner and operator of
Big Fork Farms since April, 1970.

William M. Leech, Jr. Mr. Leech has been a member of our board of directors
since August, 1977. He has been retired since December, 1988.

M. Larry Longshore. Mr. Longshore has been a member of our board of
directors since October, 1998. In addition, he has served as President and
Chief Executive Officer of Southside Electric Cooperative since October, 1998
and President and Chief Executive Officer of Newberry Electric Cooperative from
April, 1973 until September, 1998.

James M. Reynolds. Mr. Reynolds was Chairman of our board of directors from
July, 1992 until July, 1995 and has served as a member of our board of
directors since May, 1977. He has also served as General Manager of Community
Electric Cooperative since April, 1977.

Charles R. Rice, Jr. Mr. Rice has served as a member of our board of
directors since August, 1986, Vice Chairman of our board of directors from
July, 1995 until July, 1999 and our President and Chief Executive Officer from
April, 1998 through November, 1998. He has also served as President and Chief
Executive Officer of Northern Neck Electric Cooperative since August, 1986.

Cecil E. Viverette, Jr. Mr. Viverette served as the Chairman of our board of
directors from September, 1998 to July, 2001, Secretary/Treasurer of our board
of directors from July, 1997 until September, 1998 and a member of our board of
directors since March, 1988. He has also served as President of DPC since
September, 1998. Mr. Viverette has also served as President of RHI from July,
1990 until July, 1998 and President of Rappahannock Electric Cooperative since
March, 1988.

Richard L. Weaver. Mr. Weaver has served as a member of our board of
directors since 1998. He has also served as Manager of BARC Electric
Cooperative since 1998 and Vice President of Virginia Operations for Stackhouse
from November, 1995 until November, 1997.

Carl R. Widdowson. Mr. Widdowson has served as a member of our board of
directors since February, 1987. Mr. Widdowson has also been a farmer since
December, 1956.

Douglas Wine. Mr. Wine has served as a member of our board of directors
since April, 1991. He has also served as Vice President of RHI since July,
1998, President and Chief Executive Officer of Shenandoah Valley Electric
Cooperative since July, 1995, Secretary of RHI from April, 1991 until July,
1998, and Manager of North River Telephone Cooperative since January, 1994.

Executive Compensation

The following table sets forth all remuneration paid by us to each of our
executive officers during the last three years. The table also identifies the
principal position of the named executives at the end of the 2000 fiscal year.

Annual Compensation
----------------------------------
Other Annual All Other(1)
Name and Principal Position Year Salary Bonus Compensation Compensation
--------------------------- ---- -------- ------- ------------ ------------

Jackson E. Reasor....................... 2000 $240,000 $ -- $2,530 $27,694
President and Chief Executive Officer 1999 204,102 25,000 4,158 2,888
1998 20,513 -- 497 --

Daniel M. Walker........................ 2000 161,245 -- -- 22,064
Senior Vice President--Accounting & 1999 155,043 8,000 -- 26,928
Finance 1998 148,984 7,500 -- 25,578

Konstantinos N. Kappatos................ 2000 161,245 -- -- 22,064
Senior Vice President--Engineering & 1999 155,043 8,000 -- 32,035
Operations 1998 148,984 7,500 -- 30,066

Gregory W. White........................ 2000 128,333 -- -- 16,464
Senior Vice President--Retail & Alliance 1999 66,714 -- -- 6,082
Management

(1)The amounts in this column for the year 2000 reflect our aggregate
contributions under the Retirement and Security Plan, the 401(k) Plan, and
payments made by us for life insurance coverage of: $22,950, $3,400 and
$1,344 for Mr. Reasor; $17,791, $3,225, and $1,048 for Mr. Walker; $17,791,
$3,225, and $1,048, respectively, for Mr. Kappatos; and $13,124, $2,567, and
$773, respectively, for Mr. White.

On November 23, 1998, we entered into an employment agreement with Jackson
E. Reasor. Mr. Reasor's employment agreement provides for an initial annual
base salary of $200,000 and eligibility to receive a bonus as determined by our
executive committee and approval by the board of directors. The agreement is
effective for three years from its date and will be automatically extended for
an additional year unless we or Mr. Reasor provide to each other notice not to
extend the agreement within 30 days prior to the third anniversary thereof.
Pursuant to the agreement, if Mr. Reasor voluntarily terminates his employment
without a specified "good reason" or is terminated for specified causes prior
to the expiration of the employment agreement, we will pay him base
compensation and benefits through the effective date of his termination and we
will have no obligation to pay Mr. Reasor his base salary, any bonus or other
compensation for the remainder of the term of the employment agreement. If Mr.
Reasor is terminated without cause or resigns for good reason prior to the
expiration of the initial term of the employment agreement, we must pay him his
full base salary for a twelve month period from the effective date of
termination, at the rate effective on the date of termination, and medical
benefits, subject to some exceptions.

Our executive committee consists of Vernon N. Brinkley, M Dale Bradshaw,
Hunter E. Greenlaw and Bruce A. Henry. Currently, one vacancy exists on the
committee. The executive committee meets at the beginning of each fiscal year
to establish performance based measures that determine the bonus compensation
of the President and Chief Executive Officer. The performance based measures
consist of criteria established yearly based on a variety of factors including
our business objectives, our historical and projected fiscal performance and
the prevailing market conditions in our industry. At the end of the fiscal year
the Executive Committee measures the performance of the President and Chief
Executive Officer against the criteria it established at the beginning of that
fiscal year and accordingly determines his or her aggregate compensation. Our
other executive officers are compensated pursuant to an annual review of their
performance and total compensation, subject to budgeting restrictions, by the
President and Chief Executive Officer.

Board Compensation

We pay our directors who are not employees of a member a monthly retainer
fee of $1,350 per month plus $300 per day for any specially called meetings and
$150 per travel day for other than a regular scheduled monthly board meeting.
All directors are reimbursed for their out-of-pocket expenses incurred in
attending meetings.

Compensation Pursuant to Plans

Defined Benefit Plan

We have elected to participate in the National Rural Electric Cooperative
Association ("NRECA") Retirement and Security Program (the "Plan"), a
noncontributory, defined benefit, multiple employer, master pension plan
maintained and administered by the NRECA for the benefit of its members and
their employees. The Plan is a qualified pension plan under Section 401(a) of
the Internal Revenue Code.

The following table lists the estimated current annual pension benefit
payable at 62 (the "normal retirement age") for participants in the specified
final average salary and years of benefit service categories for the given
current multiplier of 1.7%. Benefits which accrue under the Plan are based on
the base annual salary as of November of the previous year. As a result of
changes in Internal Revenue Service regulations, the base annual salary used in
determining benefits is limited to $170,000 effective January 1, 2000.

Straight Life Years of Benefit Service
-------------------------------------------
Final Average Salary 15 20 25 30 35
-------------------- ------- ------- ------- -------- --------

$ 75,000...... $22,759 $30,345 $37,931 $ 45,518 $ 53,104
100,000...... 30,345 40,460 50,575 60,690 70,805
125,000...... 37,931 50,575 63,219 75,863 88,506
150,000...... 45,518 60,690 75,863 91,035 106,208
160,000...... 48,552 64,736 80,920 97,104 113,288
170,000...... 51,587 68,782 85,978 103,173 120,369

50% Joint & Spouse Years of Benefit Service
-------------------------------------------
Final Average Salary 15 20 25 30 35
-------------------- ------- ------- ------- -------- --------

$ 75,000...... $19,125 $25,500 $31,875 $38,250 $ 44,625
100,000...... 25,500 34,000 42,500 51,000 59,500
125,000...... 31,875 42,500 53,125 63,750 74,375
150,000...... 38,250 51,000 63,750 76,500 89,250
160,000...... 40,800 54,400 68,000 81,600 95,200
170,000...... 43,350 57,800 72,250 86,700 101,150

These pension benefits are the estimated amounts payable by the Plan, and
they are not subject to any deduction for Social Security or other offset
amounts. The employee's annual pension at his or her normal retirement date is
equal to the product of his or her years of benefit service times final average
salary times the multiplier in effect during years of benefit service. The
multiplier was 1.7% commencing January 1, 1992.

As of December 31, 2000, years of credited service under the Plan at "normal
retirement age" for Mr. Reasor was 1.08 years, for Mr. Walker was 15.92 years,
for Mr. Kappatos was 15.92 years and for Mr. White was 22.22 years.

Salary Continuation Plan

In addition to the Plan, two of our executives, Mr. Walker and Mr. Kappatos,
also participate in salary continuation plans. Pursuant to these plans, we
entered into agreements with Mr. Walker and Mr. Kappatos to provide them with
additional compensation after they reached the age of 65. The agreement states
that if the executive is 50 years or older on the date his employment is
terminated for any reason whatsoever, absent malfeasance in the office, we will
pay compensation for 15 years after the executive has reached age 65. The
amount of money payable to the executive is based on a formula that considers
the executive's age at termination of employment and years of service with us.
The maximum annual compensation payable under the plan is $35,000 per year,
payable if the executive's employment is terminated at age 65 or older. Each
agreement provides for payment of similar benefits to the executive's
beneficiaries in the event of his death or permanent disability.

Executive Severance Agreement

We have entered into executive severance agreements with Mr. Walker and Mr.
Kappatos. Under the agreements, each executive is entitled to receive
compensation in the amount of 1.5 times his base salary payable in 18 equal
monthly installments if his employment is terminated other than due to death,
disability or for cause. If a change of control occurs and the executive's
employment is terminated by the executive for good reason or by us other than
on account of the executive's death, disability or for cause, then the
executive will be entitled to receive compensation in the amount of his base
salary through his date of termination plus any benefits or awards earned but
not yet paid and a lump sum payment equal to 2.99 times the executive's base
salary.

BOND INSURANCE

The information set forth in this section has been provided by Ambac
Assurance Corporation ("Ambac"). We do not make any representation as to the
accuracy or completeness of the information.

The Insurance Policy

We will enter into an insurance agreement with Ambac, pursuant to which
Ambac will issue a financial guaranty insurance policy relating to the 2001
Series A Bonds, the form of which policy is attached to this prospectus as
Appendix B. The following summary of the terms of the insurance policy does not
purport to be complete and is qualified in its entirety by reference to the
insurance policy.

Ambac has made a commitment to issue the insurance policy effective as of
the date of issuance of the 2001 Series A Bonds. Under the terms of the
insurance policy, Ambac will pay to The Bank of New York in New York, New York,
or any successor thereto, as insurance trustee, that portion of the principal
of and interest on the 2001 Series A Bonds which shall become Due for Payment
but shall be unpaid by reason of Nonpayment (as such terms are defined in the
insurance policy) by us. Ambac will make such payments to The Bank of New York
on the later of the date on which such principal and interest becomes Due for
Payment or within one business day following the date on which Ambac shall have
received notice of Nonpayment from the trustee for the 2001 Series A Bonds. The
insurance policy will extend for the term of the 2001 Series A Bonds and, once
issued, cannot be canceled by Ambac.

The insurance policy will insure payment only on the stated maturity date,
in the case of principal, and on interest payment dates relating to the 2001
Series A Bonds in the case of interest. In the event of any acceleration of the
principal of the 2001 Series A Bonds, the insured payments will be made at such
times and in such amounts as would have been made had there not been an
acceleration.

In the event the trustee for the 2001 Series A Bonds has notice that any
payment of principal of or interest on a 2001 Series A Bond which has become
Due for Payment and which is made to a holder by or on our behalf has been
deemed a preferential transfer and theretofore recovered from its holder
pursuant to the United States Bankruptcy Code in accordance with a final,
nonappealable order of a court of competent jurisdiction, that holder will be
entitled to payment from Ambac to the extent of such recovery if sufficient
funds are not otherwise available from us.

The insurance policy does not insure any risk other than Nonpayment, as
defined in the insurance policy. Specifically, the insurance policy does not
cover:

. payment on acceleration of the 2001 Series A Bonds, as a result of a call
for redemption or as a result of any other advancement of maturity,

. payment of any redemption or prepayment of the 2001 Series A Bonds, and

. nonpayment of principal of or interest on the 2001 Series A Bonds caused
by the insolvency or negligence of the trustee for the 2001 Series A
Bonds.

If it becomes necessary to call upon the insurance policy, payment of
principal requires surrender of the related 2001 Series A Bonds to The Bank of
New York together with an appropriate instrument of assignment so as to permit
ownership of those 2001 Series A Bonds to be registered in the name of Ambac to
the extent of the payment under the insurance policy. Payment of interest
pursuant to the insurance policy requires proof of holder entitlement to
interest payments and an appropriate assignment of the holder's right to Ambac.

Upon payment of the insurance benefits in respect of any 2001 Series A Bonds
and to the extent Ambac makes payments of principal of or interest on the 2001
Series A Bonds, Ambac will become the owner of the related bonds or the right
to payment of principal of or interest on those bonds and will be fully
subrogated to each surrendering holder's rights to payment.

Ambac Assurance Corporation

Ambac is a Wisconsin-domiciled stock insurance corporation regulated by the
Office of the Commissioner of Insurance of the State of Wisconsin and licensed
to do business in 50 states, the District of Columbia, the Territory of Guam
and the Commonwealth of Puerto Rico, with admitted assets of approximately
$4,830,000,000 (unaudited) and statutory capital of approximately
$2,870,000,000 (unaudited) as of June 30, 2001. Statutory capital consists of
Ambac policyholders' surplus and statutory contingency reserve. Standard &
Poor's Credit Markets Services, a Division of The McGraw-Hill Companies,
Moody's Investors Service, Inc. and Fitch, Inc. have each assigned a triple-A
financial strength rating to Ambac.

Ambac has obtained a ruling from the Internal Revenue Service to the effect
that the insuring of an obligation by Ambac will not affect the treatment for
federal income tax purposes of interest on such obligation and that insurance
proceeds representing maturing interest paid by Ambac under policy provisions
substantially identical to those contained in the insurance policy shall be
treated for federal income tax purposes in the same manner as if we made such
payments on the 2001 Series A Bonds.

Ambac makes no representation regarding the 2001 Series A Bonds or the
advisability of investing in the 2001 Series A Bonds and makes no
representation regarding, nor has it participated in the preparation of, this
prospectus other than the information supplied by Ambac and presented under the
heading "BOND INSURANCE" and in the financial statements incorporated in this
prospectus by reference.

Available Information. The parent company of Ambac, Ambac Financial Group,
Inc. ("Ambac Financial"), is subject to the informational requirements of the
Securities Exchange Act and in accordance therewith files reports, proxy
statements and other information with the Securities and Exchange Commission.
Such reports, proxy statements and other information may be inspected and
copied at the public reference facilities maintained by the Securities and
Exchange Commission at 450 Fifth Street, N.W., Washington, D.C. 20549 and at
regional Securities and Exchange Commission offices at 7 World Trade Center,
New York, New York 10048 and Northwestern Atrium Center, 500 West Madison
Street, Suite 1400, Chicago, Illinois 60661. Copies of such material can be
obtained from the public reference section of the Securities and Exchange
Commission at 450 Fifth Street, N.W., Washington, D.C. 20549 at prescribed
rates. In addition, the aforementioned material may also be inspected at the
offices of The New York Stock Exchange, Inc. at 20 Broad Street, New York, New
York 10005. Ambac Financial's common stock is listed on The New York Stock
Exchange.

Copies of Ambac's financial statements prepared in accordance with
accounting practices prescribed or permitted by the Insurance Department of the
State of Wisconsin are available from Ambac. The address of Ambac's
administrative offices and its telephone number are One State Street Plaza,
15th Floor, New York, New York 10004 and (212) 668-0340.

Incorporation of Certain Documents by Reference. The following documents
filed by Ambac Financial with the Securities and Exchange Commission (File No.
001-10777) are incorporated by reference in this prospectus:

. Ambac Financial's Current Report on Form 8-K dated January 24, 2001 and
filed on January 24, 2001;

. Ambac Financial's Current Report on Form 8-K dated March 19, 2001 and
filed on March 19, 2001;

. Ambac Financial's Annual Report on Form 10-K for the fiscal year ended
December 31, 2000 and filed on March 28, 2001;

. Ambac Financial's Quarterly Report on Form 10-Q for the fiscal quarterly
period ended March 31, 2001 and filed on May 15, 2001;

. Ambac Financial's Current Report on Form 8-K dated July 18, 2001 and filed
on July 23, 2001; and

. Ambac Financial's Quarterly Report on Form 10-Q for the fiscal quarterly
period ended June 30, 2001 and filed on August 10, 2001.

All documents subsequently filed by Ambac Financial pursuant to the
requirements of the Securities Exchange Act after the date of this prospectus
will be available for inspection in the same manner as described in
"--Available Information" above.

DESCRIPTION OF THE BONDS

We will issue the 2001 Series A Bonds under the Indenture of Mortgage and
Deed of Trust, dated May 1, 1992, as amended, with Crestar Bank, as trustee
(the "Existing Indenture"). SunTrust Bank, as successor to Crestar Bank,
currently acts as trustee under the Existing Indenture. We have entered into a
supplemental indenture to the Existing Indenture which, when some provisions of
it become effective, will amend several provisions of the Existing Indenture.
These provisions of the supplemental indenture will become effective when a
majority of the holders of obligations outstanding under the Existing Indenture
consent to the amendments (the "Amendment Date"). The underwriters of the 2001
Series A Bonds and Ambac, as the issuer of the bond insurance with respect to
the bonds, and consequently the holder for purposes of granting consent to the
amendments contained in the supplemental indenture, have agreed to consent to
those amendments immediately following purchase by the underwriters of the 2001
Series A Bonds. Upon the issuance of the 2001 Series A Bonds and the delivery
of this consent by the underwriters and Ambac, there will be $691 million in
aggregate principal amount of obligations outstanding under the Existing
Indenture and we will have received consents constituting approximately 31% in
aggregate principal amount of the outstanding obligations. In this prospectus,
the Existing Indenture as amended by the amendments in the supplemental
indenture on the Amendment Date is referred to as the "Amended Indenture."

We also have entered into an Amended and Restated Indenture which, when it
becomes effective, will amend and restate the Existing Indenture or the Amended
Indenture, as the case may be (the "Restated Indenture"). The Restated
Indenture will become effective when all obligations under the Existing
Indenture issued prior to the 2001 Series A Bonds cease to be outstanding or
when the holders of those obligations consent to the release of the lien of the
Existing Indenture or the Amended Indenture, as the case may be, and the
effectiveness of the Restated Indenture (the "Release Date"). The Release Date
may occur before the Amendment Date and, in that case, the Amended Indenture
will not become effective because the Restated Indenture includes all of the
amendments incorporated into the Amended Indenture.

When we refer to the "Indenture" in this prospectus, we mean the Existing
Indenture, the Amended Indenture or the Restated Indenture, whichever is in
effect. Obligations of all series which have been or may be issued under the
Indenture, including the 2001 Series A Bonds, may be referred to as
"Obligations."

The following summaries of some of the provisions of the Indenture do not
purport to be complete and are subject to, and are qualified in their entirety
by reference to, all of the provisions of the Indenture, including the
definitions of terms. Wherever particular sections of the Indenture or terms
are referred to (whether capitalized or not), those sections and the
definitions of those terms contained in the Indenture are incorporated by
reference. The Existing Indenture and the supplemental indenture containing (1)
the amendments set forth in the Amended Indenture and (2) the Restated
Indenture, are included as an exhibit to the registration statement of which
this prospectus is a part. A copy of the Existing Indenture, the supplemental
indenture or the Restated Indenture also may be obtained from the trustee or
from us.

General

We will issue the 2001 Series A Bonds in an aggregate principal amount of
$215 million. Until the Release Date, the 2001 Series A Bonds will be secured
by a first lien on substantially all of our tangible and some of our intangible
properties equally and ratably with all other Obligations issued under the
Existing Indenture or the Amended Indenture. On the Release Date, the 2001
Series A Bonds will become unsecured general obligations, ranking equally and
ratably with all of our other unsecured and unsubordinated obligations, subject
to some exceptions described below. See "Release and Substitution of Property
Prior to Release Date; Negative Pledge After Release Date."

The 2001 Series A Bonds will bear interest at the annual rate of 6.25% (on
the basis of a 360-day year) from their date of issuance or from the most
recent interest payment date to which interest has been paid or provided

for, payable semi-annually on June 1 and December 1 of each year, commencing
December 1, 2001 to the person in whose name the 2001 Series A Bonds are
registered at the close of business on the regular record date, which is the
fifteenth day (whether or not a business day) of the calendar month next
preceding the interest payment date. If interest on the 2001 Series A Bonds is
not punctually paid or duly provided for, we may pay such amount instead to
each registered holder of the 2001 Series A Bonds on a special record date not
more than 15 nor less than 10 days prior to the date of the proposed payment.
We will pay principal of, and premium (if any) and interest on the 2001 Series
A Bonds, and the transfer of interests in the 2001 Series A Bonds will be
effected, through the facilities of The Depository Trust Company ("DTC"). See
"Book-Entry System; Exchangeability." The 2001 Series A Bonds will be issued in
multiples of $1,000.

Under the Existing Indenture, we use accounting requirements in effect on
the date of determination or computation. Under the Amended Indenture or the
Restated Indenture, for purposes of determinations or computations relating to
the Obligations, we will use accounting requirements as are in use in the
United States at the time of the determination of any computation required or
permitted under the Amended Indenture or the Restated Indenture, or, at our
option, those requirements or determinations in use on the date of the Amended
Indenture or the Restated Indenture.

Make Whole Redemption

We may redeem the 2001 Series A Bonds, in whole or in part, prior to their
stated maturity, at our option. We must give at least 30 days, but not more
than 60 days, prior notice of redemption mailed to the registered address of
each holder of bonds being redeemed except as otherwise required by the
procedures of DTC. The redemption price for the 2001 Series A Bonds will be
equal to the greater of:

. 100% of the principal amount of the bonds being redeemed plus accrued
interest to the redemption date; and

. the sum of the present values of the remaining principal and interest
payments on the bonds being redeemed, discounted on a semiannual basis
(assuming a 360-day year consisting of twelve 30-day months) at a rate
equal to the sum of (1) the yield to maturity on the U.S. Treasury
security having a life equal to the remaining life of the 2001 Series A
Bonds and trading in the secondary market at the price closest to par and
(2) twenty basis points;

plus, in either case, without duplication, interest due and payable but unpaid
on the bonds being redeemed.

If there is no U.S. Treasury security having a life equal to the life of the
2001 Series A Bonds being redeemed, the discount rate will be calculated using
a yield to maturity determined on a straight-line basis (rounding to the
nearest calendar month, if necessary) from the average yield to maturity of two
U.S. Treasury securities having lives most closely corresponding to the
remaining life of the 2001 Series A Bonds and trading in the secondary market
at the price closest to par.

If less than all of the outstanding 2001 Series A are redeemed, the 2001
Series A Bonds will be redeemed by the trustee on a pro rata basis in
accordance with the Indenture. We may not otherwise optionally or mandatorily
redeem the 2001 Series A Bonds.

Rate Covenant

Until the first to occur of the Amendment Date or the Release Date, subject
to any necessary approval or determination of any regulatory or judicial
authority with jurisdiction over our rates (which include rents, charges, fees
and other compensation), the Existing Indenture requires us to establish and
collect rates for the use or the sale of the output, capacity or service of our
electric generation, transmission and distribution system which are reasonably
expected to yield margins for interest for the 12-month period commencing with
the effective date of the rates equal to at least 1.20 times total interest
charges during that 12-month period. The Existing Indenture requires the rates
to produce moneys sufficient to enable us to comply with all covenants under
the Existing Indenture.

Margins for interest under the Existing Indenture equal the total of net
margins plus total interest charges and income tax accruals for the applicable
period less:

. the net earnings or losses of property with a fair value in excess of
$25,000 released from the lien of the Existing Indenture during that
period or thereafter.

If we acquire any property during the period for which margins for interest
is being calculated, or we will acquire with the proceeds of the Obligations
being issued any property which was, during the 6-month period prior to our
acquisition, if any, used in a business similar to ours, then, the computation
of margins for interest will include the net operating earnings or net
operating losses of that property for the entire 12-month period. The
calculation of margins for interest also will be adjusted if an independent
engineer of favorable national repute determines that efficiencies,
inefficiencies or other effects likely to result from the acquisition are
significant enough to render the historical performance of the separate
properties an inaccurate indicator of the future performance of the combined
properties. This additional adjustment will take into account the efficiencies,
inefficiencies or other effects to the extent determined by the independent
engineer. Under the Existing Indenture, in calculating margins for interest, we
factor in any item of net margin, loss, income, gain, earnings or profits of
any of our subsidiaries, regardless if we have received those net margins or
gains as a dividend or other distribution from the subsidiary or if we have
made payment with respect to the losses or expenses.

Interest charges under the Existing Indenture equal our total interest
charges (whether capitalized or expensed) on (1) all Obligations under the
Existing Indenture, (2) indebtedness secured by a lien equal or prior to the
lien of the Existing Indenture, and (3) obligations secured by liens created or
assumed in connection with a tax-exempt financing for the acquisition or
construction of property used by us, in each case including amortization of
debt discount and expense or premium.

Promptly upon any material change in the circumstances which were
contemplated at the time such rates were most recently reviewed, but not less
than once every 12 months, we will review the rates and, subject to any
necessary regulatory approval, promptly establish or revise the rates as
necessary to obtain the required margins for interest and produce moneys
sufficient to enable us to comply with our other covenants under the Indenture.
Our failure to actually achieve a 1.20 margins for interest ratio will not
itself constitute an event of default under the Existing Indenture. A failure
to establish rates reasonably expected to achieve a 1.20 margins for interest
ratio, will be an event of default if such failure continues for 45 days after
we receive notice of this failure from either the trustee or the holders of 10%
of the Obligations outstanding, unless such failure results from our inability
to obtain regulatory approval.

The Existing Indenture prohibits us from furnishing or supplying any use,
output, capacity or service of our system with respect to which a charge is
regularly or customarily made, free of charge to any person or entity. In
addition, we must use commercially reasonable efforts prior to the earlier of
the Amendment Date or the Release Date to enforce the payment of all moneys
that are owed to us.

After the earlier of the Amendment Date or the Release Date, the Amended
Indenture or the Restated Indenture will require us, subject to any necessary
approval or determination of any regulatory or judicial authority with
jurisdiction, to establish and collect rates reasonably expected to yield
margins for interest for each fiscal year equal to 1.10 times total interest
charges for the fiscal year. The Amended Indenture and the Restated Indenture
require these amounts, together with other moneys available to us, provide
moneys sufficient for us to remain in compliance with the Amended Indenture or
the Restated Indenture. Interest charges under the Amended Indenture are
calculated in the same manner as under the Existing Indenture with the
exclusion of capitalized interest. Interest charges under the Restated
Indenture equal interest charges (other than capitalized interest) on all
Obligations under the Indenture and all of our other obligations (other than
subordinated indebtedness) to repay borrowed money or the deferred purchase
price of property or services, including

amortization of debt discount and premium on issuance, but excluding the
interest charges on indebtedness attributed to any capitalized lease or similar
agreement. After the earlier of the Amendment Date or the Release Date, margins
for interest will equal the sum of:

. our net margins;

. plus revenues that are subject to refund at a later date which were
deducted in the determination of net margins;

. plus non-recurring charges that may have been deducted in determining
net-margins;

. plus total interest charges (calculated as described above); and

. plus income tax accruals imposed on income after deduction of total
interest for the applicable period.

In calculating margins for interest under the Amended Indenture and the
Restated Indenture, we factor in any item of net margin, loss, income, gain,
earnings or profits of any of our affiliates or subsidiaries, only if we have
received those amounts as a dividend or other distribution from the affiliate
or subsidiary or if we have made a contribution to, or payment under a
guarantee or like agreement for an obligation of, the affiliate or subsidiary.
Any amounts that we are required to refund in subsequent years do not reduce
margins for interest as calculated under the Amended Indenture or the Restated
Indenture for the year the refund is paid. As under the Existing Indenture, the
failure to achieve the margins for interest ratio will not itself result in an
event of default. We must, however, review our rates at least annually and
promptly revise them to comply with the margins for interest covenant subject
to any necessary regulatory approvals. A failure to establish rates reasonably
expected to achieve a 1.10 margins for interest ratio will be an event of
default under the Amended Indenture and the Restated Indenture if that failure
continues for 45 days after we receive notice of this failure from either the
trustee or the holders of 10% of the Obligations outstanding, unless this
failure results from our inability to obtain regulatory approval to revise our
rates.

Security for Payment of the Obligations Prior to Release Date; Conversion to
Unsecured Obligations on Release Date

Until the Release Date, the 2001 Series A Bonds will be secured equally and
ratably with all other Obligations issued (whether previously or subsequent to
the issuance of the 2001 Series A Bonds) under the Existing Indenture or the
Amended Indenture by a first lien on substantially all of our tangible and some
of our intangible properties, including our generation, transmission and
distribution properties and some of our contracts relating to the purchase,
sale or transmission of electricity of three years or more in duration or to
the ownership, operation or maintenance of electric generation, transmission or
distribution facilities, excluding excepted property. Excepted property as
defined in the Existing Indenture or the Amended Indenture includes among other
things:

. cash on hand or in banks (other than moneys deposited with the trustee
under the terms of the Existing Indenture or the Amended Indenture);

. contracts and contract rights not specifically subject to the lien of the
Existing Indenture or the Amended Indenture;

. instruments and specified securities (other than those required to be
deposited with the trustee);

. patents and trademarks;

. the right to bring an action or enforce a judgment;

. transportation equipment (including vehicles, vessels and barges);

. office furniture, equipment and supplies and data processing, accounting
and other computer equipment, software and supplies and leases for office
purposes;

. other leases for an original term of less than five years, specified
nonassignable permits and licenses;

. timber, oil, gas, coal, ore and other minerals and all electric energy
generated; and

. our interest in other property in which a security interest cannot legally
be perfected.

Our title to the mortgaged property and the lien of the Existing Indenture
or the Amended Indenture are subject to permitted encumbrances, which may
include, among other things identified restrictions, exceptions, reservations,
conditions and limitations existing on the mortgaged property on the date the
Existing Indenture was recorded; reservations in U.S. patents; non-delinquent
or contested tax, mechanics', materialmen's or contractors' liens; local
improvement district assessments; leases for a term of not more than two years;
specified easements; the undivided interests of other owners or liens on those
undivided interests, and the rights of those owners in property they own with
us; the pledge of current assets (other than accounts receivable) to secure
current liabilities; specified liens related to the issuance of tax exempt debt
securities for the acquisition or construction of property; the pledge or
assignment of accounts receivable or conditional sales contracts in connection
with the sale of power so long as on the date of such sale no event of default
under the Existing Indenture or the Amended Indenture then exists; and some
leases and reservations and liens for non-delinquent rent or wages.

The lien of the Existing Indenture or the Amended Indenture also is subject
to a lien in favor of the trustee to recover amounts owing to the trustee under
the Existing Indenture or the Amended Indenture. In addition, our title to the
mortgaged property and the lien of the Existing Indenture or the Amended
Indenture are subject to other prior rights and encumbrances which we do not
believe adversely affect in any material respect our right to use that property
to secure the 2001 Series A Bonds.

All of our after-acquired property, other than excepted property, is subject
to a lien under the Existing Indenture or the Amended Indenture subject further
to:

. specified purchase money and pre-existing liens;

. limitations, in the case of consolidation, merger or sale of substantially
all of our assets; and

. recordation of supplements to the Existing Indenture or the Amended
Indenture describing that after-acquired property, in the case of real
property.

From and after the Release Date, the 2001 Series A Bonds, all other
Obligations then still outstanding and any other Obligations thereafter issued
under the Indenture will be unsecured general obligations and will rank equally
and ratably with all of our other unsecured and unsubordinated obligations
subject to some exceptions. On the Release Date, any lien or security interest
arising under the Existing Indenture or the Amended Indenture will be released
and the trustee is required to take any actions reasonably necessary to confirm
or give notice of the release and to evidence the reconveyance, re-assignment
and transfer to us of all right, title and interest of the trustee in the
collateral.

Rights of Insurer

Under the Indenture, any person that unconditionally agrees to provide any
undertaking to pay any Obligations to the extent not paid by us, for example an
insurer of our Obligations, will be considered a holder of those Obligations
for purposes of giving any approval or consent with respect to:

. approving supplemental indentures or other amendments to the Indenture;

. giving any other approval, consent or notice to effect any waiver;

. exercising any remedies; and

. taking any other action that can be taken by the holders of those
Obligations.

If that person is in default of performing their undertaking they will not
be considered a holder in place of the holders of those Obligations.

Ambac will issue an insurance policy insuring the scheduled payment of the
principal and interest on the 2001 Series A Bonds when due and, as a result, be
considered the holder of the 2001 Series A Bonds for the above purposes. See
"BOND INSURANCE."

Release and Substitution of Property Prior to Release Date; Negative Pledge
After Release Date

Until the Release Date, provided no event of default exists under the
Existing Indenture or the Amended Indenture, property subject to the lien of
the Existing Indenture or the Amended Indenture may be released to facilitate
the day-to-day operation of our business. Some of these releases may require
either:

. a finding by our management that these releases are desirable in the
conduct of our business or will not adversely affect in any material
respect the security afforded by the Existing Indenture or the Amended
Indenture; or

. the substitution of bondable additions, the retirement or defeasance of
Obligations or the deposit of cash with the trustee, in each case of
equivalent value.

In addition, cash deposited with the trustee as a result of the
authentication and delivery of Obligations may be withdrawn against 90.91% of
bondable additions or retired or defeased Obligations of equivalent value. Cash
deposited with the trustee for other purposes, including releases, may be
withdrawn against bondable additions or retired or defeased Obligations of
equivalent value and may, at our option, be used for the redemption of
Obligations prior to their maturity, at their maturity or for the purchase of
Obligations. To the extent that any trust moneys deposited with the trustee
consist of the proceeds of insurance upon any part of the mortgaged property,
those moneys may be withdrawn to reimburse us for costs to repair, rebuild or
replace the destroyed or damaged property.

The lien of the Existing Indenture or the Amended Indenture will be released
on the Release Date when the Existing Indenture or the Amended Indenture is
superseded by the Restated Indenture. Unless we equally and ratably secure all
other then-outstanding Obligations, the Restated Indenture will prohibit us
from creating or permitting to exist any mortgage, lien, pledge, charge,
security interest or other encumbrance (a "security interest") of any kind on
specified properties for the purpose of securing repayment of borrowed money or
any obligation to pay the deferred purchase price for property or services,
except for (1) security interests not exceeding the greater of two percent of
our total assets and $10,000,000; and (2) security interests arising by
operation of law or those in connection with the lease transactions or
commodities trading agreements described below. These specified properties on
which a security interest cannot be granted without equally and ratably
securing the Obligations consist primarily of our real property, fixtures and
tangible personal property that we use in whole or major part in connection
with our generating facilities, including all electric production,
transmission, or distribution facilities, equipment or property and any plant,
structure or other facility for the development production or storage of fuel
or rights with respect to the supply of water. The specified properties do not
include:

. cash on hand or in banks (other than moneys deposited with the trustee
under the Restated Indenture);

. the right to bring an action or enforce a judgment;

. contracts and contract rights;

. shares of stock, bonds, notes, repurchase agreements and evidences of
indebtedness and other securities;

. patents, trademarks, trade names and other general intangibles;

. transportation vehicles and equipment (to the extent a security interest
cannot be perfected under the Uniform Commercial Code in the Commonwealth
of Virginia);

. all nuclear fuel and all related accessories and supplies used for that
fuel;

. marine equipment and airplanes and all equipment relating thereto;

. office furniture, equipment and supplies and data processing, accounting
and other computer equipment, software and supplies and leases for office
purposes;

. leasehold interests for office purposes;

. other leases for an original term of less than five years; and

. timber, oil, gas, coal, ore and other minerals and all electric energy
generated.

Under the Restated Indenture, the encumbrances resulting from our existing
lease transactions or agreements relating to a future sale and leaseback or
lease and leaseback transaction or similar transactions or a commodities
trading agreement entered into in the ordinary course of business do not
constitute security interests requiring the Obligations to be equally and
ratably secured with respect to the assets subject to the transactions. See
"POWER SUPPLY RESOURCES--Clover."

Depreciation Deposits

Until the first to occur of the Amendment Date or the Release Date, the
Existing Indenture requires us, on or before July 1 in each year, since July 1,
1993, to deposit (a "Depreciation Deposit") with the trustee cash in an amount
equal to the excess, if any, obtained by subtracting (to the extent not
previously subtracted) the aggregate amount of property that we have acquired
since April 30, 1992 that is subject to the lien of the Existing Indenture to
the date of such Depreciation Deposit, from our depreciation expense on all
property subject to the lien of the Existing Indenture for the immediately
preceding calendar year. Depreciation Deposits and other amounts deposited with
the trustee may be withdrawn on the basis of bondable additions of property or
retirement or defeasance of Obligations. To date, we have not been required to
make, and have not made, any Depreciation Deposits. The Amended Indenture and
the Restated Indenture will not require us to make any Depreciation Deposits
after the Amendment Date or the Release Date.

Limitations on Issuance of Short-Term Debt

Until the first to occur of the Amendment Date or the Release Date, the
Existing Indenture prohibits us from incurring or permitting to be outstanding
any indebtedness (other than trade payables) with an original maturity of less
than one year or which is redeemable at the option of the holder within one
year from the date of original issuance, if, after giving effect thereto, the
outstanding principal amount of that indebtedness would exceed the greater of
$100 million or 15% of our long-term debt and equities determined on a
consolidated basis as of the end of the immediately preceding fiscal quarter.
Fifteen percent of our long-term debt and equities as of June 30, 2001 was
approximately $100 million. The Amended Indenture and the Restated Indenture do
not restrict our ability to issue short-term indebtedness.

Limitation on Cash Investments

Until the first to occur of the Amendment Date or the Release Date, the
Existing Indenture prohibits us from investing or directing the trustee to
invest more than 25% of the aggregate of (1) cash on hand held for working
capital purposes, (2) moneys received by the trustee following a release of
property from the lien under the Existing Indenture, (3) proceeds from a taking
or insurance, or disposition of a portion of the trust estate or as a
depreciation deposit, and (4) cash deposited with the trustee as a basis for
additional Obligations, other than in:

. obligations issued by or unconditionally guaranteed by the United States
of America or certificates or other evidences of interests in those
obligations;

. securities issued by any agency or instrumentality of the United States of
America or any corporation created pursuant to any act of Congress;

. commercial paper rated in either of the two highest rating categories by a
national credit rating agency;

. demand or time deposits, certificates of deposit and bankers' acceptances
issued or accepted by any bank or trust company having capital surplus and
undivided profits aggregating at least $50 million and whose long-term
debt is rated in any of the three highest rating categories by a national
credit rating agency;

. repurchase agreements that are secured by a perfected security interest in
securities listed in the first two bullets above entered into with a
government bond dealer recognized as a primary dealer by the Federal
Reserve Bank of New York or any bank described in the fourth bullet above;

. non-convertible debt securities rated in any of the three highest
categories by a national credit rating agency; or

. any short-term institutional investment fund or account which invests
solely in any of the foregoing obligations.

These restrictions on our cash investments will end on the earlier to occur of
the Amendment Date or the Release Date.

Book-Entry System; Exchangeability

The 2001 Series A Bonds will be represented by one or more global bonds that
we will deposit with DTC or its agent. The 2001 Series A Bonds will be
registered in the name of DTC's nominee, Cede & Co. The deposit of the 2001
Series A Bonds with DTC and their registration in the name of Cede & Co. will
effect no change in beneficial ownership. Upon the issuance of each global
bond, DTC will credit the accounts of persons held with it with the respective
principal amounts of the 2001 Series A Bonds represented by such global bond
designated by the underwriters with respect to the 2001 Series A Bonds.

The 2001 Series A Bonds will settle in DTC's Same-Day Funds Settlement
System and trade in that system in book-entry form until maturity. Therefore,
secondary market trading activity for the 2001 Series A Bonds will settle in
immediately available funds. We will pay principal and interest to DTC in
immediately available funds. There can be no assurance as to the effect, if
any, that settlement in immediately available funds will have on trading
activity in the 2001 Series A Bonds.

DTC has advised as follows: It is a limited-purpose trust company organized
under the New York Banking Law, a "banking organization" within the meaning of
the New York Banking Law, a member of the Federal Reserve System, a "clearing
corporation" within the meaning of the New York Uniform Commercial Code, and a
"clearing agency" registered pursuant to the provisions of Section 17A of the
Securities Exchange Act. DTC was created to hold securities for its
participating organizations and to facilitate the clearance and settlement of
securities transactions between participants in these securities through
electronic computerized book-entry changes in accounts of its participants
thereby eliminating the need for physical movement of securities certificates.
Direct participants include securities brokers and dealers (including the
underwriters), banks and trust companies, clearing corporations and other
organizations. DTC is owned by a number of its direct participants and by the
New York Stock Company, Inc., the American Stock Exchange LLC, and the National
Association for Securities Dealers, Inc. Access to DTC's system is also
available to indirect participants such as banks, brokers, dealers and trust
companies that clear through or maintain a custodial relationship with direct
participants either directly or indirectly. Persons who are not participants
may beneficially own securities held by DTC only through participants. The
rules applicable to DTC and its direct and indirect participants are on file
with the Securities and Exchange Commission.

Under the terms of the Indenture, we and the trustee will treat the persons
in whose names the 2001 Series A Bonds are registered as the owners of the 2001
Series A Bonds for the purpose of receiving payment of principal and interest
on the 2001 Series A Bonds and for all other purposes. Except as set forth
below, owners of beneficial interests in a global bond representing 2001 Series
A Bonds will not be entitled to have 2001 Series A

Bonds represented by such global bond registered in their names, will not
receive or be entitled to receive physical delivery of 2001 Series A Bonds in
definitive form and will not be considered the owners or holders thereof under
the Indenture including, without limitation, for purposes of consenting to any
amendment thereof or supplement thereto.

DTC has no knowledge of the actual owners of beneficial interests in the
global bonds representing the 2001 Series A Bonds. DTC's records reflect only
the identity of the direct participants to whose accounts the 2001 Series A
Bonds are credited, which may or may not be the beneficial owners. Ownership of
beneficial interests in global bonds representing the 2001 Series A Bonds will
be shown on, and the transfer of that ownership will be effected only through,
records maintained by DTC's participants or persons that hold through DTC's
participants. DTC's participants will remain responsible for keeping account of
their holdings on behalf of their customers. The laws of some jurisdictions
require that some purchasers of securities take physical delivery of such
securities in definitive form. Such limits and such laws may impair the ability
to transfer beneficial interests in a global bond.

Payment of principal of (and premium, if any) and interest, if any, on 2001
Series A Bonds registered in the name of or held by DTC or its nominee will be
made to DTC or its nominee, as the case may be, as the registered owner or the
holder of the global bonds representing the 2001 Series A Bonds. We expect that
DTC or its nominee, upon receipt of any payment of principal of (and premium,
if any) or interest on global bonds, will credit participants' accounts on the
date such payment is payable in accordance with their respective beneficial
interests in the principal amount of such global bonds as shown on the records
of DTC or its nominee. We also expect that payments by participants to owners
of beneficial interests in such global bond held through such participants will
be governed by standing instructions and customary practices, as is now the
case with securities held for the accounts of customers in bearer form or
registered in "street name", and will be the responsibility of such
participants. None of us, the trustee, any paying agent or the security
registrar for the 2001 Series A Bonds will have any responsibility or liability
for any aspect of the records relating to or payments made on account of
beneficial ownership interests in a global bond for the 2001 Series A Bonds or
for maintaining, supervising or reviewing any records relating to such
beneficial ownership interests.

Unless and until it is exchanged in whole for 2001 Series A Bonds in
definitive form, a global bond representing 2001 Series A Bonds may not be
transferred except as a whole by DTC to DTC's nominee by a nominee of DTC to
DTC or another nominee of DTC or by DTC or any such nominee to a successor of
DTC or a nominee of such successor.

DTC may discontinue providing its services as depository for the global
bonds at any time. If DTC is at any time unwilling or unable to continue as
depositary for the global bonds representing the 2001 Series A Bonds and a
successor depositary is not appointed by us within 90 days, we will issue 2001
Series A Bonds in definitive registered form in exchange for the global bond or
securities representing the 2001 Series A Bonds. In addition, we may at any
time and in our sole discretion, determine not to have any 2001 Series A Bonds
in registered form represented by one or more global bonds and, in such event,
will issue 2001 Series A Bonds in definitive registered form in exchange for
the global bond or securities representing the 2001 Series A Bonds. In any such
instance, an owner of a beneficial interest in a global bond will be entitled
to physical delivery in definitive form of 2001 Series A Bonds represented by
such global bond equal in principal amount to such beneficial interest and to
have the 2001 Series A Bonds registered in the name of the owner of such
beneficial interest.

We have obtained the information in this section concerning DTC and DTC's
book-entry system from sources that we believe to be reliable. We take no
responsibility for the accuracy of such information.

Additional Obligations

The aggregate principal amount of Obligations that may be issued under the
Indenture is not limited.

Issuance of Additional Obligations Prior to the Amendment Date and the
Release Date

Until the Release Date, additional Obligations, ranking equally and ratably
with the existing Obligations, may be issued from time to time against:

. 10/11 (90.91%) of the amount of bondable additions,

. the aggregate principal amount of retired or defeased Obligations, and

. deposits of cash with the trustee.

Bondable additions equals the bondable value of all certified property
additions (as described immediately below), less the bondable value of all
property subject to the lien of the Existing Indenture that is retired after
April 30, 1992. Property additions are defined in the Existing Indenture to
include specified property chargeable to our fixed plant accounts, subject to
the lien of the Existing Indenture, acquired or constructed by us since April
30, 1992 and not subject to pre-existing liens securing indebtedness prior to
or on a parity with the lien of the Existing Indenture. For the purpose of
calculating the amount of property additions and retirements, the bondable
value of property acquired after April 30, 1992, is the lesser of the cost or
the fair value of that property (determined as of the time of acquisition); and
the bondable value of property acquired on or before April 30, 1992 is the
gross book value of that property as of April 30, 1992. The amount of bondable
additions available for the issuance of additional Obligations is approximately
$82.0 million, plus the bondable value of all property additions (calculated as
described above) after December 31, 2000, minus the bondable value of all
property subject to the lien of the Indenture that is retired or disposed of
after December 31, 2000. As a result, as of December 31, 2000, we could have
issued approximately $74.6 million of additional Obligations on the basis of
bondable additions. Immediately following the use of retirements for the
issuance of the 2001 Series A Bonds, $122.0 million of additional Obligations
may be issued under the Indenture on the basis of retirements.

Until the earlier to occur of the Amendment Date or the Release Date, we
cannot issue additional Obligations under the Existing Indenture on the basis
of bondable additions or retirement or defeasance of Obligations or the deposit
of cash with the trustee unless we also certify that:

. our margins for interest calculated as described above during a
consecutive 12-month period within the 18-month period immediately
preceding our request for additional Obligations was at least 1.20 times
total interest charges (as described above) during that 12-month period;
and

. the sum of (A) our margins for interest for that 12-month period; (B) the
maximum annual interest (making assumptions with respect to variable rate
debt) that will accrue on the additional Obligations to be issued; and (C)
the maximum annual interest (making assumptions with respect to variable
rate debt) on all Obligations and all indebtedness secured by a lien equal
or prior to the lien of the Existing Indenture issued since the first day
of that 12-month period to and including the date of issuance of such
additional Obligations, but only to the extent interest charges on such
other Obligations and indebtedness are not included within the computation
of margins for interest for that period (net of interest savings during
such 12-month period on any Obligations or indebtedness secured by a lien
equal to or prior to the lien of the Existing Indenture retired with the
proceeds of such additional Obligations) would equal at least 1.15 times
the sum of the total interest charges (calculated as described above)
during that 12-month period plus such maximum annual interest as
determined pursuant to clause (B) above, plus the maximum annual interest
determined pursuant to clause (C) above, minus interest savings during
that 12-month period on the retired Obligations or indebtedness secured by
a lien equal to or prior to the lien of the Existing Indenture.

Issuance of Additional Obligations After Amendment Date but Prior to the
Release Date

The Amended Indenture will continue to provide that the issuance of
additional Obligations, ranking equally and ratably with the existing
Obligations, may be made on the basis of bondable additions, retired or
defeased Obligations or deposits of cash with the trustee. The Amended
Indenture modifies, however, the certifications required before the issuance of
additional Obligations. After the Amendment Date and prior to the Release Date,

we must certify only that our margins for interest (calculated as described
above under the Amended Indenture and the Restated Indenture) during a
consecutive 12-month period within the 18-month period immediately preceding
our request for additional Obligations was at least 1.10 times total interest
charges (calculated as described above under the Amended Indenture and the
Restated Indenture) during that 12-month period. No certification of a
forward-looking margins for interest ratio will be required after the Amendment
Date.

Issuance of Additional Obligations After the Release Date

Beginning on the Release Date, we may issue additional Obligations under the
Restated Indenture, ranking equally and ratably with the 2001 Series A Bonds
and all other Obligations then outstanding under the Restated Indenture from
time to time as authorized by the board of directors. The additional
Obligations that we may issue may contain provisions for, among other things,
optional redemption, prepayment, amortization of principal, and covenants and
events of default that differ from the terms of the 2001 Series A Bonds.

The aggregate principal amount of additional Obligations which may be
authenticated and delivered and outstanding under the Restated Indenture is not
otherwise limited, except as provided in the provisions of any supplemental
indenture creating any series of Obligations and except as may be limited by
law. The Restated Indenture does not otherwise restrict us from issuing
additional or other indebtedness under another instrument.

Limitation on Distributions to Members

The Existing Indenture prohibits us from making any distribution, including
a dividend or payment or retirement of patronage capital, to our members if we
are in default under the Existing Indenture. Otherwise, we are permitted to
make a distribution to our members if, after the distribution (1) our aggregate
margins and equities as of the end of the most recent fiscal quarter would be
equal to or greater than 20% of our total long-term debt and equities and the
aggregate amount of all distributions after the date on which our aggregate
margins and equities first reached 20% of total long-term debt and equities
does not exceed 35% of our aggregate net margins earned after that date; or (2)
our aggregate margins and equities as of the end of the most recent fiscal
quarter would be equal to or greater than 30% of our total long-term debt and
equities. Under current accounting requirements, our equities consist of our
patronage capital and accumulated other comprehensive income. Accumulated other
comprehensive income consists of the change in the market value of our
investments. At June 30, 2001, we could have distributed $29.8 million to our
members under this formula. We have not made any distributions to our members
since that date.

After the Amendment Date or the Release Date, we may not make any
distribution, including a dividend or payment or retirement of patronage
capital, to our members if an event of default exists under the Amended
Indenture or the Restated Indenture. Otherwise we will be permitted to make a
distribution to our members if (1) after the distribution, our patronage
capital as of the end of the most recent fiscal quarter would be equal to or
greater than 20% of our total long-term debt and patronage capital, or (2) all
of our distributions for the year in which the distribution is to be made do
not exceed 5% of our patronage capital as of the end of the most recent fiscal
year. For this purpose, patronage capital and total long-term debt and
patronage capital do not include any earnings retained in any of our
subsidiaries or affiliates or the debt of any subsidiary or affiliate.

Events of Default and Remedies

Events of default under the Indenture consist of:

. failure to pay principal of or premium, if any, on any Obligation when due
(and after the Release Date, subject to any applicable grace period set
forth in the Obligation or supplemental indenture under which the
Obligation is issued);

. failure to pay any interest on any Obligation when due, continued beyond
any applicable grace period (the duration of which, unless, after the
Release Date, specified otherwise in the Obligation, is 45 days);

. any other breach by us of any of our warranties or covenants contained in
the Indenture, continued for 45 days after written notice from the trustee
or the holders of at least 10% in principal amount of the outstanding
Obligations;

. prior to the Amendment Date or the Release Date, failure to pay when due
any portion of the principal of, or acceleration of, any other
indebtedness for money borrowed in excess of $5 million if such
indebtedness is not discharged within any applicable grace period or such
acceleration is not rescinded or annulled;

. on or after the Amendment Date or the Release Date, failure to pay when
due (other than amounts due on acceleration) any portion of the principal
of any indebtedness for money borrowed (other than pursuant to the Amended
Indenture or the Restated Indenture), which failure resulted in the
indebtedness becoming due or being declared due and payable prior to the
date on which it would otherwise have become due and payable, in an
aggregate amount in excess of $10 million unless such indebtedness is
discharged or such acceleration rescinded or annulled within 10 days after
such acceleration;

. a judgment against us in excess of $5 million ($10 million after the
Amendment Date or the Release Date) which remains unsatisfied or unstayed
for 45 days after either entry of judgment or termination of a stay, and
such judgment remains unstayed or unsatisfied for a period of ten days
after notice thereof from the trustee or the holders of at least 10% in
principal amount of the outstanding Obligations; or

. other proceedings in bankruptcy, receivership, insolvency, liquidation or
reorganization.

Subject to the provisions of the Indenture relating to the duties of the
trustee if an event of default occurs and is continuing, the trustee will be
under no obligation to exercise any of its rights or powers under the Indenture
at the request or direction of any of the holders, unless those holders will
have offered to the trustee indemnity reasonably satisfactory to the trustee.
Subject to such provisions for the indemnification of the trustee, the holders
of a majority in aggregate principal amount of the outstanding Obligations will
have the right to require the trustee to proceed to enforce the Indenture and
to direct the time, method and place of conducting any proceeding for any
remedy available to the trustee or exercising any trust or power conferred on
the trustee except that, so long as not in default with respect to its credit
enhancement for any Obligations, a credit enhancer for, and not the actual
holders of, those Obligations shall be deemed to be the holder of those
Obligations for purposes of, among other things, taking action in connection
with the remedies set forth in the Indenture. Because Ambac is a credit
enhancer with respect to the 2001 Series A Bonds, Ambac and not the actual
holders of the 2001 Series A Bonds will have the right to exercise any remedies
that would otherwise be exercisable by the holders of the 2001 Series A Bonds
under the Indenture. See "Rights of Insurer."

If an event of default occurs and is continuing, either the trustee or the
holders of at least 25% in aggregate principal amount of the outstanding
Obligations may accelerate the maturity of all Obligations. However, after the
acceleration, but before sale of any of the trust estate or a judgment or
decree based on acceleration, the holders of a majority in aggregate principal
amount of outstanding Obligations may, under some circumstances, rescind the
acceleration if, among other things, all events of default, other than the
non-payment of accelerated principal, have been cured or waived as provided in
the Indenture.

No holder of any Obligation will have any right to institute any proceeding
with respect to the Indenture or for any remedy thereunder, unless (1) the
holder previously has given to the trustee written notice of a continuing event
of default, (2) the holders of at least 25% in aggregate principal amount of
the outstanding Obligations have made written request and offered reasonable
indemnity to the trustee to institute such proceeding as trustee, (3) the
trustee for 60 days after its receipt of such notice, request and indemnity has
failed to institute any such proceeding, and (4) the trustee has not received
from the holders of a majority in aggregate principal amount of the outstanding
Obligations a direction inconsistent with that request. However, the
limitations on the holders' rights to institute proceedings do not apply to a
suit instituted by a holder of an Obligation for the enforcement of payment of
the principal of and premium, if any, or interest on such Obligation on or
after the respective due date stated therein. If an event of default affects
the holders of the 2001 Series A Bonds only, any action previously

described that requires the approval of holders of Obligations can be taken by
the holders of the 2001 Series A Bonds alone in the same percentage.

The Indenture provides that the trustee, within 90 days after the occurrence
of an event of default (but at least 60 days after the occurrence of some
specified events of default), will give to the holders of Obligations notice of
all uncured defaults known to it, except that in the case of a default in the
payment of principal of, premium (if any), sinking fund payment or interest on
any Obligations, the trustee will be protected in withholding that notice if it
in good faith determines that the withholding of that notice is in the interest
of the holders of the Obligations.

The Indenture provides that if an event of default has occurred and is
continuing, the trustee will exercise its rights and powers under the
Indenture, and use the same degree of care and skill in its exercise, as a
prudent person would exercise or use under the circumstances in the conduct of
his or her own affairs.

If an event of default occurs and is continuing prior to the Release Date,
the trustee may sell the mortgaged property, in either judicial or nonjudicial
proceedings. The proceeds from disposition of the mortgaged property prior to
the Release Date will be applied as follows: (1) to the payment of all amounts
due the trustee; (2) if all Obligations have become due and payable, to the
payment of outstanding Obligations without preference or priority between
interest or principal or among Obligations; and (3) if any principal has not
become due and payable, then first to interest installments in the order of
their maturity and second to principal or redemption price. After the Release
Date, moneys collected by the trustee following an event of default will be
applied in the same manner.

Prior to the date the trustee obtains a judgment for the payment of money
due, the holders of at least a majority in principal amount of the outstanding
Obligations, by written notice to the trustee, may waive any past defaults,
except a default in payment of the principal or interest on any Obligation, or
in respect of any covenant or provision that by its terms cannot be modified or
amended without the consent of the holder of each Obligation affected. Upon any
such waiver, the default will cease to exist and any event of default arising
therefrom will be deemed cured.

The Indenture requires us to deliver to the trustee, within 120 days after
the end of each fiscal year, a written statement as to our compliance
(determined without regard to any grace period or notice requirement) with all
conditions and covenants under the Indenture. In addition, we are required to
deliver to the trustee, promptly after any of our officers may be reasonably
deemed to have knowledge of a default under the Indenture, a written notice
specifying the nature and duration of the default and the action we are taking
and propose to take with respect thereto.

Amendments and Supplemental Indentures

Without the Consent of Holders

Without the consent of the holders of any Obligations, we and the trustee
may from time to time enter into one or more supplemental indentures:

. to add to the conditions, limitations and restrictions on the authorized
amount, terms or purposes of the issue, authentication and delivery of
Obligations or of any series of Obligations under the Indenture;

. to create any new series of Obligations;

. to evidence the succession of another corporation and the assumption by
any such successor of our covenants;

. to add to our covenants or to surrender any of our rights or powers;

. to modify or eliminate any of the terms of the Indenture; but if any
modification or elimination made in a supplemental indenture would
adversely affect or diminish the rights of the holders of any Obligations
then outstanding against us or our property, the supplemental indenture
must state that any of these modifications or eliminations will become
effective only when there is no Obligation of any series created prior to
the execution of that supplemental indenture (subject to the trustee's
discretion, it may decline to enter into a supplemental indenture which,
in its opinion, may not afford adequate protection to the trustee when
that supplemental indenture becomes operative);

. to cure any ambiguity, to correct or supplement any provision in the
Indenture which may be inconsistent with any other provision or to make
any other provisions, with respect to matters or questions arising under
the Indenture, which is not inconsistent with the provisions of the
Indenture, provided such action will not adversely affect the interests of
the holders of the Obligations in any material respect;

. to evidence the succession of another trustee or the appointment of a
co-trustee or separate trustee;

. to add or change any provision of the Indenture to the extent necessary to
permit or facilitate the issuance of Obligations in bearer or book-entry
form;

. to modify, eliminate or add to the provisions of the Indenture to the
extent necessary to effect the qualification of the Indenture under the
Trust Indenture Act of 1939, as amended, or under any similar federal
statute hereafter enacted; or

. to make any other change in the Indenture that, in the reasonable judgment
of the trustee, will not materially and adversely affect the rights of
holders of Obligations.

Prior to the Release Date, we and the trustee may also enter into one or
more supplemental indentures, without the consent of holders of Obligations, to
correct or amplify the description of any property at any time subject to the
lien of the Existing Indenture, to confirm property subject or required to be
subjected to the lien of the Indenture, or to subject additional property to
the lien of the Existing Indenture.

Unless explicitly included in the list of matters for which consent of all
of the holders effected thereby is required prior to entering into a
supplemental indenture above, effective from and after the earlier to occur of
the Amendment Date or the Release Date, any supplemental indenture will be
presumed not to materially adversely affect the rights of holders if:

. the Amended Indenture or the Restated Indenture, as supplemented, provides
equally and ratably for the payment of principal of (and premium, if any)
and interest on the outstanding Obligations remaining outstanding; and

. we furnish to the trustee written evidence from two nationally recognized
rating agencies rating the Obligations that their respective ratings of
the outstanding Obligations (or other obligations primarily secured by
outstanding Obligations) not subject to credit enhancement will not be
withdrawn or reduced.

With the Consent of Holders

With the consent of the holders of not less than a majority in principal
amount of the Obligations of all series then outstanding affected by such
supplemental indenture, we and the trustee may enter into one or more
supplemental indentures to add, change or eliminate any of the provisions of
the Indenture or modify the rights of the holders of Obligations, but no such
supplemental indenture will, without the consent of the holder of each
outstanding Obligation affected thereby:

. change the stated maturity (the date specified in each Obligation as the
fixed date on which the principal of the Obligation or an installment of
interest on the Obligation is due and payable) of or reduce the principal
of, or any installment of interest on, any Obligation, or any premium
payable upon the redemption thereof, or change any place of payment (the
city or political subdivision thereof in which we are required by the
Indenture to maintain an office or agency for payment of the principal of
or interest on

the Obligations) where any Obligation, or the interest on the Obligation
is payable, or impair the right to institute suit for the enforcement of
any such payment on or after the stated maturity of the Obligation (or, in
the case of redemption, on or after the redemption date);

. reduce the percentage in principal amount of the outstanding Obligations
the consent of the holders of which is required for various purposes;

. modify what constitutes an outstanding Obligation, modify the Indenture in
such a manner as to affect the rights of the holders to the benefits of
the sinking fund or modify other provisions of the Indenture;

. on or after the earlier to occur of the Amendment Date or the Release
Date, modify the Indenture as to the application of moneys received by the
trustee; or

. permit (prior to the Release Date) the creation of any lien ranking prior
to or on a parity with the lien of the Existing Indenture or the Amended
Indenture with respect to any of the mortgaged property except as
otherwise permitted.

Consolidation, Merger, Conveyance or Transfer

Under the Existing Indenture and the Amended Indenture, we have agreed not
to consolidate with or merge into any other entity or convey or transfer
substantially all of our property and assets to any entity, unless:

. the consolidation, merger, conveyance or transfer is on terms that fully
preserve the lien and security under the Existing Indenture and the
Amended Indenture and the rights and powers of the trustee and the holders
of the Obligations;

. the entity formed by the consolidation or merger or the entity acquiring
all or substantially all of our property is an entity organized and
validly existing under the laws of the United States of America or any
state;

. we execute and deliver to the trustee a supplemental indenture in form
recordable and satisfactory to the trustee, meeting the relevant
requirements under the Existing Indenture and the Amended Indenture and
containing (1) an assumption by the successor of the due and punctual
payment of the principal of (and premium, if any) and interest on all the
Obligations and the performance and observance of every covenant and
condition of the Existing Indenture and the Amended Indenture to be
performed or observed by us, and (2) a grant, conveyance, transfer and
mortgage complying with the relevant provisions under the Existing
Indenture and the Amended Indenture;

. immediately after giving effect to such transaction, no event of default
under the Existing Indenture or the Amended Indenture will exist; and

. we deliver to the trustee an officers' certificate and an opinion of
counsel stating that the consolidation, merger, conveyance or transfer and
the supplemental indenture comply with the terms of the Existing Indenture
and the Amended Indenture.

Under the Restated Indenture, we have agreed not to consolidate with or
merge into any other entity or convey or transfer substantially all of our
property and assets to any entity, unless:

. the entity formed by that consolidation or merger or the entity which
acquires all or substantially all of our properties and assets is
organized and validly existing under the laws of the United States of
America or any state;

. the entity executes and delivers to the trustee a supplemental indenture
in form satisfactory to the trustee containing an assumption by the
successor entity of the due and punctual payment of the principal of (and
premium, if any) and interest on all the Obligations and the performance
and observance of every covenant and condition of the Restated Indenture
to be performed or observed by us;

. immediately after giving effect to these transactions, no event of default
exists under the Restated Indenture; and

. we deliver to the trustee an officers' certificate and an opinion of
counsel stating that the consolidation, merger, conveyance or transfer and
supplemental indenture comply with the relevant terms of the Restated
Indenture.

Defeasance

The Indenture provides that Obligations of any series, or any maturity
within a series, will be deemed to have been paid and (subject to receipt of
required rulings or opinions relating to tax matters) our obligations to the
holders of those Obligations will be discharged, if we deposit with the trustee
or paying agent cash or defeasance securities maturing as to principal and
interest in such amounts and at such times as are sufficient to pay when due
the principal or (if applicable) redemption price and interest due and to
become due on those Obligations. Permitted defeasance securities include bonds
or other obligations the principal and interest on which constitute direct
obligations of, or are unconditionally guaranteed by, the United States and,
after the Amendment Date or the Release Date, some "AAA"-rated, pre-refunded
municipal bonds, and, in both cases, certificates of interest or participation
in any such obligations, or in specified portions thereof.

Trustee, Paying Agent

The trustee and paying agent under the Indenture is SunTrust Bank, as
successor to Crestar Bank.

FEDERAL INCOME TAX MATTERS

Tax Exempt Status

We currently qualify for an exemption from federal income tax under Section
501(c)(12) of the Internal Revenue Code. To continue operating as an exempt
organization under 501(c)(12), we must operate as a cooperative and at least
85% of our gross receipts must consist of amounts paid by our members for the
sole purpose of meeting losses and expenses. See "MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS--Factors Affecting
Results--Tax Status."

Unrelated Business Taxable Income

Entities like us that are exempt from federal income taxation under 501(a)
of the Internal Revenue Code are still taxed on "unrelated business income."
Unrelated business income is income received from a trade or business that is
regularly carried on by the tax-exempt entity that is not substantially related
to the exercise or performance by the tax-exempt entity of the primary purpose
or function of the organization that constitutes its basis for tax exemption.

UNDERWRITING

Subject to the terms and conditions in the Underwriting Agreement, dated the
date of this prospectus, between us and J.P. Morgan Securities Inc., as
representative of the underwriters, we have agreed to sell to each of the
underwriters the amount of the 2001 Series A Bonds set forth below opposite the
name of the underwriter:

Underwriter Amount of Bonds
----------- ---------------

J.P. Morgan Securities Inc.......................... $150,500,000
Banc of America Securities LLC...................... $ 64,500,000
------------
Total............................................... $215,000,000
============

The Underwriting Agreement provides that the obligations of the underwriters
to pay for and accept delivery of the bonds are subject to approval of related
legal matters by its counsel and to other conditions. The underwriters are
committed to purchase all of the bonds if they purchase any of the bonds.

The underwriters propose to offer all or part of the 2001 Series A Bonds
directly to the public at the offering price set forth on the cover page of
this prospectus. After the initial offering, the public offering price may be
changed.

We have agreed to indemnify the underwriters against specified civil
liabilities, including liabilities under the Securities Act of 1933, or to
contribute to payments the underwriters may be required to make in connection
with the sale of the bonds.

The 2001 Series A Bonds are a new issue of securities with no established
trading market. We cannot give any assurances to you concerning the liquidity
of, or the existence of a trading market for, the bonds. The underwriters may
make a market in the bonds, but are not obligated to do so and may discontinue
making a market at any time without notice.

In order to facilitate the offering of the bonds, the underwriters may
engage in transactions that stabilize, maintain or otherwise affect the price
of the bonds. Specifically, the representatives, on behalf of the underwriters,
may overallot in connection with the offering, creating short positions in the
bonds for their own accounts. In addition, to cover overallotments or to
stabilize the price of the bonds, the representatives may bid for, and purchase
the bonds in the open market. Any of these activities may stabilize or maintain
the market price of the bonds above independent market levels. The underwriters
are not required to engage in these activities and may end any of the
activities at any time.

The underwriters may engage in transactions with and perform services for us
from time-to-time in the ordinary course of business.

LEGAL OPINIONS

LeClair Ryan, a Professional Corporation, and Orrick, Herrington & Sutcliffe
LLP will pass upon the legality of the 2001 Series A Bonds for us. Sutherland
Asbill & Brennan LLP will pass upon other legal matters in connection with the
2001 Series A Bonds for the underwriters.

EXPERTS

The consolidated financial statements of Old Dominion Electric Cooperative
at December 31, 2000 and for the year then ended, appearing in this Prospectus
and Registration Statement have been audited by Ernst & Young LLP, independent
auditors, as set forth in its report thereon appearing elsewhere in this
prospectus, and are included in reliance upon such report given on the
authority of such firm as experts in accounting and auditing.

The financial statements as of December 31, 1999, and for each of the two
year periods ended December 31, 1999, included in this prospectus have been so
included in reliance on the report of PricewaterhouseCoopers LLP, independent
accountants, given on the authority of such firm as experts in auditing and
accounting.

WHERE TO FIND ADDITIONAL INFORMATION ABOUT US

We have filed with the Securities and Exchange Commission a registration
statement on a Form S-1. This prospectus, which constitutes a part of the
registration statement, does not contain all of the information included in the
registration statement. You may review a copy of the registration statement,
including exhibits, at the Securities and Exchange Commission's public
reference room at Judiciary Plaza, 450 Fifth Street, N.W., Washington, D.C.
20549.

You can also obtain copies of these documents, upon payment of a duplicating
fee, by writing to the Public Reference Section of the Securities and Exchange
Commission at 450 Fifth Street, N.W., Washington D.C. 20549. Please call the
Securities and Exchange Commission at 1-800-SEC-0330 for further information
about the public reference room. Our filings with the Securities and Exchange
Commission are also available to the public from the Securities and Exchange
Commission's web site at http://www.sec.gov.

We do not intend to register the 2001 Series A Bonds under the Securities
Exchange Act. We will, however, initially be subject to the reporting
requirements of Section 15(d) of the Securities Exchange Act. The Indenture
requires us to file reports under the Securities Exchange Act as long as any of
the 2001 Series A Bonds are outstanding, even if we are not required by law to
do so. Quarterly and annual reports will be made available upon request of
holders of the 2001 Series A Bonds, which annual reports will contain financial
information that has been examined and reported upon by, with an opinion
expressed by, an independent public or certified public accountant.

Information contained on our web site does not constitute part of this
prospectus.

INDEX TO FINANCIAL STATEMENTS

Page
----

Audited Annual Financial Statements:
Report of Ernst & Young LLP, Independent Auditors............................................. F-2
Report of Independent Accountants............................................................. F-3
Consolidated Balance Sheets, as of December 31, 2000 and 1999................................. F-4
Consolidated Statements of Revenues, Expenses and Patronage Capital, For the Years Ended
December 31, 2000, 1999, and 1998........................................................... F-5
Consolidated Statements of Comprehensive Income, For the Years Ended December 31, 2000, 1999,
and 1998.................................................................................... F-5
Consolidated Statements of Cash Flows, For the Years Ended December 31, 2000, 1999, and 1998.. F-6
Notes to Consolidated Financial Statements.................................................... F-7

Unaudited Interim Financial Statements:
Condensed Consolidated Balance Sheets as of June 30, 2001 and December 31, 2000............... F-21
Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital, For the Six
Months Ended June 30, 2001 and 2000......................................................... F-22
Condensed Consolidated Statements of Comprehensive Income, For the Six Months Ended
June 30, 2001 and 2000...................................................................... F-22
Condensed Consolidated Statements of Cash Flows, For the Six Months Ended June 30, 2001
and 2000.................................................................................... F-23
Notes to Condensed Consolidated Financial Statements.......................................... F-24

F-1

REPORT OF ERNST & YOUNG LLP, INDEPENDENT AUDITORS

To The Board of Directors
Old Dominion Electric Cooperative

We have audited the accompanying consolidated balance sheet of Old Dominion
Electric Cooperative as of December 31, 2000, and the related consolidated
statements of revenues, expenses and patronage capital, comprehensive income
and cash flows for the year then ended. These financial statements are the
responsibility of the Cooperative's management. Our responsibility is to
express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally
accepted in the United States. 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 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 consolidated financial position of Old Dominion
Electric Cooperative at December 31, 2000, and the consolidated results of its
operations and its cash flows for the year then ended in conformity with
accounting principles generally accepted in the United States.

/s/ ERNST & YOUNG LLP

Richmond, Virginia
March 2, 2001

F-2

REPORT OF INDEPENDENT ACCOUNTANTS

To The Board of Directors
Old Dominion Electric Cooperative:

In our opinion, the consolidated balance sheet as of December 31, 1999 and
the related consolidated statements of revenues, expenses and patronage
capital, of comprehensive income and of cash flows for each of the two years in
the period ended December 31, 1999 present fairly, in all material respects,
the financial position, results of operations and cash flows of Old Dominion
Electric Cooperative ("the Cooperative") at December 31, 1999 and for each of
the two years in the period ended December 31, 1999, in conformity with
accounting principles generally accepted in the United States of America. These
financial statements are the responsibility of the Cooperative's management;
our responsibility is to express an opinion on these financial statements based
on our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion. We have not audited the consolidated
financial statements of the Cooperative for any period subsequent to December
31, 1999.

/S/ PRICEWATERHOUSECOOPERS LLP

Richmond, Virginia
March 10, 2000

F-3

OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED BALANCE SHEETS

December 31,
----------------------
2000 1999
---------- ----------
(in thousands)

ASSETS:
Electric Plant:
In service............................................... $ 900,290 $ 889,392
Less accumulated depreciation............................ (304,588) (209,865)
---------- ----------
595,702 679,527
Nuclear fuel, at amortized cost.......................... 5,598 6,981
Construction work in progress............................ 47,598 13,023
---------- ----------
Net Electric Plant................................... 648,898 699,531
---------- ----------
Investments:
Nuclear decommissioning trust fund....................... 60,530 54,159
Lease deposits........................................... 131,364 125,845
Other.................................................... 54,836 82,020
---------- ----------
Total Investments.................................... 246,730 262,024
---------- ----------
Current Assets:
Cash and cash equivalents................................ 20,259 25,088
Receivables.............................................. 46,769 34,044
Fuel, materials and supplies, at average cost............ 10,236 9,312
Prepayments.............................................. 1,508 2,244
Deferred energy.......................................... 15,376 --
---------- ----------
Total Current Assets................................. 94,148 70,688
---------- ----------
Deferred Charges............................................ 20,796 18,269
---------- ----------
Total Assets......................................... $1,010,572 $1,050,512
========== ==========
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital........................................ $ 224,598 $ 216,369
Accumulated other comprehensive income................... (256) (2,316)
Long-term debt........................................... 449,823 509,606
---------- ----------
Total Capitalization................................. 674,165 723,659
---------- ----------
Current Liabilities:
Long-term debt due within one year....................... 30,488 29,700
Accounts payable......................................... 29,091 18,886
Due to Members........................................... 20,912 28,752
Deferred energy.......................................... -- 3,263
Accrued expenses......................................... 6,849 6,770
---------- ----------
Total Current Liabilities............................ 87,340 87,371
---------- ----------
Deferred Credits and Other Liabilities:
Decommissioning reserve.................................. 60,530 54,159
Obligations under long-term leases....................... 134,463 129,010
Other.................................................... 54,074 56,313
---------- ----------
Total Deferred Credits and Other Liabilities......... 249,067 239,482
---------- ----------
Commitments and Contingencies (Notes 1, 2, 3, 9, 10, and 13) -- --
---------- ----------
Total Capitalization and Liabilities................. $1,010,572 $1,050,512
========== ==========

The accompanying notes are an integral part of the consolidated financial
statements.

F-4

OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF REVENUES,
EXPENSES AND PATRONAGE CAPITAL

Years Ended December 31,
----------------------------
2000 1999 1998
-------- -------- --------
(in thousands)

Operating Revenues:................................ $422,031 $390,060 $364,221
-------- -------- --------
Operating Expenses:
Fuel............................................ 49,578 46,045 46,747
Purchased power................................. 170,428 162,242 149,409
Operations and maintenance...................... 34,855 34,096 33,020
Administrative and general...................... 19,602 18,659 15,071
Depreciation, amortization, and decommissioning. 94,257 68,015 46,421
Taxes other than income taxes................... 8,615 7,678 7,358
-------- -------- --------
Total Operating Expenses.................... 377,335 336,735 298,026
-------- -------- --------
Operating Margin................................... 44,696 53,325 66,195
Other Income/(Expense), net........................ 323 (152) 1,301
Investment Income.................................. 4,091 5,552 4,640
Interest Charges, net.............................. (40,881) (48,886) (60,042)
-------- -------- --------
Net Margin......................................... 8,229 9,839 12,094
Patronage Capital--Beginning of Year............... 216,369 206,530 197,552
Capital Credit Payments............................ -- -- (3,116)
-------- -------- --------
Patronage Capital--End of Year..................... $224,598 $216,369 $206,530
======== ======== ========

OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Years Ended December 31,
------------------------
2000 1999 1998
------- ------- -------
(in thousands)

Net Margin............................... $ 8,229 $ 9,839 $12,094
Other Comprehensive Income:
Unrealized gain/(loss) on investments. 2,060 (3,013) 697
------- ------- -------
Comprehensive Income..................... $10,289 $ 6,826 $12,791
======= ======= =======

The accompanying notes are an integral part of the consolidated financial
statements.

F-5

OLD DOMINION ELECTRIC COOPERATIVE

CONSOLIDATED STATEMENTS OF CASH FLOWS

Years Ended December 31,
----------------------------
2000 1999 1998
-------- -------- --------
(in thousands)

Operating Activities:
Net margin............................................................ $ 8,229 $ 9,839 $ 12,094
Adjustments to reconcile net margin to net cash provided by operating
activities:
Depreciation, amortization and decommissioning.................... 94,257 68,015 46,421
Other non-cash charges............................................ 8,514 10,238 17,442
Amortization of lease obligation.................................. 9,093 8,725 8,361
Interest on lease deposits........................................ (8,894) (8,521) (8,153)
Changes in current assets......................................... (28,289) 3,591 (3,554)
Changes in current liabilities.................................... (1,226) (12,797) (589)
Deferred charges and credits...................................... (2,142) (3,615) (263)
-------- -------- --------
Net Cash Provided by Operating Activities...................... 79,542 75,475 71,759
-------- -------- --------
Financing Activities:
Principal payments and purchases of long-term debt.................... (62,683) (78,427) (30,116)
Obligations under long-term lease..................................... (265) (262) (248)
Additions to long-term debt........................................... 1,190 1,130 6,075
Payment of capital credits............................................ -- -- (3,116)
-------- -------- --------
Net Cash used in Financing Activities.......................... (61,758) (77,559) (27,405)
-------- -------- --------
Investing Activities:
Lease deposits and other investments.................................. 29,244 (46,344) (6,967)
Electric plant additions.............................................. (51,176) (8,185) (9,578)
Decommissioning fund deposits......................................... (681) (681) (681)
-------- -------- --------
Net Cash Used in Investing Activities.......................... (22,613) (55,210) (17,226)
-------- -------- --------
Net Change in Cash and Cash Equivalents........................ (4,829) (57,294) 27,128
Cash and Cash Equivalents--Beginning of Year............................. 25,088 82,382 55,254
-------- -------- --------
Cash and Cash Equivalents--End of Year................................... $ 20,259 $ 25,088 $ 82,382
======== ======== ========

The accompanying notes are an integral part of the consolidated financial
statements.

F-6

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1--Summary of Significant Accounting Policies

General:

Old Dominion Electric Cooperative ("Old Dominion"), a not-for-profit
wholesale power supply cooperative, was incorporated under the laws of the
Commonwealth of Virginia in 1948. It provides wholesale electric service to 12
member distribution cooperatives ("Members") engaged in the retail sale of
power to member customers located in Virginia, Delaware, Maryland, and parts of
West Virginia. Old Dominion's Board of Directors is composed of two
representatives from each of the Members. Old Dominion's rates are not
regulated by the respective states' public service commissions, but are set
periodically by a formula that was accepted for filing by the Federal Energy
Regulatory Commission ("FERC") on May 18, 1992.

Old Dominion complies with the Uniform System of Accounts prescribed by
FERC. In conformity with accounting principles generally accepted in the United
States ("GAAP"), the accounting policies and practices applied by Old Dominion
in the determination of rates are also employed for financial reporting
purposes.

The preparation of the consolidated financial statements in conformity with
GAAP requires management to make estimates and assumptions that affect the
amounts reported therein. Actual results could differ from those estimates.

The accompanying financial statements reflect the consolidated accounts of
Old Dominion and its subsidiaries. All intercompany balances and transactions
have been eliminated in consolidation. Old Dominion's 50% ownership interest in
Regional Headquarters, Inc. ("RHI") (Note 11) is recorded using the equity
method of accounting.

Electric Plant:

Electric plant is stated at original cost when first placed in service. Such
cost includes contract work, direct labor and materials, allocable overhead,
and an allowance for borrowed funds used during construction. Upon the partial
sale or retirement of plant assets, the original asset cost and current
disposal costs less sale proceeds, if any, are charged or credited to
accumulated depreciation. In accordance with industry practice, no profit or
loss is recognized in connection with normal sales and retirements of property
units.

Maintenance and repair costs are expensed as incurred. Replacements and
renewals of items considered to be units of property are capitalized to the
property accounts.

Depreciation, Amortization, and Decommissioning:

Depreciation is based on the straight-line method at rates that are designed
to amortize the original cost of properties over their service lives.
Depreciation rates, excluding accelerated depreciation associated with Old
Dominion's Strategic Plan Initiative ("Strategic Plan Initiative" or "SPI"),
for jointly owned depreciable plant balances at the North Anna Nuclear Power
Station ("North Anna") were approximately 3.0% in 2000, 3.3% in 1999, and 3.1%
in 1998. The depreciation rates, excluding accelerated depreciation associated
with the SPI, for jointly owned depreciable plant balances at the Clover Power
Station ("Clover") were approximately 2.7% in 2000, 2.8% in 1999, and 2.7% in
1998.

In accordance with the SPI, Old Dominion recorded $65.0 million and $43.7
million of accelerated depreciation on its generation assets in 2000 and 1999,
respectively. See Note 13 to the Consolidated Financial Statements. In 1998,
$20.7 million of accelerated amortization was recorded on the plant acquisition
adjustment to fully amortize the asset.

F-7

Old Dominion accrues decommissioning costs over the expected service life of
North Anna and makes periodic deposits in a trust fund, such that the fund
balance will equal Old Dominion's estimated decommissioning cost at the time of
decommissioning. The present value of the future decommissioning cost is
credited to the decommissioning reserve; increases are charged to Members
through their rates. The estimated cost to decommission North Anna is based on
a site-specific study performed by Virginia Electric and Power Company
("Virginia Power") in 1998 and assumes that the plant will be dismantled when
it is decommissioned. Old Dominion's portion of the estimated cost to
decommission North Anna is expected to be approximately $91.3 million in 1998
dollars. The decommissioning of North Anna is expected to begin at the
expiration date of each unit's operating license, which is 2018 and 2020 for
North Anna Units 1 and 2, respectively. In the event the assumed return on the
trust fund is not earned, management of Old Dominion believes that any
additional cost incurred would be recoverable through rates.

Amounts held in the decommissioning trust fund, which equals the
decommissioning reserve at December 31, 2000 and 1999, were $60.5 million and
$54.2 million, respectively. Annual decommissioning expense, net of earnings on
the fund, was $0.7 million in 2000, 1999, and 1998.

In June 2001, Virginia Power plans to file an application with the NRC to
renew the operating licenses for North Anna. The renewed licenses would extend
the operation of North Anna Units 1 and 2 to 2038 and 2040, respectively.

Nuclear Fuel:

Owned nuclear fuel is amortized on a unit-of-production basis sufficient to
fully amortize, over the estimated service life, the cost of fuel plus future
storage and disposal costs.

Under the Nuclear Waste Policy Act of 1982, the Department of Energy ("DOE")
is required to provide for the permanent disposal of spent nuclear fuel
produced by nuclear facilities, such as North Anna, in accordance with
contracts executed with the DOE. However, since the DOE did not begin accepting
spent fuel in 1998 as specified in its contracts, Virginia Power is providing
on-site spent nuclear fuel storage at the North Anna facility. These facilities
are expected to be adequate until the DOE begins accepting the spent nuclear
fuel.

Allowance for Borrowed Funds Used During Construction:

Allowance for borrowed funds used during construction is defined as the net
cost during the construction period of borrowed funds used for construction
purposes and a reasonable rate on other funds when so used. Old Dominion
capitalizes interest on borrowings for significant construction facilities.
Interest capitalized in 2000, 1999, and 1998 was $0.3 million, $0.3 million,
and $0.4 million, respectively.

Income Taxes:

As a not-for-profit electric cooperative, Old Dominion is currently exempt
from federal income taxation under Section 501(c)(12) of the Internal Revenue
Code of 1986. Accordingly, provisions for income taxes have not been reflected
in the accompanying consolidated financial statements.

Operating Revenues:

Operating revenues are derived from sales to Members and to nonmembers.
Sales to Members consist of power sales pursuant to long-term wholesale power
contracts ("wholesale power contracts") that Old Dominion maintains with each
of its Members. These wholesale power contracts obligate each Member to pay Old
Dominion for power furnished in accordance with rates established by Old
Dominion. Power furnished is determined based on month-end meter readings.

Sales to nonmembers represent sales of excess purchased energy and sales of
excess energy from Clover. Excess purchased energy is sold to the
Pennsylvania-New Jersey-Maryland Interconnection, LLC ("PJM") power pool.

F-8

Excess energy from Clover is sold to Virginia Power, a related party, under the
terms of the contracts between Old Dominion and Virginia Power relating to the
construction and operation of Clover ("Clover Agreements").

Deferred Charges:

Certain costs have been deferred based on rate action by Old Dominion's
Board of Directors and approval by FERC. These costs will be recognized as
expenses concurrent with their recovery through rates. In 1999 and 1998, Old
Dominion accelerated the amortization and recovery in rates of debt refinancing
premiums in the amounts of $1.7 million and $8.1 million, respectively.

Deferred charges also include costs associated with the issuance of debt.
These costs are being amortized using the effective interest method over the
life of the respective debt issues.

Deferred Energy:

A deferral method of accounting is used to recognize differences between Old
Dominion's actual energy and fuel expenses and energy and fuel revenues
collected from its Members. The deferred charge at December 31, 2000, was $15.4
million, which will be recovered from the Members in 2001 in accordance with
the tariffs then in effect. The deferred credit at December 31, 1999, of $3.3
million was returned to the Members in 2000 in accordance with the tariffs then
in effect.

Investments:

Financial instruments included in the decommissioning fund are classified as
available-for-sale, and accordingly, are carried at fair value. Unrealized
gains and losses on investments held in the decommissioning fund are deferred
as an adjustment to the decommissioning reserve until realized.

Old Dominion's investments in marketable securities, which are actively
managed, are classified as available-for-sale and are recorded at fair value.
Unrealized gains or losses on other investments, if material, are reflected as
a component of capitalization. Investments that Old Dominion has the positive
intent and ability to hold to maturity are classified as held-to-maturity and
are recorded at amortized cost. Other investments are recorded at cost which
approximates market value.

In June 1998, the Financial Accounting Standards Board ("FASB") issued
Statement of Financial Accounting Standards ("SFAS") No. 133, "Accounting for
Derivative Instruments and Hedging Activities," which, as amended, is effective
for all fiscal quarters of all fiscal years beginning after June 15, 2000. SFAS
No. 133 requires that all derivative instruments, including those embedded in
other contracts, be recorded as either assets or liabilities at fair value. Any
changes in value should be reported currently in earnings, unless the
derivative instrument is specifically designated as a hedge and meets certain
accounting criteria required for such designation. In June 2000, the FASB
issued SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain
Hedging Activities-An Amendment to FASB Statement No. 133," which further
clarifies certain SFAS No. 133 implementation issues. Old Dominion believes the
impact of adopting SFAS No. 133 and No. 138 will not be material to its
financial position or result of operations.

Patronage Capital:

Old Dominion is organized and operates as a cooperative. Patronage capital
represents the retained net margins of Old Dominion which have been allocated
to its Members based upon their respective power purchases in accordance with
Old Dominion's bylaws. Any distributions are subject to the discretion of Old
Dominion's Board of Directors and the restrictions contained in the Indenture
of Mortgage and Deed of Trust, dated as of May 1, 1992, between Old Dominion
and Crestar Bank, as trustee (as supplemented by ten supplemental indentures
thereto and hereinafter referred to as the "Indenture"). In December 1997, Old
Dominion's Board of Directors approved the retirement of approximately $3.1
million of patronage capital, which was disbursed in February 1998.

F-9

Concentrations of Credit Risk:

Financial instruments which potentially subject Old Dominion to
concentrations of credit risk consist of cash equivalents, investments, and
receivables arising from energy sales to Members and from Virginia Power
related to Clover and other transactions. Old Dominion places its temporary
cash investments with high credit quality financial institutions and invests in
debt securities with high credit standards as required by the Indenture and the
Board of Directors. Cash and cash investment balances may exceed FDIC insurance
limits. Concentrations of credit risk with respect to receivables arising from
energy sales to Members are limited due to the large member customer base that
represents Old Dominion's cooperative Members' accounts receivable. Receivables
from Members at December 31, 2000 and 1999 were $44.2 million and $33.9
million, respectively.

Cash Equivalents:

For purposes of the Consolidated Statements of Cash Flows, Old Dominion
considers all unrestricted highly liquid debt instruments purchased with an
original maturity of three months or less to be cash equivalents.

Reclassifications:

Certain reclassifications have been made to the prior years' consolidated
financial statements to conform to the current year's presentation.

NOTE 2--Jointly Owned Plants

Old Dominion owns an 11.6% undivided ownership interest in North Anna, a
two-unit, 1,790 MW (net capacity rating) nuclear generating facility, as well
as nuclear fuel and common facilities at the power station, and a portion of
spare parts, inventory and other support facilities. North Anna is operated by
Virginia Power, which owns the balance of the plant. Old Dominion is
responsible for 11.6% of all post acquisition date additions and operating
costs associated with the plant, as well as a pro rata portion of Virginia
Power's administrative and general expenses for North Anna, and must provide
its own financing for these items. Old Dominion's portion of assets,
liabilities, and operating expenses associated with North Anna are included in
the consolidated financial statements. At December 31, 2000 and 1999, Old
Dominion had an outstanding accounts receivable balance of $0.9 million and
$0.4 million due from Virginia Power for operation, maintenance, and capital
investment at the facility.

Old Dominion and Virginia Power each hold a 50% undivided ownership interest
in Clover, a two-unit, 882 MW (net capacity rating) coal-fired generating
facility operated by Virginia Power. Old Dominion is responsible for 50% of all
post-construction additions and operating costs associated with Clover, as well
as a pro rata portion of Virginia Power's administrative and general expenses
for Clover, and must provide its own financing for these items. Old Dominion's
portion of assets, liabilities, and operating expense associated with Clover
are included in the consolidated financial statements. At December 31, 2000 and
1999, Old Dominion had an outstanding accounts receivable balance of $2.5
million and 2.1 million, respectively, due from Virginia Power for operation,
maintenance, and capital investment at the facility.

Old Dominion's investment in jointly owned plants at December 31, 2000,
excluding accelerated depreciation of $108.7 million, was as follows:

North Anna Clover
---------- ------
(in millions,
except percentages)

Ownership interest..................... 11.6% 50.0%
Electric plant......................... $ 354.5 $635.6
Accumulated depreciation & amortization (196.7) (86.9)
Construction work in progress.......... 5.0 3.2

F-10

Projected capital expenditures for North Anna for 2001 through 2003 are
$14.8 million, $12.3 million, and $10.0 million, respectively. Projected
capital expenditures for Clover for 2001 through 2003 are $1.9 million, $2.6
million, and $1.5 million, respectively.

NOTE 3--Power Purchase Agreements

In 2000, 1999, and 1998, North Anna and Clover together furnished
approximately 55.7%, 57.0%, and 57.2%, respectively, of Old Dominion's energy
requirements. The remaining needs were satisfied through purchases of
supplemental power from Virginia Power and other power companies.

Under the terms of the Amended and Restated Interconnection and Operating
Agreement with Virginia Power ("I&O Agreement"), as accepted by FERC on March
11, 1998, Virginia Power agreed to sell to Old Dominion reserve capacity and
energy for North Anna and Clover until the earlier of the date on which all
facilities at North Anna have been retired or decommissioned and the date upon
which Old Dominion's interest in North Anna is reduced to zero. Through the end
of 2001, Virginia Power has the obligation to provide Old Dominion's entire
monthly supplemental and peaking demand and energy requirements to meet the
needs of its Virginia Members (except A&N Electric Cooperative) not met from
Old Dominion's portion of North Anna and Clover generation. Under the terms of
the I&O Agreement, Old Dominion will purchase from Virginia Power half of its
supplemental requirements in 2002 and none of its supplemental requirements in
2003. Old Dominion will continue to purchase its peaking requirements from
Virginia Power through 2003.

Beginning January 1, 2000, energy pricing for the peaking portion of
Virginia Power purchases changed from the Virginia Power system average cost to
a charge that reflects Virginia Power's owned combustion turbine costs. As
noted previously, Old Dominion has the right to displace those purchases if
more economical power is available from other sources.

Additionally, under the terms of the I&O Agreement, services to Old Dominion
have been unbundled and terms for the provision of transmission and ancillary
services have been removed. These services will be provided pursuant to
Virginia Power's open access transmission tariff. Specific terms are provided
in a Service Agreement for Network Integration Transmission Service and a
Network Operating Agreement between Virginia Power and Old Dominion, both of
which also were approved by FERC on March 11, 1998, retroactively effective to
January 1, 1998.

Old Dominion has an agreement with Public Service Electric & Gas ("PSE&G
Agreement") to purchase 150 MW of capacity, consisting of 75 MW intermediate
and/or peaking capacity and 75 MW base load capacity, as well as reserves and
associated energy, through 2004. The PSE&G Agreement contains fixed capacity
charges for the base, intermediate, and peaking capacity to be provided under
the agreement. However, either party can (within certain limits) apply to FERC
to recover changes in certain costs of providing services. In the event of a
change in rate, the party adversely affected may terminate the PSE&G Agreement,
with one-year notice. Old Dominion may purchase the energy associated with the
PSE&G capacity from PSE&G or other power suppliers. If purchased from PSE&G,
the energy cost is based on PSE&G's incremental cost above its native load
requirements, taking into account the pool energy transactions with PJM. If
purchased from other power suppliers, Old Dominion pays a negotiated energy
rate. In 2000, Old Dominion purchased most of the energy requirements from the
short-term markets.

Until December 1, 1999, Old Dominion had a partial requirements agreement
with Conectiv, which obligated Conectiv to provide the balance of Old
Dominion's power requirements for its three Members east of the Chesapeake Bay
in excess of the 150 MW purchased from PSE&G and a 60 MW capacity contract with
Conectiv/Pennsylvania Power & Light.

In 1999, Old Dominion renegotiated its partial requirements contract with
Conectiv for the period December 1, 1999 through August 31, 2001. Under this
agreement, Conectiv will provide 200 MW of capacity credits to

F-11

Old Dominion for the term of the agreement. Old Dominion exercised an option
under the agreement to purchase an additional 20 MW of capacity credits
effective January 1, 2001 through the remaining term of the contract. There is
no commitment to provide energy under the contract, and Old Dominion utilized
forward and short-term energy contracts and spot market purchases to supply the
energy requirements.

Due to transmission import limitations into the Delmarva Peninsula, Old
Dominion paid approximately $12.0 million in congestion costs during 2000.
These costs were incurred under the PJM Independent System Operator rules when
higher cost generation must be run due to transmission contingencies or
outages.

Old Dominion's power purchase costs for the past three years were as
follows:

2000 1999 1998
------ ------ ------
(in millions)

Virginia Power $ 68.9 $ 69.8 $ 70.4
Delmarva Area. 67.1 66.5 69.9
Other......... 34.4 25.9 9.1
------ ------ ------
Total......... $170.4 $162.2 $149.4
====== ====== ======

Old Dominion's power purchase agreements contain certain firm capacity and
minimum energy requirements. As of December 31, 2000, Old Dominion's minimum
purchase commitments under the various agreements, without regard to capacity
reductions or cost adjustments, were as follows:

Firm Minimum
Capacity Energy
Year Ending December 31, Requirements Requirements Total
------------------------ ------------ ------------ -----
(in millions)

2001.......... $16.8 -- $16.8
2002.......... 8.2 -- 8.2
2003.......... 8.1 -- 8.1
2004.......... 7.0 -- 7.0
2005.......... -- -- --
----- -- -----
$40.1 -- $40.1
===== == =====

At December 31, 2000, Old Dominion had no short-term commitments to buy
energy over the next six months.

NOTE 4--Wholesale Power Contracts

Old Dominion has wholesale power contracts with all of its Members whereby
each Member is obligated to purchase substantially all of its power
requirements from Old Dominion through the year 2028. Each such contract
provides that Old Dominion shall provide all of the power that the Member
requires for the operation of the Member's system to the extent that Old
Dominion has the power and facilities available. Each Member is required to pay
Old Dominion monthly for power furnished under its wholesale power contract in
accordance with rates and charges established by Old Dominion pursuant to a
rate formula filed with FERC. Under the accepted rate formula, the rates
charged by Old Dominion are developed using a rate methodology under which all
categories of costs are specifically separated as components of the formula to
determine Old Dominion's revenue requirements. The rate formula method uses
traditional techniques to allocate costs to capacity and energy in establishing
rates to the Members. The formula is intended to permit collection of revenues,
which, together with revenues from all other sources, are equal to all costs
and expenses recorded on Old Dominion's books, plus an additional 20% of total
interest charges, plus additional equity contributions as approved by Old
Dominion's Board of Directors. It also provides for the periodic adjustment of
rates to recover actual, prudently incurred costs, whether they increase or
decrease, without further application to and acceptance by FERC. In accordance
with the formula, the Board of Directors can authorize accelerating the
recovery of costs in the

F-12

establishment of rates. Old Dominion's rate formula allows Old Dominion to
recover and refund amounts under the Margin Stabilization Plan (as hereinafter
defined). In order to ensure that only actual cost of power service plus
necessary margins are billed to the Members each year, and to provide for
uncertainties connected with the establishment of prospective rates, in 1984
Old Dominion's Board of Directors established a plan (the "Margin Stabilization
Plan") which allows Old Dominion to review its actual cost of service and power
sales as of year end and adjust revenues from the Members to take into account
actual results and financial coverages. All adjustments, whether increases or
decreases, are recorded in the year affected and allocated to Members based on
power sales during that year. Such increases or decreases are either collected
from Members, or offset against amounts owed by the Members, in the succeeding
year. Under the Margin Stabilization Plan, Old Dominion reduced revenues from
power sales and increased accounts payable to Members for 1999 and 1998 in the
amount of $7.2 million, and $4.4 million, respectively. Revenues from the
following Members equaled or exceeded 10% of Old Dominion's total revenues for
the past three years:

Year Ended December 31,
-----------------------
2000 1999 1998
------ ------ -----
(in millions)

Northern Virginia Electric Cooperative $110.5 $102.6 $95.4
Rappahannock Electric Cooperative..... 89.0 82.2 77.0
Delaware Electric Cooperative......... 44.1 41.7 39.0

NOTE 5--Long-Term Lease Transactions

On March 1, 1996, Old Dominion finalized a long-term lease transaction with
an owner trust for the benefit of an equity investor. Under the terms of the
transaction, Old Dominion entered into a 48.8-year lease of its interest in
Clover Unit 1 (valued at $315.0 million) to such owner trustee, and
simultaneously entered into a 21.8-year lease of the interest back from such
owner trustee. As a result of the transaction, Old Dominion recorded a deferred
gain of $23.6 million, which is being amortized into income ratably over the
21.8-year operating lease term. A portion of the proceeds from the transaction,
$23.9 million, was used to retire a portion of Old Dominion's 8.76% First
Mortgage Bonds, 1992 Series A. Concurrent with the retirement of its 1992
Series A Bonds, Old Dominion issued a like amount of zero coupon First Mortgage
Bonds, 1996 Series A with an effective interest rate of 7.06%.

On July 31, 1996, Old Dominion finalized a long-term lease transaction with
a business trust created for the benefit of another equity investor. Under the
terms of the transaction, Old Dominion entered into a 63.4-year lease of its
interest in Clover Unit 2 (valued at $320.0 million) to such business trust and
simultaneously entered into a 23.4-year lease of the interest back from such
business trust. As a result of the transaction, Old Dominion recorded a
deferred gain of $39.3 million, which is being amortized into income ratably
over the 23.4-year operating lease term.

F-13

NOTE 6--Investments

Investments were as follows at December 31, 2000 and 1999 (in thousands):

December 31, 2000
-----------------------------------------------------
Gross Unrealized Gross Unrealized
Description Cost Gains Losses Fair Value
----------- -------- ---------------- ---------------- ----------

Available-for-Sale:
Corporate obligations............... $ 27,131 $ 6 $ (268) $ 26,869
Registered investment companies/(1)/ 23,583 -- (1,181) 22,402
Asset-backed securities............. 9,987 7 (23) 9,971
Mortgage-backed securities.......... 7,967 32 (10) 7,989
Common stock........................ 29,371 9,383 (684) 38,070
Short-term investments.............. 64,046 -- -- 64,046
Other............................... 58 -- -- 58
-------- ------- ------- --------
$162,143 $ 9,428 $(2,166) $169,405
-------- ------- ------- --------
Held-to-Maturity:
U.S. Government obligations......... $ 43,541 $13,171 $ -- $ 56,712
Corporate obligations............... 32,512 -- -- 32,512
-------- ------- ------- --------
$ 76,053 $13,171 -- $ 89,224
-------- ------- ------- --------
Other:.............................. $ 1,272 -- -- $ 1,272
-------- ------- ------- --------

December 31, 1999
-----------------------------------------------------
Gross Unrealized Gross Unrealized
Description Cost Gains Losses Fair Value
----------- -------- ---------------- ---------------- ----------

Available-for-Sale:
U.S. Government obligations......... $ 11,299 $ -- $ (330) $ 10,969
Corporate obligations............... 33,198 3 (1,179) 32,022
Registered investment companies/(1)/ 21,960 -- (2,371) 19,589
Asset-backed securities............. 23,221 2 (607) 22,616
Mortgage-backed securities.......... 4,751 -- (207) 4,544
Common stock........................ 27,858 6,677 -- 34,535
Short-term investments.............. 65,226 2 -- 65,228
-------- ------ ------- --------
$187,513 $6,684 $(4,694) $189,503
-------- ------ ------- --------
Held-to-Maturity:
U.S. Government securities.......... $ 40,784 $2,781 $ (143) $ 43,422
Corporate obligations............... 30,368 -- -- 30,368
-------- ------ ------- --------
$ 71,152 $2,781 $ (143) $ 73,790
-------- ------ ------- --------
Other:.............................. $ 1,369 -- -- $ 1,369
-------- ------ ------- --------

/(1)/Investments included herein are primarily invested in corporate
obligations.

Contractual maturities of debt securities at December 31, 2000 were as
follows (in thousands):

Less Than One One Through Five More Than Five
Year Years Years Total
Description ------------- ---------------- -------------- --------

Available-for-Sale $ -- $34,858 $ -- $ 34,858
Held-to-Maturity.. 270 1,108 74,675 76,053
---- ------- ------- --------
$270 $35,966 $74,675 $110,911
==== ======= ======= ========

F-14

Realized gains and losses on the sale of securities are determined on the
basis of specific identification. During 2000 and 1999, sales proceeds from the
sale of available-for-sale securities were $117.9 million and $81.6 million,
respectively. Gross realized gains on the sale of available-for-sale securities
in 2000, 1999, and 1998 were $0.6 million, $0.2 million, and $83,000,
respectively. Gross realized losses on the sale of available-for-sale
securities in 2000, 1999, and 1998 were $0.9 million, $0.5 million, and 35,000,
respectively.

NOTE 7--Long-Term Debt

Long-term debt consists of the following:

December 31,
------------------
2000 1999
-------- --------
(in thousands)

$5,000,000 principal amount of First Mortgage Bonds, 1998 Series B, due 2002 at an
interest rate of 4.25%............................................................. $ 5,000 $ 5,000
$109,182,937 principal amount of First Mortgage Bonds, 1996 Series B, due 2018 at an
effective rate of 7.06%............................................................ 108,601 108,601
$130,000,000 principal amount of First Mortgage Bonds, 1993 Series A, due 2013 at an
interest rate of 7.48%............................................................. 125,300 128,300
$120,000,000 principal amount of First Mortgage Bonds, 1993 Series A, due 2023 at an
interest rate of 7.78%............................................................. 18,500 38,500
$150,000,000 principal amount of First Mortgage Bonds, 1992 Series A, due 2002 at an
interest rate of 7.97%............................................................. 56,322 84,480
$350,000,000 principal amount of First Mortgage Bonds, 1992 Series A, due 2022 at an
interest rate of 8.76%............................................................. 180,155 190,405
$60,210,000 principal amount of First Mortgage Bonds, 1992 Series C, due 1997 through
2022 at interest rates ranging from 4.90% to 6.50%................................. 55,790 56,980
Louisa County Pollution Control Revenue Bonds (North Anna), due December 1, 2008,
with variable interest rates (averaging 4.16% in 2000 and 3.27% in 1999)........... 6,750 6,750
First Mortgage Bonds due 2002 at interest rates ranging from 4.25% to 5.25%.......... 4,420 3,230
Non-recourse debt due 2001, with variable interest rates (averaging 5.46% in 2000 and
4.11% in 1999)..................................................................... 1,072 1,422
-------- --------
561,910 623,668
Less unamortized discounts........................................................... (81,599) (84,362)
Less current maturities.............................................................. (30,488) (29,700)
-------- --------
Total Long-Term Debt................................................................. $449,823 $509,606
======== ========

Substantially all assets of Old Dominion are pledged as collateral under the
Indenture.

The non-recourse debt is collateralized by a $1.6 million letter of credit.

During 2000 and 1999, Old Dominion purchased approximately $33.3 million and
$49.3 million, respectively, of its First Mortgage Bonds, 1992 Series A and
1993 Series A. The transactions resulted in a net gain of approximately $0.5
million in 2000 and a net loss of approximately $4.2 million in 1999, including
the write-off of original issuance costs. The net gains and losses have been
deferred and are being amortized over the life of the remaining bonds. At
December 31, 2000, deferred gains and losses on reacquired debt totaled a net
loss of approximately $11.8 million.

During the past three years, Old Dominion refinanced $3.4 million of its
First Mortgage Bonds, 1992 Series C, due 1998 through 2000. The refinanced
bonds are due in 2002 at interest rates ranging from 4.25% to 5.25%.

F-15

Estimated maturities of long-term debt for the next five years are as
follows:

Years Ending December 31, (in thousands)
------------------------- --------------

2001........... $30,488
2002........... 38,910
2003........... 22,326
2004........... 22,329
2005........... 22,332

The aggregate fair value of long-term debt was $581.6 million and $630.9
million at December 31, 2000 and 1999, respectively, based on current market
prices. For debt issues that are not quoted on an exchange, interest rates
currently available to Old Dominion for issuance of debt with similar terms and
remaining maturities are used to estimate fair value. Old Dominion believes
that the carrying amount of debt issues with variable rates that are refinanced
at current market rates is a reasonable estimate of their fair value.

NOTE 8--Short-Term Borrowing Arrangements

Old Dominion has unsecured short-term lines of credit to provide additional
sources of financing. These include $70.0 million in committed lines of credit
which expire in 2001 and are expected to be renewed and a $15.0 million
committed line of credit which expires in 2002 and is expected to be renewed.
Old Dominion also has uncommitted short-term borrowing arrangements aggregating
$30.0 million. Due to limitations contained in certain of these uncommitted
facilities, no more than $85.0 million in total can be outstanding at any time
under Old Dominion's committed and uncommitted short-term borrowing
arrangements. At December 31, 2000 and 1999, Old Dominion had no short-term
borrowings outstanding under any of these arrangements.

Old Dominion maintains a policy which allows Members to pay monthly power
bills before their final due date. Under this policy, Old Dominion pays
interest on early payment balances at a blended investment and outside
short-term borrowing rate. Amounts advanced by Members are classified as due to
Members and totaled $20.9 million and $28.8 million at December 31, 2000 and
1999, respectively.

NOTE 9--Employee Benefits

Substantially all Old Dominion employees participate in the National Rural
Electric Cooperative Association ("NRECA") Retirement and Security Program, a
noncontributory, defined benefit multi-employer master pension plan. The cost
of the plan is funded annually by payments to NRECA to ensure that annuities in
amounts established by the plan will be available to individual participants
upon their retirement. Pension expense for 2000, 1999, and 1998 was $430,000,
$272,000, and $265,000, respectively.

Old Dominion has also elected to participate in the SelectRe Pension Plan, a
defined contribution multi-employer retirement plan administered by the NRECA.
Under the plan, employees may elect to have up to 23% or $10,500, whichever is
less, of their salary withheld on a pre-tax basis, subject to Internal Revenue
Service limitations, and invested on their behalf. As an additional incentive,
Old Dominion matches up to the first 2% of each employee's contribution to the
plan. Old Dominion's matching contributions were $75,000, $66,000, and $61,000
in 2000, 1999, and 1998, respectively.

Old Dominion provides no other significant postretirement benefits to its
employees. However, in conjunction with the I&O Agreement, Old Dominion is
required to pay 11.6% of the operating costs associated with North Anna and 50%
of the operating costs associated with Clover, including postretirement
benefits of Virginia Power employees whose costs are allocated to those
stations. These postretirement benefits other than pensions resulted in an
increase in expense to Old Dominion of approximately $0.7 million in 2000, $0.9
million in 1999, and $0.7 million in 1998. Old Dominion is recovering the
expense as it is billed by Virginia Power.

F-16

NOTE 10--Insurance

As a joint owner of North Anna, Old Dominion is a party to the insurance
policies that Virginia Power procures to limit the risk of loss associated with
a possible nuclear incident at the station, as well as policies regarding
general liability and property coverage. All policies are administered by
Virginia Power, which charges Old Dominion for its proportionate share of the
costs.

The Price-Anderson Act limits the public liability of an owner of a nuclear
power plant to $9.5 billion for a single nuclear incident. The Price-Anderson
Act Amendment of 1988 allows for an inflationary provision adjustment every
five years. Virginia Power has purchased $200 million of coverage from the
commercial insurance pools with the remainder provided through a mandatory
industry risk-sharing program. In the event of a nuclear incident at any
licensed nuclear reactor in the United States, Virginia Power and Old Dominion,
jointly, could be assessed up to $88.0 million for each licensed reactor not to
exceed $10.0 million per year per reactor. There is no limit to the number of
incidents for which this retrospective premium can be assessed.

Virginia Power's current level of property insurance coverage, $2.55 billion
for North Anna, exceeds the Nuclear Regulatory Commission's ("NRC") minimum
requirement for nuclear power plant licensees of $1.06 billion for each reactor
site and includes coverage for premature decommissioning and functional total
loss. The NRC requires that the proceeds from this insurance be used first to
return the reactor to and maintain it in a safe and stable condition, and
second to decontaminate the reactor and station site in accordance with a plan
approved by the NRC. The property insurance coverage provided to Virginia Power
and Old Dominion, jointly, is provided by Nuclear Electric Insurance Limited
("NEIL"), a mutual insurance company, and is subject to retrospective premium
assessments in any policy year in which losses exceed the funds available to
the insurance company. The maximum assessment for the current policy period is
$21.0 million. Based on the severity of the incident, the board of directors of
the nuclear insurer has the discretion to lower or eliminate the maximum
retrospective premium assessment. Virginia Power and Old Dominion, jointly,
have the financial responsibility for any losses that exceed the limits or for
which insurance proceeds are not available, because they must first be used for
stabilization and decontamination.

Virginia Power purchases insurance from NEIL to cover the cost of
replacement power during a prolonged outage of a nuclear unit due to direct
physical damage of the unit. Under this program, Virginia Power and Old
Dominion, jointly, are subject to a retrospective premium assessment for any
policy year in which losses exceed funds available to NEIL. The current policy
period's maximum assessment is $5.0 million.

Old Dominion's share of the contingent liability for the coverage
assessments described above is a maximum of $23.4 million at December 31, 2000.

F-17

NOTE 11--Regional Headquarters, Inc.

Old Dominion owns 50% of RHI, which holds title to the office building that
is being partially leased to Old Dominion. Old Dominion is obligated to make
lease payments equal to one-half of RHI's annual operating expenses, net of
rental income from third party lessees, through the year 2016. During 2000,
1999, and 1998, Old Dominion paid $236,000, $236,000, and $184,000,
respectively, to RHI for rent.

Estimated future lease payments, without regard to changes in square
footage, third party occupancy rates, operating costs, and inflation are as
follows:

Years Ending December 31, (in thousands)
------------------------- --------------

2001.................. $ 350
2002.................. 350
2003.................. 350
2004.................. 350
2005.................. 350
2006 and thereafter... 3,850
------
$5,600
======

NOTE 12--Supplemental Cash Flows Information

Cash paid for interest, net of allowance for funds used during construction,
in 2000, 1999, and 1998 was $41.3 million, $49.4 million, and $60.3 million,
respectively.

Unrealized deferred gains on the decommissioning fund of approximately $3.0
million and $4.0 million in 2000 and 1999, respectively, have been included in
the decommissioning reserve.

In 1998, Old Dominion charged off $6.0 million of accounts receivable as
uncollectible.

NOTE 13--Commitments and Contingencies

Strategic Plan Initiative--On October 14, 1997, Old Dominion's Board of
Directors approved a resolution adopting certain strategic objectives designed
to mitigate the effects of the transition to a competitive electric market (the
"Strategic Plan Initiative" or "SPI"). Subsequently, an independent assessment
of the impact on Old Dominion of transition to a competitive market was
performed and the resulting recommendations to mitigate the transition effects
were approved by the Board of Directors on July 28, 1998, and incorporated into
the SPI. The SPI, as then approved, called for the accumulation of
approximately $330.0 million in cash and cash equivalents from 1998 through
2003 with the funds to be used for the prepayment of a portion of outstanding
debt. A provision of the SPI requires that it be updated periodically based on
revised projections, projected targets, legislation, and the status of the SPI
in terms of achieving its objective. The Board of Directors will approve all
revisions or modifications.

In conjunction with the SPI, on May 10, 1999, Old Dominion's Board of
Directors unanimously approved a resolution to record accelerated depreciation
on generation assets during the period January 1, 1999 through December 31,
2003, and to recover the additional expense through rates pursuant to the
comprehensive rate formula filed with and accepted by FERC.

A study was undertaken in late 1999 to assess the status of the SPI and the
numerous factors that impact its results. This update considered changes in
market rate forecasts, components of Old Dominion's cost of service and
deregulation timelines. Additionally, it incorporated the effects of recording
accelerated depreciation. As a result of this study the targeted collection
amount of $330.0 million was reduced to $241.0 million. Old Dominion will
continue to evaluate the various factors that impact the results of the SPI,
monitor its progress, and, upon approval from its Board of Directors, adjust
the SPI as necessary to achieve its objective.

F-18

To date Old Dominion has collected cash totaling of $141.8 million ($65.0
million, $45.4 million, and $31.4 million in 2000, 1999, and 1998,
respectively) toward the revised SPI target of $241.0 million. Rates approved
by the Board of Directors for 2001 include the recovery of additional
depreciation of approximately $57.2 million. Old Dominion anticipates
collecting the remaining $99.2 million over the next three years to fulfill its
SPI goal.

In conjunction with the SPI, Old Dominion had purchased a total of $82.5
million of its higher cost debt, $33.3 million in 2000. In February 2001, Old
Dominion purchased an additional $1.6 million of its outstanding debt.

Combustion Turbine Generation Project--Old Dominion has entered into
contracts to purchase combustion turbines with a total rated capacity of 1,350
MW to be used in generating plants it is planning to construct. In November
2000, Old Dominion obtained a Certificate of Public Convenience and Necessity
("CPCN") from the Maryland Public Service Commission and all major
environmental permits subject to the CPCN conditions for a generation facility
to be located in Rock Springs, Maryland. Old Dominion may begin construction as
early as May 1, 2001. In October 2000, Old Dominion made application to the
Rural Utilities Service ("RUS") for approximately $210.0 million to permanently
finance its portion of the cost to construct the Rock Springs facility over the
next four years. The timing of the project is intended to coincide with the
expiration of power purchase contracts.

Old Dominion is also developing generation projects in Virginia to replace
expiring power purchase contracts in that power supply area and has made
application to RUS for approximately $493.0 million to permanently finance its
portion of the cost of these projects. These projects are still under
development and in the permitting process.

Legal--Old Dominion is subject to legal proceedings and claims which arise
from the ordinary course of business. In the opinion of management, the amount
of ultimate liability with respect to such actions will not materially affect
the consolidated financial position of Old Dominion.

Environmental--Old Dominion is currently subject to regulation by the
Environmental Protection Agency ("EPA") and other federal, state, and local
authorities with respect to the emission, discharge, or release of certain
materials into the environment. As with all electric utilities, the operation
of Old Dominion's generating units could be affected by any environmental
regulations promulgated in the future. Capital expenditures and increased
operating costs required to comply with any such future regulations could be
significant. Expenditures necessary to ensure compliance with environmental
standards or deadlines will continue to be reflected in Old Dominion's capital
and operating costs.

Old Dominion is subject to certain requirements of the Clean Air Act
("CAA"). The CAA requires utilities owning fossil fuel fired power stations to,
among other things, limit emissions of sulfur dioxide and nitrogen oxides, one
of the precursors of ground-level ozone, or obtain allowances for such
emissions. Clover is designed and licensed to operate at full capacity below
the permitted sulfur dioxide emissions levels and utilizes equipment which
operates at a level which is below the current limitations for nitrogen oxides
emissions.

In 1998, the EPA issued a Final Rule addressing regional transport of
ground-level ozone through reductions in nitrogen oxides (NOx) commonly known
as the NOx State Implementation Plan ("SIP") call. The NOx SIP call, which
affects 22 states, including Virginia and the District of Columbia, required
those states to develop a plan by October 30, 2000, to reduce NOx emissions in
the respective states. The NOx SIP call also required emissions reduction to be
implemented by May 1, 2004. On December 26, 2000, the EPA issued its findings
that several states covered by the SIP call, including Virginia, had failed to
submit a complete plan. If a state fails to make the required submittal, which
the EPA determines is complete, within 18 months of the findings, the emissions
offset sanction will apply. This sanction requires new or modified sources,
subject to the CAA new source review program for NOx, to obtain reductions in
existing emissions in a 2:1 ratio to offset their

F-19

new emissions. The sanctions will be lifted when the EPA finds that the state
has made a complete filing under the SIP call. The EPA can also promulgate a
federal implementation plan as late as two years after the initial findings,
unless the affected state has submitted a complete plan by that time. In a
federal plan, the EPA rather than the states would determine the specific
sources that must reduce NOx emissions. Old Dominion anticipates that fossil
fuel electric generation facilities greater than 250 mmBtu/hr. will be required
to reduce their NOx emissions or obtain NOx emissions credits from another
source. Old Dominion does not anticipate installing NOx controls at Clover but
rather will obtain NOx credits from a facility that has over-controlled its
emissions.

In a related action, several Northeast utilities filed petitions under
Section 126 of the CAA requesting that the EPA take action to mitigate
interstate transport of NOx. In December 1999, the EPA issued its Findings of
Significant Contribution and Rulemaking on Section 126 Petitions, Final Rule
establishing NOx allocations for 392 power plants, including Clover Units 1 and
2, and many industrial facilities. Additionally, this final rule established a
trading program to help those companies meet the required reductions in NOx by
May 3, 2003.

In December 2000, the EPA announced that to reduce the health risk of
mercury exposure, it will regulate emissions of mercury and other air toxins
from coal- and oil-fired electric utility steam generating units. Clover Units
1 and 2 would be subject to such regulation; however, as existing pollution
control equipment on these units currently reduce mercury emissions,
installation of additional equipment is not required at this time. The timeline
stated by the EPA for developing regulations in this area is that the EPA will
propose regulations by December 15, 2003, and issue final regulations by
December 15, 2004.

Old Dominion is also subject to permit limitations for surface water
discharge and for the operation of a combustion waste landfill at Clover.
Permits required by the Clean Water Act, the Resource Conservation and Recovery
Act, and state laws have been issued. These permits are subject to reissuance
and continued review.

Insurance--Under several of the nuclear insurance policies procured by
Virginia Power and to which Old Dominion is a party, Old Dominion is subject to
retrospective premium assessments in any policy year in which losses exceed the
funds available to the insurance companies. See Note 10 to the Consolidated
Financial Statements.

F-20

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED BALANCE SHEETS

June 30, December 31,
2001 2000
----------- ------------
(in thousands)
(unaudited) (*)

ASSETS:
Electric Plant:
In service........................................... $ 899,957 $ 900,290
Less accumulated depreciation........................ (334,267) (304,588)
---------- ----------
565,690 595,702
---------- ----------
Nuclear fuel, at amortized cost...................... 2,962 5,598
Construction work in progress........................ 80,389 47,598
---------- ----------
Net Electric Plant............................... 649,041 648,898
---------- ----------
Investments:
Nuclear decommissioning trust fund................... 60,374 60,530
Lease deposits....................................... 132,754 131,364
Other................................................ 57,545 54,836
---------- ----------
Total Investments................................ 250,673 246,730
---------- ----------
Current Assets:
Cash and cash equivalents............................ 32,046 20,259
Receivables.......................................... 44,500 46,769
Fuel, materials and supplies, at average cost........ 10,904 10,236
Prepayments.......................................... 1,898 1,508
Deferred energy...................................... 21,085 15,376
---------- ----------
Total Current Assets............................. 110,433 94,148
---------- ----------
Deferred Charges:....................................... 22,804 20,796
---------- ----------
Total Assets......................................... $1,032,951 $1,010,572
========== ==========
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital.................................... $ 220,994 $ 224,598
Accumulated other comprehensive income............... 642 (256)
Long-term debt....................................... 447,564 449,823
---------- ----------
Total Capitalization............................. 669,200 674,165
---------- ----------
Current Liabilities:
Long-term debt due within one year................... 30,488 30,488
Accounts payable..................................... 31,039 29,091
Accounts payable--Members............................ 45,222 20,912
Accrued expenses..................................... 6,877 6,849
---------- ----------
Total Current Liabilities........................ 113,626 87,340
---------- ----------
Deferred Credits and Other Liabilities:
Decommissioning reserve.............................. 60,374 60,530
Obligations under long-term leases................... 135,772 134,463
Other................................................ 53,979 54,074
---------- ----------
Total Deferred Credits and Other Liabilities..... 250,125 249,067
---------- ----------
Commitments and Contingencies........................... -- --
---------- ----------
Total Capitalization and Liabilities................. $1,032,951 $1,010,572
========== ==========

(*)The Consolidated Balance Sheet at December 31, 2000, has been taken from the
audited financial statements at the date, but does not include all
disclosures required by generally accepted accounting principles.

The accompanying notes are an integral part of the consolidated financial
statements.

F-21

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES, EXPENSES AND PATRONAGE CAPITAL
(UNAUDITED)

Six Months Ended
June 30,
------------------
2001 2000
-------- --------
(in thousands)

Operating Revenues................................. $234,221 $200,234
-------- --------
Operating Expenses:
Fuel............................................ 27,753 23,317
Purchased power................................. 123,428 80,976
Operations and maintenance...................... 17,304 17,594
Administrative and general...................... 11,455 9,394
Depreciation, amortization, and decommissioning. 31,658 40,826
Taxes other than income taxes................... 1,587 4,496
-------- --------
Total Operating Expenses.................... 213,185 176,603
-------- --------
Operating Margin................................... 21,036 23,631
Other Income/(Expense), net........................ 682 (713)
Investment Income.................................. 1,467 2,452
Interest Charges, net.............................. (19,289) (21,116)
-------- --------
Net Margin......................................... 3,896 4,254
Patronage Capital--Beginning of Period............. 224,598 216,369
Payment of Capital Credits......................... (7,500) --
-------- --------
Patronage Capital--End of Period................... $220,994 $220,623
======== ========

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF
COMPREHENSIVE INCOME (UNAUDITED)

Six Months Ended
June 30,
----------------
2001 2000
------ ------
(in thousands)

Net Margin........................ $3,896 $4,254
Other comprehensive income:
Unrealized gain on investments. 898 165
------ ------
Comprehensive income.............. $4,794 $4,419
====== ======

The accompanying notes are an integral part of the consolidated financial
statements.

F-22

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

Six Months Ended
June 30,
------------------
2001 2000
-------- --------
(in thousands)

Operating Activities:
Net margin........................................................................ $ 3,896 $ 4,254
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation, amortization, and decommissioning............................... 30,358 40,826
Other noncash charges......................................................... 4,051 4,081
Amortization of lease obligations............................................. 4,729 4,535
Interest on lease deposits.................................................... (4,629) (4,431)
Change in current assets...................................................... (4,498) (7,837)
Change in current liabilities................................................. 18,786 5,987
Deferred charges and other........................................................ (827) (2,049)
-------- --------
Net Cash Provided by Operating Activities.................................. 51,866 45,366
-------- --------
Financing Activities:
Reductions of long-term debt...................................................... (3,572) (32,985)
Obligations under long-term leases................................................ (180) (177)
-------- --------
Net Cash Used in Financing Activities......................................... (3,752) (33,162)
-------- --------
Investing Activities:
Lease deposits and other investments.............................................. (1,811) 392
Electric plant additions.......................................................... (34,176) (6,488)
Decommissioning fund deposits..................................................... (340) (340)
-------- --------
Net Cash Used in Investing Activities......................................... (36,327) (6,436)
-------- --------
Net Change in Cash and Cash Equivalents....................................... 11,787 5,768
Cash and Cash Equivalents--Beginning of Period....................................... 20,259 25,088
-------- --------
Cash and Cash Equivalents--End of Period............................................. $ 32,046 $ 30,856
======== ========

The accompanying notes are an integral part of the consolidated financial
statements.

F-23

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. In the opinion of the management of Old Dominion Electric Cooperative (Old
Dominion), the accompanying unaudited condensed consolidated financial
statements contain all adjustments, which include only normal recurring
adjustments, necessary for a fair statement of Old Dominion's consolidated
financial position as of June 30, 2001, and its consolidated results of
operations, comprehensive income, and cash flows for the three and six
months ended June 30, 2001 and 2000. The consolidated results of operations
for the three and six months ended June 30, 2001, are not necessarily
indicative of the results to be expected for the entire year. These
financial statements should be read in conjunction with the financial
statements and notes thereto included in Old Dominion's 2000 Annual Report
on Form 10-K filed with the Securities and Exchange Commission.

2. In 1997, we adopted certain strategic objectives designed to mitigate the
effects of transition to a competitive electric market, which became known
as our Strategic Plan Initiative. As part of our Strategic Plan Initiative,
our board of directors unanimously approved a resolution to record
accelerated depreciation on our generation assets from January 1, 1999
through December 31, 2003, and to recover the additional expense through
rates pursuant to our formulary rate. During the first half of 2001, we
recorded additional depreciation of $18.5 million ($4.2 million in the
second quarter) as compared to $26.2 million in the first half of 2000 ($8.3
million in the second quarter).

To date we have collected $160.3 million through our Strategic Plan
Initiative and have purchased $86.1 million of our outstanding debt ($3.6
million in the first half of 2001).

Based on current market projections, we believe that the $160.3 million
accumulated through the Strategic Plan Initiative since 1998 and held as
cash or investments or already applied to reduce our indebtedness is
sufficient to reduce our costs to a level which would enable the member
distribution cooperatives' rates for power to their customers to be at or
below projected market rates by January 1, 2004. As a result, we ceased
recording accelerated depreciation of our generating facilities effective
June 1, 2001. At the same time, our board of directors authorized a revenue
deferral plan for the period June 1, 2001 through December 31, 2002. Under
this plan we estimate that we will collect approximately $9.1 million
through our demand rate in 2001, which we will use to partially offset the
increases in our demand rate we expect in 2002. At June 30, 2001, we had
deferred $1.3 million, which is included in other assets and depreciation,
amortization and decommissioning expense.

3. Effective January 1, 2001, Old Dominion adopted Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and
Hedging Activities" (SFAS 133), as amended by Statement of Financial
Accounting Standards No. 138 (SFAS 138), "Accounting for Certain Derivative
Instruments and Certain Hedging Activities." The adoption of these
accounting standards did not have a significant effect on Old Dominion's
financial statements.

4. In June 2001, we formed ODEC Power Trading, Inc. ("ODEC Power Trading") with
$7.5 million of capital and immediately distributed the stock of ODEC Power
Trading as a patronage distribution to our member distribution cooperatives
on the same date. ODEC Power Trading is now owned by our member distribution
cooperatives to sell power in the market, manage the members' exposure to
changes in fuel prices and take advantage of other power trading
opportunities, which may become available in the market. In addition, to
facilitate ODEC Power Trading's ability to sell power to the market, we have
agreed to guarantee a maximum of $42.5 million of ODEC Power Trading's
delivery and payment obligations associated with its energy trades. Our
guarantee of ODEC Power Trading's obligations will enable it to maintain
credit support sufficient to meet its delivery and payment obligations
associated with its energy trades.

5. Certain reclassifications have been made to the accompanying prior year's
consolidated financial statements to conform to the current year's
presentation.

F-24

APPENDIX A

MEMBER FINANCIAL AND STATISTICAL INFORMATION

Our member distribution cooperatives operate their systems on a
not-for-profit basis. Accumulated margins remaining after payment of expenses
and provision for depreciation constitute patronage capital of the customers of
these members. Refunds of accumulated patronage capital to the individual
customers are made from time to time on a patronage basis subject to each
member distribution cooperative's policies and in conformity with limitations
contained in each member distribution cooperative's mortgage. These mortgages
generally prohibit these distributions unless, afterwards, the member
distribution cooperative'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 earned by the member distribution cooperative in the
preceding year, provided that, after the distribution, the total equity of the
member distribution cooperative will equal or exceed 20% of its assets.

The member distribution cooperatives are not our subsidiaries, but rather
our owners. We have no legal interest in the properties, liabilities, equity,
revenues or margins of the member distribution cooperatives. The revenues of
our member distribution cooperatives are not pledged to us, but their revenues
are the source from which they pay for power received from us. Revenues of the
member distribution cooperatives are, however, pledged under their respective
mortgages or other financial documents.

Financial and statistical information relating to the member distribution
cooperatives is set forth below. This information about our member distribution
cooperatives may not be indicative of their future results. The recent
enactment of legislation enabling retail customers to choose their supplier of
electric service, but not transmission and distribution service, may
significantly affect the member distribution cooperatives' future results and
financial condition. See "BUSINESS--Retail Competition" for a discussion of the
new electric restructuring legislation in Virginia, Maryland and Delaware.

The information contained in these tables has been taken from RUS Financial
and Statistical Reports (RUS Form 7) prepared by our member distribution
cooperatives. Neither we nor the RUS has independently verified this
information. We have compiled the information in the "Total" columns for
informational purposes only.

A-1

TABLE 1

OLD DOMINION ELECTRIC COOPERATIVE

SELECTED STATISTICS OF EACH MEMBER/*/
(AS OF DECEMBER 31)

A&N BARC Choptank Community Delaware
----- ----- -------- --------- --------

2000
----
Full time employees.................................... 40 48 159 30 115
Total miles energized.................................. 1,167 1,913 5,207 1,430 5,027
Average monthly residential revenue (dollars).......... 75.77 74.94 99.43 111.03 90.34
Average monthly residential kilowatt-hours............. 874 828 1,064 1,346 1,031
Average residential revenue (dollars) per kilowatt-hour 8.67 9.05 9.34 8.25 8.76
Times interest earned ratio............................ 1.55 1.37 1.55 2.81 2.41
Debt service coverage.................................. 2.37 1.61 2.32 2.93 3.34
Total equity (percentage of assets).................... 39.3 36.1 42.2 51.1 48.2

1999
----
Full time employees.................................... 40 48 157 30 112
Total miles energized.................................. 1,154 1,843 5,137 1,415 4,902
Average monthly residential revenue (dollars).......... 73.19 72.69 99.23 104.79 87.76
Average monthly residential kilowatt-hours............. 849 811 1,056 1,280 1,013
Average residential revenue (dollars) per kilowatt-hour 8.62 8.97 9.40 8.19 8.67
Times interest earned ratio............................ 1.51 1.34 2.16 2.47 2.56
Debt service coverage.................................. 2.34 1.66 2.91 2.62 3.40
Total equity (percentage of assets).................... 42.3 37.3 43.1 49.6 47.2

1998
----
Full time employees.................................... 40 51 145 30 110
Total miles energized.................................. 1,138 1,827 5,092 1,402 4,796
Average monthly residential revenue (dollars).......... 69.37 71.12 96.23 103.57 86.34
Average monthly residential kilowatt-hours............. 814 802 1,025 1,285 968
Average residential revenue (dollars) per kilowatt-hour 8.52 8.86 9.39 8.06 8.92
Times interest earned ratio............................ 1.97 1.54 2.52 2.52 2.43
Debt service coverage.................................. 2.23 1.81 6.37 2.44 3.24
Total equity (percentage of assets).................... 41.9 37.7 41.5 47.5 45.5

*These statistics were compiled from RUS Form 7 Financial and Statistical
Reports.

A-2

TABLE 1 - (Continued)

OLD DOMINION ELECTRIC COOPERATIVE

SELECTED STATISTICS OF EACH MEMBER/*/
(AS OF DECEMBER 31)

Northern Northern Prince Shenandoah
Mecklenburg Neck Virginia George Rappahannock Valley Southside Total
----------- -------- -------- ------ ------------ ---------- --------- ------

122 48 315 34 267 113 156 1,447
4,145 1,806 4,950 1,058 10,294 4,701 7,340 49,038
79.20 85.61 102.74 104.84 109.78 87.34 97.63 97.04
931 948 1,150 1,335 1,229 1,206 1,079 1,107
8.51 9.03 8.93 7.85 8.93 7.24 9.05 8.76
1.72 1.48 2.88 2.44 2.10 1.88 1.46 2.11
1.82 2.24 2.66 2.66 2.21 1.99 1.69 2.32
38.4 50.2 52.6 47.9 43.4 44.8 32.0 45.0

126 48 288 31 258 111 150 1,399
4,107 1,779 4,927 1,045 9,984 4,638 7,210 48,141
78.01 82.90 106.50 100.94 103.56 85.31 92.06 95.12
924 928 1,205 1,290 1,179 1,173 1,043 1,063
8.45 8.94 8.84 7.83 8.78 7.27 8.83 8.57
1.55 1.52 3.25 2.31 1.77 1.70 1.20 2.16
2.00 2.57 2.91 2.41 1.77 1.97 1.45 2.33
40.2 51.2 51.3 52.2 42.5 44.1 33.1 44.5

123 47 279 28 255 112 146 1,366
4,072 1,745 4,836 1,026 9,788 4,580 7,087 47,389
75.70 80.79 100.85 95.17 100.15 82.28 91.12 91.89
920 914 1,198 1,228 1,162 1,171 1,044 1,079
8.23 8.84 8.42 7.75 8.62 7.03 8.73 8.52
2.19 2.41 3.43 2.16 1.93 2.01 1.65 2.43
2.17 2.75 3.05 2.29 2.03 2.25 2.08 2.67
41.6 54.0 49.4 52.8 41.1 46.5 34.4 44.2

A-3

TABLE 2

OLD DOMINION ELECTRIC COOPERATIVE

AVERAGE NUMBER OF CUSTOMERS SERVED BY EACH MEMBER/*/

A&N BARC Choptank Community Delaware
------ ------ -------- --------- --------

2000
----
Residential service (farm and non-farm) 9,692 10,669 37,765 7,907 53,237
Commercial and industrial--Small....... 611 583 2,722 1,423 3,974
Commercial and industrial--Large....... 2 2 15 2 2
Irrigation............................. 67 0 0 9 167
Other electric service................. 127 0 265 28 403
------ ------ ------ ----- ------
Total customers served.............. 10,499 11,254 40,767 9,369 57,783

1999
----
Residential service (farm and non-farm) 9,544 10,460 37,175 7,795 51,928
Commercial and industrial--Small....... 577 582 2,505 1,391 3,974
Commercial and industrial--Large....... 2 2 14 2 1
Irrigation............................. 61 0 0 8 167
Other electric service................. 116 0 247 24 403
------ ------ ------ ----- ------
Total customers served.............. 10,300 11,044 39,941 9,220 56,473

1998
----
Residential service (farm and non-farm) 9,460 10,301 36,679 7,708 50,736
Commercial and industrial--Small....... 575 571 2,360 1,378 3,832
Commercial and industrial--Large....... 2 3 12 1 1
Irrigation............................. 61 0 0 7 155
Other electric service................. 108 0 204 21 388
------ ------ ------ ----- ------
Total customers served.............. 10,206 10,875 39,255 9,115 55,112

*These statistics were compiled from RUS Form 7 Financial and Statistical
Reports.

A-4

TABLE 2 - (Continued)

OLD DOMINION ELECTRIC COOPERATIVE

AVERAGE NUMBER OF CUSTOMERS SERVED BY EACH MEMBER/*/

Northern Northern Prince Shenandoah
Mecklenburg Neck Virginia George Rappahannock Valley Southside Total
----------- -------- -------- ------ ------------ ---------- --------- -------

27,392 14,480 92,394 8,308 71,297 28,229 43,319 404,689
1,347 845 6,443 829 3,768 4,449 1,472 28,466
12 0 29 33 193 14 232 536
0 0 0 0 0 0 0 243
261 75 15 91 547 0 169 1,981
------ ------ ------ ----- ------ ------ ------ -------
29,012 15,400 98,881 9,261 75,805 32,692 45,192 435,915

26,976 14,210 88,315 7,915 68,684 27,619 42,156 392,777
1,302 835 6,089 801 3,678 4,167 1,412 27,313
12 0 28 30 182 14 217 504
0 0 0 0 0 0 0 236
258 75 18 90 516 0 150 1,897
------ ------ ------ ----- ------ ------ ------ -------
28,548 15,120 94,450 8,836 73,060 31,800 43,935 422,727

26,545 13,931 85,028 7,680 66,257 27,090 40,968 382,383
1,292 826 5,692 779 3,561 3,938 1,375 26,179
10 0 25 28 170 13 206 471
0 0 0 0 0 0 0 223
243 75 19 87 466 0 142 1,753
------ ------ ------ ----- ------ ------ ------ -------
28,090 14,832 90,764 8,574 70,454 31,041 42,691 411,009

A-5

TABLE 3

OLD DOMINION ELECTRIC COOPERATIVE

ANNUAL MEGAWATT-HOUR SALES BY CUSTOMER CLASS OF EACH MEMBER/*/

A&N BARC Choptank Community Delaware
------- ------- -------- --------- --------

2000
----
Residential service (farm and non-farm) 101,650 106,006 482,329 127,674 658,847
Commercial and industrial--Small....... 24,040 29,597 134,679 17,623 113,859
Commercial and industrial--Large....... 72,790 17,691 77,753 2,764 10,536
Irrigation............................. 721 0 0 205 771
Other electric service................. 1,677 0 205 7,111 5,444
------- ------- ------- ------- -------
Total megawatt-hour sales........... 200,878 153,294 694,966 155,377 789,457

1999
----
Residential service (farm and non-farm) 97,284 101,772 470,997 119,730 630,960
Commercial and industrial--Small....... 22,613 25,855 132,458 17,827 107,286
Commercial and industrial--Large....... 67,759 20,280 72,564 1,561 9,725
Irrigation............................. 858 0 0 135 2,478
Other electric service................. 1,627 0 352 6,628 5,009
------- ------- ------- ------- -------
Total megawatt-hour sales........... 190,141 147,907 676,371 145,881 755,458

1998
----
Residential service (farm and non-farm) 92,388 99,176 451,092 118,826 589,520
Commercial and industrial--Small....... 21,541 25,281 123,995 19,629 94,838
Commercial and industrial--Large....... 62,557 19,658 66,167 1,700 9,316
Irrigation............................. 768 0 0 332 1,989
Other electric service................. 1,573 0 430 6,239 4,726
------- ------- ------- ------- -------
Total megawatt-hour sales........... 178,827 144,115 641,684 146,726 700,389

*These statistics were compiled from RUS Form 7 Financial and Statistical
Reports.

A-6

TABLE 3 - (Continued)

OLD DOMINION ELECTRIC COOPERATIVE

ANNUAL MEGAWATT-HOUR SALES BY CUSTOMER CLASS OF EACH MEMBER/*/

Northern Northern Prince Shenandoah
Mecklenburg Neck Virginia George Rappahannock Valley Southside Total
----------- -------- --------- ------- ------------ ---------- --------- ---------

306,040 164,760 1,275,375 133,127 1,051,670 408,656 560,760 5,376,894
60,987 30,786 618,612 8,982 99,945 95,156 19,730 1,253,996
116,043 0 261,955 60,400 936,254 167,782 85,789 1,809,757
0 0 0 0 0 0 0 1,697
25,036 1,443 2,678 30,046 6,082 0 11,069 90,791
------- ------- --------- ------- --------- ------- ------- ---------
508,106 196,989 2,158,620 232,555 2,093,951 671,594 677,348 8,533,135

299,011 158,183 1,276,941 122,488 971,747 388,920 527,393 5,165,426
58,859 30,564 601,058 8,178 95,343 97,472 18,720 1,216,233
103,205 0 186,621 53,989 884,887 160,099 78,690 1,639,380
0 0 0 0 0 0 0 3,471
23,880 1,365 2,462 28,979 5,292 0 7,936 83,530
------- ------- --------- ------- --------- ------- ------- ---------
484,955 190,112 2,067,082 213,634 1,957,269 646,491 632,739 8,108,040

292,933 152,751 1,222,181 113,135 923,571 380,516 513,275 4,949,364
58,875 29,633 535,691 10,371 92,148 103,958 19,186 1,135,146
99,708 0 186,674 46,935 884,397 148,883 78,646 1,604,641
0 0 0 0 0 0 0 3,089
20,086 1,334 2,376 22,589 7,155 0 13,190 79,698
------- ------- --------- ------- --------- ------- ------- ---------
471,602 183,718 1,946,922 193,030 1,907,271 633,357 624,297 7,771,938

A-7

TABLE 4

OLD DOMINION ELECTRIC COOPERATIVE

ANNUAL REVENUES BY CUSTOMER CLASS OF EACH MEMBER/*/

A&N BARC Choptank Community Delaware
----------- ----------- ----------- ----------- -----------

2000
----
Residential service (farm and non-farm) $ 8,812,142 $ 9,594,712 $45,058,674 $10,534,632 $57,712,465
Commercial and industrial--Small....... 2,111,398 2,275,994 11,440,508 1,575,090 8,849,499
Commercial and industrial--Large....... 4,228,437 1,222,104 4,587,028 169,772 644,569
Irrigation............................. 71,110 0 0 31,015 58,810
Other electric service................. 166,815 0 78,648 556,784 687,221
----------- ----------- ----------- ----------- -----------
Total electric sales................ 15,389,902 13,092,810 61,164,858 12,867,293 67,952,564
Other operating revenue................ 256,752 214,945 927,203 132,419 793,366
----------- ----------- ----------- ----------- -----------
Total operating revenue............. $15,646,654 $13,307,755 $62,092,061 $12,999,712 $68,745,930
=========== =========== =========== =========== ===========
1999
----
Residential service (farm and non-farm) $ 8,382,377 $ 9,124,529 $44,267,321 $ 9,802,323 $54,683,608
Commercial and industrial--Small....... 1,979,307 2,185,473 11,191,047 1,568,465 8,159,393
Commercial and industrial--Large....... 3,806,501 1,174,965 4,217,028 89,902 619,971
Irrigation............................. 78,954 0 0 29,023 213,400
Other electric service................. 160,298 0 67,163 523,373 629,093
----------- ----------- ----------- ----------- -----------
Total electric sales................ 14,407,437 12,484,967 59,742,559 12,013,086 64,305,465
Other operating revenue................ 236,940 212,978 841,094 121,290 789,707
----------- ----------- ----------- ----------- -----------
Total operating revenue............. $14,644,377 $12,697,945 $60,583,653 $12,134,376 $65,095,172
=========== =========== =========== =========== ===========
1998
----
Residential service (farm and non-farm) $ 7,874,713 $ 8,791,660 $42,353,307 $ 9,579,406 $52,565,413
Commercial and industrial--Small....... 1,826,306 2,103,651 10,796,929 1,664,861 7,610,172
Commercial and industrial--Large....... 3,484,444 1,160,032 4,079,939 108,336 579,138
Irrigation............................. 63,693 0 0 32,945 179,935
Other electric service................. 145,465 0 64,091 501,685 600,785
----------- ----------- ----------- ----------- -----------
Total electric sales................ 13,394,621 12,055,343 57,294,266 11,887,233 61,535,443
Other operating revenue................ 221,672 212,764 274,844 115,988 801,869
----------- ----------- ----------- ----------- -----------
Total operating revenue............. $13,616,293 $12,268,107 $57,569,110 $12,003,221 $62,337,312
=========== =========== =========== =========== ===========

*These statistics were compiled from RUS Form 7 Financial and Statistical
Reports.

A-8

TABLE 4 - (Continued)

OLD DOMINION ELECTRIC COOPERATIVE

ANNUAL REVENUES BY CUSTOMER CLASS OF EACH MEMBER/*/

Northern Northern Shenandoah
Mecklenburg Neck Virginia Prince George Rappahannock Valley Southside Total
----------- ----------- ------------ ------------- ------------ ----------- ----------- ------------

$26,032,950 $14,876,158 $113,915,590 $10,451,665 $ 93,927,535 $29,585,909 $50,751,772 $471,254,204
4,834,196 2,588,116 48,480,651 734,859 9,095,678 7,407,798 1,690,076 101,083,863
5,997,707 0 13,654,104 3,227,972 37,689,528 8,222,205 5,617,040 85,260,466
0 0 0 0 0 0 0 160,935
1,702,272 125,819 431,646 1,790,177 602,628 0 811,885 6,953,895
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
38,567,125 17,590,093 176,481,991 16,204,673 141,315,369 45,215,912 58,870,773 664,713,363
294,781 334,472 1,897,892 158,306 1,279,555 501,629 356,497 7,147,817
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
$38,861,906 $17,924,565 $178,379,883 $16,362,979 $142,594,924 $45,717,541 $59,227,270 $671,861,180
=========== =========== ============ =========== ============ =========== =========== ============

$25,254,275 $14,136,475 $112,867,376 $ 9,586,863 $ 85,356,386 $28,274,468 $46,571,914 $448,307,915
4,594,485 2,539,307 44,032,101 670,615 8,524,201 7,538,881 1,562,249 94,545,524
5,434,199 0 11,700,727 2,744,291 34,686,527 7,250,156 5,154,752 76,879,019
0 0 0 0 0 0 0 321,377
1,593,952 118,099 395,181 1,713,493 514,624 0 642,921 6,358,197
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
36,876,911 16,793,881 168,995,385 14,715,262 129,081,738 43,063,505 53,931,836 626,412,032
300,695 322,288 2,122,353 133,271 1,415,495 408,776 304,870 7,209,757
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
$37,177,606 $17,116,169 $171,117,738 $14,848,533 $130,497,233 $43,472,281 $54,236,706 $633,621,789
=========== =========== ============ =========== ============ =========== =========== ============

$24,112,765 $13,505,741 $102,902,794 $ 8,770,764 $ 79,625,506 $26,747,093 $44,797,327 $421,626,489
4,459,867 2,406,048 42,856,142 796,903 8,130,650 7,409,346 1,565,127 91,626,002
4,802,831 0 11,656,197 2,443,479 32,059,883 6,965,956 4,990,317 72,330,552
0 0 0 0 0 0 0 276,573
1,290,656 114,195 388,057 1,357,545 662,555 0 998,418 6,123,452
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
34,666,119 16,025,984 157,803,190 13,368,691 120,478,594 41,122,395 52,351,189 591,983,068
295,731 312,708 2,122,069 130,111 1,125,528 375,928 300,021 6,289,233
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
$34,961,850 $16,338,692 $159,925,259 $13,498,802 $121,604,122 $41,498,323 $52,651,210 $598,272,301
=========== =========== ============ =========== ============ =========== =========== ============

A-9

TABLE 5

OLD DOMINION ELECTRIC COOPERATIVE

SELECTED STATISTICS OF EACH MEMBER/*/
(AS OF DECEMBER 31)

A&N BARC Choptank Community Delaware
----------- ----------- ----------- ----------- -----------

2000
----
Operating revenue and patronage
capital...................... $15,646,655 $13,307,755 $62,092,062 $12,999,712 $68,745,930
Depreciation and amortization.. 1,959,462 1,200,492 4,580,392 1,238,079 8,136,360
Other operating expenses....... 12,726,863 10,671,646 51,739,205 10,338,783 57,157,098
----------- ----------- ----------- ----------- -----------
Electric operating margins.. 960,330 1,435,617 5,772,465 1,422,850 3,452,472
Other income................... 368,829 321,815 1,298,628 420,636 3,448,261
----------- ----------- ----------- ----------- -----------
Gross operating margins........ 1,329,159 1,757,432 7,071,093 1,843,486 6,900,733
Interest on long-term debt..... 834,577 1,268,673 4,326,002 651,839 2,837,668
Other deductions............... 35,378 15,698 345,358 9,946 67,285
----------- ----------- ----------- ----------- -----------
Net margins................. $ 459,204 $ 473,061 $ 2,399,733 $ 1,181,701 $ 3,995,780
=========== =========== =========== =========== ===========
1999
----
Operating revenue and patronage
capital...................... $14,644,377 $12,697,945 $60,595,103 $12,134,376 $65,095,173
Depreciation and amortization.. 1,908,152 1,226,685 4,391,634 1,085,966 7,815,899
Other operating expenses....... 11,920,349 10,249,244 48,348,103 9,853,878 51,785,047
----------- ----------- ----------- ----------- -----------
Electric operating margins.. 815,876 1,222,016 7,855,366 1,194,532 5,494,227
Other income................... 331,423 314,262 1,577,445 441,970 1,793,171
----------- ----------- ----------- ----------- -----------
Gross operating margins........ 1,147,299 1,536,278 9,432,811 1,636,502 7,287,398
Interest on long-term debt..... 733,564 1,141,861 4,333,116 661,365 2,823,508
Other deductions............... 41,955 4,302 72,664 3,653 47,427
----------- ----------- ----------- ----------- -----------
Net margins................. $ 371,780 $ 390,115 $ 5,027,031 $ 971,484 $ 4,416,463
=========== =========== =========== =========== ===========
1998
----
Operating revenue and patronage
capital...................... $13,616,291 $12,268,107 $57,569,106 $12,003,221 $62,337,312
Depreciation and amortization.. 1,313,381 1,167,669 4,038,660 867,737 7,406,176
Other operating expenses....... 11,133,982 9,686,907 45,175,214 9,817,316 49,472,494
----------- ----------- ----------- ----------- -----------
Electric operating margins.. 1,168,928 1,413,531 8,355,232 1,318,168 5,458,642
Other income................... 308,904 310,019 1,900,604 447,095 1,695,974
----------- ----------- ----------- ----------- -----------
Gross operating margins........ 1,477,832 1,723,550 10,255,836 1,765,263 7,154,616
Interest on long-term debt..... 719,040 1,114,455 4,038,660 695,946 2,920,613
Other deductions............... 61,501 3,611 72,377 8,759 62,238
----------- ----------- ----------- ----------- -----------
Net margins................. $ 697,291 $ 605,484 $ 6,144,799 $ 1,060,558 $ 4,171,765
=========== =========== =========== =========== ===========

*These statistics were compiled from RUS Form 7 Financial and Statistical
Reports.

A-10

TABLE 5 - (Continued)

OLD DOMINION ELECTRIC COOPERATIVE
SELECTED STATISTICS OF EACH MEMBER/*/
(AS OF DECEMBER 31)

$38,861,906 $17,924,565 $178,550,033 $16,362,979 $142,594,924 $45,717,541 $59,227,270 $672,031,332
2,668,175 1,894,486 11,130,605 996,970 10,332,017 3,599,265 5,079,389 52,815,692
32,738,287 15,051,705 145,329,096 14,240,889 117,687,193 37,726,723 47,378,603 552,786,091
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
3,455,444 978,374 22,090,332 1,125,120 14,575,714 4,391,553 6,769,278 66,429,549
568,526 312,264 6,900,702 309,856 2,547,284 928,300 1,056,056 18,481,157
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
4,023,970 1,290,638 28,991,034 1,434,976 17,122,998 5,319,853 7,825,334 84,910,706
2,283,679 852,474 10,071,664 577,877 8,053,535 2,821,390 5,323,929 39,903,307
97,270 31,690 (44,125) 27,069 197,945 27,104 48,051 858,669
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
$ 1,643,021 $ 406,474 $ 18,963,495 $ 830,030 $ 8,871,518 $ 2,471,359 $ 2,453,354 $ 44,148,730
=========== =========== ============ =========== ============ =========== =========== ============

$37,177,606 $17,116,169 $171,082,535 $14,848,533 $130,497,233 $43,472,281 $54,236,706 $633,598,037
3,482,584 2,149,929 10,553,904 796,968 9,502,850 3,415,113 4,808,931 51,138,615
30,989,960 14,170,618 133,603,682 13,230,558 110,033,767 36,997,999 44,837,970 516,021,175
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
2,705,062 795,622 26,924,949 821,007 10,960,616 3,059,169 4,589,805 66,438,247
594,582 402,109 6,644,552 338,010 3,751,433 1,059,049 1,294,139 18,542,145
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
3,299,644 1,197,731 33,569,501 1,159,017 14,712,049 4,118,218 5,883,944 84,980,392
2,094,928 773,826 10,094,130 474,951 8,154,165 2,365,066 4,875,455 38,525,935
56,832 20,518 761,734 64,023 246,135 94,513 43,399 1,457,155
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
$ 1,147,884 $ 403,387 $ 22,713,637 $ 620,043 $ 6,311,749 $ 1,658,639 $ 965,090 $ 44,997,302
=========== =========== ============ =========== ============ =========== =========== ============

$34,961,850 $16,338,692 $159,925,259 $13,498,802 $121,604,122 $41,498,314 $52,651,210 $598,272,286
2,351,498 1,652,161 10,283,141 763,601 8,273,019 3,251,724 4,542,231 45,910,998
29,245,084 13,201,039 120,919,840 12,081,661 100,832,018 34,696,339 41,597,965 477,859,859
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
3,365,268 1,485,492 28,722,278 653,540 12,499,085 3,550,251 6,511,014 74,501,429
967,120 393,157 7,044,467 314,491 4,283,403 1,024,332 1,235,386 19,924,952
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
4,332,388 1,878,649 35,766,745 968,031 16,782,488 4,574,583 7,746,400 94,426,381
1,962,124 756,465 10,421,594 429,425 8,543,072 2,252,788 4,624,074 38,478,256
43,174 55,850 53,578 41,502 303,430 44,389 99,282 849,691
----------- ----------- ------------ ----------- ------------ ----------- ----------- ------------
$ 2,327,090 $ 1,066,334 $ 25,291,573 $ 497,104 $ 7,935,986 $ 2,277,406 $ 3,023,044 $ 55,098,434
=========== =========== ============ =========== ============ =========== =========== ============

A-11

APPENDIX B

SPECIMEN OF INSURANCE POLICY

B-1

Ambac Ambac Assurance Corporation
One State Street Plaza, 15th Floor
New York, New York 10004
Financial Guaranty Insurance Policy Telephone: (212) 668-0340

Obligor: Policy Number:

Obligations: Premium:

THE WORD SPECIMEN APPEARS DIAGONALLY ON FACE OF POLICY

Ambac Assurance Corporation (Ambac), a Wisconsin stock insurance corporation,
in consideration of the payment of the premium and subject to the terms of this
Policy, hereby agrees to pay to The Bank of New York, as trustee, or its
successor (the "Insurance Trustee"), for the benefit of the Holders, that
portion of the principal of and interest on the above-described obligations
(the "Obligations") which shall become Due for Payment but shall be unpaid by
reason of Nonpayment by the Obligor.

Ambac will make such payments to the Insurance Trustee within one (1) business
day following written notification to Ambac of Nonpayment. Upon a Holder's
presentation and surrender to the Insurance Trustee of such unpaid Obligations
or related coupons, uncanceled and in bearer form and free of any adverse
claim, the Insurance Trustee will disburse to the Holder the amount of
principal and interest which is then Due for Payment but is unpaid. Upon such
disbursement, Ambac shall become the owner of the surrendered Obligations
and/or coupons and shall be fully subrogated to all of the Holder's rights to
payment thereon.

In cases where the Obligations are issued in registered form, the Insurance
Trustee shall disburse principal to a Holder only upon presentation and
surrender to the Insurance Trustee of the unpaid Obligation, uncanceled and
free of any adverse claim, together with an instrument of assignment, in form
satisfactory to Ambac and the Insurance Trustee duly executed by the Holder or
such Holder's duly authorized representative, so as to permit ownership of such
Obligation to be registered in the name of Ambac or its nominee. The Insurance
Trustee shall disburse interest to a Holder of a registered Obligation only
upon presentation to the Insurance Trustee of proof that the claimant is the
person entitled to the payment of interest on the Obligation and delivery to
the Insurance Trustee of an instrument of assignment, in form satisfactory to
Ambac and the Insurance Trustee, duly executed by the Holder or such Holder's
duly authorized representative, transferring to Ambac all rights under such
Obligation to receive the interest in respect of which the insurance
disbursement was made. Ambac shall be subrogated to all of the Holders' rights
to payment on registered Obligations to the extent of any insurance
disbursements so made.

In the event that a trustee or paying agent for the Obligations has notice that
any payment of principal of or interest on an Obligation which has become Due
for Payment and which is made to a Holder by or on behalf of the Obligor has
been deemed a preferential transfer and theretofore recovered from the Holder
pursuant to the United States Bankruptcy Code in accordance with a final,
nonappealable order of a court of competent jurisdiction, such Holder will be
entitled to payment from Ambac to the extent of such recovery if sufficient
funds are not otherwise available.

As used herein, the term "Holder" means any person other than (i) the Obligor
or (ii) any person whose obligations constitute the underlying security or
source of payment for the Obligations who, at the time of Nonpayment, is the
owner of an Obligation or of a coupon relating to an Obligation. As used
herein, "Due for Payment", when referring to the principal of Obligations, is
when the scheduled maturity date or mandatory redemption date for the

B-1

application of a required sinking fund installment has been reached and does not
refer to any earlier date on which payment is due by reason of call for
redemption (other than by application of required sinking fund installments),
acceleration or other advancement of maturity; and, when referring to interest
on the Obligations, is when the scheduled date for payment of interest has been
reached. As used herein, "Nonpayment" means the failure of the Obligor to have
provided sufficient funds to the trustee or paying agent for payment in full of
all principal of and interest on the Obligations which are Due for Payment.

This Policy is noncancelable. The premium on this Policy is not refundable for
any reason, including payment of the Obligations prior to maturity. This Policy
does not insure against loss of any prepayment or other acceleration payment
which at any time may become due in respect of any Obligation, other than at
the sole option of Ambac, nor against any risk other than Nonpayment.

In witness whereof, Ambac has caused this Policy to be affixed with a facsimile
of its corporate seal and to be signed by its duly authorized officers in
facsimile to become effective as its original seal and signatures and binding
upon Ambac by virtue of the countersignature of its duly authorized
representative.

/s/ Robert J. XXXXX AMBAC ASSURANCE CORPORATION /s/ Anne G. Gill
CORPORATE

President _____ Secretary
SEAL
_____

Effective Date WISCONSIN Authorized Representative

THE BANK OF NEW YORK acknowledges that it has agreed /s/ Noraida Lauro
to perform the duties of Insurance Trustee under this Policy.

Form No.: 2B-0012(1/01) Authorized Officer of Insurance Trustee

B-2

--------------------------------------
--------------------------------------

You should rely only on the information contained in this prospectus. We
have not authorized anyone to provide you with information different from that
contained in this prospectus. We are offering to sell, and seeking offers to
buy, the 2001 Series A Bonds only in jurisdictions where offers and sales are
permitted. The information contained in this prospectus is accurate only as of
the date of this prospectus, regardless of the time of delivery of this
prospectus or of any sale of the 2001 Series A Bonds.

-----------------

TABLE OF CONTENTS
Page
----
Summary................................. 3
Background.............................. 11
Plan of Finance and Use of Proceeds..... 13
Selected Financial Data................. 15
Management's Discussion and Analysis
of Financial Condition and Results of
Operations............................ 16
Quantitative and Qualitative Disclosures
About Market Risk..................... 30
Business................................ 32
Power Supply Resources.................. 43
Regulation and Legal Proceedings........ 53
Management.............................. 57
Bond Insurance.......................... 63
Description of The Bonds................ 65
Federal Income Tax Matters.............. 80
Underwriting............................ 81
Legal Opinions.......................... 81
Experts................................. 82
Where to Find Additional Information
About Us.............................. 82
Index to Financial Statements........... F-1
Appendix A--Member Financial and
Statistical Information............... A-1
Appendix B--Specimen Insurance
Policy................................ B-1
-----------------

Until November 4, 2001, all dealers that effect transaction in our 2001
Series A Bonds, whether or not participating in this offering, may be required
to deliver a prospectus. This requirement is in addition to the dealer's
obligation to deliver a prospectus when acting as underwriters and with respect
to their unsold allotments or subscriptions.

--------------------------------------
--------------------------------------

$215,000,000

Old Dominion
Electric Cooperative

2001 Series A Bonds Due 2011

[LOGO] Old Dominion Electric Cooperative

-----------------

PROSPECTUS

-----------------

JPMorgan

Banc of America Securities LLC

--------------------------------------
--------------------------------------