Text

Decommissioning Financial Assurance, Attachments 1 and 2
	ML030930425
Person / Time
Site:	North Anna
Issue date:	03/28/2003
From:	Walker D; Old Dominion Electric Cooperative
To:	; Document Control Desk, Office of Nuclear Reactor Regulation
References
	Download: ML030930425 (188)
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Attachment 1 OLD DOMINION ELECTRIC COOPERATIVE NORTH ANNA POWER STATIONS UNITS 1 AND 2 2003 NUCLEAR DECOMMISSIONING FINANCIAL ASSURANCE North Anna' North Anna1 Unit I Unit 2 Total For NPF-4 NPF-7 All Units 2003 NRC Minimum Financial Assurance Amount: $38.23 $38.23 $76.45 Projected Annual Escalation Factors In Decommissiong Costs: 4.28% 4.28% 4.28%

Year Operating License Expires: 2038 2040 2003 NRC Minimum Financial Assurance Amounts Stated In Future Dollars: $209.71 $214.56 $424.27 Funds Held In External Trust At December 31, 20022: $22.73 $23.26 $45.99 Old Dominion's Current Annual Sinking Fund Contributions2'3 : $0.27 $0.28 $0.55 Expected Earnings On Existing Decommissioning Funds- 7.31% 7.31% 7.31%

Annual Funding Levels Necessary To Meet 2002 NRC Minimum Financial Assurance Amount: 0.00 0.00 0.00 1 The North Anna Power Station is jointly owned by Virginia Electric and Power Company (88.4%) and Old Dominion Electric Cooperative (11.6%). However, Old Dominion Electric Cooperative is responsible for 10.74% of the decommissioning obligation. The amounts stated in the above tables reflect only that portion of the decommissioning obligation attributable to Old Dominion Electric Cooperative.

2 Excludes amounts designated for the decommissioning of the independent spent fuel storage installation.

3Old Dominion Electric Cooperative relies upon the sinking fund method for providing financial assurance.

Attachment 2 "All-Requirements" Wholesale Power Contracts Between Old Dominion Electric Cooperative and A&N Electric Cooperative, BARC Electric Cooperative, Choptank Electric Cooperative, CommunitV Electric Cooperative, Delaware Electric Cooperative, Mecklenburq 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

OLD DOMINION ELECTRIC COOPERATIVE AMENDED AND RESTATED WHOLESALE POWER CONTRACT THIS AMENDED AND RESTATED CONTRACT is made as of this 24th day of April , 1992, between OLD DOMINION ELECTRIC COOPERATIVE (hereinafter called the "Seller"), a corporation organized and existing under the laws of the Commonwealth of Virginia, and A & N ELECTRIC COOPERATIVE (hereinafter called the "Member"), a corporation organized and existing under the laws of the State of Virginia.

RECITALS:

A. The Seller has executed contracts to acquire ownership of certain electric generating facilities and to construct electric generating facilities, or a transmission system, or both, and may purchase or otherwise obtain electric power and energy for the purpose, among others, of supplying electric power and energy to certain rural electric cooperatives (the "Coopera-tives") which are or may become members of the Seller.

B. The Seller has heretofore entered into contracts for the sale of electric power and energy with Cooperatives which are members of the Seller (such contracts as they may have been amended and supplemented to the date hereof are hereinafter referred to as the "Original Wholesale Power Contracts").

C. In reliance upon the commitments of the Seller herein set forth, the Member is entering into this contract and the Member acknowledges by entering into this contract that the Seller (i) has obtained and will obtain financing, (ii) has invested and will in the future invest in plant and facilities, (iii) has developed and will continue to develop an organizational structure, management team and staff, (iv) has engaged and will continue to engage in planning, and (v) has made and will continue to make commitments relating to long-term power supply arrangements, all on the basis of the cash flow produced by this contract and similar contracts between the Seller and its other members.

D. The Seller has entered into certain contracts in connection with the construction of a two unit, coal-fired electric generating station located in Clover, Virginia (the "Clover Generating Station") and has acquired an undivided ownership interest in the Clover Generating Station.

E. In connection with the financing of the construction costs of the Clover Generating Station, the Seller and the Member desire to reaffirm the terms and provisions of the Original Wholesale Power Contract (except as amended hereby) and to amend and restate the Original Wholesale Power Contract as provided herein. The Seller intends to enter into similar contracts with all Cooperatives which are members of the Seller and may enter into similar contracts with Cooperatives who become Members of the Seller in the future (the Original Wholesale Power Contracts as so amended and restated together with such additional contracts may be collectively referred to herein as the "Wholesale Power Con-tracts").

F. The Seller is incurring debt to construct, improve or acquire facilities which are intended to directly or indirectly benefit the Member and its members as well as other members of the Seller, although the Member recognizes that such benefits cannot be assured.

G. The Member has determined that its interest and the interest of its own members will be best served by entering in.to this contract with the Seller in lieu of undertaking the risks of developing other sources of electricity itself or of purchasing electricity from other sources.

H. The Member desires to purchase electric power and energy from the Seller, and the Seller desires to sell, electric power and energy to the Member on the terms and conditions set forth in this Amended and Restated Contract as follows:

WITNESSETH:

NOW THEREFORE, in consideration of the mutual undertak-ings herein contained, the parties agree that the Original Wholesale Power Contract between them be, and hereby is, amended and restated to read in its entirety as follows:

1. GENERAL. Except as otherwise provided in this Section 1, the Seller shall sell and deliver to the Member and the Member shall purchase and receive from the Seller all electric power and energy which the Member shall require for the operation of the Member's system to the extent that the Seller shall have the power, energy and facilities available.

The Member shall have the right to continue to purchase electric power and energy under any contract or contracts existing on March 1, 1992 with a supplier other than the Seller during the remainder of the term thereof, and with respect to power acquired from the Southeastern Power Administration ("SEPA"), or its successor, shall have the right to extend such contracts or to enter into new contracts unless the Seller shall qualify as a customer of and contract for electric service from SEPA or its successor. All such existing contracts which the Member is a party to are set forth on Schedule 1 hereto.

If the Member continues to purchase electric power and energy under a contract or contracts with a supplier or suppliers other than Seller, and other than SEPA, then the power and energy purchased under such contract or contracts shall be paid for by Seller for the account of the Member, and the Member shall be billed by Seller for such power and energy in accordance with the terms and conditions of Section 4. The Member shall terminate, if the Seller shall so request, any such existing contract or contracts with a supplier other than the Seller or SEPA, or its successor, at such times as it may legally do so, provided the Seller shall have sufficient electric power and energy and facilities available for the Member.

The Seller and the Member agree that if the Member, upon being requested to do so by the Seller, shall fail to terminate any contract with a power supplier other than the Seller or SEPA, the Seller shall have the right to enforce the obligations of the Member under the provisions of this Section 1 by instituting all necessary actions at law or suits in equity, including, without limitation, suits for specific performance. Except contracts with Seller and SEPA as provided by this Section 1, the Member will not renew, amend or extend any power contract or contracts or enter into any new power contract without approval of Seller.

The Member may continue to utilize the power and energy produced by its owned generating facilities set forth on Schedule 1 hereto.

In the event that, pursuant to the Public Utility Regulatory Policies Act of 1978 or other provisions of law, electric power is required to be purchased from a small power production facility, a cogeneration facility or other facility, the Member shall make the required purchases and sell the power purchased to the Seller should Seller elect to accept such purchases. Any such required purchases made by the Member shall be at a rate not to exceed the Seller's avoided cost as established by the Seller. At Seller's option the Member shall then sell such electric power to the Seller at a price not to exceed such rate.

The Member may appoint the Seller to act as its agent in all dealings with the owner of any such facility from which power is to be purchased and in connection with all other matters relating to such purchases.

2. ELECTRIC CHARACTERISTICS AND POINTS OF DELIVERY.

Electric power and energy to be furnished hereunder shall be alternating current, sixty hertz.

As used in this contract, "Points of Delivery", shall be those points where the system of the Member is connected to the transmission or distribution system that the Seller has ownership of, or right to deliver power and energy through.

The Member shall keep the Seller advised concerning anticipated loads at established points of delivery and the need for additional points of delivery by furnishing to the Seller each year, on a date to be established by the Seller from time to time and communicated to the Member at least sixty (60) days in advance of any changed date, a revised "Exhibit A" substantially in the form attached to and made a part of this contract.

The initial point or points of delivery and their initial delivery voltages shall be as set forth in "Exhibit B" attached to and made a part of this contract. Other points of delivery and their initial delivery voltages may be established by mutual agreement of the Member and the Seller, and "Exhibit B" shall be revised accordingly.

3. DELIVERY FACILITIES. Bulk power supply planning shall be the responsibility of the Seller. The Seller shall be responsible for the facilities to deliver power and energy to the point(s) of delivery. The Member shall be responsible for the facilities to take and use the power and energy from the point(s) of delivery. The parties shall provide and maintain, or cause to be provided and maintained, switching and protective equipment which may be reasonably necessary to protect the system of the other.

Meters and metering equipment shall be, or caused to be, furnished, maintained and read by the Seller. Special equipment furnished at the request of the Member shall be listed on "Exhibit C" attached to and made a part of this contract.

4. RATE. (a) The Member shall pay the Seller for all electric power and energy furnished hereunder at rates and charges determined pursuant to the formula set forth in "Exhibit D" attached hereto and made a part of this contract and on the terms and conditions set forth in "Exhibit D". "Exhibit DI' contains a formula pursuant to which rates and charges are to be set from time to time as follows:

(i) The Board of Directors of the Seller shall approve a budget annually which "x" provides for all costs and expenses of the Seller as set forth in paragraph (b) of this Section 4 and "y" estimates sales of power and energy. Approval of such budget will result in rates and charges by operation of the formula set forth in "Exhibit D", sufficient, but only sufficient, with the revenues of the Seller from all other sources, to meet such costs and expenses.

(ii) If at any time during a year it becomes apparent that the then current budget no longer accurately reflects such costs and expenses or sales of power and energy, the Board of Directors may revise such budget which revision will result in new rates and charges by operation of the formula set forth in "Exhibit D".

(iii) In the event that the actual costs and expenses of the Seller and/or sales of power and energy during any year shall differ from those reflected in the budget for such year, as from time to time revised, such that the rates and charges collected during such year shall not equal the amount (the "Actual Amount")

which would result from applying the formula to such actual costs and expenses and sales of power and energy, then such rates and charges shall be revised so that, as so revised, the rates and charges equal the Actual Amount. Any amounts owed as a result of such revision by the Seller to the Member or by the Member to the Seller shall be paid over the next ensuing year by adjustments to the payments required pursuant to this Section 4 for such ensuing year provided, however, such adjustments shall, for all purposes, be treated as due, owing, incurred and accrued for the year to which such revision relates.

(b) The formula initially set forth in "Exhibit D" is intended to meet all costs and expenses paid or incurred or to be paid or incurred by the Seller (including amortization, deprecia-tion or other charges recorded on the Seller's books) resulting from the ownership, operation, maintenance, termination, retirement from service and decommissioning of, and repairs, renewals, replacements, additions, improvements, betterments and modifica-tions to, the generating plants, transmission system and related facilities of the Seller or otherwise relating to the acquisition and sale of power and energy, transmission, load management, conservation or related services hereunder and performance by the Seller of its obligations under the Wholesale Power Contracts including, without limitation, the following items of cost:

(i) payments of principal of and premium, if any, and interest on all debt issued by the Seller; provided, however, that rates shall not include any principal of or premium, if any, or interest on any debt due solely by virtue of the acceleration of the maturity of such debt; (ii) amounts which the Seller may be required to pay for the prevention or correction of any loss or damage to its generat-ing plants, transmission system or related facilities or for renewals, replacements, repairs, additions, improvements, betterments, and modifications which are necessary to keep'any such facilities whether owned by the Seller or available to the Seller under -any contract, in good operating condition or to prevent a loss of revenues therefrom; (iii) costs of operating and maintaining the Seller's generating plants, transmission system or related facilities and of producing and delivering power and energy therefrom (including, without limitation, fuel costs, administrative and general expenses and working capital, for fuel or otherwise, regulatory costs, insurance premiums, and taxes or payments in lieu thereof);

(iv) the cost of any electric power and energy purchased for resale by the Seller under the Wholesale Power Contracts and the costs of transmission, scheduling, dispatching and controlling services for delivery of electric power and energy under the Wholesale Power Contracts; (v) all costs incurred or associated with the salvage, discontinuance, decommissioning and disposition or sale of properties; (vi) all costs, settlements and expenses relating to claims asserted against the Seller; (vii) any additional cost or expense not specified in the other items of this subsection (b) imposed or permitted by any regulatory agency or which is paid or incurred by the Seller relating to its generating plants, transmission system or related facilities or relating to the provision of services to the Members which is not otherwise included in any of the costs specified herein; (viii) amounts required to be paid by the Seller under any contract to which it is a party not covered under any other clause of this subsection (b) including, without limitation, amounts payable with respect to interest rate swaps, option contracts and hedging contracts; (ix) reserves the Seller shall determine to be necessary for the payment of those items of costs and expenses referred to in this subsection (b) to the extent not already included in any other clause of this subsection (b); and (x) additional amounts which must be realized by the Seller in order to meet the requirement of any rate covenant with respect to coverage of principal of and interest on its debt contained in any indenture or contract with holders of its debt or which the Board of Directors deems advisable in the marketing of its debt.

If at any time the Board of Directors shall determine that the formula set forth in "Exhibit DI does not meet all such costs and expenses it may, subject to any necessary regulatory review and/or approval, adopt a new formula to meet all such costs and expenses.

(c) The formula from time to time set forth in "Exhibit D" and the rates and charges established thereby shall at all times be sufficient to enable the Seller to comply with all mortgage, indenture, regulatory and governmental requirements as they may exist from time to time.

(d) The Seller shall cause a notice in writing to be given to the Member and all other members of the Seller which shall set out all the proposed revisions of the formula with the effective date of the revised formula which shall not be less than thirty (30) no more than ninety (90) days after the date of the notice and-shall set forth the basis upon which the formula is proposed to be adjusted and established. The Member agrees that the formula from time to time established by the Board of Directors of the Seller shall be deemed to be substituted for the formula thereto set forth in "Exhibit D" and agrees to pay for electric power and energy furnished by the Seller to it after the effective date of any such revision at rates and charges set pursuant to the revised formula.

5. METER READINGS AND PAYMENT OF BILLS. Attached to and made a part of this contract is "Exhibit D", which establishes the rates to be charged and defines the following:

a. The intervals at which the Seller shall read, or cause to be read, the electric meters;

b. The date on which, and the office to which, all accounts shall be paid for electric power and energy furnished by the Seller; C. The penalty to a member who shall fail to pay its bill within the designated pay period, which penalty shall include, but not be limited to, late payment charges and conditions under which the Seller may discontinue delivery of electric power and energy;

d. The time and manner of delivery of notices.

6. METER TESTING AND BILLING ADJUSTMENT. The Seller shall test and calibrate, or cause to be tested and calibrated, meters by comparison with accurate standards at intervals not greater than the periodic test schedule for the type of meter in use as set forth in the Code for Electricity Metering ANSI C12-1975 or later revisions. The Seller shall also make, or cause to be made, special meter tests at any time at the Members request.

The costs of all tests shall be borne by the Seller; however, if a special meter test made at the Member's request shall disclose that the meters are recording accurately, the Member shall reimburse the Seller for the cost of such test. Meters registering not more than two percent (2%) above or below normal shall be deemed accurate. The readings of any meter which shall have been disclosed by test to be inaccurate shall be corrected for the period the inaccuracy is known, or for a mutually agreed upon period, or lacking knowledge or agreement, a period of ninety (90) days from the date of discovery of such inaccuracy or malfunction in accordance with the percentage of inaccuracy found by such test.

If any meter shall fail to register for any period, the Member and the Seller shall agree as to the amount of energy furnished during such period and the Seller shall render a bill for that amount.

7. NOTICE OF METER READING OR TEST. Upon request, the Seller shall notify the Member in advance of the time of any meter reading or test so that the Member's representative be present at the meter reading or test. Representatives of Seller and Seller's affected power supplier, if any, shall be afforded the opportunity to be present at all routine or special tests.

8. RIGHT OF ACCESS. Duly authorized representatives of either party shall be permitted to enter the premises of the other party at all reasonable times in order to carry out the provisions of this contract.

9. CONTINUITY OF SERVICE. The parties shall use reasonable diligence to deliver and receive a constant and uninterrupted supply of electric power and energy. If the supply of electric power and energy shall fail, or be interrupted, or become defective through an act of God, force majeure, or of the public enemy, or because of accident, labor troubles, or any other cause beyond the control of the Seller, the Seller shall not be liable for damages caused by the failure, interruption or defect.

In the event of any interruption of service, the parties shall use all due diligence to restore their respective systems to enable the delivery and receipt of power.

In the event of a power shortage, or an adverse condition or disturbance, the Seller may, without incurring liability, take such emergency action as, in the judgement of the Seller, may be necessary. Such emergency action may include, but not be limited to, reduction or interruption of the supply of electricity to some points of delivery in order to compensate for an emergency condition on the system of the Seller, or on any other directly or indirectly interconnected system.

10. TERM. This contract shall become effective only upon approval in writing by the Administrator of the Rural Electrification Administration (the "Administrator") and shall remain in effect for a term of forty-five (45) years from the effective date of the Original Wholesale Power Contract and thereafter until terminated by either party giving to the other not less than three (3) years written notice of its intention to terminate. Subject to the provisions of Article 1, service supplied and the obligation of the Member to pay shall commence upon Seller making service available to Member.

11. TRANSFERS BY THE MEMBER. During the term of this contract, the Member will not, without the approval in writing of the Seller and, so long as the Member remains a borrower of the Rural Electrification Administration, the approval in writing of the Administrator, take or suffer to be taken any steps for corporate reorganization or dissolution, or to consolidate with or merge into any corporation, or to sell, lease or transfer (or make any agreement therefor) all or a substantial portion of its assets, whether now owned or hereafter acquired. Seller will not unreason-ably withhold or condition its consent to any reorganization, dissolution, consolidation, or merger, or to any sale, lease or transfer (or any agreement therefor) of assets. Seller will not withhold or condition its consent except in cases where to do otherwise would result in rate increases for the other members of the Seller, impair the ability of the Seller to repay its debt or any other obligations in accordance with their terms, or adversely affect system performance in a material way. Notwithstanding the foregoing, the Member may take or suffer to be taken any steps for reorganization or dissolution or to consolidate with or merge into any corporation or to sell, lease or transfer (or make any agreement therefor) all or a substantial portion of its assets, whether now owned or hereafter acquired without the Seller's consent, so long as the Member shall pay such portion of the outstanding indebtedness on the Seller's debt or other obligations as shall be determined by the Seller and shall otherwise comply with such reasonable terms and conditions as the Seller may require either (i) to eliminate any adverse effect that such action seems likely to have on the rates of the other members of the Seller or (ii) to assure that the Seller's ability to repay its debt and other obligations of the Seller in accordance with their terms is not impaired. For purposes of this section "substantial portion of its assets" shall mean assets that have a value of ten percent (10%) or more of the Member's total utility plant or assets, that if sold, will have an effect of more than five percent (5%) on the Member's power requirements.

12. ASSIGNMENTS. This contract shall be binding upon and inure to the benefit of the successors and permitted assigns of the parties, except that this contract may not be assigned by either party unless (i) prior consent to such assignment is given in writing by the other party or (ii) such assignment has been approved in writing by the Seller and is incident to a merger or consolidation with, or transfer of all or substantially all of the assets of the transferor to, another person or entity which shall, as a part of such succession, assume all the obligations of the transferor under this contract. Any assignment made without a consent required hereunder shall be void and of no force or effect as against the non-consenting party. Notwithstanding the forego-ing, a party, without the other party's consent, may assign, transfer, mortgage and pledge its interest in this contract as security for any obligation secured by an indenture, mortgage or similar lien on its system assets without limitation on the right of the secured party to further assign this contract including, without limitation, the assignment by the Member to create a security interest for the benefit of the United States of America, acting through the Administrator and thereafter, the Administrator, without the approval of the Seller, may (i) cause this contract to be sold, assigned, transferred or otherwise disposed of to a third party pursuant to the terms governing such security interest, or (ii) if the Administrator first acquires this contract pursuant to 7 U.S.C. §907, sell, assign, transfer or otherwise dispose of this contract to a third party; provided, however, that in either case (a) the Member is in default of its obligations to the Administra-tor that are secured by such security interest and the Administra-tor has given Seller notice of such default; and (b) the Adminis-trator has given Seller thirty days' prior notice of its intention to sell, assign, transfer or otherwise dispose of this contract indicating the identity of the intended third-party assignee or purchaser. No permitted sale, assignment, transfer or .other disposition shall release or discharge the Member from its obligations under this contract.

13. REASONABLENESS OF RATES. This contract was established between the parties hereto, taking into account their present and projected needs for capacity and energy, the costs of the facilities contemplated by this contract and the alternatives thereto. The parties agree that the rates established hereunder are formulae which are just and reasonable under the current circumstances and reflect their determination of what would be just and reasonable under future conditions reasonably contemplated by them. The rates take into account specific benefits achieved by the parties through this contract and not otherwise available to the parties, and reflect the sharing of those benefits without undue discrimination against any current or future customer of the Seller. The charges to be paid by the Member to the Seller for capacity and energy provided under this contract are intended to be adjusted only pursuant to and in accordance with the formulaic rates.

14. AMENDMENTS. This contract may be amended only by a written instrument executed by the Seller and the Member; provided, however, that so long as the Member remains a borrower of the Rural Electrification Administration, any such amendment must be approved in writing by the Administrator.

15. SEVERABILITY. If any part, term, or provision of this contract is held by a court of competent jurisdiction to be unenforceable, the validity of the remaining portions or provisions shall not be affected, and the rights and obligations of the parties shall be construed and enforced as if this contract did not contain the particular part, term, or provision held to be unenforceable.

16. GOVERNING LAW. This contract shall be governed by, and construed in accordance with, the laws of the State of Virginia.

Executed this day and year first mentioned.

OLD DOMINION ELECTRIC COOPERATIVE By:

u President ecretary A & N ELECTRIC COOPERATIVE By:' <c f 6/J it,3 President ATTEST:

f/ //

Secretary STATE OF VIRGINIA

-eI-rY/COUNTY OF s'N r*

The foregoing instrument was acknowledged before me this

\ day of 0, 1992, bylJ~zQ.g President of Old Dominion Electric Cooperative,\ha Virginia corporation, on behalf of said corporation.

My commission expires Notary Public STATE OF VIRGINIA

-e1TY/COUNTY OF meek The foregoing instrument was acknowledged before me this auj day of Arj , 1992, by LF) --jfjen , President of A & N ELECTRIC COOPERATIVE, a Virginia corporation, on behalf of said corporation.

My commission expires L0c46Q i Z3 , 19q5 q ' c X L.

Notark Public (

16-Apr-92 Page I EXHIBITA-I TO WHOLESALE POWER CONTRACT EXISTING POINTS OF DEUVERY REQUIREMENTS, DEU VERY VOLTAGES AND PROPOSED CHANGES NAME OF MEMBER: A & N Electdc Cooperative

1. Existinc Points of DeliverV Voltage of Delivery Indicate Year of Estimated Peak Load From Above Date Change and New Name Voltage IfAny 1 Yr. Hence 2 Yrs. Hence 3 Yrs. Hence 5 Yrs. Hence IO Yrs. Hence

1. Parksley 69 kV 23,358 23,942 24,540 25,637 28,485

2. Belle Haven 69 kV 4,456 4,567 4,681 4,890 3,623

3. EastvMlle 69 kV 4,002 4,102 4,204 4,392 3,253

4. Hallwood 69 kV 3,489 3,576 3,666 3,830 4,255 11.Requested Points of Delivery

1. Warehouse Creek 69 kV 0f 0 0 0 3,438

64z XAq- 4:25 t 8a4 6s5 --574a

_ -O *, 1 ANEC P. 02 wholeeale Power Contraet Bchodule No. I Xt is hereby agreed that A & N Electric Cooperative (A & N) may continue to use its existing generation which has a name plate capacity of 2803 KW for those purposes A & N deems appropriate.

It is also agreed that A & N Electric Cooperative may install additional generation at its Tangier and Smith Island facilities.

It is agreed .. that A & N will notify Old Dominion Electric Cooperative (ODEC) of any generation in excess of the base generation of 2803 KW when the excess generation occurs at the time of the Delmarva Power and Light (DP&L) monthly coincident peak.

For all KW generated in excess of the base 2803 KW A & N will receive a credit per KW equal to the avoided demand cost DP&L charges ODEC.

Page No. I April 17, 1992 EXHIBIT B TO WHOLESALE POWER CONTRACT BETWEEN OLD DOMINION ELECTRIC COOPERATIVE AND A&N Electric Cooperative ELECTRIC SERVICE SPECIFICATIONS

1. Name of Delivery Point Parksley Substation

2. Location Near Greenbush Circuit 6790

3. The characteristics of electricity supplied hereunder are as follows:

3 phase, _wire, (wye) (delta) at approximately 60 cycles and 69000 volts.

4. The service facilities installed for the sole purpose of supplying electricity to the member at this location are as follows:

1) Transformer capacity

2) Line facilities (feet), kv line and (feet)

(miles) kv line.

3) Control and protective equipment:

5. The delivery point shall be

6. Electricity will be metered at 69000 volts or metered in effect at volts.

7. The application rate schedule is OD

8. SEPA allocation: 0

9. Orginially connect Rebuilt 1971

Page No. 2 April 17, 1992 EXHIBIT B TO WHOLESALE POWER CONTRACT BETWEEN OLD DOMINION ELECTRIC COOPERATIVE AND A&N Electric Cooperative ELECTRIC SERVICE SPECIFICATIONS

1. Name of Delivery Point Belle Haven Substation

2. Location Near Belle Haven Circuit 6750

3. The characteristics of electricity supplied hereunder are as follows:

3 phase, _wire, (wye) (delta) at approximately 60 cycles and 69000 volts.

4. The service facilities installed for the sole purpose of supplying electricity to the member at this location are as follows:

1) Transformer capacity

2) Line facilities (feet), kv line and (feet)

(miles) kv line.

3) Control and protective equipment:

5. The delivery point shall be

6. Electricity will be metered at 12000 volts or metered in effect at volts.

7. The application rate schedule is OD

8. SEPA allocation: 0

9. Orginially connect April 1956

Page No. 3 April 17, 1992 EXHIBIT B TO WHOLESALE POWER CONTRACT BETWEEN OLD DOMINION ELECTRIC COOPERATIVE AND A&N Electric Cooperative ELECTRIC SERVICE SPECIFICATIONS

1. Name of Delivery Point Eastville Substation

2. Location Near Eastville Circuit 6750

3. The characteristics of electricity supplied hereunder are as follows:

3 phase, _ wire, (wye) (delta) at approximately 60 cycles and 69000 volts.

4. The service facilities installed for the sole purpose of supplying electricity to the member at this location are as follows:

1) Transformer capacity

2) line facilities __ (feet), kv line and (feet)

(miles) kv line.

3) Control and protective equipment:

5. The delivery point shall be

6. Electricity will be metered at 12000 volts or metered in effect at volts.

7. The application rate schedule is OD

8. SEPA allocation: 0

9. Orginially connect November 1973

Page No. 4 April 17, 1992 EXHIBIT B TO WHOLESALE POWER CONTRACT BETWEEN OLD DOMINION ELECTRIC COOPERATIVE AND A&N Electric Cooperative ELECTRIC SERVICE SPECIFICATIONS

1. Name of Delivery Point Haliwood Substation

2. Location Near Hallwood Circuit 6709

3. The characteristics of electricity supplied hereunder are as follows:

3 phase, wire, (wye) (delta) at approximately 60 cycles and 69000 volts.

4. The service facilities installed for the sole purpose of supplying electricity to the member at this location are as follows:

1) Transformer capacity

2) Line facilities __ (feet), kv line and (feet)

(miles) kv line.

3) Control and protective equipment:

5. The delivery point shall be

6. Electricity will be metered at 12000 volts or metered in effect at volts.

7. The application rate schedule is OD

8. SEPA allocation: 0

9. Orginially connect July 1981

Page 1 April 17, 1992 EX H IBT C TO WHOLESALE POWER CONTRACT lBLlWEE OLD DOMINION ELECTRIC COOPERATIVE AND A&N ELECTRIC COOPERATIVE SPECIAL EQUIPMENT

1. None

EXHIBIT D TO WHOLESALE POWER CONTRACT BETWEEN OLD DOMINION ELECTRIC COOPERATIVE AND A&N ELECTRIC COOPERATIVE OLD DOMINION ELECTRIC COOPERATIVE COMPREHENSIVE COST OF SERVICE FORMULA FEDERAL ENERGY REGULATORY COMMISSION Docket No. ER92-432-000

OLD DOMINION ELECTRIC COOPERATIVE COMPREHENSIVE COST OF SERVICE STUDY

Executive Summary Old Dominion's revenues are based on the formula rate contained herein which is applied to the sales made to each of tie member cooperatives' (customers) of Old Dominion. Cost estimates to be included in the formula rate are revised at least annually through the budget process by Old Dominion's Board of Directors (Board), which is composed of two representatives from each member cooperative. The rate is designed to recover the cost of service and create a firm equity base for the cooperative. Being a not-for-profit cooperative, Old Dominion's rate formula is not designed to assure a return on equity.

Rather the rate formula is designed to collect required revenues based on estimated costs with a true-up mechanism at year end to ensure that all costs are collected. Any difference is refunded or collected as required.

Development and implementation of the Formula Rate The process of reviewing and revising the estimates to be include in the rate begins with the development of a calendar year budget under the direction of the Board. A standing committee of the full Board is appointed annually by the Chairman of the Board. This committee is the Budget and Finance Committee and it includes representation from a broad spectrum of the member cooperatives. Under its direction:

(1) Power supply requirements are forecasted; (2) The budget is developed and approved; (3) The resulting cost estimates are included in the formula.

(1) Forecast of Power Supply Requirements The estimation process at Old Dominion begins with preparation of a projection of the resale loads (kW and kWH), less Southeastern Power Administration (SEPA) 2 loads (kW and kWH), expected during the coming calendar year. The Power Requirements Study, jointly developed by Old Dominion and its member systems is the baseline for developing the expected sales of Old Dominion.

The member cooperatives are both the owners and customers of Old Dominion.

They are referred to interchangeably as members, member systems or member distribution cooperatives.

2 Virginia area members have individual contracts with SEPA.

1

Old Dominion develops separate forecasts for its two primary power supply areas, the Virginia Mainland and the Delmarva Area. The Virginia Mainland power supply is provided by Old Dominion's 11.6% undivided interest in the North Anna Nuclear Power Station (North Anna), member power purchase agreements with SEPA, and Old Dominion's power purchase agreements with Virginia Electric and Power Company (VEPCO), Potomac Edison Company (PE), Allegheny Power System (APS),

and Appalachian Power Company (APCo). The Delmarva Area power supply requirements are provided through a power purchase agreement with Delmarva Power and Light (DP&L).

(2) Budget Development After forecasting resale loads, the budget is developed. The budget considers Old Dominion's two primary cost functions: power supply costs and administrative and general expenses. The power supply budget does not include SEPA cost estimates because those costs are billed directly to the member cooperatives by SEPA.

Budgets for each FERC category of expense that are not directly related to power purchases are developed by Old Dominion staff reviewed by the Budget and Finance Committee, and eventually approved by the full Board. Capital budgets and projections for cash are taken into account in forecasting interest cost as well as interest income. Allowances for equity requirements and financial performance included in Old Dominion's Indenture or defined within the formulary rate are also factored into the budget projections.

(3) Implementing the Formula Rate After the Board's approval of the budget the estimates are included in the formulary rate contained herein.

This process normally starts in August of the preceding calendar year in order to provide the Cominttee and the full Board adequate review time. The budget and all assumptions made in developing the budget are presented to the full Board for approval. This approval is customarily done at the regularly scheduled Board meeting held during the first week in December.

Synchronization Adjustments in the Formula Rate The Old Dominion budget is a calendar year budget, however, the charges resulting from application of the formula are not placed into effect until April 1. The delay is needed for the member systems to obtain approval from the various State Commissions to adjust rates 2

to their member-consumers 3 . The member systems of Old Dominion have wholesale power cost adjustment filings to modify rates to the member-consumers which are subject to State Commission approval and typically require a 90 day period for notice requirements and administrative approval at the State Commissions. Additionally, the Old Dominion Board has directed that the effect of the cost estimates for the rate year begin in the month of April when the member-consumer's usage is at a low point, thereby minimizing the impact of any increase in their electricity cost.

There are two prior period adjustment mechanisms, to ensure that Old Dominion does not collect revenues other than those resulting from an application of the prescribed formula by using actual data for the prior calendar year.

Prior Period Adjustments for Demand Revenues This prior period adjustment is used to true-up differences between actual and estimated demand related costs in accordance with the prescribed formula. Any differential between allowed costs under the formula and actual costs for the period is allocated based-on actual demand billing units and returned as a separate adjustment to the power bills. The adjustment will consist of one twelfth (1/12) of the total applied to each monthly bill for the following calendar year.

Prior Period Adjustments for Energy Revenues This prior period adjustment for over or under collection of energy revenues is included as a credit to expenses in the formulary rate described herein. Fuel costs of Old Dominion owned generation and energy costs from partial and full requirements suppliers, including any associated fuel adjustment factors, are examined every six months to permit any mismatch between revenue collections and actual energy costs to be more quickly reflected in the rates to the members. These member systems incorporate this adjustment in their retail rate schedules.

In addition, Old Dominion has a monthly energy adjustment clause which is applicable to delivery points for which the member system contracts for the interruptible load provision.

3 The terminology employed by cooperatives to refer to the ultimate consumer is member-consumers since they are both the customer and the owner of the distribution cooperative. A G&T Cooperative, like Old Dominion, who has no retail customers refers to its owners and wholesale customers as members or member systems interchangeably.

3

OLD DOMINION COMPREHENSIVE COST OF SERVICE FORMULA Demand Enerrv I. O&M Expenses Energy Related

1. FERC Acct. 501 X

2. Acct. 503 X

3. Acct. 504 X

4. Acct. 510 X

5. Acct. 512 X

6. Acct. 513 X

7. Acct. 518 X

8. Acct. 528 X

9. Acct. 530 X

10. Acct. 531 X

11. Acct. 544 X

12. Acct. 547 X

13. Acct. 555 - Energy related purchase power X B. Demand Related All of Accts. 500 through 935 not contained in (G.A.) above X II. Depreciation Expense Acct. 403 X m11. Decommissioning Expense (see Note A)

Acct. 403 X IV. Amortization Expense Acct. 404 through 407 (see Note B) X Acct. 425 (see Note C) X V. Taxes Other Than Income (Acct. 408.1)

1. Payroll X

2. Property X

3. Gross Receipts Taxes (see Note D) X X 4

VI. Other Income, Credits, or Discounts Acct. 412 through 421 (see Note E) X Acct. 450 through 456 (see Note F) X Acct. 447 Sale to Non-Members X X VII. Debt Expense Acct. 427 through 432 X VIII. Gains From Disposition of Utility Plant Acct. 411.6 X IX Life Insurance Acct. 426.2 X X Expenditures for Certain Civic Activities, etc.

Acct. 426 excluding 426.2 X X1. Extraordinary Gains Acct. 434 X XII. Equity Contribution (see Note G) and Margin Requirement (see Note H) X X Up to 20% of Accts. 427 through 431 Subtotal Demand and Energy Expenses

[+II+[II+[V+V+VII+VIII+IX+X+X1+XI-(VI) A B XII. Annual Delivery Point Charge (see Note I) X XIV. First Quarter Revenues (see Note J) X X In Excess of Minimum Delivery Point Charges XV. Non-Coincident Demand Charge (see Note P) X APR-DEC XV1. High Voltage Service Credit (see Note L) X (69 kV or Greater) APR-DEC XVII. Reactive Power Charge (see Note M) X APR-DEC TOTAL DEMAND EXPENSES A-XIII-XIV+XV+XVI-XVII C TOTAL ENERGY EXPENSES B-XIV+XV D 5

Rate Determinants DEMAND RATE = Total Demand Expenses (C)

Total Delivery Point kW Demand (APR-DEC) less 300 kW minimum per Delivery Point ENERGY RATE = Total Energy Expenses (D)

Total Delivery Point Energy For (APR-DEC)

Adjusted For Losses To Generation HIGH VOLTAGE ENERGY (HV ENERGY) RATE =

Energy Rate

HV Loss Factor LOW VOLTAGE ENERGY (LV ENERGY) RATE =

Energy Rate

LV Loss Factor MINIMUM CHARGE RATE (see Note I)

RKVA RATE = $.06/RKVA (see Note M)

HIGH VOLTAGE CREDIT (HV CREDIT) RATE (see Note L)

HIGH VOLTAGE LOSS FACTOR (HV LOSS FACTOR) (see Note N)

LOW VOLTAGE LOSS FACTOR (LV LOSS FACTOR) (see Note N)

EXCESS FACIIUTIES CHARGES as assigned (see Note F).

MAXIMUM DIVERSIFIED DEMAND CHARGES as assigned (see Note F).

PRIOR PERIOD ADJUSTMENT FOR DEMAND REVENUES (see Note 0).

NON-COINCIDENT DEMAND CHARGE (see Note P).

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Bill Determination LOW VOLTAGE DELIVERY POINT (BELOW 69 KV) =

Minimum Charge Rate

+ (kW Demand - 300 kW)

Demand Rate

+ RKVA Demand

RKVA Rate

+ KWH

LV Energy Rate

+ Assigned Excess Facilities Charges

+ Assigned Maximum Diversified Demand

+ Prior Period Adjustments for Demand Revenues

+ Non-Coincident Demand Charge x [NCP-(2 x CP)]

HIGH VOLTAGE DELIVERY POINT (69 KV AND ABOVE) =

Minimum Charge Rate

+ (kW Demand - 300 kW) * (Demand Rate - HV Credit Rate)

+ RKVA Demand

RKVA Rate

+ KWH

HV Energy Rate

+ Assigned Excess Facilities Charges

+ Assigned Maximum Diversified Demand

+ Prior Period Adjustments for Demand Revenues

+ Non-Coincident Demand Charge x [NCP-(2 x CP)]

General Information All estimated and actual costs included in this formula shall be determined by Old Dominion Electric Cooperative (Old Dominion). The capacity and energy to be provided to the members by Old Dominion shall be paid for by the members as provided in this formula.

Penalties, Property Losses, and Extraordinary Losses will be filed separately with the Commission for collection by Old Dominion. After providing appropriate support to the Commission, these accounts will be identified and collected through specific riders to the formulary rate.

The following circumstances require a rate change application.

1. An allocation is called for which is not provided for in the formula.

2. Changes made in the applicable Uniform System of Accounts which cause the costs to be recorded in accounts other than those referenced herein.

3. Changes to reflect any expense or cost not presently included in the formula.

4. Any other changes.

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Note A Decommissioning Expense The decommissioning expense (Acct. 403) results from Old Dominion's 11.6%

undivided ownership in the North Anna Nuclear Station.

As an owner of North Anna, Old Dominion is required to set aside funds, pursuant to certain statutory and regulatory requirements, to ensure that North Anna is safely taken out of service at the appropriate time. Deposits to the Trust are made by Old Dominion on a periodic basis, in such an amount that the fund balance will equal Old Dominion's costs at the time of decommissioning.

Old Dominion's portion of the estimated costs of decommissioning North Anna is approximately $48.5 million in 1990 dollars and $247.5 million in 2020 dollars.

In determining the decommissioning fund level, Old Dominion adopts the decommissioning studies as filed by Virginia Power in their wholesale rate applications at the FERC. Old Dominion's $247.5 million share as derived from the Virginia Power study will be collected over the remaining life of the units. Old Dominion's share is derived from the formula ((Z) x 11.6% x Unit 1 decommissioning costs) and ((s) x 11.6% x Unit 2 decommissioning costs) due to Old Dominion's purchase of North Anna Units 1 and 2 taking place five and three years, respectively, after the commercial operations start date. Decommissioning is scheduled to begin in 2020. The present value of the future decommissioning costs is being charged to members through rates and is credited to the decommissioning reserve. Because Old Dominion is a not-for-profit electric cooperative, exempt from taxation under 501(C)(12) of the Code, the Trust was created as a grantor trust so that for federal income tax purposes, income of the Trust is income to Old Dominion. Funds in the Trust are available only for decommissioning costs.

Annual values are as follows:

1992 $680,872 1993 $680,872 1994 $680,872 Note B Amortization Expense - North Anna On December 21, 1983, Old Dominion purchased from Virginia Power an 11.6%

undivided ownership in North Anna Units 1 and 2, nuclear fuel and common facilities at the power station, and a portion of spare parts, inventory, and other support facilities. Consequently an acquisition adjustment is being amortized for rate-making and accounting purposes over a 25-year period using the straight line method.

8

Note C Amortization Expense - Pollution Control The only expenses to be recovered in this account are Pollution Control Debt Issuance Costs.

Note D Gross Receipts Taxes Old Dominion pays a Gross Receipts Tax (GRT) on its electric revenues within the state of Virginia net of the cost of the purchased power which GRT is paid by the supplier used to serve Virginia loads on. Gross Receipts Tax is identified as energy related based on the revenues for energy net of the respective cost of energy related purchased power on which GRT is paid by the supplier. Gross Receipts Tax is identified as demand related based on the revenues for demand net of the respective cost of demand related purchased power on which GRT is paid by the supplier.

Note E Other Income, Credits, or Discounts Amounts in these accounts reflect interest earnings. Any future other income, credits or discounts properly booked in these accounts will be reflected in the formulary rate.

Note F Other Income, Credits, or Discounts Amounts in these accounts reflect income received from member systems for Excess Facilities Charges and Maximum Diversified Demand billed to Old Dominion. Any future other income, credits or discounts properly booked in these accounts will be reflected in the formulary rate.

Excess Facilities Charges Whenever Old Dominion requests Virginia Power to supply electricity in a manner which will require facilities in excess of defined "Normal Service Facilities," such facilities will be subject to an excess facilities charge. This charge is defined in the Virginia Power wholesale rate schedules applicable to Old Dominion.

Excess facilities charges are based on equipment assigned to specific delivery points. Virginia Power includes, on its monthly power bill to Old Dominion, a charge for these facilities based on the FERC rate schedule, Appendix E - Charges for Purchases by Old Dominion. Old Dominion, in turn, passes these charges through to the delivery points based on cost causation. As these costs are 9

specifically assigned and treated as a pass through of Virginia Power assigned costs, Old Dominion passes the costs directly to the appropriate member system.

Maximum Diversified Demand (MDD) Charges The billing demand under the Interconnection and Operations Agreement with Virginia Power consists of two distinct parts. The first part is what is generally referred to as Old Dominion's coincidental peak demand. This is the total demand that Old Dominion (net of its own resources) places on the Virginia Power monthly system peak.

The second component for billing demand is referred to as "maximum diversified demand." This component was established to allow Virginia Power to collect additional demand cost if Old Dominion's non-coincident peak demand during any on-peak hour was substantially greater than the Old Dominion coincidental peak demand including its own resources. Virginia Power bills Old Dominion for maximum diversified demand when the most recent twelve month average non-coincidental peak exceeds the most recent twelve month average coincidental peak by more than ten percent (10%). The excess over 10% is billed at the same rate as coincidental peak demand.

Old Dominion, in turn, passes the charge through to the delivery points based on a pro-rata basis. Pro-rata basis means that each delivery point which contributes to a MDD charge will be assessed its share of the charge based on its MDD as measured. To date all demand costs billed to Old Dominion have been under the coincidental peak demand.

Note G Equity Contribution Old Dominion has established a goal of achieving an equity level of 20% for the purpose as described in the Indenture.

Old Dominion has entered into two short-term contracts for power as a precedent to the construction of 400 MWs of coal-fired generation at Clover, Virginia. Old Dominion has set special equity contribution targets equal to the savings these transactions generate. The expected savings are determined as the difference between the cost of short-term power transactions and the cost of firm long-term power purchases from Virginia Power. The resulting equity contribution is allocated to energy and demand costs in proportion to the savings generated for each of those components. All savings are returned to the members in the form of patronage capital distributions on a pro-rata basis in proportion to the demand and energy determinants through which the contribution was collected.

10

Note H Margin Requirement The Margin Requirement shall be up to 20% of the amount in Accounts 427 through 431 for the purpose of determining the rates under the formula. This will provide a TIER of 1.2 which was selected as the bare minimum Indenture requirement necessary to respond to the rating agencies and to attract capital in the markets. The G&T Accounting and Finance Association publishes the TIER for G&T cooperatives. Out of the 55 cooperatives which responded to the survey in 1991, 21 reported TIER results greater than 1.2.

Note I Annual Delivery Point Charge Each delivery point is assessed the 300 kW demand charge monthly, regardless of voltage level of service or the delivered demand on the delivery point. The Old Dominion Board of Directors wants to encourage the efficient design of the combined transmission and distribution systems. Transmission investment for a new delivery point is made either by Old Dominion or the host utility supplying transmission service to Old Dominion. When the carrying cost of that investment is rolled into a melding pot rate, it is borne by all the members of Old Dominion.

Therefore, a direct cost signal to the member system is not available to balance the decision between distribution system upgrades and transmission system additions.

The minimum 300 kW demand charge is designed to transmit a cost signal to prevent the proliferation of small delivery points which are inefficient investments for the entire Old Dominion systems. This rate design promotes increased system operating efficiencies by encouraging upgrades to the existing system rather than adding additional delivery points.

A Minimum Delivery Point Charge is calculated for the first 300 kW of demand for each delivery point. There are two components of the Minimum Delivery Point Charge consisting of 1) the Average Demand Rate multiplied by 300 kW plus 2)

$800. The additional $800 provides for miscellaneous costs that are incurred by the creation of a new delivery point. The Minimum Charge Rate for April through March of the following year is determined by subtracting the First Quarter Minimum Charge Revenue from the Annual Delivery Point Charge then dividing by the sum of the number of delivery points for April through December.

Average Demand Rate (ADR) =

[SUBTOTAL DEIWD EXPENSES (A) - NON-COINCIJDr DEMAND CHARGE REV (SEE NOE P)-RrVA REP AW DEMND 11

Minimum Dlivery Point Charge (MDPC) = ADR

300 kW + $800 Annual Delivery Point Charge (ADPC) = MDPC

Sum of the No. of Delivery Points for 12 Months First Quarter Minimum Charge Revenue (FQMCR) = Sum of the No. of Delivery Points for the First Quarter

the applicable Minimum Charge Rate Minimum Charge Rate (for APR-MAR) =

ADPC-FQDPR TOTAL OF THE NO. OF DELIVERY POINTS FOR APR-DEC Note J First Quarter Revenues The Old Dominion budget projects expenses for the calendar year, whereas, the Old Dominion rate year extends from April 1 through March 31 of the following year. Therefore, rates set in April will generate revenues for the first quarter of the following year. To match the Budget expenses to rate design, the annual revenue requirements must be reduced to reflect revenues collected during the first quarter, with the remaining nine month revenue requirement divided by the nine month projected sales to derive the rate determinants for energy and demand.

Note K Bear Island Contractual Obligation Under an agreement with the Bear Island Paper Company, included in Section 4, Old Dominion has established the basis for the determination of its charges to Rappahannock Electric Cooperative for the Bear Island delivery point for the term of the Agreement.

As a result of becoming subject to FERC regulation, Old Dominion has established a comprehensive cost of service formula which develops a rate which may be higher than that developed pursuant to the Agreement. In the event such rate is higher, Old Dominion will bill to Rappahannock Electric Cooperative for the Bear Island delivery point an amount no greater than the amount developed pursuant to the Agreement. This rate "cap" will be applied as necessary on a monthly billing basis.

12

Note L High Voltage Demand Credit The l&O Agreement between Old Dominion and Virginia Power states that new interconnection points between the parties will be established at transmission level voltages, where practicable. Also, Old Dominion wishes to encourage system operating efficiency by promoting cost based discounts to transmission voltage level delivery points. This is accomplished through offering a discount on each kW above the minimum delivery point charge purchased at transmission voltages.

This cost based discount reflects the cost to Old Dominion of delivering power to distribution level voltages and allows a member system to make the economic comparison between delivery at distribution level and delivery at the transmission level. Since the distribution rates paid by Old Dominion to power suppliers have been accepted by the FERC, they are reasonable.

Any distribution related power cost expenses paid by Old Dominion should be borne by only the distribution delivery points using that service. The cost for this service is determined using the method from which Old Dominion is billed from its power suppliers. For instance, power purchased from DP&L includes a separate transmission and distribution demand rate. For Virginia Power, the settlement agreement for Docket No. ER91-562-000 currently pending FERC approval, will identify distribution costs assigned to Old Dominion and collect them through a separate distribution rate. Virginia Power's Transmission Service Rate also identifies a separate low voltage delivery charge. Distribution costs related to Old Dominion's purchases from APCo and the PE will be included if identifiable.

Old Dominion determines the High Voltage Credit Rate by dividing these distribution costs by the distribution level demand in excess of the minimum (300 kW per Delivery Point). The credit is this rate times the high voltage demand in excess of the minimum (300 kW per Delivery Point).

Note M Reactive Power Charge Old Dominion has included a power factor charge in its rate equal to $0.06/RKVA (RKVA Rate). This rate matches the RKVA rate included in the rate schedules filed by Virginia Power in FERC Docket No. ER 91-562-000. The Reactive Power Charge equals the RKVA Demand times the RKVA Rate.

13

Note N Loss Factors Old Dominion's loss factors are based on the latest load flow study used by Virginia Power to determine the Combined Transmission Loss Percentage as defined in the I&O Agreement. This study includes line loss factors for use of the Virginia Power transmission system (High Voltage Loss Factor) and a separate loss factor for service at distribution level voltages (Low Voltage Loss Factor). If, and when more detailed line loss information is available, it will be used.

Note 0 Prior Period Adjustments for Demand Revenues This prior period adjustment is used to true-up differences between actual and estimated demand related costs in accordance with the prescribed formula. Any differential between allowed costs under the formula and actual costs for the period is allocated based on actual demand billing units and returned as a separate adjustment to the power bills. The adjustment will consist of one twelfth (1/12) of the total applied to each monthly bill for the following calendar year.

Note P Non-Coincident Demand Charge (NCDC)

As a consequence of billing under a coincident peak methodology, administrative and general expenses are not always properly recovered from each delivery point.

This results from the inclusion of administrative and general costs in the demand charge and applying such charge to delivery point demands which have been significantly reduced through a load management program. Since the lowered demand occurs for a brief period, administrative and general costs are not fully recovered.

Because administrative and general expenses are fixed in nature and do not vary with changes in kilowatts demanded, a monthly non-coincident demand charge is needed to correct this inequity. Old Dominion will bill the delivery point a NCDC when the most recent twelve month average non-coincident peak exceeds by 200%

the most recent twelve month average coincident peak. Excess kilowatts are those kilowatts equal to the twelve month average non-coincident peak minus two times the twelve month average coincident peak. The amount charged will be determined by multiplying the excess kilowatts by the NCDC, where:

JCDC- 7TTAL or ACCOUN7/ 92-931

117QO CONM7EU)ON

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GAS xtCXZim 7AXES JTOAL OLD DOUNRON ELCIJC COOXPMUATVN DaUrr POWT NONT-COOACDCN7 PE4 14

OLD DOMINION ELECTRIC COOPERATIVE Rate Schedule OD APPLICABLE FOR POWER SERVICES RENDERED TO:

A&N Electric Cooperative BARC Electric Cooperative Choptank Electric Cooperative Community Electric Cooperative Delaware Electric Cooperative Mecklenburg Electric Cooperative Northern Neck Electric Cooperative Northern Virginia Electric Cooperative Prince George Electric Cooperative Rappahannock Electric Cooperative Shenandoah Valley Electric Cooperative Southside Electric Cooperative

EFFECTIEE:-

Communication Regarding this Tariff should be addressed to:

John P. Edwards President OLD DOMINION ELECTRIC COOPERATIVE Innsbrook Corporate Center 4201 Dominion Boulevard Glen Allen, Virginia 23060

Old Dominion Electric Cooperative Original OD FERC Tariff Supersedes None A. AVAILABILITY Available to A&N Electric Cooperative, BARC Electric Cooperative, Choptank Electric Cooperative, Community Electric Cooperative, Delaware 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, (the Cooperative(s))

purchasing full requirements electric service on a firm power wholesale for resale basis.

B. CHARACTER OF SERVICE Firm electric power at three phase, sixty hertz, alternating current at a voltage as may be mutually agreed upon, subject to availability of existing facilities.

C. MONTHLY RATE The monthly rate shall be determined pursuant to Old Dominion's Comprehensive Cost of Service Formula.

D. ENERGY ADJUSTMENT The estimated current period factor shall be effective for each six month period from April 1 to September 30 and from October 1 to March 31. This factor shall be based on the estimated fuel expenses and purchased energy expenses for Old Dominion.

When the estimated unit cost of fuel (Fm/Sm) used to meet Old Dominion's Net Energy Requirement less losses (Sm) is above or below the base unit cost of 18.15 mills per kilowatthour (Fb/Sb), an additional charge or credit equal to the product of the monthly Billing Energy and an energy adjustment factor (A) shall be made, where (A), calculated to the nearest thousandth of a cent, Issued: Effective:

Page 2 of 8

Old Dominion Electric Cooperative Original OD FERC Tariff Supersedes None is as defined below:

Adjustment Factor (A) = [Fm/Sm] - [Fb/Sb]

Any difference between the estimated cost of energy used to meet Old Dominion's Net Energy Requirement and the actual cost of such energy will be reflected in the calculation of the Energy Adjustment Factor in the second succeeding period.

in the above formula (F) is the expense of energy in the base (b) and current (m) periods; and (s) is the kWh sales in the base and current periods.

Sales (S) shall be the sum of (a) generation and (b) purchases, less (c) losses associated with Old Dominion's deliveries to customers served under this schedule.

The adjustment factor developed according to the preceding paragraphs may be further modified to allow the recovery of gross receipts or other similar revenue based tax charges occasioned by the fuel adjustment revenues.

E. DETERMINATION OF KW DEMAND AND DEMAND E. VE AREA - applicable to 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.

(a) The kW of demand billed shall be the Delivered Demand plus Excess Demand, both as determined under I(b) below.

(b) (i) Delivered Demand shall be the 60 minute integrated kW demand during the same hourly period in which the Old Dominion Monthly Demand is determined pursuant to the Interconnection and Operating Issued: Effective:-

Page 3 of 8

Old Dominion Electric Cooperative Original OD FERC Tariff Supersedes None Agreement between ODEC and VEPCO. This 60 minute period represents the clock-hour in each calendar month during which the combined system (VEPCO and ODEC's VE area members) peak demand occurs.

(ii) Excess Demand shall be an allocated share of the kW, if any, by which the most recent 12 month average Diversified Demand, as determined under I(b)(iii), exceeds 110% of the most recent 12 month average Old Dominion Monthly Delivered Demand.

(iii) Diversified Demand shall be the Old Dominion Monthly Maximum Diversified Demand as determined pursuant to the Interconnection and Operating Agreement between ODEC and VEPCO. This hourly demand represents the combined ODEC members' monthly maximum coincident demand during the on-peak period 7 a.m. to 10- p.m.

weekdays from October through May and 10 A.M. to 10 P.M. on weekdays from June through September.

(iv) Allocation of the total ODEC Excess Demand shall be made to each delivery point on the basis of Excess Demand computed separately for each delivery point.

(c) Determination of RKVA Demand The RKVA of demand billed shall be the highest average RKVA measured in any 30-minute interval during the current billing month.

For those Cooperatives for whom RKVA is not measured but for whom kW and kVA are measured, the RKVA will be calculated by using the measured kVA simultaneously at the time of either the maximum on-peak or off-peak kW, whichever results in the higher RKVA during the current billing month until the metering equipment is changed to measure the maximum monthly RKVA.

Issued: Effective:

Page 4 of 8

Old Dominion Electric Cooperative Original OD FERC Tariff Supersedes None IL DE AREA - applicable to A&N Electric Cooperative, Choptank Electric Cooperative, and Delaware Electric Cooperative.

(a) The kW of-demand billed shall be the Delivered Demand as determined under 11(b) below.

(b) Delivered Demand shall be the coincident sixty (60) minute integrated kW demand. This 60 minute period shall be the greatest demand established by the Customer during the sixty (60) minute clock hour of the month which coincides with the maximum sixty (60) minute clock hour demand of the combined system (DP&L and A&N Electric Cooperative, Choptank Electric Cooperative and Delaware Electric Cooperative).

(c) Determination of RKVA Demand Until actual RKVA demand data is available, the RKVA of demand billed shall be calculated by using the average RKVA during the billing period and the delivered demand for the same billing period.

II1. PE AREA - applicable to BARC Electric Cooperative, Rappahannock Electric Cooperative, and Shenandoah Valley Electric Cooperative at delivery points interconnected to the Potomac Edison Company's Electric System.

(1) Determination of kW Demand (a) The kW of demand billed shall be the Delivered Demand as determined under III (1)(b).

(b) i) Delivered Demand shall be the 60 minute integrated kW demand during the same hourly period in which the Old Dominion Monthly Delivered Demand is determined pursuant to the Interconnection and Operating Agreement between ODEC and VEPCO. This 60 minute period represents the clock-hour in each calendar month during which the combined Issued: Effective:

Page 5 of 8

Old Dominion Electric Cooperative Original OD FERC Tariff Supersedes None system (VEPCO and ODEC) peak demand occurs.

(ii) Until such time as demand metering is available for the delivery points interconnected to the PE system the kW of demand billed shall be:

The maximum sixty (60) minute demand multiplied by 75%

(coincidence factor).

(c) Determination of RKVA Demand The RKVA demand shall be zero (0) until such time as metering equipment is available to measure the RKVA Demand.

IV. APCo AREA - applicable to Southside Electric Cooperative at delivery points interconnected to the Appalachian Power Company's Electric System.

(1) Determination of kW Demand (a) The kW of demand billed shall be the Delivered Demand as determined under IV(1)(b).

(b)(i) Delivered Demand shall be the 60 minute integrated kW demand during the same hourly period in which the Old Dominion Monthly Delivered Demand is determined pursuant to the Interconnection and Operating Agreement between ODEC and VEPCO. This 60 minute period represents the clock-hour in each calendar month during which the combined system (VEPCO and ODEC) peak demand occurs.

(ii) Until such time as demand metering is available for the delivery points interconnected to the APCo. system, the kW of demand billed shall be:

The maximum thirty (30) minute demand multiplied by 85%

(coincidence factor).

Issued: Effective:

Page 6 of 8

Old Dominion Electric Cooperative Original OD FERC Tariff Supersedes None (c) Determination of RKVA Demand The RKVA demand shall be zero (0) until such time as metering equipment is available to measure the RKVA Demand.

F. PAYMENT TERMS (1) When Bills Are Payable All bills are due and payable upon presentation. In the case of a disputed bill, payment shall not be withheld but shall be made subject to adjustment upon determination of the dispute.

(2) Late Payment Charge A monthly late payment charge will be added by ODEC when payments are not received within ten (10) days from the date the invoice is mailed to the Cooperative. The late payment charge for each day beyond the final due date shall be computed as the simple interest on the unpaid balance at a rate of 18% per annum. The late payment charge will be added to the billing amount for the next month. Payments will be credited against the most delinquent charges.

Issued: Effective:_

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Old Dominion Electric Cooperative Original OD FERC Tariff Supersedes None A. AVAILABILITY

a. Excess Facilities Service will be available to ODEC's VE service area cooperatives as provided under A(b), B, C and D below.

b. Whenever the Cooperative requests ODEC to supply electricity in a manner which will require facilities in excess of Normal Service Facilities as defined in Paragraph C hereof, and ODEC finds it practicable, such facilities will be provided in accordance with Paragraphs B and D hereof.

B. DETERMINATION OF NORMAL SERVICE FACILITIES The ODEC's Normal Service Facilities at a point of delivery to the Cooperative shall be those facilities that VEPCO is committed to provide for transmission service under ODEC's Interconnection and Operating Agreement with VEPCO. Multiple supply sources with manual or automatic switching, multiple transformers, and multiple meters with or without totalized demands may be provided with no facilities charge if ODEC so elects for its convenience.

C. EXCESS FACILITIES SERVICE Excess Facilities Service supplied hereunder shall be subject to the provisions of Appendix H of ODEC's Interconnection and Operating Agreement with VEPCO.

Issued: Effective:

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OLD DOMINION ELECTRIC COOPERATIVE AMENDED AND RESTATED WHOLESALE POWER CONTRACT THIS AMENDED AND RESTATED CONTRACT is made as of this 22nd day of April , 1992, between OLD DOMINION ELECTRIC COOPERATIVE (hereinafter called the "Seller"), a corporation organized and existing under the laws of the Commonwealth of Virginia, and BARC ELECTRIC COOPERATIVE (hereinafter called the "Member"), a corporation organized and existing under the laws of the State of Virginia.

RECITALS:

A. The Seller has executed contracts to acquire ownership of certain electric generating facilities and to construct electric generating facilities, or a transmission system, or both, and may purchase or otherwise obtain electric power and energy for the purpose, among others, of supplying electric power and energy to certain rural electric cooperatives (the "Coopera-tives") which are or may become members of the Seller.

B. The Seller has heretofore entered into contracts for the sale of electric power and energy with Cooperatives which are members of the Seller (such contracts as they may have been amended and supplemented to the date hereof are hereinafter referred to as the "Original Wholesale Power Contracts").

C. In reliance upon the commitments of the Seller herein set forth, the Member is entering into this contract and the Member acknowledges by entering into this contract that the Seller (i) has obtained and will obtain financing, (ii) has invested and will in the future invest in plant and facilities, (iii) has developed and will continue to develop an organizational structure, management team and staff, (iv) has engaged and will continue to engage in planning, and (v) has made and will continue to make commitments relating to long-term power supply arrangements, all on the basis of the cash flow produced by this contract and similar contracts between the Seller and its other members.

D. The Seller has entered into certain contracts in connection with the construction of a two unit, coal-fired electric generating station located in Clover, Virginia (the "Clover Generating Station") and has acquired an undivided ownership interest in the Clover Generating Station.

E. In connection with the financing of the construction costs of the Clover Generating Station, the Seller and the Member desire to reaffirm the terms and provisions of the Original Wholesale Power Contract (except as amended hereby) and to amend and restate the Original Wholesale Power Contract as provided herein. The Seller intends to enter into similar contracts with all Cooperatives which are members of the Seller and may enter into similar contracts with Cooperatives who become Members of the Seller in the future (the Original Wholesale Power Contracts as so amended and restated together with such additional contracts may be collectively referred to herein as the "Wholesale Power Con-tracts").

F. The Seller is incurring debt to construct, improve or acquire facilities which are intended to directly or indirectly benefit the Member and its members as well as other members of the Seller, although the Member recognizes that such benefits cannot be assured.

G. The Member has determined that its interest and the interest of its own members will be best served by entering in~to this contract with the Seller in lieu of undertaking the risks of developing other sources of electricity itself or of purchasing electricity from other sources.