EX-10.1

EX-10.1 2 ck0000885568-ex10_1.htm EX-10.1 EX-10.1

Exhibit 10.1

OLD DOMINION ELECTRIC COOPERATIVE

THIRD AMENDED AND RESTATED WHOLESALE POWER CONTRACT

THIS THIRD AMENDED AND RESTATED WHOLESALE POWER CONTRACT (the “Contract”) is made as of September 30, 2024, between OLD DOMINION ELECTRIC COOPERATIVE (hereinafter called the “Seller”), a utility aggregation cooperative organized and existing under the laws of the Commonwealth of Virginia, and A & N ELECTRIC COOPERATIVE (hereinafter called the “Member”), a utility consumer services cooperative organized and existing under the laws of the Commonwealth of Virginia (hereinafter either individually a “Party,” or collectively the “Parties”).

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 electric cooperatives (the “Cooperatives”) which are or may become members of the Seller.

B. The Seller has heretofore entered into the Second Amended and Restated Wholesale Power Contracts, dated on or about January 1, 2009, 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 set forth herein, 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 in 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 Member may in the future desire more flexibility in meeting its needs for electric supply service.

E. 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 Contracts”).

F. The Member has determined that its interest and the interest of its own members will be best served by entering into this Contract with the Seller in lieu of taking the risks, generally, of developing or purchasing electricity from other sources.

G. The Member desires to purchase electric capacity, energy, transmission service, and ancillary services (the “Requirements Service”) from the Seller, and the Seller desires to sell such Requirements Service to the Member, on the terms and conditions set forth in this Contract, as follows:

WITNESSETH:

NOW THEREFORE, in consideration of the mutual undertakings 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:

PURCHASE AND SALE OBLIGATIONS.

(a)

All-Requirements Obligations. Except as otherwise provided in Section 1, the Seller shall sell and deliver to the Member and the Member shall purchase and receive from the Seller all Requirements Service, which the Member shall require for the operation of the Member’s system to the extent that the Seller shall have the Requirements Service available. The Member may continue to utilize the electricity produced by its owned generating facilities set forth on Schedule 1 hereto, and such facilities shall not constitute use of the Limited Right to Alternate Supply as described in subsection 1(c) herein.

(b)

SEPA. The Member shall have the right to purchase electric supply service from the Southeastern Power Administration (“SEPA”) or its successor unless the Seller shall qualify as a customer of and contract for electric service from SEPA or its successor.

(c)

Limited Right to Alternate Supply. The Member shall have the right to receive up to the greater of five percent (5%) or five (5) megawatts of its demand requirements and associated energy from (i) generating facilities owned or leased by the Member (excepting those facilities set forth on Schedule 1 hereto, which are subject to the exception in Section 1(a) of this Contract) or (ii) purchases from any third-party, subject to delivery of one hundred and eighty (180) days’ prior written notice thereof to the Seller or such shorter notice period as the Parties mutually may agree (the “Alternate Supply”). For purposes of determining the Member’s Alternate Supply, such amount shall be calculated by reference to the greatest amount of the Member’s measured demand during any prior calendar year (the Member’s non-coincident peak), excluding amounts purchased by the Member as described in subsection 1(b). In receiving any such Alternate Supply, the Member shall comply with such policies and procedures as the Seller may reasonably establish for the scheduling and receipt of such Alternate Supply. If the Member fails to comply with any such policies and procedures, the Seller may bill the Member as though such Alternate Supply was provided by Seller under this Contract. In no event shall Seller be responsible for any costs or expense incurred by the Member with respect to such Alternate Supply. The Member shall provide the Seller not less than one hundred and eighty (180) days’ prior written notice of the termination, expiration, or cessation of any portion of the Alternate Supply pursuant to this subsection 1(c). Seller shall have no obligation to sell and deliver Requirements Service to

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the Member in replacement for or substitution of any portion of the Alternate Supply pursuant to this subsection 1(c) until the date one hundred and eighty (180) days after the date the Seller receives unconditional and irrevocable written notice from the Member of the termination, expiration, or cessation of such Alternate Supply.

(d)

Alternate Purchase Subject to Approval of the Seller’s Board of Directors. In the event an opportunity is presented to Member to purchase any component of the Requirements Service from another supplier in excess of that permitted under subsection 1(c), Member shall offer that opportunity to the Seller (the “Alternate Purchase”). If the Seller determines not to avail itself of such Alternate Purchase or is unable to agree on an acceptable contract for such Alternate Purchase, then Member shall be permitted to purchase that component of the Requirements Service for its own use so long as (i) the Seller has contractual or market purchases that it can eliminate in an amount at least equal to the amount of such Alternate Purchase and (ii) the Seller’s Board of Directors determines that it will not materially adversely affect the Seller or its other members if Member effects such Alternate Purchase (taking into account financial, power supply, reliability and credit-related costs and risks). Any determination by the Seller’s Board of Directors may be based on conditions to be fulfilled or satisfied prior to the execution of any contract for purchase of such Alternate Purchase. Such conditions may include whether and on what terms and conditions the Seller shall have any obligation to sell or deliver Requirement Service (or any component thereof) in the future as replacement for or substitution of such Alternate Purchase entered into pursuant to this subsection 1(d) following the termination, expiration, or cessation of such Alternate Purchase. If the Alternate Purchase represents a significant portion of the Member’s electric service requirements for a term in excess of three (3) years, and if the Seller’s Board of Directors deems it appropriate, such conditions may include a change in the membership classification of the Member. Prior to considering a request of the Member to receive any component of the Requirements Service from another supplier, the Member shall provide the Seller, at the Member’s sole cost and expense, such information, documents, studies, analyses, or reports as the Seller reasonably may request in connection with an evaluation of the Member’s request hereunder. In receiving such Alternate Purchase, the Member shall comply with such policies and procedures as the Seller may reasonably establish for the scheduling and receipt of such Alternate Purchase. If the Member fails to comply with any such policies and procedures, the Seller may bill the Member as though such Alternate Purchase was provided by the Seller under this Contract. In no event shall the Seller be responsible for any costs or expenses incurred by the Member with respect to such Alternate Purchase.

(e)

Requirements Service Outside Current Certificated Service Territories. From time to time, the Board of Directors shall establish and maintain policies and procedures with respect to providing Requirements Service for delivery by Cooperatives to persons or entities which are not located within the certificated service territory of the Cooperatives as of the date of this Contract or any subsequent date specified in such policies or procedures (“Existing Service Territories”). Such policies and procedures may include, inter alia, that the Seller will not be obligated under this Contract to supply any component of the Requirements Service with respect to a cooperative’s service outside the Existing Service Territories or that the rates and charges applicable to the provision of such Requirements Service for loads outside the Existing Service Territories will be different than those which otherwise would be applicable under this Contract. The Member shall deliver not less than one hundred and eighty (180) days’ prior written notice to the Seller, unless the Parties agree to a shorter notice period, setting forth (i) its intention to serve

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such customers, (ii) the date it proposes to commence providing Requirements Service to such customers, (iii) a description of such customers and their requirements, and (iv) a description of any definitive agreement entered into by the Member with respect to such service (a copy of such definitive agreement shall be attached to such notice), including any material conditions to the Member’s obligations to commence service to such customers. The Member shall provide the Seller with any information the Seller reasonably requests following delivery of such notice. The Member shall comply with all such policies and procedures in effect at the time of the delivery of such notice in connection with the commencement of service to such customers. Any change in such policies and procedures adopted by the Seller following the delivery of such notice shall not be effective with respect to service to the customers identified in such notice without the consent of the Member unless the Member shall have failed to enter into a written letter of intent or agreement with the current supplier to such customers by the first anniversary of the date of such notice providing for the Member to commence service to such customers. If the policies in effect at the time of the delivery of such notice provide that service to the new customers shall be on terms and conditions different than the service to the Member’s other customers, the Member may at its election serve such customers located outside the Existing Service Territories other than pursuant to this Contract. In such case, a Member’s receipt of service other than pursuant to this Contract shall not be considered for purposes of calculating the Member’s Alternate Supply under subsection 1(c).

ELECTRIC CHARACTERISTICS AND POINTS OF DELIVERY. Electricity delivered as part of the Requirements Service, to be furnished hereunder shall be alternating current, sixty (60) 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 the Requirements Service 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.

DELIVERY FACILITIES. Bulk power supply planning shall be the responsibility of the Seller. The Seller shall be responsible for the facilities to deliver the Requirements Service to the Point(s) of Delivery. The Member shall be responsible for the facilities to take and use the Requirements Service from the Points 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 Party.

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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 at Member’s expense and shall be listed on Exhibit C.

RATE.

(a)

The Member shall pay the Seller for the Requirements Service 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 D contains a formula pursuant to which rates and charges are to be set from time to time.

(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, depreciation or other charges recorded on the Seller’s books) resulting from the ownership, lease, operation, maintenance, termination, retirement from service and decommissioning of, and repairs, renewals, replacements, additions, improvements, betterments and modifications 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, including all components of the Requirements Service, hereunder and performance by the Seller of its obligations under the Wholesale Power Contracts with the Cooperatives 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 generating 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, fuel transportation costs, costs of backup power, administrative and general expenses, regulatory costs, insurance premiums, and taxes or payments in lieu thereof, and any components of the Requirements Service);

(iv)

the cost of any components of the Requirements Service purchased for resale by the Seller under the Wholesale Power Contracts including the costs of transmission, scheduling, dispatching and

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controlling services for delivery of the Requirements Service 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)

all rentals and other payments required to be paid by the Seller as lessee under any lease of real or personal property or under any contract or agreement relating to any such lease;

(viii)

any additional cost or expense not specified in the other items of this subsection 4(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 Cooperatives which is not otherwise included in any of the costs specified herein;

(ix)

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 4(b) including, without limitation, amounts payable with respect to interest rate swaps, futures contracts, option contracts and hedging contracts;

(x)

reserves the Seller shall determine to be necessary for the payment of those items of costs and expenses referred to in this subsection 4(b) to the extent not already included in any other clause of this subsection 4(b);

(xi)

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 or insurers of its debt or which the Board of Directors deems advisable in the marketing of its debt;

(xii)

any amounts required to be paid to any taxing authority (including any income taxes payable if the Seller should become subject to income tax); and

(xiii)

any amounts which the Board of Directors deems advisable to increase the equity or interest coverage of the Seller.

At least every three (3) years the Seller’s Board of Directors shall review the rate formula set forth in Exhibit D to determine if it reflects and recovers all such costs and expenses and if it represents the best way to allocate such costs and expenses. In making such review, the Board of Directors shall consider if the formula results in the proper price signals to the

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Cooperatives. If the Board of Directors determines that the formula no longer reflects and recovers, or does not allocate appropriately, such costs and expenses, the Board of Directors shall, within a reasonable timeframe, subject to any necessary regulatory approvals, adopt a new formula to reflect appropriately and recover 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) and 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 set forth in Exhibit D and agrees to pay for the Requirements Service furnished by the Seller to it after the effective date of any such revision at rates and charges set pursuant to the revised formula.

(e)

The Member acknowledges and agrees that the Seller may provide Requirements Service to the Member under this Contract, including Exhibit D, pursuant to any authority granted to the Seller under applicable law, including by any governmental authority with jurisdiction thereover, including, without limitation, pursuant to (i) a cost-of-service tariff including one or more formulary rates filed by the Seller and accepted by the Federal Energy Regulatory Commission (“FERC”), or (ii) a market-based rate tariff filed by the Seller and accepted by FERC.

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 Requirements Service furnished by the Seller;

(c)

The penalty to a member who shall fail to pay its bill within the designated pay period (including any extensions), which penalty shall include, but not be limited to, late payment charges and conditions under which the Seller may discontinue delivery of the Requirements Service; and

(d)

The time and manner of delivery of notices.

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

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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 the Member requests.

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 Requirements Service during such period, and the Seller shall render a bill for that amount.

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 is 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.

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.

CONTINUITY OF SERVICE. The Parties shall use reasonable diligence to deliver and receive constant and uninterrupted Requirements Service. If the Requirements Service 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 such 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 the Requirements Service.

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 judgment 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 USDA Rural Development Utilities Program (the “Rural Utilities Service” and its “Administrator”) and shall remain in effect for a term extending until January 1, 2079, 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 Section 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

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a borrower of the Rural Utilities Service, 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 unreasonably 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 Seller’s outstanding indebtedness 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 foregoing, 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 Administrator that are secured by such security interest and the Administrator has given Seller notice of such default; and (b) the Administrator has given Seller thirty (30) 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.

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13.

REASONABLENESS OF RATES. This Contract was established between the Parties hereto, taking into account their present and projected needs for Requirements Service, the costs of the facilities contemplated by this Contract and the alternatives thereto. The Parties agree that the rates established hereunder 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 Requirements Service provided under this Contract are intended to be adjusted only pursuant to and in accordance with the 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 Utilities Service, 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 Commonwealth of Virginia.

Remainder of this page intentionally left blank.

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Executed this day and year first mentioned.


	OLD DOMINION ELECTRIC COOPERATIVE
	a Virginia Utility Aggregation Cooperative


	By: /s/ John C. Lee, Jr
	Its: President and Chief Executive Officer

ATTEST:

By: /s/Gregory S. Rogers

Its: Secretary/Treasurer


	A & N ELECTRIC COOPERATIVE
	a Virginia Utility Consumer Services Cooperative


	By: /s/ Belvin Williamson, Jr.
	Its: President and Chief Executive Officer

ATTEST:

By: /s/Ralph W. Dodd

Its: Secretary

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SCHEDULE 1

THIRD AMENDED AND RESTATED WHOLESALE POWER CONTRACT

BETWEEN

OLD DOMINION ELECTRIC COOPERATIVE

AND

A & N ELECTRIC COOPERATIVE

OWNED GENERATING FACILITIES

It is understood that A&N Electric Cooperative (A&N) had an initial name plate capacity of 2803 KW of installed generation on Tangier and Smith Island. It is also understood that A&N has installed additional generation with the total capability as listed below. It is hereby agreed that A&N Electric Cooperative may continue to operate and use its generation as listed below for those purposes A&N deems appropriate.

•

Two diesel generators located on Tangier Island, each with a nameplate rating of 1200 KW

•

One diesel generator located on Smith Island with a nameplate rating of 1200 KW

•

One diesel generator located on Smith Island with a nameplate rating of 500 KW

It is agreed that A&N 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 the hourly amounts of any generation from the existing or expanded facilities when such generation will have an impact on A&N’s power bill from ODEC. A&N shall be entitled to reduce its monthly billing peak by the base generation amount up to 2803 KW of demand. A&N will receive a credit per KW equal to the avoided demand cost that ODEC incurs for any excess generation above 2803 KW.

A&N and ODEC may mutually enter into other agreements from time to time as may be necessary to implement the pricing provisions of this Schedule.

EXHIBIT A

THIRD AMENDED AND RESTATED WHOLESALE POWER CONTRACT

BETWEEN

OLD DOMINION ELECTRIC COOPERATIVE

AND

A & N ELECTRIC COOPERATIVE

ANTICIPATED LOADS AND NEED FOR ADDITIONAL POINTS OF DELIVERY


Name of Member:

Date:


	Voltage of Delivery*	Estimated Peak Load from Above Date
Name		1 Year Hence	2 Years Hence	3 Years Hence	5 Years Hence	10 Years Hence

I. Existing Points of Delivery
1.
2.
3.
4.
5.
6.
7.

II. Requested Points of Delivery
1.
2.
3.

* Indicate year of change and new voltage if any.

EXHIBIT B

THIRD AMENDED AND RESTATED WHOLESALE POWER CONTRACT

BETWEEN

OLD DOMINION ELECTRIC COOPERATIVE

AND

A & N ELECTRIC COOPERATIVE

ELECTRIC SERVICE SPECIFICATIONS


Delivery Points	Initial Delivery Voltage (kV)

Greenbush (Parksley & Onancock)	69
Belle Haven	69
Eastville	69
Hallwood	69
Perdue	69
Wallops	69
Cheriton 1	69
Cheriton 2	69
Chincoteague 1	69
Chincoteague 2	69
Commonwealth Chesapeake	138
Kellam 1	69
Kellam 2	69
Oak Hall 1	138
Oak Hall 2	69
Red Bank	69
Signpost	69
Tasley 1	69
Tasley 4	69
Wattsville 1	69
Wattsville 2	69

EXHIBIT C

THIRD AMENDED AND RESTATED WHOLESALE POWER CONTRACT

BETWEEN

OLD DOMINION ELECTRIC COOPERATIVE

AND

A & N ELECTRIC COOPERATIVE

SPECIAL EQUIPMENT

1. None

EXHIBIT D

THIRD AMENDED AND RESTATED WHOLESALE POWER CONTRACT

BETWEEN

OLD DOMINION ELECTRIC COOPERATIVE

AND

A & N ELECTRIC COOPERATIVE

OLD DOMINION ELECTRIC COOPERATIVE FERC FORMULA RATE TARIFF

OLD DOMINION ELECTRIC COOPERATIVE

Name of filing Public Utility

A&N Electric Cooperative

BARC Electric Cooperative

Choptank Electric Cooperative, Inc.

Community Electric Cooperative

Delaware Electric Cooperative, Inc.

Mecklenburg Electric Cooperative

Northern Neck Electric Cooperative

Prince George Electric Cooperative

Rappahannock Electric Cooperative

Shenandoah Valley Electric Cooperative

Southside Electric Cooperative

_____________________________________

Names of Other Utilities Receiving

Service under the Rate Schedule

Sale for Resale

Brief Description of the Service to be Provided

Under the Rate Schedule

Executive Summary

Old Dominion Electric Cooperative (ODEC) is a not-for-profit generation and transmission electric cooperative which supplies power, on a wholesale basis, to its member distribution cooperatives. ODEC's member distribution cooperatives are A&N Electric Cooperative, BARC Electric Cooperative, Choptank Electric Cooperative, Inc., Community Electric Cooperative, Delaware Electric Cooperative, Inc., Mecklenburg Electric Cooperative, Northern Neck Electric Cooperative, Prince George Electric Cooperative, Rappahannock Electric Cooperative, Shenandoah Valley Electric Cooperative, and Southside Electric Cooperative. ODEC serves its member distribution cooperatives' power requirements pursuant to long-term, virtually all-requirements wholesale power contracts. ODEC’s member distribution cooperatives, in turn, supply power on a retail basis to their member-owners.

ODEC is owned entirely by its members, which are the primary purchasers of the power ODEC sells. ODEC has two classes of members. ODEC’s Class A members are the eleven member-owned electric distribution cooperatives named above. ODEC’s sole Class B member is TEC Trading, Inc. (TEC), which is a taxable corporation owned by the Class A members. ODEC is governed by its Board of Directors (Board) which includes two representatives from each of ODEC’s member distribution cooperatives and one representative from TEC.

ODEC’s charges to its member distribution cooperatives are determined by the formula rate contained herein, which is applied to the sales of demand and energy made to each of the member distribution cooperatives. The formula rate recovers ODEC’s cost of service, including equity. It collects required revenues based on budgeted cost estimates with true-up mechanisms to ensure that all costs, including Board-approved margins, are collected. Margins represent ODEC's equity and are allocated to the member distribution cooperatives. Any difference between budgeted and actual costs is refunded or collected in accordance with this rate schedule. ODEC’s budget is developed annually. The annual budget and any revisions to the budget are approved by the Board.

A. Development and Implementation of the Formula Rate

The process of preparing, reviewing and revising the estimates to be included in the formula rate begins with the development of a calendar year budget which typically is submitted to the Board for its approval by December of the prior year. The approved budget is the basis for ODEC’s revenue requirements and loads which are included in the formula rate. The formula rate will typically be placed into effect January 1, which is the beginning of the budget year.

Throughout the year, ODEC provides its Board with monthly financial reports that compare actual results to budgeted and/or prior year’s actual results, and with information regarding revised estimates of costs and/or loads. If at any time during

the year it is determined that the current budget is not an accurate reflection of estimated costs and/or loads, the Board may approve a revised budget which may result in new rates and charges.

The specific steps involved in developing and implementing the formula rate include:

Forecasting of power supply requirements;

Development and approval of the budget; and

Inclusion of the budget in the formula rate.

1. Forecasting of Power Supply Requirements

The budgeting process begins with preparation of a projection of the annual loads (kW and kWh) to be supplied by ODEC during the budget period.

2. Development and Approval of the Budget

After forecasting loads, the budget is developed. The budget considers ODEC’s costs associated with providing power supply service to its member distribution cooperatives, including power costs, interest charges and margins, and administrative and general expenses. Budgeted costs for each Federal Energy Regulatory Commission (FERC) category of expense are developed by ODEC staff. The budget is then presented to the Board and, after review and discussion, is approved.

3. Inclusion of the Budget in the Formula Rate

After the Board's approval of the budget, the resulting estimated loads and costs are included in the formula rate contained herein.

B. True-up Mechanisms

1. Margin Stabilization

Any differential between total demand revenues collected for Transmission Service, RTO Capacity Service and Remaining Owned Capacity Service under the formula and demand costs incurred for those services in the period is allocated to each member distribution cooperative as follows: (1) for Transmission Service, based on the member distribution cooperative’s contribution to the single zonal coincident peak (1 CP) for the previous PJM Transmission Year, within each of the PJM Transmission Zones, as defined in Section III.A.1.a.; (2) for RTO Capacity Service, on the basis of each member distribution cooperative’s contribution to the prior PJM Capacity Year average of the five hourly CPs (5 CP), as defined in Section III A.1.b.; and (3) for Remaining Owned Capacity Service based on Remaining Owned Capacity Service demand billing units as defined in Section III.A.1.d.

Margin stabilization is refunded to, or collected from, each member distribution cooperative in subsequent periods.

2. Deferred Energy

Any differential between total energy revenues collected under the formula rate and actual energy costs incurred for the period is included in FERC Account 555 and accumulated on the balance sheet as Deferred Energy. Total ODEC energy costs are examined periodically to determine if an adjustment is warranted to better match energy revenue collections and actual energy costs.

C. Coordination with Market-Based Rate Tariff

With the exception of sales made upon request of a member distribution cooperative pursuant to the Board policy, “Market-Based Rates for New or Expanding Loads,” all sales to member distribution cooperatives will be made pursuant to this tariff. Except as specifically provided above, the member distribution cooperatives will not be subject to market-based rates, including any rates contemplated by FERC Electric Tariff Original Volume No. 2 Market-Based Rates filed on October 5, 2004, and amended on January 7, 2005.

II.

ODEC Cost of Service and Revenue Requirements Formula Rate


1. O&M Expenses	Demand	Energy

A. Energy Related (See Note A)
Acct. 501		X
Acct. 503		X
Acct. 504		X
Acct. 509		X
Acct. 510		X
Acct. 512		X
Acct. 513		X
Acct. 518		X
Acct. 528		X
Acct. 530		X
Acct. 531		X
Acct. 544		X
Acct. 547		X
Acct. 555 Energy related purchased power costs		X

B. Transmission Related
Acct. 456.1	X
Acct. 560 through Acct. 576.5	X

C. Distribution Related
Acct. 580 through Acct. 598	X

D. Demand Related.
All amounts in Acct. 500 through Acct. 935
not contained in 1.A., 1.B., and 1.C. above	X

2. Depreciation Expense (see Worksheet A)
Acct 403	X

3. Nuclear Decommissioning Expense (See Note B)
Acct. 403.1	X
Acct. 411.10	X

4. Amortization Expense
Acct. 404 through Acct. 407	X
Acct. 425	X


	Demand	Energy

5. Taxes Other Than Income Taxes
Acct 408.1	X
Acct 408.2	X

6. Income Taxes
Acct. 409.1 through 411.5	X

7. Other Income, Credits or Discounts (See Note C)
Acct. 412 through Acct. 421	X
Acct. 450 through Acct. 456, excluding Acct. 456.1	X	X
Acct. 447 (see Note D)	X	X

8. Debt Expense
Acct. 427 through Acct. 432	X

9. Gains and Losses from Disposition of Utility Plant
Acct 411.6	X
Acct 411.7	X

10. Gains and Losses from Disposition of Allowances
Acct 411.8	X
Acct 411.9	X

11. Accretion Expense
Acct 411.10	X

12. Life Insurance, Expenditures for Certain Civic Activities and Other Deductions
Acct. 426.1 through Acct. 426.5	X

13. Extraordinary Gains and Losses
Acct 434	X
Acct 435	X

14. Equity Contribution (See Note E) and	X
Margin Requirement (See Note F)	X


Total Demand Expenses	X
Total Energy Expenses		X

II.A. Notes

Note A Accounting for Derivatives and Hedging

ODEC enters into derivative contracts to hedge its price risk associated with the purchase of fuel and energy. These contracts serve to mitigate the market and price volatility and stabilize the cost of power sold to its member distribution cooperatives. ODEC follows the accounting guidance provided by FERC in its Order No. 627, issued October 10, 2002, "Accounting and Reporting of Financial Instruments, Comprehensive Income, Derivatives and Hedging Activities," and Accounting Standards Board Codification (ASC) 815, “Accounting for Derivative Instruments and Hedging Activities,” for recording unrealized and realized gains and losses.

Unrealized gains and losses on derivative instruments that do not meet the hedge criteria of ASC 815 for recording the unrealized gains and losses in Account 211 – Miscellaneous Paid-In Capital will be recorded as a regulatory liability in Account 254 – Other Regulatory Liabilities or as a regulatory asset in Account 182.3 – Other Regulatory Assets, as appropriate. When the derivative instruments are settled, the realized gain or loss will be matched and recognized in the same time period and recorded to the same expense account as the item for which risk is being mitigated.

ODEC enters into derivative instruments, such as forward or option contracts, for a specific time period and for a specific purpose, such as to hedge the purchase of natural gas to fuel its combustion turbine facilities. Realized gains and losses from the derivative instruments are matched and recognized in the same time period the expense is incurred for the hedged item, such as the purchase and consumption of natural gas. If it is determined that a derivative instrument is no longer needed due to changes in market conditions or assumptions of need, then the derivative instrument is settled and the realized gain or loss is recognized in the current period and recorded to the same expense account as the item for which risk is being mitigated.

Thus, amounts in Accounts 501 and 547 – Fuel, and Account 555 – Purchased Power include realized gains and losses from derivative contracts.

Note B Accounting for Nuclear Decommissioning Expense

Annual decommissioning expense results from ODEC’s 11.6% undivided ownership interest in the North Anna Nuclear Power Station (North Anna). As an owner of North Anna, ODEC is required to set aside funds for the decommissioning of North Anna. ODEC created a nuclear decommissioning trust fund and makes deposits to the fund on a periodic basis so that the fund balance will be sufficient to cover ODEC’s share of the decommissioning costs. ODEC’s share of the decommissioning cost is based upon Article 3.03 of the

Purchase, Construction and Ownership Agreement between Virginia Electric and Power Company and Old Dominion Electric Cooperative, dated as of December 28, 1982, amended and restated October 17, 1983.

Effective January 1, 2003, ODEC’s decommissioning liability and funding of the nuclear decommissioning trust fund is computed using ASC 410, “Accounting for Asset Retirement and Environmental Obligations.” ODEC also follows the accounting guidance provided by FERC in its Order No. 631, issued April 9, 2003, "Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations."

To ensure that ODEC’s asset retirement obligation liability is properly stated and the related nuclear decommissioning trust fund is adequately funded, periodic decommissioning studies are performed for North Anna and periodic reviews of the nuclear decommissioning trust fund balance and the projected income on the fund are performed.

Annually, asset retirement obligation expense will be recorded as depreciation and accretion expense in Accounts 403.1 and 411.10, respectively. These expenses will be partially offset by the amortization of the regulatory liability recorded in Account 254 resulting in a net asset retirement obligation expense. The amortization of the regulatory liability will be recorded in account 407.4 and will reflect the ASC 410 liability excluding costs related to third party and market risk premium. The net ASC 410 expense will be charged to member distribution cooperatives through rates and deposited to the nuclear decommissioning trust fund.

Realized income or loss on the nuclear decommissioning trust fund will be recognized in Account 419. This amount will be offset by an equal amount in Account 407.3 or 407.4, as appropriate, and the offset of the corresponding amount to the regulatory liability in Account 254.

Since 2003, the nuclear decommissioning trust fund has been adequately funded, based upon the current nuclear decommissioning trust fund balance, the current North Anna decommissioning study, and projected realized income on the nuclear decommissioning trust fund. As a result, collection of funds for, and deposits to, the nuclear decommissioning trust fund, recorded in Account 403 were discontinued effective August 30, 2003. The net asset retirement obligation expense is offset by an equal amount in Account 407.4 and the corresponding amount to the regulatory liability in Account 254.

Note C Other Income, Credits or Discounts

All income received or costs incurred by ODEC on behalf of an individual member distribution cooperative for its transactions or arrangements under FERC-approved agreements with Virginia Electric and Power Company, doing business as Dominion Virginia Power; Allegheny Power; Delmarva Power and

Light Company; and/or American Electric Power Company will be directly assigned to the member distribution cooperative on whose behalf the income is received or the cost is incurred, including but not limited to excess facilities charges and power factor correction charges. Amounts to be directly assigned to the individual member distribution cooperative(s) may also include transition fees as provided for in the Board Policy on Addition of Non-Native Load and/or amounts as provided for in the Board Policy on Distributed Solar.

Note D Sales for Resale

ODEC sells excess purchased and generated demand and energy to non-members and its Class B member, TEC. Additionally, ODEC sells renewable energy credits to its member distribution cooperatives and non-members.

Note E Equity Contribution

The Board may budget and set rates to collect margins beyond the Margin Requirement (Note F) to meet and maintain targeted equity levels. Equity development above the Margin Requirement must be approved by the Board and be consistent with Board-approved goals. Equity contributions will be collected from and allocated back to each member distribution cooperative based on Remaining Owned Capacity Service (see Section III.A.1.d., "Remaining Owned Capacity Service") demand billing units for the period.

Note F Margin Requirement

The Margin Requirement shall be up to 20% of the amount in Accts. 427 through 431 for the purpose of determining the rates under the formula. This will provide a times interest earned ratio (“TIER”) of up to 1.2 times, which is necessary to respond to the requirements of the credit rating agencies and to attract capital in the markets.

II.B. Worksheet A – Depreciation Rates

Clover Facility

    FERC Account

    Description

    Depreciation Rate

    310
350
311

    Land
Land Rights – Relocation
Structure & Improvements

    0.00%
1.11%
1.74%

   

    312
314
315

    Boiler Plant Equipment
Turbo Generator Equipment
Accessory Electric Equipment

    2.08%
1.42%
1.71%

   

    316
352
353

    Misc Power Equipment
Structure & Improvements
Station Equipment

    3.79%
2.22%
1.62%

   

    354
355
391

    Towers & Fixtures
Poles & Fixtures
Office Furniture & Equipment

    1.68%
1.66%
6.06%

   

    392
397
398

    Transportation Equipment
Communication Equipment
Miscellaneous Equipment

    5.41%
2.91%
2.11%

   

North Anna Facility


FERC Account	Description	Depreciation Rate
320	Land and Land Rights	0.00%
320.1	Land and Land Rights - Relocation	1.74%
303	Intangible Assets	7.30%
321	Structure & Improvements	2.61%
322	Reactor Plant Equipment	2.93%
323	Turbo Generator Units	4.49%
324	Accessory Electric Equipment	2.55%
325	Misc Power Equipment	6.39%
352	Structure & Improvements	7.44%
353	Station Equipment	4.84%
362	Station Equipment	1.06%
390	Structure & Improvements	0.84%
391	Office Furniture & Equipment	8.26%
392	Transportation Equipment	8.38%
393	Stores Equipment	6.44%
394	Tools, Shop & Garage Equipment	3.45%
395	Laboratory Equipment	2.75%
396	Power Operated Equipment	7.03%
397	Communication Equipment	2.67%
398	Miscellaneous Equipment	8.08%

Louisa Facility


FERC Account	Description	Depreciation Rate
340	Land	0.00%
303	Intangible Assets	3.39%
341	Structure & Improvements	3.50%
342	Fuel Plant	3.36%
343	Prime Mover	3.01%
344	Generator	2.89%
345	Accessory Electric Equipment	4.09%
346	Miscellaneous Power Equipment	4.95%
353 391	Station Equipment Office Furniture, Equipment	3.26% 5.89%
392	Transportation Equipment	1.48%

Marsh Run Facility


FERC Account	Description	Depreciation Rate
340	Land and Land Rights	0.00%
303	Intangible Assets	3.57%
341	Structures & Improvements	3.48%
342	Fuel Plant	3.06%
343	Prime Mover	3.03%
344	Generator	2.75%
345	Accessory Electric Equipment	3.46%
346	Miscellaneous Power Equipment	4.17%
353	Station Equipment	2.87%
391	Office Furniture	10.24%
392	Transportation Equipment	1.05%

Diesel Units


FERC Account	Description	Depreciation Rate
303 341 342 343	Intangible Plant Structures & Improvements Fuel Plant Prime Movers	4.09% 4.18% 3.56% 3.68%
344	Generator	3.86%
345 346 353	Accessory Electric Equipment Misc Power Plant Equipment Station Equipment	3.70% 8.74% 4.01%
392	Transportation Equipment	3.43%

Wildcat Point

     
    Description
 
Initial Composite Rate

    Depreciation Rate
 
3.10%

Battery Electric Storage System – BESS

    FERC Account
 
348

    Description
 
Energy Storage Equipment - Production

    Depreciation Rate
 
7.00%

    353

    Station Equipment

    6.67%

III.

Rate Design and Development of Charges

A. Rate Design

1. Demand Rates

Demand rates shall be developed annually to collect through the formula rate contained herein demand charges as estimated in ODEC's budget. Each member distribution cooperative shall be charged monthly based on its demand billing units multiplied by demand rates for the following, rounded to two decimal places:

Transmission Service

Regional Transmission Operator (RTO) Capacity Service

Remaining Owned Capacity Service

Transmission Service

Transmission Service shall include ODEC’s transmission-related and distribution-related expenses and shall be billed based on the member distribution cooperative’s contribution to the single zonal coincident peak (1 CP) for the previous PJM Transmission Year (November 1–October 31), within each of the PJM Transmission Zones as defined below.

Virginia Electric and Power Company (Dominion) Zone – applicable to BARC Electric Cooperative, Community Electric Cooperative, Mecklenburg Electric Cooperative, Northern Neck Electric Cooperative, Prince George Electric Cooperative, Rappahannock Electric Cooperative, Shenandoah Valley Electric Cooperative, and Southside Electric Cooperative at service points interconnected to the Dominion transmission system.

Delmarva Power and Light Company (DPL) Zone – applicable to A&N Electric Cooperative, Choptank Electric Cooperative, Inc., and Delaware Electric Cooperative, Inc., at service points interconnected to the DPL transmission system.

Allegheny Power (APS) Zone – applicable to BARC Electric Cooperative, Rappahannock Electric Cooperative, and Shenandoah Valley Electric Cooperative at service points interconnected to the APS transmission system.

AEP East (AEP) Zone – applicable to Southside Electric Cooperative at service points interconnected to the AEP transmission system.

i. Transmission Service Rate

Transmission Service Rate = Annual Budgeted Transmission Expense

1 CP kW Demand

1 CP kW Demand = Sum of Prior Year Zonal 1 CPs * 12

ii. Distribution Service Rate

Distribution-related power costs paid by ODEC shall be borne only by the member distribution cooperatives receiving transmission service at distribution service points.

Distribution Service Rate = Annual Budgeted Distribution Expense

1 CP kW Distribution Demand

1 CP kW Distribution Demand = Sum of Prior Year Distribution Zonal 1 CPs * 12

b. RTO Capacity Service

RTO Capacity Service shall include ODEC’s Annual PJM Capacity Costs, excluding Add-backs, and shall be billed based on each member distribution cooperative’s contribution to the prior PJM Capacity Year (June 1 – May 31) average of the five hourly CPs.

RTO Capacity Service Rate =

Annual PJM Capacity Costs (excluding Add-backs)

5 CP kW Demand (excluding Add-backs)

Annual PJM Capacity Costs = All costs incurred by ODEC as a result of capacity acquired in capacity auctions conducted by PJM.

5 CP kW Demand = Sum of Prior Year’s averaged 5 CPs * 12

Add-backs = load reduction, as calculated by PJM, as a result of end-use customers’ participation in PJM demand response programs.

c. Add-backs

In addition to the RTO Capacity Service Rate, to the extent any member distribution cooperative’s customer(s) cause ODEC to incur an Add-back, the member distribution cooperative(s) shall beb directly allocated the Add-back, at actual cost to the member distribution cooperative.

d. Remaining Owned Capacity Service

Remaining Owned Capacity Service shall represent all demand costs not billed under the Transmission Service and RTO Capacity Service charges. It shall be billed based on each member distribution cooperative’s contribution to the average hourly demand for the prior period September 1 through August 31.

Remaining Owned Capacity Rate =

Annual Budgeted Remaining Owned Capacity Expense

Average kW Demand

Average kW Demand = Average demand of all hours from the prior period September 1 through August 31 * 12

2. Energy Rates

a. Base Energy

A Base Energy Rate shall be developed annually to collect through the formula rate contained herein energy charges as estimated in ODEC's budget. The budget shall include adjustments, if any, to collect amounts in the Deferred Energy account from the prior year. Each member distribution cooperative shall be charged monthly based on its monthly energy usage multiplied by the applicable Transmission Energy Rate or Distribution Energy Rate. The Base Energy Rate shall be rounded to five decimal places.

( Annual Budgeted Energy Expenses + Deferred Energy Balance)

Base Energy Rate = ______________________________________________________

(Annual Budgeted Transmission kWh + Annual Budgeted Distribution kWh Adjusted to Transmission)

Any Deferred Energy Balance under-collection projected as of the prior year end shall be added to Annual Budgeted Energy Expenses, whereas, any Deferred Energy Balance over-collection projected as of the prior year end shall be subtracted from the Annual Budgeted Energy Expenses.

Transmission Energy Rate = Base Energy Rate

Distribution Energy Rate = Base Energy Rate * Distribution Loss Factor

Distribution Loss Factor = an average loss factor calculated based on loss factors

b. Energy Adjustment

If at any time during a year it becomes apparent that the Base Energy Rate no longer accurately reflects costs and expenses, the Board may implement or modify the Energy Adjustment Rate to be applied for the remainder of the budget year. The Energy Adjustment Rate shall be an additional charge or credit calculated in accordance with ODEC’s Board-approved policy regarding collection of energy costs and expenses. The Board may implement an Energy Adjustment Rate when the Energy Adjustment Rate would be greater than +/- 2.0% of the Base Energy Rate. The Energy Adjustment Rate shall be rounded to five decimal places.

B. Development of Charges

1. Service Point Level Charges

Energy Charges shall be collected at the service point level with each kWh determinant being derived from revenue quality meters located at each of the service points. These service points are the demarcation points whereby ODEC takes wholesale transmission service for delivery to the member distribution cooperatives. The Service Point Level Charges are as follows:

Transmission Energy Charges = Transmission Energy Rate * Transmission Service Point kWh

Distribution Energy Charges = Distribution Energy Rate * Distribution Service Point kWh

Energy Adjustment Charges = Energy Adjustment Rate * Service Point kWh

2. Member Distribution Cooperative Level Demand Charges

Transmission Service Charges, RTO Capacity Service Charges, and Remaining Owned Capacity Service Charges shall be fixed monthly charges for the budget year. Transmission service costs shall be allocated based on each member distribution cooperative's contribution to the respective Zonal 1 CP kW demand. RTO Capacity Service costs shall be allocated based on the average of each member distribution cooperative's contribution to the top five hourly PJM CPs exclusive of add-backs for demand response participation. Remaining Owned Capacity Service costs shall be allocated based on each member distribution cooperative’s average hourly demand. The Member Distribution Cooperative Level Demand Charges are as follows:

Transmission Service Charges = Transmission Service Rate * Member Distribution Cooperative’s Contribution to Zonal 1 CP kW Transmission Demand

Distribution Service Charges = (Transmission Service Rate + Distribution Service Rate) * Member Distribution Cooperative’s Contribution to Zonal 1 CP kW Distribution Demand

RTO Capacity Service Charges = RTO Capacity Service Rate * Member Distribution Cooperative’s Contribution to PJM 5 CP kW Demand

Remaining Owned Capacity Service Charges = Remaining Owned Capacity Service Rate * Member Distribution Cooperative’s Contribution to the Average kW Demand Period (September 1 – August 31)

IV.

Payment Terms

Bills are due and payable within ten calendar days after the ninth working day of each month, provided, however, that the payment date can be extended and/or bills can be prepaid pursuant to ODEC’s Cash Management Program.