RESOURCE CONSERVATION AGREEMENT

Exhibit 10.15

This Resource Conservation Agreement, including the attachments and exhibits hereto, (“RCA”) is made this 12^th day of February, 2004, between the Midland Cogeneration Venture Limited Partnership (“MCV”), a Michigan limited partnership with offices at 000 Xxxxxxxx Xxxxx, Xxxxxxx, Xxxxxxxx 00000, and Consumers Energy Company (“CECo” or “Consumers”), a Michigan corporation with offices at Xxx Xxxxxx Xxxxx, Xxxxxxx, Xxxxxxxx 00000 (sometimes referred to in the singular as “Party,” and sometimes collectively as “Parties”).

WHEREAS, MCV and CECo have entered into a Power Purchase Agreement dated as of July 17, 1986 (as amended, the “PPA”), and

WHEREAS, the PPA provides for the supply by MCV to CECo of 1240 megawatts (“MW”) of capacity and associated energy produced by the natural gas–fired MCV cogeneration facility (“MC-Facility” as that term is defined in the PPA) located in Midland, Michigan, and

WHEREAS, CECo has informed MCV that to be consistent with ratemaking practices adopted by the Michigan Public Service Commission (“MPSC”), CECo commenced dispatching the MC-Facility, on January 1, 2004, at a minimum production level of 1100 MW during both on-peak and off-peak periods as provided in Michigan Public Service Commission orders in Case No. U-8871/U-10127 (“Option 2 Dispatch”) and will continue to dispatch the MC-Facility in such a fashion, unless the MPSC approves the relief requested by CECo in Case No. U-14031, and

WHEREAS, the Parties desire to reduce financial losses associated with the use of high cost natural gas at the MC-Facility and conserve natural gas during a period of high and volatile natural gas prices, and CECo desires to promote the development of renewable resources in Michigan, and

WHEREAS, the Parties desire to establish terms and conditions that will achieve the above-stated benefits while assuring that electric utility customers of CECo are protected from increased costs,

NOW, THEREFORE, the Parties agree as follows:

	1.	This RCA shall not limit or alter in any way any of the rights and obligations of the Parties under the PPA. The Parties agree that this RCA is independent of the PPA, and is not intended as an amendment, modification or supplement to the PPA. This RCA has been entered into by the Parties for the purpose of administering certain features of the PPA.

	2.	All Contract Capacity in excess of an amount of megawatts (“MW”) to be specified hourly by the MCV (“Minimum Dispatch”) that is subject to the PPA will be economically dispatched by CECo based on the higher of (i) the variable energy cost recovery rate¹ or (ii) the market price of natural gas multiplied by the MC-Facility’s heat rate plus (or minus) NOx emissions expense and variable operation and maintenance expense (sometimes referred to as “MCV’s Cost of Production” or “COP”). The Minimum Dispatch shall not exceed 550 MW. For purposes of this RCA, the market price of natural gas will be based upon market indices agreed upon by the Parties. The precise method for determining the economic dispatch price including COP will be developed and mutually agreed upon by the Parties.

	3.	The economic dispatch procedure identified in Section 2 of this RCA is expected to reduce electric production at the MC-Facility from what would have occurred under the Option 2 Dispatch procedure. The reduction in electric production at the MC-Facility will result in replacement of energy from some combination of increased output from

¹ The variable energy cost recovery rate is: for capacity of 1100 MW or less, the variable energy payment rate as defined in Exhibit C to the PPA (“VEP”); and for capacity greater than 1100 MW but less than or equal to 1240 MW, VEP plus $5.00/MWh.

		other generating units owned or controlled by CECo and/or increased purchases of energy from third-party power suppliers. The integrated hourly cost of the energy supplied from these replacement sources will be compared to the integrated hourly cost of the energy that would have been supplied by the MC-Facility under the Option 2 Dispatch procedure, and the MCV will reimburse to CECo an amount equal to the net difference in such costs so that CECo will be financially indifferent, thereby allowing CECo to hold its customers harmless. This netted reimbursement amount is hereinafter referred to as the “Hold Harmless Payment.” The Hold Harmless Payment shall be determined as set forth on Attachment 1 to this RCA which is incorporated herein and made a part hereof.

	4.	The economic dispatch procedure described in Section 2 of this RCA is expected to result in a decrease in the consumption of natural gas at the MC-Facility. The natural gas conserved in this manner will be determined on a daily basis and made available for purchase by CECo. Before MCV disposes of such gas, it shall offer to sell such gas to CECo at market price. If CECo does not exercise this right, MCV shall be entitled to dispose of such gas. The amount of the natural gas that is subject to CECo’s right of first refusal, the market price applicable to the exercise of this right, and the manner of exercising this right shall be as set forth on Attachment 2 to this RCA which is incorporated herein and made a part hereof.

(a).

This RCA is part of a resource conservation plan submitted to the MPSC by CECo. As set forth in Section 2 of this RCA, one element of this plan is a change from the Option 2 Dispatch procedure to an economic dispatch procedure. Notwithstanding this change in dispatch procedures, CECo will, during the term of this RCA, continue to make payments to MCV of capacity and fixed energy charges as previously agreed to by the Parties. The Parties agree that they will determine the availability of the MC-Facility in the manner

		set forth on Attachment 3 to this RCA, which will be used as the basis for CECo seeking cost recovery in future proceedings conducted by the MPSC. Attachment 3 to this RCA is incorporated herein and made a part hereof. Notwithstanding anything to the contrary herein, Attachment 3 shall survive the termination of this RCA since it is an Operating Practice established by the Parties to administer the PPA. CECo will continue to pay MCV the VEP for all energy actually delivered from Contract Capacity as previously agreed to by the Parties.

	(b)	Consumers shall file an application with the MPSC seeking approval of the material terms and conditions of this RCA.

	(c)	As a condition precedent to this RCA becoming effective, both Consumers and MCV must accept the terms and conditions of the MPSC order that results from the Application referred to in subparagraph (b) immediately above. In determining whether to accept said MPSC order, each Party shall be entitled to act in its sole and absolute discretion and in its sole best interests. The Parties shall make their determination within 20 days of the date of the MPSC order, or sooner should the MPSC fix an earlier time. This subparagraph applies to any interim order, final order, or order on rehearing issued by the MPSC.

	(d)	Each Party shall notify the other within the time period in subparagraph (c) immediately above, of its decision to accept or reject the MPSC order(s) and, upon acceptance, file with the MPSC any documents required to effectuate such acceptance.

(a)

The term of this RCA shall commence within seven calendar days after the date that CECo and MCV accept or otherwise do not object to the MPSC order or orders referred to in paragraph 5 (c).

	(b)	This RCA shall expire the earlier of midnight on March 15, 2025, or the termination of the PPA, unless sooner terminated in accordance with the provisions of this RCA.

	(c)	Either Party may terminate this RCA upon 30 days written notice if (i) the MPSC issues an order addressing any matter covered by or affecting this RCA that the terminating Party determines, in good faith, would significantly adversely affect its financial interests, or (ii) the MPSC staff makes an official filing addressing any matter covered by or affecting this RCA that the terminating Party determines, in good faith, would, if adopted by the MPSC, significantly adversely affect its financial interests.

	(d)	Either Party may terminate this RCA upon 30 days written notice if: (i) there is an adoption of any accounting requirement, law, rule, regulation, ordinance, statute, MPSC order, court order, and/or FERC order or ruling addressing any matter covered by or affecting this RCA that the terminating Party determines, in good faith, would significantly adversely affect its financial interests; (ii) there is any governmental action associated with any accounting requirement, law, rule, regulation, ordinance, statute, MPSC order, court order, and/or FERC order or ruling addressing any matter covered by or affecting this RCA that the terminating Party determines, in good faith, would significantly adversely affect its financial interests; (iii) there is any change in any accounting requirement, law, rule, regulation, ordinance, statute, MPSC order, court order, and/or FERC order or ruling addressing any matter covered by or affecting this RCA that the terminating Party determines, in good faith, would significantly adversely affect its financial interests; or (iv) either Party implements a change in any accounting requirement that the terminating Party

		determines, in good faith, would significantly adversely affect its financial interests.

	(e)	MCV may terminate this RCA upon 30 days written notice if an Owner Participant, the Owner Trustee, any Indenture Trustee, or any other party to any of the Overall Project Documents (as those terms are defined in the sale/leaseback documents) indicates in any communication to MCV any objection to any matter covered by or affecting this RCA that MCV determines, in good faith, would significantly adversely affect its contractual or financial interests.

	(f)	Either Party shall have the right to terminate this RCA upon 5 days written notice without liability of any kind whatsoever to the other Party at any time prior to the issuance of a final order by the MPSC addressing the relief sought in Case No. U-14031; provided that such right of termination cannot be exercised prior to April 1, 2004.

	(g)	The Parties agree that the full implementation of this RCA will require the negotiation and execution of a further agreement that fully identifies the manner in which various provisions of this RCA will be implemented and administered. If such a further agreement is not executed within 30 days of the date of execution of this RCA, either Party has the right to terminate this RCA upon 5 days written notice without liability of any kind whatsoever to the other Party.

	(h)	If termination of this RCA occurs pursuant to subparagraphs (b), (c), (d), (e), (f) or (g) above, such termination shall not affect or excuse the performance of either Party incurred prior to the effective date of such termination and both Parties shall fulfill such obligations.

	(i)	The Parties agree that the transactions hereunder constitute a “Forward Contract” within the meaning of the United States

		Bankruptcy Code and the Parties are each “Forward Contract Merchants” within the meaning of the United States Bankruptcy Code. In the event either Party shall: (i) make an assignment or any general arrangement for the benefit of creditors; (ii) file a petition or otherwise commence, authorize, or acquiesce in the commencement of a proceeding or case under any bankruptcy or similar law for the protection of creditors or have such a petition filed or proceeding commenced against it; or (iii) shall otherwise become bankrupt or insolvent (however evidenced), then the other Party shall have the right, at its sole election and in its sole discretion, to immediately terminate this RCA and shall thereupon send notice of such termination to the other Party.

	(j)	Either Party may terminate this RCA upon 10 days written notice in the event the non-terminating Party is in default in the performance of a material provision of this RCA and such default continues for 10 days following receipt of such notice by the non-terminating Party. Notwithstanding such termination, the terminating Party shall be entitled to all other remedies available to it at law or in equity as a result of such default.

Unless otherwise provided in this RCA, any notice, consent or other communication required or permitted to be made under this RCA shall be in writing and shall be delivered to the address or facsimile number set forth below or such other address or facsimile number as the receiving Party may designate in writing. All notices shall be effective when received provided that any notice received after 5:00 p.m. shall be deemed received the next business day of the recipient.


For CECo:		For MCV:

Consumers Energy Company		Midland Cogeneration Venture
One Energy Plaza		Limited Partnership
Xxxxxxx, Xxxxxxxx 00000		000 Xxxxxxxx Xxxxx
Attention: Xxxxxxx X. Xxxxxxx		Xxxxxxx, Xxxxxxxx 00000
Fax #: 000-000-0000		Attention: XxXxx X. Xxxxx
		Fax #: 000-000-0000

		Each Party may change the name and address of its contact person by giving the other Party written notice of the change.

	8.	Except to the extent specifically provided for in this RCA, neither Party shall in any event be liable to the other for any special, incidental, exemplary, punitive or consequential damages such as, but not limited to, lost profits, revenue or good will, interest, loss by reason of shutdown or nonoperation of equipment or machinery, increased expense of operation of equipment or machinery, loss of use of equipment or machinery, whether such loss is based on contract, warranty, negligence, indemnity, strict liability or otherwise. Except for remedies specifically provided for elsewhere in this RCA, no liability shall attach to a Party for failure to settle any strike or other labor problem in a manner not completely satisfactory to it.

	9.	Notwithstanding anything to the contrary contained in this RCA, the liabilities and obligations of MCV arising out of, or in connection with this RCA or any other agreements entered into pursuant hereto shall not be enforced by any action or proceeding wherein damages or any money judgment or specific performance of any covenant in any such document and whether based upon contract, warranty, negligence, indemnity, strict liability or otherwise, shall be sought against the assets of the partners comprising MCV. By entering into this RCA, CECo waives any and all right to xxx for, seek or demand any judgment against such partners and their affiliates, other than MCV, by reason of the liabilities and obligations of MCV arising out of, or in connection with, this RCA or any other agreements entered into pursuant hereto, except to the extent such partners are legally required to be named in any action to be brought against MCV.

	10.	This RCA shall be deemed to be a Michigan contract and shall be construed in accordance with and governed by the laws of Michigan, without regard to principles of conflicts of law.

	11.	This RCA shall not be interpreted or construed to create an association, joint venture or partnership between the Parties or to impose any partnership obligation or liability upon either Party. Neither Party shall have any right, power or authority to enter into any agreement or undertaking for, or act on behalf of, or to act as or be an agent or representative of, or to otherwise bind, the other Party.

	12.	This RCA may be executed and delivered in counterparts (including by facsimile transmission), each of which may be deemed an original.

IN WITNESS WHEREOF, this RCA is executed as of the day and year first herein above written.


MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP		CONSUMERS ENERGY COMPANY

/s/ Xxxxx X. Xxxxx		/s/ Xxxxx X. Xxxx

Xxxxx X. Xxxxx		Xxxxx X. Xxxx,
President and CEO		President and Chief Operating Officer
Midland Cogeneration Venture Limited Partnership		Consumers Energy Company

ATTACHMENT 1

Hold Harmless Payment

Consumers Energy Company (“CECo”) will save, in electronic form or otherwise, all integrated hourly data in its possession that is necessary to calculate and support the amount and cost of owned, controlled and purchased Resources (defined below) used or available to serve its load and to make sales to other parties (collectively “Cost Data”) for each day that CECo believes a Hold Harmless Payment is due hereunder. The numbered steps of the following procedure describe how the Hold Harmless Payment will be determined from the Cost Data. To perform this determination, Consumers’ Actual Dispatch (defined below) of Resources will be compared to a hypothetical dispatch of Resources that would have occurred had the MC-Facility been forced dispatched in accordance with the Option 2 Dispatch (“Hypothetical System Dispatch”) instead of the MC-Facility’s COP.

Except for the capitalized terms defined herein, all other capitalized terms are as defined in the RCA or PPA.

“Business Day” means a calendar day other than a Saturday, Sunday, or a North American Electric Reliability Council holiday.

“Incremental Cost” means, for any hour, the cost to CECo of the next available least cost Resource (adjusted by Penalty Factor) to serve an incremental increase in CECo’s load (including wholesale sales to third parties) as determined pursuant to RCP Procedure 1 (attached hereto as Exhibit A).

“Market Price of Energy” means the assumed price that energy may be sold in the power market as determined pursuant to RCP Procedure 2 (attached hereto as Exhibit B).

“Penalty Factor” means, to the extent available and able to be practicably calculated and implemented, the incremental transmission loss factor applied to the Incremental Cost of a Resource to reflect the cost of the Resource at CECo’s load center or other common reference point. The Penalty Factor is determined in accordance with RCP Procedure 1.

“PPA Dispatch Cost” means the Incremental Cost that CECo would use to dispatch the last 140 MW of MC-Facility Contract Capacity (i.e., the Incremental Cost associated with the variable energy rate as defined in Exhibit C to the PPA (“VEP”) plus $5/MWh).

“Resource(s)” means the owned, controlled and purchased power resources available to CECo to serve its load and make wholesale sales to third parties.

ATTACHMENT 1

Procedure

The following procedure will be performed by CECo using software it developed along with a Microsoft Excel spreadsheet. The software may perform some of the following tasks simultaneously.

Step 1.

On the Business Day immediately following each day that the MC-Facility is dispatched at the COP, CECo will run internally developed software that uses the Cost Data of the day the MC-Facility was dispatched at the COP as the input. The output of this software shall be an accurate integrated hourly list of Resources ordered in one (1) MW blocks from least Incremental Cost at the bottom of the list to highest Incremental Cost at the top of the list (“Incremental Cost List” or “IC List”).¹ The IC List constructed in this manner (as adjusted pursuant to the following two paragraphs) is called the “Actual Dispatch.”

Non-dispatchable Resources and the portions of dispatchable Resources that must run (i.e., must run generation) are placed at the bottom of the list at their total integrated output or portion of total integrated output (as applicable) instead of the one (1) MW blocks referred to above. This includes the Minimum Generation (currently at 350 MW) for the MC-Facility as specified in the PPA.

Resources that have a constant Incremental Cost (i.e., the cost is independent of output level) for their entire output and the portions of dispatchable Resources (i.e., above must run generation) that have a constant Incremental Cost are listed at their total integrated hourly output (or portion thereof, as applicable) instead of the one (1) MW blocks referred to above.

For the CECo developed software used for the following step, all entries in the IC List described above are represented as one (1) MW blocks.

Step 2.

In the procedure detailed below in this Step 2, the Hypothetical System Dispatch for each hour is constructed from the Actual Dispatch by determining (1) which Resources in the Actual Dispatch would not have been used had the MC-Facility been dispatched under the Option 2 Dispatch (excluding any Resources used for potential sales that could have been made beyond the amount of sales that occurred in the Actual Dispatch), and (2) any sales beyond the amount of sales that occurred in

¹ While the MC-Facility will be dispatched at COP and thus the quantity of energy dispatched for the MC-Facility will be consistent with such a price, the actual price recovered by CECo from its customers for this energy is the same price that would be so recovered if the MC-Facility was subject to Option 2 Dispatch as reflected in the Hypothetical System Dispatch constructed herein. Therefore, when the Actual Dispatch is compared with the Hypothetical System Dispatch, the Incremental Cost of energy from the MC-Facility is considered to be the same in both dispatches. MCV will be paid fixed energy based on availability up to 1100 MW in the Hypothetical System Dispatch and will be paid capacity payments and variable energy payments as set forth in the RCA.

ATTACHMENT 1

the Actual Dispatch that potentially could have been made had the MC-Facility been dispatched under the Option 2 Dispatch. In constructing the Hypothetical System Dispatch, the Ludington Plant is incorporated as per RCP Procedure 1. In addition, MC-Facility capacity in the IC List of the Actual Dispatch is ignored in the construction of the Hypothetical System Dispatch unless otherwise indicated below.

	(a)	The number of one (1) MW blocks of Resources in the Actual Dispatch that would not have been used in the Actual Dispatch had the MC-Facility been dispatched under the Option 2 Dispatch are equal to the number of one (1) MW blocks of the 1100 MW block of the MC-Facility Contract Capacity above Minimum Generation that were available (“Available Capacity” as verified pursuant to Attachment 3 to the RCA) but not dispatched in the Actual Dispatch. These one (1) MW blocks of Resources are identified by counting down from the top of the IC List in the Actual Dispatch.²

	(b)	The PPA Dispatch Cost of each one (1) MW block of the remaining 140 MW block of MC-Facility Contract Capacity (to the extent each such block is available) is then compared to the Incremental Costs of the Resources in the IC List of the Actual Dispatch beginning with the first one (1) MW block of Resources encountered at the top of the IC List after counting down the one (1) MW blocks in (a) above. The savings or costs, as the case may be, that would be realized by replacing each one (1) MW Resource with each one (1) MW block of the 140 MW block for all the hours in the Hypothetical System Dispatch being constructed are then used to create the least cost dispatch for such hours of the 140 MW block given the operating constraints³ identified in Operating Practice 2 between the Parties. The least cost dispatch is then used to determine which one (1) MW blocks of Resources would not have been used in the Actual Dispatch had the 140 MW block of MC-Facility Contract Capacity been dispatched at PPA Dispatch Cost.

(c)

The number of one (1) MW blocks of Resources that would not have been used in the Actual Dispatch pursuant to procedures 2(a) and 2(b) above plus any remaining one (1) MW blocks of the 140 MW block not dispatched in 2(b) above constitute the number of one (1) MW blocks available for potential sales. Said number of one (1) MW blocks is used in RCP Procedure 2, as applicable, to determine the amount of one (1) MW blocks that could potentially be sold taking into account market

² In the event that this Step would have resulted in the displacement of must run Resources, it will be assumed that, pursuing the least cost alternative, CECo would have exercised its rights under its contracts with some of its Resources to cycle such Resources off-line pursuant to 18 CFR 292.304(f) and/or made a sale at the Market Price of Energy determined in accordance with RCP Procedure 2 assuming (a) no limitations due to Spread, and (b) if a Market Price of Energy cannot be established pursuant to RCP Procedure 2, then the Market Price of Energy shall be deemed to equal zero $/MWh.

³ Specifically, the constraints identified in Subsections 1.2.3.4 (except that the two-hour constraint will be applied to all reversals) and 1.2.3.6 of Operating Practice 2.

ATTACHMENT 1

		depth constraints and the Market Price of Energy of each such one (1) MW block. Potential sales from these one (1) MW blocks are then determined pursuant to RCP Procedure 2.

	(d)	The Hypothetical System Dispatch, then, is the Actual Dispatch less those Resources that would not have been used as a result of dispatch under the Option 2 Dispatch of the available 1100 MW block of MC-Facility Contract Capacity pursuant to 2(a) above and least cost dispatch of the available 140 MW block of MC-Facility Contract Capacity pursuant to 2(b) above, plus the Resources and any available portion of the 140 MW block used for sales pursuant to 2(c) above.

Step 3.

The hourly IC Lists of the Actual Dispatch and the Hypothetical System Dispatch are then compared to determine the costs of the Resources in the Actual Dispatch that were not used in the Hypothetical System Dispatch (excluding the costs of any Resources used for potential sales that could have been made beyond the amount of sales that occurred in the Actual Dispatch). These Resources in the Actual Dispatch took the place of (or “displaced”) the MC-Facility Contract Capacity as a result of dispatching such MC-Facility capacity at the COP pursuant to the RCA and are called “Displacement Resources”. The costs of these Resources in the Actual Dispatch are called “Displacement Costs” as further defined below.


Step 4.	Potential sales from Displacement Resources and available 140 MW block of MC-Facility Contract Capacity determined pursuant to Step 2(c) are deemed to involve sales gains that CECo would have received had the MC-Facility been dispatched under the Option 2 Dispatch. Said sales gains shall be determined by subtracting the Incremental Cost of each one (1) MW block of Displacement Resources deemed sold and each one (1) MW of available 140 MW block of MC-Facility Contract Capacity deemed sold from the applicable Market Price of Energy during each hour. These sales gains from such potential sales to third parties will be reimbursed to CECo by MCV pursuant to Step (6).

Step 5.	The weighted average (by MW) cost of the Displacement Resources in the Actual Dispatch that displaced MC-Facility Contract Capacity is calculated for each hour from the amounts and prices of the Resources determined pursuant to Steps (2) and (3) above and divided by the MC-Facility Penalty Factor to reflect the cost at the point of delivery under the PPA (“Displacement Costs”).

	The weighted average (by MW) cost of the portions of the 1100 MW block (i.e., VEP) and 140 MW block (i.e., VEP plus $5/MWh) of the available MC-Facility Contract Capacity displaced by the Displacement Resources in the Actual Dispatch pursuant to Steps (2) and (3) above (“PPA Cost”) is also calculated for each hour.

ATTACHMENT 1

Step 6.

The Hold Harmless Payment for each calendar day is the sum of the hourly products of the total MW of the Displacement Resources in the Actual Dispatch that displaced the MC-Facility pursuant to Steps (2) and (3) above times the difference between the unit Displacement Costs and the unit PPA Cost pursuant to Step 5 above, plus the sum of the hourly sales gains from any potential sales that CECo would have made from Displacement Resources and from available portions of the 140 MW block pursuant to Steps (2) and (4) above.


Step 7.	On each Business Day, CECo shall communicate to MCV the determinations and calculations of the Hold Harmless Payment for the prior calendar day or days, as applicable.

Exhibit A
(RCP Procedure 1)
to Attachment 1 of the
Resource Conservation Agreement
between
Consumers Energy Company
and
Midland Cogeneration Venture Limited Partnership

RCP Procedure 1
Resource Pricing

This RCP Procedure is entered into pursuant to the RCA dated February 12, 2004 between Midland Cogeneration Venture Limited Partnership (“MCV”) and Consumers Energy Company (“CECo”). Capitalized terms that are not defined herein are as defined in the RCA, PPA or RCP Procedure 2, as applicable.

“Good Utility Practice” means at a particular time, any of the practices, methods and acts, which, in the exercise of reasonable judgment in the light of the facts known at the time the decision was made, would have been expected to accomplish the desired result at a reasonable cost consistent with reliability and safety and all applicable laws and governmental rules, regulations and orders pertaining to the subject matter. Such practices, methods and acts shall include, but shall not be limited to, any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry prior to the time the decision was made. Good Utility Practice is not intended to be limited to the optimum practice, method or act, to the exclusion of all others, but rather to be a number of possible practices, methods or acts. For purposes of the RCA CECo shall employ the same practices, methods, and acts as the Michigan Public Service Commission approves for CECo cost recovery and other matters related to the RCA.

“Pumping Efficiency Factor” is the efficiency by which the Ludington Pumped Storage Plant’s (“Ludington Plant”) ability to generate power is less than the power requirements for pumping.

The purpose of this RCP Procedure 1 is to describe the method that will be used to prepare the hourly Incremental Cost Lists for the Actual Dispatch and the Hypothetical System Dispatch, as required to implement the RCA. Unless specified herein, the Incremental Costs described below are prior to adjustment by the Penalty Factor.

Determination of CECo’s Owned Resources Incremental Cost. Of CECo’s owned Resources, only those Resources that are dispatchable have an associated Incremental Cost. The Incremental Cost of CECo’s dispatchable owned Resources shall be determined in accordance with Good Utility Practice by applying each plant’s fuel cost and adders for variable operation and maintenance costs, fuel handling cost, emission allowance value, and the cost of other allowances and credits that have value, against its incremental heat rate and operating factor, so as to provide an accurate estimate, as is reasonably possible, of the costs expected to be incurred and deemed to have been actually incurred in the dispatch of those Resources. This Incremental Cost does not include the start up cost or no-

load cost associated with the initial production of energy from a formerly idle facility.

1.1

Ludington. The Incremental Cost of generation from CECo’s portion of the Ludington Plant is determined by the cost of Resources used to pump water into the plant’s reservoir and the Pumping Efficiency Factor. For the purposes of determining the Hypothetical System Dispatch in the RCA, the Incremental Cost of the Ludington Plant during generating cycles shall be determined as follows:

	(a)	The total MW pumped and generated in each hour of each day in the Hypothetical System Dispatch shall match those of the Actual Dispatch.

	(b)	The Incremental Cost List (in one (1) MW blocks) of the Resources used to pump water into the reservoir during each hour of the pumping cycle is obtained from the IC List of the Hypothetical System Dispatch constructed pursuant to Step 2 of Attachment 1 to the RCA for said pumping cycle and removing the one (1) MW blocks of Resources used for sales from the top of this IC List.

	(c)	The one (1) MW blocks of Resources used to pump water into the reservoir during each hour in the Hypothetical System Dispatch are identified by counting down from the top of the IC List in (b) above the number of one (1) MW blocks used to pump water into the reservoir during each hour in the Actual Dispatch.

	(d)	An average Incremental Cost of all the one (1) MW blocks identified in (c) above for the pumping cycle is calculated. This average, divided by the Pumping Efficiency Factor, is the Incremental Cost to be used for the Ludington Plant during the generating cycle in the Hypothetical System Dispatch.

	(e)	To the extent that there is remaining “energy” in the reservoir following the subsequent generating cycle (“First Generating Cycle”), the Incremental Cost of the Ludington Plant for the generating cycles after the First Generating Cycle shall be the weighted average of the Incremental Cost of the remaining “energy” and the Incremental Cost of the new (as determined in accordance with (a) through (d) above) “energy” placed in the reservoir.

Determination of CECo’s Controlled and Purchased Resources Cost. All of CECo’s short-term purchases of power are considered dispatchable. For the purposes of this RCP Procedure 1, “short term purchases” means all hourly, balance of day, day-ahead (e.g., 1 day x 16 hours), balance of week (e.g., on-peak — up to 4 days, off-peak and round the clock – up to 6 days) and all dispatchable energy and capacity purchases. CECo has some long-term purchases that are also dispatchable. As of the date of this RCP

Procedure 1, CECo’s long-term dispatchable purchases include (with the exception of MCV): (i) Ada Cogeneration Limited Partnership, (ii) Bio Energy Partners, (iii) Cadillac Renewable Energy LLC, (iv) Genesee Power Station Limited Partnership, (v) Xxxxxxx Electric Company (Grand Blanc Generating Station), (vi) Xxxxxxx Electric Company (Landfill No. 1), (vii) Xxxxxxx Electric Company (Landfill No. 2), and (viii) Grayling Generating Station Limited Partnership. The Incremental Costs of CECo’s controlled and purchased resources shall be determined in accordance with Good Utility Practice and shall be comprised of the following components:

	(a)	The purchase price at the point of delivery, excluding any option premium amounts, capacity payments under dispatchable and energy contracts, and other similar fixed cost considerations.

	(b)	The transmission service costs (including losses, if applicable) to transmit the power from the point of delivery to the CECo Bus (defined below), if applicable. If CECo transmitted the power to the CECo Bus by using a transmission service reservation that can accommodate purchases of greater size than that of a specific transaction, only the prorata cost for the MW transmitted are to be included.

	(c)	For purchases that require transmission service to deliver the power to the CECo Bus, the Penalty Factor shall be applied which is based on a weighted average of (i) 70% of the Penalty Factor associated with power received at the Michigan Electric Transmission Company’s or any successor’s (“METC”) interconnection with the American Electric Power Company (or any successor) and (ii) 30% of the Penalty Factor associated with power received at the METC’s interconnection with the International Transmission Company (or any successor). The 70% / 30% allocation shall be reviewed and revised as necessary annually for implementation on February 1 of each year by mutual agreement of the Parties.

Penalty Factor. If available, CECo shall use the Penalty Factors provided by the METC for CECo’s Resources. Should such Penalty Factors not be available, the Parties, by mutual agreement, shall consider other means of reflecting prices at a common reference point to determine a Penalty Factor to the extent such can be practicably calculated and implemented.

CECo Bus. As a reference point for pricing, “CECo Bus” means the commercial point of receipt where the buyer of power from CECo is responsible for all charges and transmission losses for power transmitted across the METC and across any other transmission provider’s system to the ultimate point of delivery.

Exhibit B
(RCP Procedure 2)
to Attachment 1 of the
Resource Conservation Agreement
between
Consumers Energy Company
and
Midland Cogeneration Venture Limited Partnership

RCP Procedure 2
Market Price and Sales Determination

The purpose of this RCP Procedure 2 is to describe the method that will be used pursuant to the RCA to measure the sales gain, if any, that could have been realized from third-party sales that would have been made under the Hypothetical System Dispatch from (i) Resources that, in the Actual Dispatch, were used to displace MC-Facility Contract Capacity, but would have been available for sale to third parties under the Hypothetical System Dispatch, and (ii) any portion of the MC-Facility Contract Capacity that is not utilized in the Hypothetical System Dispatch, and would therefore have been available for third-party sales under the Hypothetical System Dispatch.

“Off-Peak Hours” means all hours other than On-Peak Hours.

“On-Peak Hours” means all hours between 7:00 A.M. and 11:00 P.M. EST, Monday through Friday except holidays as established by the North American Electric Reliability Council (“NERC”) on an annual basis (“NERC Holiday(s)”).

The term “Spread” used herein means the positive difference between the Market Price of Energy (as determined below) and (a) the Incremental Cost associated with available portions of the last 140 MW block of the MC-Facility’s Contract Capacity (i.e., VEP plus $5/MWh adjusted by Penalty Factor), or (b) the Incremental Cost of other CECo available Resources, as applicable

On-Peak Hours

“Market Price of Energy” for On-Peak Hours is determined from the three methods specified below in preferential order. That is, if the Market Price of Energy cannot be determined from the first method, then the second method will be applied, and so on. The application of these methods will reflect the fact that market prices decline with increasing volumes of energy sold, but only down to a point at which no further decline occurs (assumed at the inception of this agreement to be 300 MW for the purposes of this RCP Procedure 2). Consequently, the following methods will employ incremental market prices (i.e., market prices expressed in one (1) MW blocks) to model this dilution of prices as sales to third parties increase. The model for market price dilution is based on 2003 historical data of CECo’s sales volumes and associated prices. The model shall be updated annually for use beginning February 1, by mutual agreement of the Parties so that the most current annual data will be used. An analysis of 2003 data produced the formula specified in Item (2) of Method 1 below which relates a median market price to the maximum market price that could be obtained if energy sales were sold in one (1) MW increments. This

same formula is then rearranged in Item (3) of Method 1 below to determine a Market Price of Energy for each one (1) MW block available to be sold beginning with the lowest cost available one (1) MW block and ending with the highest cost available one (1) MW block. Therefore, the purpose of each method below is to: (1) Establish the average market price for a given hour (if such average market price can be established, then the average market price will be used to determine the maximum Market Price of Energy), (2) Assign a Market Price of Energy, beginning with the lowest cost available one (1) MW block at the maximum Market Price of Energy, to each individual one (1) MW block sold (in the Actual Dispatch, if any) and available to be sold and included in the Hypothetical System Dispatch sales gain calculation, and (3) Compare the Market Price of Energy assigned to each available one (1) MW block to be sold to the Incremental Cost of such available one (1) MW block to determine the sales gain from the deemed sale of each said one (1) MW block. In the event that any Spread from the foregoing comparison is less than $1/MWhr, then it shall be deemed that no sale would have been made.

Method 1:

(1)

An initial Market Price of Energy will be determined for each On-Peak Hour from the weighted average of all hourly sales by CECo for such hour for delivery at the CECo Bus (excluding sales of emergency energy) that in aggregate total at least 100 MW. In the event a sale is made from a delivery location other than the CECo Bus, the price for such a sale shall be discounted for transmission service charges and losses associated with the applicable delivery location to make such a sale equivalent to a sale at the CECo Bus (Exhibit 1 shows the current applicable delivery location for specific CECo counterparties, which Exhibit shall be updated annually for use beginning February 1, by mutual agreement of the Parties so that the most current annual data will be used). An example of Method 1 for sales at the CECo Bus for a given hour is below:



Method 1 Example 1
(1)	(2)		(3) = (1) x (2)		(4)
Sale	MW		Weighted		Weighted
Price	Sold		Cost		Average
32		50	$	1,600	$	7,425
31		75	$	2,325	divided by
35		100	$	3,500	225 MW
						=
Total		225	$	7,425	$33/MW

(2)	A maximum Market Price of Energy will be determined from the average market price in (1) above. Such maximum Market Price of Energy will be determined from the following formula:

	Where MP_I is the initial Market Price of Energy from (1) above and MW_TSM is the lower of 50% of the total sold (in MW) in the applicable hour or 150 MW. If the above formula was applied to Method 1 Example 1: (a) MP_I would equal $33/MW, (b) MW_TSM would equal 112.5 MW, and (c) MP_MAX would equal $35.10/MW.

(3)	The Market Price of Energy of the individual one (1) MW blocks sold and available to be sold is then determined from the following formula:

	MP_K = -0.000532 x (K-1) x MP_MAX + MP_MAX

	Where K is the range of one (1) MW to the total sold (in MW) and deemed sold in the applicable hour. When K is greater than 300, MP_K shall equal MP₃₀₀.

(4)	The Market Price of Energy of the individual one (1) MW blocks from (3) above is then compared to the Incremental Costs of said blocks and the total sales gains from the hour are determined. An example for 10 MW available to be sold (beyond the 225 MW sold in Example 1 above) is below.



Method 1 Example 2
			Incremental
	Market		Cost of		Sales
MW Sold	Price		Available MW		Gain
(in order)	($/MW)		($/MW)		($)
226		30.90		29.77		1.13
227		30.88		29.79		1.09
228		30.86		29.80		1.06
229		30.84		29.81		1.03
230		30.82		29.85	No Sale
231		30.81		29.87	No Sale
232		30.79		29.88	No Sale
233		30.77		29.90	No Sale
234		30.75		29.92	No Sale
235		30.73		29.93	No Sale
			Total Sales Gain			4.31

Method 2:

In the event that there is insufficient data to apply Method 1 for any hour:

(1)

An initial Market Price of Energy will be determined for each On-Peak Hour from the average of bids to purchase power received by CECo for such hours for delivery at the CECo Bus. Such bids shall include any sales made in the Actual Dispatch that were insufficient in total to apply Method 1. In the event a bid is deemed for delivery at a bus other than the CECo Bus, the price for such a bid shall be adjusted for transmission service charges and losses associated with the applicable delivery location to make such bid equivalent to a bid at the CECo Bus (Exhibit 1 shows the

	applicable delivery location for specific CECo counterparties). For purposes of determining the Market Price of Energy using Method 2, CECo (i) must have at least two bids from a “Large Buyer” (as designated on Exhibit 1 hereto), (ii) shall not be required to use bids which it considers, in a commercially reasonable manner, not to be representative of the market, and (iii) shall solicit bids in a commercially reasonable manner as to the number of parties contacted and the manner in which each party is contacted to determine Market Price of Energy.

(2)	A maximum Market Price of Energy shall be determined from the formula set forth in Method 1 for MP_MAX, except that MP_I is the initial Market Price of Energy determined from (1) in this Method 2 and MW_TSM is the lower of 50% of the total bid (in MW) to comprise MP_I (each bid is deemed to be 50 MW) in the applicable hour or 150 MW.

(3)	The Market Price of Energy of the individual one (1) MW blocks for the applicable hours is then determined from the formula set forth in Method 1 for MP_K, except that K is the range of one (1) MW to the total bid (in MW) to comprise MP_I in the applicable hour. As in Method 1, when K is greater than 300, MP_K shall equal MP₃₀₀.

(4)	The Market Price of Energy of the individual one (1) MW blocks from (3) above is then compared to the Incremental Costs of said blocks and the total sales gain from the hour is determined.

Method 3:

In the event that there is insufficient data to apply Method 2 for any hour, then to the extent that there are no more than four (4) consecutive On-Peak Hours of insufficient data available for Method 2 or Method 1 (the “Gap”), the Market Price of Energy for each available one (1) MW block in such hours shall be determined by linearly interpolating between the Market Price of Energy for such blocks in the hour immediately preceding the Gap and the Market Price of Energy immediately following the Gap. The Market Price of Energy of the individual available one (1) MW blocks from the Gap above is then compared to the Incremental Costs of said blocks and the total sales gain from the hour is determined.

If Market Price of Energy cannot be determined for any hour from the above methods or if the Spread for a one (1) MW block is less than or equal to $1/MWh, then it will be deemed that no sales for such hour or such block would have been made.

Off-Peak Hours

For Off-Peak Hours, Market Price of Energy and sales gain shall be determined using the same methods as the On-Peak Hours, except that (1) “0.000532” in the formulas used for the On-Peak Hours shall be changed to “0.000682, and (2) the quantity of power deemed to have been sold will be constrained (to reflect market depth limitations during Off-Peak Hours) according to the following criteria:

(a)	For one (1) MW blocks for which Spreads are under $1/MWhr, it will be deemed that no sales would have been made from such blocks.

(b)	For one (1) MW blocks for which Spreads are equal to or greater than $1/MWhr and less than or equal to $5/MWhr, the portion of the blocks deemed to have been available to be sold shall be determined in accordance with the following formula:

	% of block sold = 6.0816 e^{0.5756 & Speed}(not to exceed 100%)

(c)	For one (1) MW blocks for which Spreads are greater than $5/MWhr, all of the blocks will be deemed to have been sold.

The following procedure will be used to apply the above criteria to determine the number of one (1) MW blocks sold and available to be sold for Off-Peak Hours and their associated Market Price of Energy:

(i)	MP_K shall be determined for all one (1) MW blocks sold and available to be sold from the formula as specified above for Off-Peak hours.

(ii)	The portions of each one (1) MW block available to be sold pursuant to the formula in (b) above shall be summed and rounded to the nearest whole MW.

(iii)

The number of one (1) MW blocks sold and deemed available to be sold shall be equal to the number of said blocks sold in the Actual Dispatch plus the number of available blocks associated with Spreads greater than $5/MWhr plus the number of MW determined from (ii) above. The foregoing one (1) MW blocks shall then be ordered from least Incremental Cost (K = 1) to highest Incremental Cost (K = total number of blocks sold and available to be sold) and the Market Price of Energy associated with these blocks will be MP_K , where MP_K = MP₃₀₀ when K is greater than 300.

Exhibit 1 to
RCP Procedure 2

Assumed Delivery Locations
for Sales and Bids with CECo Counterparties

The assumed delivery locations for sales and bids associated with the following CECo counterparties are shown in the table below:


	Delivery Location for	Large Buyer
Company	Sale/Bid	(= X)

American Electric Power (“AEPM”)	into AEP	X
Ameren Energy (“AME”)	into AEP	X
Aquila Merchant Services (“AMSI”)	@ CECo Bus¹
BP Energy Company (“BPEC”)	into AEP	X
CMS Marketing, Services and Trading (“CMS”)	@ CECo Bus	X
Carolina Power and Light (“CPLC”)	into AEP	X
Cinergy Services (“CPMT”)	into AEP	X
Constellation Power Source (“CPS”)	@ CECo Bus	X
Cargill Power Markets (“CRGL”)	@ CECo Bus¹	X
The Detroit Edison Company (“DEMO”)	@ CECo Bus	X
Duke Energy Trading and Marketing (“DETM”)	@ CECo Bus¹	X
Dayton Power and Light Company (“DPLG”)	into AEP	X
DTE Energy Trading (“DTET”)	@ CECo Bus	X
Duke Power Company (“DUKE”)	into AEP
Dynegy Power Marketing (“DYPM”)	@ CECo Bus	X
Engage Energy, LLC (“EEA”)	@ CECo Bus¹
Entergy-Xxxx Trading (“ENKO”)	into AEP	X
Exelon Generation Company (“EXEL”)	into AEP	X
First Energy Solutions Corp (“FESC”)	@ CECo Bus	X
Holland Board of Public Works (“XXXX”)	@ CECo Bus	X
LG&E Energy Corp (“LGE”)	into AEP	X
Mirant Americas Energy Marketing (“MAEM”)	into AEP
Merchant Energy Group of the Americas (“MEGA”)	into AEP
Michigan South Central Power Agency (“MSCP”)	@ CECo Bus	X
Municipal Cooperative Coordinated Pool (“MCCP”)	@ CECo Bus	X
Northern Indiana Public Service Co (“NIPEM”)	@ CECo Bus	X
Ontario Power Generation, Inc. (“OPG”)	into AEP	X
Reliant Energy Services (“RES”)	into AEP
Tenaska Power Services (“TNSK”)	@ CECo Bus	X
Virginia Electric and Power Company (“VAPG”)	into AEP	X
Wisconsin Electric Power Company (“WEPM”)	into AEP
Xxxxxxxx Power Company (“WESC”)	@ CECo Bus
Wolverine Power Supply Cooperative (“WPSC”)	@ CECo Bus	X
WPS Energy (“WPSE”)	@ CECo Bus	X

Notes:

(1)	Delivery locations vary — assumed CECo Bus for purposes of this RCP Procedure 2.

(2)	“Large Buyer” means a buyer whose annual average purchase quantity from CECo is greater than 10 MW.

ATTACHMENT 2

Agreement Granting Right of first Refusal from MCV to CECO
For the Purchase of Certain Excess Gas Owned by MCV (“ROFR”)

This ROFR Agreement is made and entered into effective February 12, 2004, by and between Consumers Energy Company, herein referred to as “CECO” and Midland Cogeneration Venture Limited Partnership, herein referred to as “MCV” (individually a “Party” and collectively the “Parties”).

1.	CECO and MCV are concurrently herewith entering into a NAESB Base Contract for the Sale and Purchase of Natural Gas (“Base Contract”), which shall govern the purchase and sale of gas under this ROFR Agreement and a Resource Conservation Agreement (“RCA”) intended to optimize the economic value of MCV’s generating and fuel resources.

2.	MCV, from time to time, may have available volumes of natural gas, which are not required for its operations as a result of the RCA entered into between the Parties (“Excess Gas”). MCV desires to have the ability and flexibility to offer such Excess Gas for purchase to CECO. The precise method for determining the volume of gas to be made available each day will be developed and mutually agreed upon by the parties.

3.	The Parties have agreed to enter into this ROFR Agreement whereby MCV will grant CECO a right of first refusal to purchase the Excess Gas that MCV may have available as hereinafter set forth.

4.	On each Business Day (as such term is defined in the Base Contract), no later than 8:10 a.m. eastern standard time (“EST”), unless daylight savings time is being observed in Midland, Michigan, then 8:10 a.m. eastern daylight time (“EDT”), MCV will advise CECO of the estimated volume and available delivery location of Excess Gas, if any, available for the next Gas Day (defined as the 24-hour period beginning at 9:00 a.m. central clock time) and any additional Gas Days beginning after that Business Day and before or on the next Business Day, if applicable.

5.	CECO will have a right of first refusal to purchase all or a portion of the Excess Gas available from MCV. CECO must decide and notify MCV of CECO’s decision no later than the latter of (i) 8:15 a.m. EST, unless daylight time is being observed in Midland Michigan, then 8:15 am EDT, of the Business Day prior to the Gas Day for which the Excess Gas is available or (ii) 5 minutes following receipt of MCV’s notice given pursuant to the proceeding paragraph, of the extent, if any, to which CECO desires to exercise its right to purchase gas for delivery on the next Gas Day and any additional Gas Days beginning after that Business Day and before or on the next Business Day.

ATTACHMENT 2

6.	All Excess Gas volumes on which CECO exercises its right of first refusal will be delivered at either (i) At CECO’s city-gate, as identified in the transaction confirmation of the Base Contract or (ii) As an in place transfer of gas that CECO is holding in storage for MCV pursuant to a contract between the Parties dated March 2, 1988. CECO’s notice to purchase Excess Gas shall include the location where they wish the purchase to take place.

7.	The right of first refusal will apply to each and every offer of Excess Gas from MCV to CECO. This Agreement shall expire the earlier of midnight March 15, 2025, or upon termination of the RCA.

8.	CECO will not have an obligation to purchase any Excess Gas offered to it by MCV.

9.	The Parties agree that the purchase price for each transaction or exercise by CECO of its right of first refusal for the Excess Gas shall be as developed and mutually agreed between the parties. If the Excess Gas is delivered in place in storage, CECO agrees to reimburse MCV for the 1.75% fuel gas associated with any such volumes.

10.	Each purchase of Excess Gas by CECO from MCV pursuant to CECO’s continuing right of first refusal will be documented with the standard transaction confirmation (Exhibit A to the NAESB Base Contract).

11.	If the Parties are unable to agree on any matter under this ROFR Agreement, such disagreement shall be subject to resolution pursuant to Paragraph 18 of the Power Purchase Agreement (PPA) dated July 17, 1986.


CONSUMERS ENERGY COMPANY		MIDLAND COGENERATION VENTURE LIMITED PARTNERSHIP

By:	/s/ Xxxxxxx X. Xxxxxxx	By:	/s/ XxXxx X. Xxxxx
	Xxxxxxx X. Xxxxxxx		XxXxx X. Xxxxx

Title:	Vice President,	Title:	Vice President, Energy
	Electric and Gas Supply		Supply and Marketing

ATTACHMENT 3

OPERATING PRACTICE 5
CONSUMERS/MCV
POWER PURCHASE AGREEMENT

AVAILABLE CAPACITY

GENERAL

Available Capacity as defined in Section 1(c) of the Power Purchase Agreement is that total electric generating capacity that MCV is capable of providing to Consumers after deducting that electric generating capacity required for MCV station auxiliary power, The Dow Chemical Company-Michigan Division (Dow), bulk power sales to purchasers (as agreed by both CE and MCV), bulk power sales to Permissible Purchasers, and that associated with outages and derates of MCV generating units. During periods when MCV requests Consumers to supply energy to Dow, MCV will retain its capacity commitment to Dow and therefore, Available Capacity will be determined by deducting MCV’s capacity commitment to Dow from the total generating capacity available. MCV will declare to Consumers any changes to Available Capacity in advance or as soon as practical. Consumers has the right to evaluate the ability of MCV to achieve the declared Available Capacity, and to review documentation and test records to verify such declaration.

PROCEDURE

1.0	MCV will maintain and retain plant status records that Consumers can review to monitor Available Capacity as follows:

The following records or their successor will be retained for at least three years:

	1)	Hourly data from MCV’s model used to calculate capacity of the MC-Facility (“CAPCALC”).

	2)	Operator logbook entries and associated equipment data which contain information regarding equipment status and derates.

	3)	The electric and steam energy usage of Dow and others.

	4)	Sales to purchasers (as agreed by the parties) and Permissible Purchasers.

The following records or their successor will be retained for at least four months:

	1)	Equipment work order and tagging records.

	2)	Requested Distributed Control System (DCS) data records.

	3)	Agreed upon non-DCS instrumentation data that would reflect any potential equipment problems (e.g., thermocouple data).

1.1

Observed changes in equipment performance that impact MCV capability will be appropriately reflected in CAPCALC.

ATTACHMENT 3

2.0	The Available Capacity declared by MCV or adjusted, after the fact, for billing purposes relating to capacity charge payments shall be based on the following:

	a.	MCV will immediately enter derates or outages in CAPCALC at the time they occur or as soon thereafter as practical and shall notify Consumers as soon thereafter as practical, but in no event later than one hour. A generating unit will be considered unavailable if it cannot be started and loaded within the amount of time specified in Operating Practice 4.

	b.	If a unit fails to start and the cause of failure is determined and corrective action is completed within two hours, the unit will be considered available. However, if the next attempt to start and load the unit after such two hours fails due to the same or a related problem, or if corrective action is not completed within such two hours, the unit will be considered unavailable retroactive to the initial failed start.

	c.	If equipment data indicates (i) that there is a reasonable likelihood that the next attempt to start and load a unit would fail, and no corrective action is taken and (ii) the next attempt to start and load the unit fails due to the same or a related problem as indicated by the equipment data, the unit will be considered unavailable retroactive to the time the data initially indicated a problem existed.

	d.	MCV will adjust MCV’s declared Available Capacity for derates under the following rules governing the delivery of energy from the MC-Facility to meet dispatch orders as set out in Operating Practice 2:

	1)	A derate of MCV’s Available Capacity shall occur if MCV’s actual energy delivery, on an integrated hourly basis (integrated hour is defined as starting and ending on the hour), is lower than the Final Total Delivery Schedule as defined in Operating Practice 2 for more than two consecutive integrated hours.

	2)	If MCV’s actual energy delivery is lower than the Final Total Delivery Schedule as defined in Operating Practice 2 for three consecutive integrated hours, the Available Capacity will be set equal to the actual energy delivery in the third integrated hour.

	3)	If MCV’s actual energy delivery is lower than the Final Total Delivery Schedule as defined in Operating Practice 2 for more than three consecutive integrated hours, the Available Capacity will be set equal to the actual energy delivery beginning with the first hour the deficiency occurs until the derate is eliminated.

3.0	Questions and clarifications on Available Capacity shall be directed to the MCV Operations shift Supervisor.

4.0	Consumers may audit the Available Capacity declared by MCV for billing purposes relating to capacity charge payments.

4.1

Consumers may elect to request a performance test to determine MCV’s ability to achieve the declared Available Capacity. Consumers shall notify MCV of such a test period as part of the rules governing an Advance Dispatch Order or a Revised Dispatch Order of Operating Practice 2. These evaluations shall conform to Section 8(h) in the PPA.

ATTACHMENT 3

4.2

Consumers may elect, as an alternative to testing, to review operating records/logs and have access to equipment for the purpose of verifying Available Capacity. MCV shall permit full access by Consumers during regular business hours to all pertinent operating records and equipment, including, but limited to:

	a.	Requested DCS data records

	b.	Operator logbook entries and associated equipment data

	c.	CAPCALC data sheets and associated documentation

	d.	Tagging and work order records

	A reduction in the Capacity Payment will occur when operating records/logs or equipment review do not support the declared Available Capacity, for four (4) consecutive integrated hours, as specified in Section 8(h) of the PPA.

Effective Data /s/ 2/13/04


	Operating Committee
	/s/ Xxxxxxx X. Xxxxxxx
	Consumers



	/s/ Xxxxx X. Xxxxx
	MCV



	/s/ 2/13/04
	Signature Date

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Table of Contents

RESOURCE CONSERVATION AGREEMENT

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