Exhibit


EXECUTION VERSION
 










RESTRUCTURING AMENDMENT AMENDING AND RESTATING THE
AMENDED AND RESTATED 
SAN JUAN PROJECT PARTICIPATION AGREEMENT
AMONG
PUBLIC SERVICE COMPANY OF NEW MEXICO
TUCSON ELECTRIC POWER COMPANY
THE CITY OF FARMINGTON, NEW MEXICO
M-S-R PUBLIC POWER AGENCY
THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO
SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY
CITY OF ANAHEIM
UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS
TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC.
PNMR DEVELOPMENT AND MANAGEMENT CORPORATION






July 31, 2015





EXECUTION VERSION
 








TABLE OF CONTENTS
	
			
	SECTION
	



I.  PARTIES AND INTRODUCTORY MATTERS


	PAGE

	1
	PARTIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	1

	2
	RECITALS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	3

	3
	AGREEMENT . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	10

	4
	EFFECTIVE DATE AND TERMINATION . . . . . . . . . . . . . . . . . . . . . . . .
	11

	5
	DEFINITIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	13

	 
	II.  OWNERSHIP OF SAN JUAN PROJECT
	 

	6
	OWNERSHIPS AND TITLES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	28

	7
	CAPITAL IMPROVEMENTS AND RETIREMENTS OF SAN JUAN PROJECT AND PARTICIPANTS’ SOLELY OWNED FACILITIES . . .


	33

	8
	WAIVER OF RIGHT TO PARTITION . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	42

	9
	BINDING COVENANTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	43

	10
	MORTGAGE AND TRANSFER OF PARTICIPANTS’ INTERESTS . . .
	46

	11
	RIGHTS OF FIRST REFUSAL . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	49

	12
	RIGHTS OF PNM AND TEP IN WATER AND COAL . . . . . . . . . . . . . .
	55

	13
	SEVERANCE OF IMPROVEMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	56

	 
	III.  ENTITLEMENTS TO OUTPUT OF SAN JUAN PROJECT
	 

	14
	ENTITLEMENT TO CAPACITY AND ENERGY . . . . . . . . . . . . . . . . . .
	57

	15
	CAPACITY ALLOCATION OF SWITCHYARD FACILITIES . . . . . . .
	59

	16
	USE OF FACILITIES DURING CURTAILMENTS . . . . . . . . . . . . . . . . .
	61





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	17
	START-UP AND AUXILIARY POWER AND ENERGY REQUIREMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 


	63

	 
	IV.  ADMINISTRATION
	 

	18
	COORDINATION COMMITTEE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	64

	19
	ENGINEERING AND OPERATING COMMITTEE . . . . . . . . . . . . . . . .
	69

	20
	FUELS COMMITTEE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	74

	21
	AUDITING COMMITTEE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	81

	 
	V.  BUDGETS AND OPERATING EXPENSES


	 

	22
	OPERATION AND MAINTENANCE EXPENSES . . . . . . . . . . . . . . . . .
	85

	23
	FUEL COSTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	94

	24
	ANNUAL BUDGETS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	113

	25
	PAYMENT OF TAXES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	114

	26
	MATERIALS AND SUPPLIES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	115

	27
	EMERGENCY SPARE PARTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	117

	 
	VI.  OPERATING AGENT
	 

	28
	OPERATION AND MAINTENANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	118

	29
	OPERATING EMERGENCY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	125

	30
	PAYMENT OF EXPENSES BY PARTICIPANTS . . . . . . . . . . . . . . . . . .
	128

	31
	OPERATING INSURANCE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	131

	32
	SURPLUS OR RETIRED PROPERTY . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	136

	33
	REMOVAL OF OPERATING AGENT . . . . . . . . . . . . . . . . . . . . . . . . . . .
	137

	34
	DEFAULTS BY OPERATING AGENT . . . . . . . . . . . . . . . . . . . . . . . . . . .
	139





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	VII.  DEFAULTS, LIABILITY AND ARBITRATION


	 

	35
	DEFAULTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . .
	141

	36
	LIABILITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .  . . . . . . . . . . . . .
	148

	37
	ARBITRATION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	154

	 
	VIII.  RETIREMENT AND RECONSTRUCTION
	 

	38
	DESTRUCTION, DAMAGE OR CONDEMNATION OF A UNIT. . . . .
	158

	39
	RIGHTS OF PARTICIPANTS UPON TERMINATION . . . . . . . . . . . . . .
	160

	40
	DECOMMISSIONING OF THE PROJECT . . . . . . . . . . . . . . . . . . . . . . . .
	161

	 
	IX.  MISCELLANEOUS PROVISIONS
	 

	41
	RELATIONSHIP OF PARTICIPANTS . . . . . . . . . . . . . . . . . . . . . . . . . . .
	162

	42
	NOTICES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	163

	43
	OTHER PROVISIONS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	166

	44
	EXECUTION IN COUNTERPARTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	169

	45
	AMENDMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
	170






EXHIBIT I                Real Property 
EXHIBIT II                Annual Minimum Coal
EXHIBIT III                Switchyard Facilities
EXHIBIT IV                Ownership of Equipment
EXHIBIT V                O&M of Equipment
EXHIBIT VI                A&G Expenses
EXHIBIT VII                Coal Allocation and Billing
EXHIBIT VIII                Adjustment of Voting Requirements
EXHIBIT IX                Fixed Fuel Expense
EXHIBIT X                Variable Fuel Expense
        



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PART I
PARTIES AND INTRODUCTORY MATTERS
1.0    PARTIES:  
The parties to this Restructuring Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement (“Agreement”) are:  PUBLIC SERVICE COMPANY OF NEW MEXICO, a New Mexico corporation (“PNM”); TUCSON ELECTRIC POWER COMPANY, an Arizona corporation (“TEP”);  THE CITY OF FARMINGTON, NEW MEXICO, an incorporated municipality and a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“Farmington”); M-S-R PUBLIC POWER AGENCY, a joint exercise of powers agency organized under the laws of the State of California (“M-S-R”);  THE INCORPORATED COUNTY OF LOS ALAMOS, NEW MEXICO, a body politic and corporate, existing as a political subdivision under the constitution and laws of the State of New Mexico (“LAC”); SOUTHERN CALIFORNIA PUBLIC POWER AUTHORITY, a joint exercise of powers agency organized under the laws of the State of California (“SCPPA”); CITY OF ANAHEIM, a municipal corporation organized under the laws of the State of California (“Anaheim”); UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS, a political subdivision of the State of Utah (“UAMPS”); TRI-STATE GENERATION AND TRANSMISSION ASSOCIATION, INC., a Colorado cooperative corporation (“Tri-State”); and PNMR DEVELOPMENT AND MANAGEMENT CORPORATION, a New Mexico corporation (“PNMR-D”).  The Parties, other than PNMR-D, are the participants in the San Juan Project, and are  hereinafter  sometimes  referred  to  individually  as  a  “Participant”  and  collectively  as 



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“Participants.”  PNMR-D is being added as a Party to this Agreement in anticipation of its future acquisition of an interest in the San Juan Project, as provided for herein, and because PNMR-D will assume certain financial obligations under this Agreement. 



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2.0    RECITALS:  This Agreement is made with reference to the following facts, among others: 
2.1    PNM is an electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of New Mexico.  
2.2    TEP is an electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of Arizona. 
2.3    Farmington operates a municipal electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of New Mexico.
2.4    M-S-R is a public entity engaged in the generation, transmission, purchase and sale of electric power and energy in the western United States for the benefit of its member public agencies.
2.5    LAC operates a municipal electric utility engaged in the generation, transmission and distribution of electric power and energy in a part of the State of New Mexico.
2.6    SCPPA is a public entity created to acquire, construct, finance, operate and maintain generation and transmission projects on behalf of its members.
2.7    Anaheim operates a municipal utility in the State of California engaged in the generation, transmission and distribution of electric power.
2.8    UAMPS is a public entity created to plan, finance, develop, acquire, construct, improve, better, operate and maintain projects, or ownership interests or capacity 



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rights therein, for the generation, transmission and distribution of electric energy for the benefit of its members.
2.9    Tri-State is a cooperative corporation created pursuant to the laws of the State of Colorado.  Tri-State’s primary functions involve the generation, transmission, transformation and sale of electricity to its member distribution cooperatives.
2.9(a)    PNMR-D is a New Mexico corporation, a wholly owned subsidiary of PNM Resources, Inc. and an affiliate of PNM.  
2.10    PNM and TEP each has an undivided one-half (1/2) ownership interest in the real property associated with the San Juan Project, which real property is described in Exhibit I, attached hereto and incorporated herein, and is identified therein as Parcels A through F. 
2.11    PNM and TEP entered into the Coal Sales Agreement with San Juan Coal Company (“SJCC”), pursuant to which SJCC agreed to supply the San Juan Project with coal. PNM and TEP also entered into the Transportation Agreement with San Juan Transportation Company (“SJTC”) dated April 30, 1984, under which coal was transported from the La Plata Mine. Subsequently, PNM and TEP entered into the Underground Coal Sales Agreement with SJCC, pursuant to which SJCC agreed to supply coal to the San Juan Project beginning January 1, 2003. The Underground Coal Sales Agreement superseded and replaced the Coal Sales Agreement, except for certain provisions of the Coal Sales Agreement which survived through the provisions of the Coal Sales Agreement Buy Out Agreement. The Transportation Agreement was terminated effective December 31, 2002,



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except for certain provisions which survived through provisions of the Transportation Agreement Buy Out Agreement.
2.11(a)     PNM entered into a new Coal Supply Agreement (“CSA”) for the supply of all the coal requirements for the San Juan Project from January 1, 2016 through June 30, 2022.  PNM also entered into a Coal Combustion Residual Disposal Agreement (“CCRDA”), for the performance of all ash disposal activities for the San Juan Project over the term of the CSA and a Reclamation Services Agreement (“RSA”), for the performance of all reclamation obligations of the mines that have supplied coal for the San Juan Project from the RSA’s effective date until the full release of all reclamation and similar bonds associated with federal and state leases, agreements and permits.  The anticipated effective date of the CSA, CCRDA and RSA is January 1, 2016.  
2.11(b)      In connection with the CSA, RSA and CCRDA becoming effective, PNM, TEP, SJCC and BHP Billiton New Mexico Coal, Inc., parent company to SJCC, agreed to terminate the UG-CSA and the CCBDA.
2.12    PNM contracted with the United States Department of the Interior, Bureau of Reclamation, under the Colorado River Storage Project Act to purchase 20,200 acre feet of water per year from Navajo Reservoir under Contract 14‐06‐400‐4821 dated April 11, 1968.  Said contract was amended by an amendatory contract dated September 29, 1977, wherein the United States Department of the Interior, Bureau of Reclamation (i) acknowledged PNM’s assignment to TEP of an undivided one-half (1/2) interest in PNM’s rights and obligations imposed under the April 11, 1968, contract; and (ii) revised 



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the amount of water available for consumptive use by the San Juan Project from the Navajo Reservoir from 20,200 acre feet per year to 16,200 acre feet per year.  Upon expiration of the above-referenced contract with the United States Department of the Interior, Bureau of Reclamation, on December 31, 2005, water from the Navajo Reservoir is delivered to the San Juan Project under contractual arrangements with the Jicarilla Apache Nation.  From time-to-time, contracts for surplus water supply may also be entered into by the Operating Agent for supply to the San Juan Project. Additional water for use at the San Juan Project is based on a Grant of Authority for 8,000 acre-feet of water, dated August 18, 1980, from Utah International (predecessor in interest to SJCC) to PNM and TEP.
2.13     The San Juan Project Co-Tenancy Agreement was executed as of February 15, 1972, effective as of July 1, 1969.  The original Co-Tenancy Agreement was modified by joint action of PNM and TEP, as follows: Modification No. 1 on May 16, 1979, Modification No. 2 on December 31, 1983, Modification No. 3 on July 17, 1984, Modification No. 4 on October 25, 1984, Modification No. 5 on July 1, 1985, Modification No. 6 on April 1, 1993, Modification No. 7 on April 1, 1993, Modification No. 8 on September 15, 1993, Modification No. 9 on January 12, 1994 and Modification No. 10 on November 30, 1995 (the original of such Co-Tenancy Agreement, as amended by Modifications 1 through 10, is referred to herein as the “Co-Tenancy Agreement”).
2.14    The San Juan Project Operating Agreement was executed as of December 21, 1973, effective as of July 1, 1969.  The original Operating Agreement was modified by  joint  action  of  PNM  and  TEP,  as  follows:  Modification  No. 1 on  May 16, 1979, 



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Modification No. 2 on December 31, 1983, Modification No. 3, on July 17, 1984, Modification No. 4 on October 25, 1984, Modification No. 5 on July 1, 1985, Modification No. 6 on April 1, 1993, Modification No. 7 on April 1, 1993, Modification No. 8 on September 15, 1993, Modification No. 9 on January 12, 1994 and Modification No. 10 on November 30, 1995 (the original of such Operating Agreement, as amended by Modifications 1 through 10, is referred to herein as the “Operating Agreement”).
2.15    A San Juan Project Construction Agreement was executed as of December 21, 1973, effective as of July 1, 1969, to govern the construction of the San Juan Project; this agreement was thereafter modified from time to time and was terminated in 1995 by action of PNM and TEP.
2.16    On May 16, 1979, TEP and PNM entered into an agreement whereby on that date TEP conveyed to PNM TEP’s 50 percent undivided ownership interest in Unit 4.
2.17    On November 17, 1981, PNM transferred an 8.475 percent undivided ownership interest in Unit 4 to Farmington.
2.18    On December 31, 1983, PNM transferred a 28.8 percent undivided ownership interest in Unit 4 to M-S-R.
2.19    On October 31, 1984, TEP transferred its 50 percent undivided ownership interest in Unit 3 to Alamito Company, which later changed its name to Century Power Company (“Century”).
2.20    On July 1, 1985, PNM transferred a 7.2 percent undivided ownership interest in Unit 4 to LAC.
        



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2.21    On July 1, 1993, Century transferred a 41.8 percent undivided ownership interest in Unit 3 to SCPPA.
2.22    On August 12, 1993, PNM transferred a 10.04 percent undivided ownership interest in Unit 4 to Anaheim.
2.23    On June 2, 1994, PNM transferred a 7.028 percent undivided ownership interest in Unit 4 to UAMPS.
2.24    On January 2, 1996, Century transferred an 8.2 percent undivided ownership interest in Unit 3 to Tri-State.
2.25     Farmington, M-S-R, LAC, SCPPA, Anaheim, UAMPS and Tri-State were classified as “Unit Participants” in the San Juan Project, pursuant to the Co-Tenancy Agreement.
2.26    As of April 29, 1994, PNM, TEP, Century, SCPPA, Farmington, M-S-R, LAC and Anaheim executed the San Juan Project Designated Representative Agreement (the “DR Agreement”) to implement the requirements of the federal Clean Air Act Amendments of 1990; the DR Agreement was thereafter accepted by UAMPS and Tri-State at the time of their respective purchases of ownership interests in the San Juan Project.
2.27    As of October 27, 1999, the Participants entered into the San Juan Project Participation Agreement (“Original San Juan PPA”).  The purpose of the Original San Juan PPA was to amend and restate, and to replace in their entirety, the Co-Tenancy Agreement and the Operating Agreement and to set out in one instrument all of the matters previously included in the Co-Tenancy Agreement and the Operating Agreement. 
        



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2.28    As of March 23, 2006, the Participants entered into an Amended and Restated San Juan Project Participation Agreement to amend and restate the Original San Juan PPA to reflect certain amendments agreed to by the Participants including, but not limited to, changes to the provisions of the Original San Juan PPA pertaining to fuel supply.  Certain changes to the Amended and Restated San Juan Project Participation Agreement were subsequently accepted by FERC for filing as PNM Rate Schedule No. 144.
2.29    The Parties have executed the San Juan Project Restructuring Agreement (“Restructuring Agreement”) relating to the restructuring of ownership interests in the San Juan Project.  On the same date, the Parties also executed the San Juan Decommissioning and Trust Funds Agreement (“Decommissioning Agreement”), which relates to decommissioning of the San Juan Project, and the Amended and Restated Mine Reclamation and Trust Funds Agreement (“Mine Reclamation Agreement”), which relates to reclamation of the San Juan Mine.



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3.0    AGREEMENT:  The Parties, for and in consideration of the mutual covenants to be by them kept and performed, agree as follows. 



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4.0    EFFECTIVE DATE AND TERMINATION:
4.1    Except as otherwise provided in Section 4.3, this Agreement shall become effective upon the effective date established by the FERC in its order accepting this Agreement for filing; provided that, if the FERC orders a hearing to determine whether this Agreement is just and reasonable, this Agreement shall not become effective until the date when an order has been issued by the FERC determining this Agreement to be just and reasonable without changes or modifications unacceptable to the Parties.
4.2    Following execution by all Parties, PNM shall file a copy of this Agreement with the FERC in a timely manner.  In such filing, PNM shall request waiver of applicable FERC notice requirements in order to allow this Agreement to become effective consistent with the effective date provisions of the Restructuring Agreement.  All other Parties shall support PNM’s filing by the prompt filing of a certificate or letter of concurrence or intervention in support of the filing or shall not take any action to oppose the filing of this Agreement.
4.3    Following an order by the FERC or any other regulatory agency having jurisdiction, if any, the Parties shall each review such order, letter or communication to determine if the FERC or any agency having jurisdiction has changed or modified a condition or conditions, deleted a condition or conditions, or imposed a new condition or conditions with regard to this Agreement; or has conditioned its approval of this Agreement upon changes or modifications to a condition or conditions, deletion of a condition or conditions or imposition of a new condition or conditions.  The Party receiving such order, 



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letter or communication shall promptly provide a copy of such order, letter or communication to the other Parties.  Within fifteen (15) business days after receipt by the other Parties of the copy of the order, letter or communication, the Parties shall indicate to each other in writing their acceptance or rejection of this Agreement based upon any changes, modifications, deletions or new conditions required by the FERC or any agency having jurisdiction.  A failure to notify within said fifteen (15) day period shall be the equivalent to a notification of acceptance.  If any Party rejects this Agreement because the FERC or any agency having jurisdiction has modified a condition, deleted a condition or imposed a new condition in this Agreement, or has conditioned its approval on such a change, modification, deletion or new condition, the Parties will be deemed to have rejected this Agreement and they shall attempt, in good faith, to renegotiate the terms and conditions of this Agreement to resolve such changed, modified, deleted or new condition to the satisfaction of the Parties within one hundred twenty (120) days after the date of such order, letter or communication and thereafter to obtain requisite regulatory approval of such renegotiated agreement. 
4.4    This Agreement shall continue in force and effect until July 1, 2022, unless otherwise agreed in writing by the Parties. 





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5.0    DEFINITIONS:  The following terms, when used herein with initial capitalization, and whether in the singular or the plural, shall have the meaning specified: 
5.1    ACCOUNTING PRACTICE:  Generally accepted accounting principles in accordance with FERC Accounts applicable to electric utility operations.
5.2    AGREEMENT:  This Amended and Restated San Juan Project Participation Agreement, including all exhibits and attachments hereto, and as may be modified or amended from time to time.
5.3    AUDITING COMMITTEE:  A committee which is described in Section 21.   
5.4    AVAILABLE OPERATING CAPACITY:  The maximum net electrical capacity of each installed and operating Unit which is available at any given time to the Participants at the 345 kV buses.
5.4(a)    AVAILABLE PRE-EXISTING STOCKPILE TONS has the meaning provided for in Section 12.1(C)(1) of the CSA.  
5.5    CAPACITY:  Electrical rating expressed in megawatts (“MW”).
5.6    CAPITAL IMPROVEMENTS: Any property, land or land rights added to the San Juan Project or the substitution, replacement, enlargement or improvement of any Units of Property, structures, facilities, equipment, property, land or land rights constituting a part of the San Juan Project, which in accordance with Accounting Practice would be capitalized, and also including the costs of removal, salvage or disposal of any Units of Property being replaced or substituted.
        



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5.6(a)    CCBDA means the Coal Combustion Byproducts Disposal Agreement between PNM, TEP and SJCC.
5.6(b)    CCBDA TERMINATION AGREEMENT means the Coal Combustion Byproducts Disposal Agreement Termination and Mutual Release Agreement between SJCC, BHP Billiton, PNM and TEP.  
5.6(c)  CCR means ash and gypsum byproducts produced by the San Juan Project.
5.6(d)    CCRDA means the new Coal Combustion Residuals Disposal Agreement entered into between PNM and Westmoreland Coal Company with an anticipated effective date of January 1, 2016.
5.7    COAL SALES AGREEMENT:  Agreement between PNM, TEP and SJCC executed on August 18, 1980, as amended or modified from time to time and which was replaced by the Underground Coal Sales Agreement. However, certain provisions of the Coal Sales Agreement survive through the provisions of the Coal Sales Agreement Buy Out Agreement dated August 31, 2001. 
5.8    COAL SALES AGREEMENT BUY OUT AGREEMENT: Agreement between PNM, TEP and SJCC executed on August 31, 2001, as may be amended or modified from time to time.
5.8(a)    COAL TONNAGE COMPONENT means coal tonnage categories as defined in the CSA and comprised of Pre-existing Stockpile Coal, Force Majeure Tons, Available Pre-existing Stockpile Tons, Tier 1 Tons and Tier 2 Tons.
        



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5.9    COMMON PARTICIPATION SHARE: Each Party’s percentage ownership interest as set forth in Section 6.2.6.
5.9(a)    COMMON PARTICIPATION SHARE OF SHARED COAL INVENTORY means a Party’s share of equipment and facilities common to all of the Units (as shown in Section 6.2.6) multiplied by the sum of (i) coal tons stockpiled on SJCC’s property and (ii) coal tons stockpiled on the SJGS plant site. 
5.10    CONTROL AREA:  An area comprised of an electric system or systems bounded by interconnection metering and telemetry, capable of controlling generation to maintain its interchange schedules with other control areas while maintaining frequency regulation of the interconnection.
5.11    COORDINATION COMMITTEE:  A committee which is described in Section 18.  
5.12    CO-TENANCY AGREEMENT:  The agreement described in Section 2.13.
5.12(a)     CSA means the new Coal Supply Agreement entered into between PNM and Westmoreland Coal Company with an anticipated effective date of January 1, 2016, as it may be amended or replaced.
5.12(b)     DECOMMISSIONING AGREEMENT means the San Juan Project Decommissioning and Trust Funds Agreement among the Parties executed concurrently with the Restructuring Agreement and effective on the Exit Date.
5.12(c) DEMAND CHARGE has the meaning provided for in Section 7.13.2.



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5.13    DR AGREEMENT:  The agreement described in Section 2.26, as amended from time to time.   
5.14    EMERGENCY COAL STORAGE PILE:  The coal storage pile for the San Juan Project, sometimes referred to as the “minimum coal storage pile,” or as the “force majeure pile,” which is to be drawn upon when fuel deliveries are interrupted.
5.15    EMERGENCY SPARE PARTS:  Spare parts or auxiliary equipment, the cost of which is capitalized, which are stocked for emergency use for the San Juan Project and which are not scheduled for periodic replacement.  
5.16    ENERGY:  The accumulated amount of power produced over a stated time interval, expressed in kilowatt hours (“kWh”) or megawatt hours (“MWh”).  
5.17    ENGINEERING AND OPERATING COMMITTEE:  A committee which is described in Section 19. 
5.17(a)     EXIT DATE means the date upon which the Exiting Participants transfer all of their respective rights, titles and interests in and to their Ownership Interests to PNM or PNMR-D, as provided in the Restructuring Agreement, and terminate their active involvement in the operation of the SJGS, except as expressly provided for in the Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement; the Exit Date will be on or about December 31, 2017.
5.17(b)     EXITING PARTICIPANTS means those Participants that will transfer all of their respective rights, titles and interests in and to their Ownership Interests to PNM or PNMR-D and terminate their active involvement in the operation of SJGS on the Exit 



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Date, except as expressly provided for in the Restructuring Agreement, the Mine Reclamation Agreement and the Decommissioning Agreement; the Exiting Participants are M-S-R, Anaheim, SCPPA and Tri-State. 
5.18    FC LINE:    That 345 kV transmission line between the San Juan generating station and the Four Corners generating plant.
5.19    FIXED FUEL EXPENSE:  Those expenses itemized on Exhibit IX, attached hereto and incorporated herein.
5.20    FERC:    The Federal Energy Regulatory Commission or any successor thereto.
5.21    FERC ACCOUNTS:  The FERC Uniform System of Accounts prescribed for Public Utilities and Licensees (Class A and Class B).  References in this Agreement to a specific FERC account number shall mean the number in effect as of the date of this Agreement and any successor account number.
5.21(a)     FORCE MAJEURE TONS has the meaning provided for in Section 12.1(C)(3) of the CSA. 
5.22    FUELS COMMITTEE:  A committee which is described in Section 20.
5.22(a)     LEGACY COSTS means those costs payable under Sections 8.2, 8.3 and 8.4 of the CSA.
5.23    MATERIALS AND SUPPLIES:  Those materials and supplies, the cost of which is charged to FERC Account 154, which are stocked for use in the operation and maintenance of the San Juan Project.



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5.23(a)     MINE RECLAMATION AGREEMENT means the Amended and Restated Mine Reclamation and Trust Funds Agreement among the Parties, executed concurrently with the Restructuring Agreement.
5.23(b)     MINIMUM ANNUAL GENERATION (“MAG”) (expressed in MWh) means Net Maximum Capacity (“NMC”) (of Unit 3 or Unit 4, as applicable), and expressed in MW, multiplied by each Participant’s percentage Ownership Interest (“I”) in a Unit multiplied by 0.85 multiplied by (the Unit 3 Equivalent Availability Factor  (“EAF”), as defined in the North American Electric Reliability Corporation’s Generating Availability Data System Data Reporting Instructions, for SCPPA and Tri-State or the Unit 4 EAF for M-S-R and Anaheim) multiplied by the total annual hours in the calendar year (“AH”). The AH in calendar year 2016 equals 8784 hours and the AH in calendar year 2017 equals 8760 hours.  The foregoing is expressed in the following formula: .
5.23(c)    MINIMUM ANNUAL TONNAGE PURCHASE OBLIGATION (“MTO”) means Minimum Annual Generation multiplied by the Participant’s respective actual average net unit heat rate (“NUHR”), expressed in Btu/kWh, for the year, divided by two times the weighted average heat content (“HC”), expressed in Btu/Lb, of coal delivered by SJCC in the year. The foregoing is expressed in the following formula: 
5.24    MINIMUM ANNUAL TONS:  The quantities of coal, also defined as Minimum  Annual  Tons  (“MAT”)  in  Section  8.2(F)7  of  the  Underground  Coal  Sales 



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Agreement, and set forth in Exhibit H to the Underground Coal Sales Agreement, which amounts are shown on Exhibit II, attached hereto and incorporated herein.
5.25    MINIMUM NET GENERATION:  The lowest net load at which each Unit can be reliably maintained in service on a continuous basis on coal fuel.
5.26    MONTHLY MINIMUM TONS:  Monthly Minimum Tons (“MMT”) as also defined in Section 8.2(F)8 of the Underground Coal Sales Agreement, shall be allocated each year to each Participant pursuant to a monthly schedule approved annually by the Fuels Committee as provided in Section 20.3.3, such that the annual sum of each Participant’s Monthly Minimum Tons equals its Common Participation Share of MAT as defined in Section 8.2(F)7 of the Underground Coal Sales Agreement. In the event that a monthly allocation of MMT has not been approved by the Fuels Committee, MMT shall be allocated to each Participant based on Common Participation Share.  
5.27    NET EFFECTIVE GENERATING CAPACITY:  The maximum continuous ability of each Unit to produce power, less auxiliary power requirements.
5.28    NET ENERGY GENERATION:  The Energy generated by each Unit which is available to the respective Participants at the 345 kV bus. 
5.29    OPERATING ACCOUNT:    The bank account(s) in the names of the Parties established by the Operating Agent pursuant to Section 28. 
5.30    OPERATING AGENT:  The Participant or other entity which has been selected by the Participants as the entity responsible for the operation and maintenance of the San Juan Project pursuant to this Agreement.
        



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5.31    OPERATING AGREEMENT: The agreement described in Section 2.14.
5.32    OPERATING EMERGENCY:  An unplanned event or circumstance at the San Juan Project which reduces or may reduce the availability of Capacity or Energy from a Unit.
5.33    OPERATING FUNDS:  Monies advanced to, and disbursed by, the Operating Agent on behalf of the Parties in accordance with this Agreement.  
5.34    OPERATING INSURANCE:  Policies of insurance secured or to be secured and maintained in accordance with Section 31.
5.35    OPERATING WORK:  Engineering, contract preparation and administration, purchasing, repair, supervision, training, expediting, inspection, testing, protection, operation, use, management, replacement, retirement, reconstruction and maintenance of and for the benefit of the San Juan Project pursuant to this Agreement, including the administration of this Agreement, the Restructuring Agreement and of any Project Agreements, environmental compliance activities and the procurement of fuel and water and other necessary materials and supplies.
5.36    ORIGINAL SAN JUAN PPA:  The San Juan Project Participation Agreement dated October 27, 1999. 
5.36(a)     OWNERSHIP INTEREST means a Party’s percentage undivided ownership interest in a Unit and in common equipment and facilities and as increased, decreased, acquired or transferred as provided in Sections 6.3 and 6.4 of the Restructuring Agreement, and rights incidental thereto.
        



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5.37    PARTICIPANT:  PNM, TEP, Farmington, M-S-R, LAC, SCPPA, Anaheim, UAMPS or Tri-State.
5.38    PARTICIPANT COAL CONSUMPTION:    Each Participant’s total San Juan Project coal consumption in tons as determined by the Operating Agent. A Participant’s Coal Consumption is comprised of its share of coal consumed in its Unit(s) plus its share of coal consumed for common loads, auxiliary loads and start-up for all Units. 
5.39    PARTICIPATION SHARE:  Each Participant’s percentage ownership interest in the various elements of the San Juan Project as set forth in Section 6.
5.39(a)      PARTY or PARTIES:  Each entity identified in the first sentence of Section 1.0.
5.39(b)  PRE-EXISTING STOCKPILE COAL means coal that as of the effective date of the Restructuring Agreement is stockpiled on SJCC property.  
5.40    PROJECT AGREEMENTS:  Other than the Restructuring Agreement, Decommissioning Agreement and Mine Reclamation Agreement, which are not Project Agreements, Project Agreements will be this Agreement and such other agreements as are determined by the Coordination Committee to be necessary to define the rights and duties of the Participants with respect to the San Juan Project.  
5.41    PROJECT COAL INVENTORY:    The sum of coal in coal storage piles, silos, conveying systems, hoppers, and all other coal storage at the San Juan Project as accounted in FERC Account No. 151. 
        



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5.42    PRUDENT UTILITY PRACTICE:  Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or 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, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition.  Prudent Utility Practice is intended to be acceptable practices, methods or acts generally accepted in the industry, as such practices may be affected by special operational design characteristics of the San Juan Project, the quality and quantity of fuel delivered in accordance with the Underground Coal Sales Agreement or successor agreement, the rights and obligations of the Parties in accordance with this Agreement and any other special circumstances affecting the Operating Work.
5.42(a)     REFINED COAL SUPPLY AGREEMENT means the Refined Coal Supply Agreement by and between San Juan Fuels, LLC and PNM dated June 21, 2013.
5.42(b)     REMAINING PARTICIPANTS means those Parties that will continue participation, or acquire an Ownership Interest, in the Project on and after the Exit Date; the Remaining Participants are PNM, TEP, Farmington, UAMPS, LAC and PNMR-D.
5.42(c)     RESTRUCTURING AGREEMENT means the San Juan Project Restructuring Agreement among the Parties.
        



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5.42(d) RSA means the new Reclamation Services Agreement entered into between PNM and Westmoreland Coal Company with an anticipated effective date of January 1, 2016.
5.43    SAN JUAN PROJECT or SAN JUAN GENERATING STATION (“SJGS”):  The four unit, coal-fired electric generation plant located in San Juan County, New Mexico, near Farmington, New Mexico.  The San Juan Project includes all facilities, structures, transmission and distribution lines incident to the four-unit electric generating plant.  The San Juan Project does not include distribution lines, transmission lines, equipment in the Switchyard Facilities or other facilities owned exclusively by a Party.
5.43(a)     SJCC means San Juan Coal Company, a Delaware corporation, or its successors or assigns.  
5.44    SWITCHYARD FACILITIES:  The switchyard facilities required for the San Juan Project as shown by materials listed in Exhibit III, attached hereto and incorporated herein.
5.44(a)    TIER 1 TONNAGE ALLOCATION means a schedule allocating Tier 1 Tons on a monthly basis based on the SJGS monthly planned coal consumption.
5.44(b)    TIER 1 TONS means, with respect to:  (i) each of 2016 and 2017, 5.75 million tons; (ii) each of 2018 and 2019, 2.8 million tons; (iii) each of 2020 and 2021, 2.65 million tons; and (iv) in 2022, 1.4 million tons.
5.44(c)    TIER 2 TONS means all tons delivered to and accepted by SJGS in a year in excess of Tier 1 Tons.  
        



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5.45    TOTAL MONTHLY COAL COST:  The amount charged the Operating Agent each month in accordance with the Underground Coal Sales Agreement, the Coal Sales Agreement Buy Out Agreement and the Transportation Agreement Buy Out Agreement.  
5.46    TRANSPORTATION AGREEMENT BUY OUT AGREEMENT: Agreement between PNM, TEP and San Juan Transportation Company (“SJTC”) executed on August 31, 2001, as may be amended or modified from time to time, terminated the Transportation Agreement with SJTC dated April 30, 1984.
5.46(a)     UG-CSA TERMINATION AGREEMENT means the Underground Coal Sales Agreement Termination and Mutual Release Agreement among PNM, TEP, SJCC and BHP Billiton New Mexico Coal.
5.47    UNDERGROUND COAL SALES AGREEMENT:  Agreement between PNM, TEP and SJCC executed on August 31, 2001, as amended or modified and as may be amended or modified from time to time.
5.48    UNIT:  Unit 1, Unit 2, Unit 3 or Unit 4.
5.49    UNIT 1:  The second operating unit of the San Juan Project, which was placed in commercial service on December 31, 1976 and which presently has a net capacity rating of 340 MW. 
5.50    UNIT 2:  The first operating unit of the San Juan Project, which was placed in commercial service on November 30, 1973 and which presently has a net capacity rating of 340 MW. 



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5.51    UNIT 3:  The third operating unit of the San Juan Project, which was placed in commercial service on December 31, 1979 and which presently has a net capacity rating of 496 MW. 
5.52    UNIT 4:  The fourth operating unit of the San Juan Project, which was placed in commercial service on April 27, 1982 and which presently has a net capacity rating of 507 MW. 
5.53    UNITS OF PROPERTY:   Property as described in the FERC’s list of units of property for use in connection with the Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act, contained in 18 CFR Part 116, in effect on the effective date of this Agreement, as thereafter modified or amended.
5.54    UTILITY PAYMENT STREAM (“UPS”): Those payments defined in Section 8.5(C) of the Underground Coal Sales Agreement.
5.55    VARIABLE FUEL EXPENSE: Those expenses itemized on Exhibit X, attached hereto and incorporated herein.
5.56    WATER CONTRACT(S):  The applicable contract or contracts under which water is delivered to the San Juan Project, as more fully described in Section 2.12.
5.57    WILLFUL ACTION:  
5.57.1    Action taken or not taken by a Party (or the Operating Agent), at the direction of its directors, members of its governing body, officers or employees having management or administrative responsibility affecting its performance under 



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a Project Agreement, which action is knowingly or intentionally taken or not taken with conscious indifference to the consequences thereof or with intent that injury or damage would probably result therefrom; or  
5.57.2    Action taken or not taken by a Party (or the Operating Agent) at the direction of its directors, members of its governing body, officers or employees having management or administrative responsibility affecting its performance under a Project Agreement, which action has been determined by final arbitration award or final judgment or judicial decree to be a material default under a Project Agreement and which action occurs or continues beyond the time specified in such arbitration award or judgment or judicial decree for curing such default, or if no time to cure is specified therein, occurs or continues beyond a reasonable time to cure such default; or  
5.57.3    Action taken or not taken by a Party (or the Operating Agent), at the direction of its directors, members of its governing body, officers or employees having management or administrative responsibility affecting its performance under a Project Agreement, which action is knowingly or intentionally taken or not taken with the knowledge that such action taken or not taken is a material default under a Project Agreement.
5.57.4    The phrase “employees having management or administrative responsibility,” as used in this Section 5.57, means employees of a Party who are responsible  for  one  or  more  of  the  executive  functions  of  planning,  organizing, 



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coordinating, directing, controlling and supervising such Party’s performance under a Project Agreement; provided however, that, with respect to employees of the Operating Agent acting in its capacity as such and not in its capacity as a Party, such phrase shall refer only to (i) the senior employee of the Operating Agent on duty at the San Juan Project who is responsible for the operation of the Units, and (ii) anyone in the organizational structure of the Operating Agent between such senior employee and an officer.  
5.57.5    Willful Action does not include any act or failure to act which is merely involuntary, accidental or negligent.  



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PART II
OWNERSHIP OF SAN JUAN PROJECT
6.0    OWNERSHIPS AND TITLES:  
6.1    PNM and TEP, respectively, each has an undivided one-half (1/2) ownership interest in the real property interests described in Exhibit I as Parcels A through F.  
6.2    Unless otherwise provided in Exhibit IV or Section 7.13, the Units and other facilities of the San Juan Project and Capital Improvements shall be owned and title held by the Parties in the following percentages:
6.2.1    For Units 1 and 2 and for all equipment and facilities directly related to Units 1 and 2 only, in accordance with the following percentages:
  
6.2.1.1        PNM:  50 percent
6.2.1.2        TEP:  50 percent
6.2.1.3        M‐S‐R:  0 percent
6.2.1.4        Farmington:  0 percent
6.2.1.5        Tri-State:  0 percent
6.2.1.6        LAC:  0 percent
6.2.1.7        SCPPA:  0 percent
6.2.1.8        Anaheim:  0 percent
6.2.1.9        UAMPS:  0 percent
6.2.1.10    PNMR-D:  0 percent


6.2.2    For Unit 3 and for all equipment and facilities directly related to Unit 3 only, in accordance with the following percentages:  


6.2.2.1        PNM:  50 percent
6.2.2.2        TEP:  0 percent
6.2.2.3        M‐S‐R:  0 percent
6.2.2.4        Farmington:  0 percent
6.2.2.5        Tri-State:  8.2 percent
6.2.2.6        LAC:  0 percent
6.2.2.7        SCPPA:  41.8 percent
                



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6.2.2.8        Anaheim:  0 percent
6.2.2.9        UAMPS:  0 percent
6.2.2.10    PNMR-D:  0 percent


6.2.3    For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages:  


6.2.3.1        PNM:  38.457 percent
6.2.3.2        TEP:  0 percent
6.2.3.3        M‐S‐R:  28.8 percent
6.2.3.4        Farmington:  8.475 percent
6.2.3.5        Tri-State:  0 percent
6.2.3.6        LAC:  7.20 percent
6.2.3.7        SCPPA:  0 percent
6.2.3.8        Anaheim:  10.04 percent
6.2.3.9        UAMPS:  7.028 percent
6.2.3.10    PNMR-D:  0 percent


6.2.4    For equipment and facilities common to Units 1 and 2 only, in accordance with the following percentages:  


6.2.4.1        PNM:  50 percent
6.2.4.2        TEP:  50 percent
6.2.4.3        M‐S‐R:  0 percent
6.2.4.4        Farmington:  0 percent
6.2.4.5        Tri-State:  0 percent
6.2.4.6        LAC:  0 percent
6.2.4.7        SCPPA:  0 percent
6.2.4.8        Anaheim:  0 percent
6.2.4.9        UAMPS:  0 percent
6.2.4.10    PNMR-D:  0 percent


6.2.5    For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:  


6.2.5.1        PNM:  44.119 percent
6.2.5.2        TEP:  0 percent
6.2.5.3        M‐S‐R:  14.4 percent
6.2.5.4        Farmington:  4.249 percent



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6.2.5.5        Tri-State:  4.1 percent
6.2.5.6        LAC:  3.612 percent
6.2.5.7        SCPPA:  20.9 percent
6.2.5.8        Anaheim:  5.07 percent
6.2.5.9        UAMPS:  3.55 percent
6.2.5.10    PNMR-D:  0 percent


6.2.6    For equipment and facilities common to all of the Units in accordance with the following percentages: 


6.2.6.1        PNM:  46.297 percent
6.2.6.2        TEP:  19.8 percent
6.2.6.3        M‐S‐R:  8.7 percent
6.2.6.4        Farmington:  2.559 percent
6.2.6.5        Tri-State:  2.49 percent
6.2.6.6        LAC:  2.175 percent
6.2.6.7        SCPPA:  12.71 percent
6.2.6.8        Anaheim:  3.10 percent
6.2.6.9        UAMPS:  2.169 percent
6.2.6.10    PNMR-D:  0 percent
6.2.7    San Juan Project equipment and facilities not included in Sections 6.2.1 through 6.2.6 which were in service as of May 16, 1979, remain in individual one-half (1/2) ownership, with each of PNM and TEP retaining title to an equal undivided one-half (1/2) interest therein; provided, however, that subsequent to the in-service date of Unit 4, PNM, on behalf of itself and the Participants to which PNM conveyed ownership interests and generation entitlements in the San Juan Project, shall have the right to use sixty-five percent (65%), and TEP, on behalf of itself and the Participants which succeeded to TEP-conveyed ownership interests and generation entitlements in the San Juan Project, shall have the right to use thirty-five  percent  (35%)  of  the  real  property  associated  with  the  San  Juan  Project, 



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the water, the then existing oil for ignition and flame stabilization, and the use of the 345 kV switchyard capacity up to the combined installed capacity of Units 1, 2, 3 and 4, except as otherwise provided in Section 7, and except that, subject to Section 15.2.3, PNM and TEP shall each be entitled to use 50 percent (50%) of switchyard capacity in excess of the combined installed capacity of Units 1, 2, 3 and 4 for the San Juan Project.
6.2.8    Exhibit IV (a through h), attached hereto and incorporated herein, is a partial list of equipment and facilities of the San Juan Project and reflects the Parties’ ownership interests therein.  This exhibit is to provide the Engineering and Operating Committee, the Auditing Committee, the Fuels Committee and the Coordination Committee with guidelines for carrying out their duties under this Agreement.
6.2.9    In areas where ownership of equipment and facilities is not clearly defined by Sections 6.2.1 to 6.2.7, the Engineering and Operating Committee shall make a determination of such ownership in accordance with Section 19.  Disputes arising from such determination shall be resolved by the Coordination Committee in accordance with Section 18.
6.2.10    Materials and Supplies shall be owned by the Participants in proportion to their respective current investments in the Materials and Supplies.
6.3    Upon the effective date of this Agreement, the Emergency Coal Storage Pile shall be owned as follows: 
                



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6.3.1        PNM:          73.297 percent
6.3.2        TEP:          19.8 percent
6.3.3        M‐S‐R:      0 percent
6.3.4        Farmington:      2.559 percent
6.3.5        Tri-State:      0 percent
6.3.6        LAC:          2.175 percent
6.3.7        SCPPA:      0 percent
6.3.8        Anaheim:      0 percent
6.3.9        UAMPS:      2.169 percent
6.3.10        PNMR-D:      0 percent


6.4    In the event that a Party transfers or assigns any of its rights, titles or interests in and to the San Juan Project in accordance with the terms and conditions of this Agreement, the Parties (including the transferee or assignee of a Party) shall jointly make, execute and deliver a supplement to this Agreement in recordable form which shall describe with particularity and in detail the rights, titles and interests of each Party following such transfer or assignment.
6.5    PNM and TEP own as tenants in common the Switchyard Facilities described in Exhibit III in equal, undivided one-half (1/2) interests.  



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7.0    CAPITAL IMPROVEMENTS AND RETIREMENTS OF SAN JUAN PROJECT AND PARTICIPANTS’ SOLELY OWNED FACILITIES:  
7.1    The Parties recognize that from time to time it may be necessary or desirable to make Capital Improvements to and retirements of facilities comprising the San Juan Project.  
7.2    Any such Capital Improvements and retirements shall be noted by an appropriate revision in or supplement to the appropriate exhibits hereto attached.  
7.3    The rights, titles and interests, including Participation Shares, of a Party in and to any Capital Improvements shall be as provided for the respective classes of property described in Section 6.  Except as provided in Section 7.13, the Parties shall be obligated for the costs of such Capital Improvements in the same percentages as their Participation Shares.  
7.4    All Capital Improvements, and a contingency allowance for capital expenditures necessitated by an Operating Emergency or otherwise deemed justifiable by the Operating Agent, shall be included in the annual capital expenditures budget.  The Engineering and Operating Committee may authorize Capital Improvements not included in the annual capital expenditures budget; provided, that such Capital Improvements shall not exceed the sum of five hundred thousand dollars ($500,000) for each such Capital Improvement, unless also authorized by the Coordination Committee.
7.5    The Operating Agent shall submit to the Parties a forecast of cash requirements by months for Capital Improvements.  Said forecast will be submitted on a 



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yearly basis after final budget approvals have been made.  A revised forecast shall be submitted when the capital expenditures budget is revised, or when significant changes in monthly expenditures from those previously forecast are anticipated.  The Operating Agent shall be authorized to make additional expenditures related to Capital Improvements; provided, however, that such additional expenditures for Capital Improvements shall not exceed the sum of one hundred thousand dollars ($100,000) or cause the total expenditure limit contained in the capital expenditures budget to be exceeded, unless also authorized by the Engineering and Operating Committee, or by the Coordination Committee if the total expenditure for such Capital Improvement exceeds five hundred thousand dollars ($500,000).  
7.6    In the event of the removal or retirement of any facilities comprising part of the San Juan Project, any proceeds realized from the salvage of such facilities shall be distributed to the Participants in accordance with their Participation Shares therein, or shall be applied on account of the Participant’s obligations to pay for Capital Improvements replacing facilities removed or retired.  Units of Property retired from service shall be disposed of by the Operating Agent on the best available terms as soon as practicable.
7.7    Each Participant shall have the right, at its own expense, to add facilities to the Switchyard Facilities, provided the Engineering and Operating Committee approves the design of such additional facilities and determines that space is available therefor, and that such committee also determines that such additional facilities will not (i) infringe upon the rights  of  another  Participant  in  the  Switchyard Facilities, (ii) unreasonably interfere with 



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future expansion plans at the San Juan Project, (iii) impair or interfere with the contractual rights of another Party, or (iv) jeopardize the reliability of another Participant’s system.  The Engineering and Operating Committee shall have authority to impose conditions on a Participant allowed to make such additions in order to protect the other Parties consistent with applicable rules and regulations of the FERC.  Such facilities shall be and remain the sole and exclusive property of the Participant installing same until and unless the Coordination Committee determines that such facilities are necessary and beneficial for operation of the San Juan Project as a whole.  In the event of such determination, the facilities shall be acquired as a part of the San Juan Project by the Remaining Participants and compensation shall be paid to the selling Participant by the Remaining Participants acquiring such interest based on the net book value of such facilities.  
7.8    Each Participant shall have the right, at its own expense, to add protective relay or communication equipment to facilities solely owned by it, if the Participant determines the protective relay or communication equipment is needed for the protection of its electric system, provided the Engineering and Operating Committee approves the design of such additional equipment and determines that space is available therefor, and that such committee also determines that such additional facilities will not (i) infringe upon the rights of another Participant in the facilities, (ii) unreasonably interfere with future expansion plans at the San Juan Project, (iii) impair or interfere with the contractual rights of another Party, or (iv) jeopardize the reliability of another Participant’s system.  
        



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7.9    Transportation and motorized equipment which is to be utilized by the Operating Agent for Operating Work may be purchased or leased by the Operating Agent upon receipt of the approval referred to in Section 19.3.4.  Ownership of such purchased equipment and the purchase price thereof shall be allocated between and paid by the Participants in proportion to the percentages established in Section 6.  Lease payments made by the Operating Agent for such leased equipment shall be apportioned between and paid by the Participants in accordance with Section 22.1.  No allowance to the Operating Agent for administrative and general expense shall be included in or added to such lease payments for transportation and motorized equipment which, in lieu of acquiring such equipment by purchase, has been leased on a long-term basis.
7.10    Upon retirement of leased transportation and motorized equipment utilized for Operating Work, an amount, which shall be treated as a charge (or credit), shall be determined by multiplying the difference between the salvage value and the unamortized balance owing to the leasing company for each piece of such equipment by a fraction, the numerator of which is the sum of the monthly lease payments for such equipment charged to Operating Work and the denominator of which is the sum of all monthly lease payments made by the Operating Agent for such equipment.  Such charge or credit shall be allocated among the Participants in accordance with the applicable percentages set forth in Section 22.  
7.11    Administrative and general expenses which have been incurred by the Operating Agent which are applicable to authorized Capital Improvements, shall be applied 



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monthly to construction costs incurred during the preceding month. A rate will be developed by the Operating Agent every three (3) years in conjunction with the administrative and general (“A&G”) expenses study referenced in Attachment A to Exhibit VI.  The current methodology for calculating the A&G Ratio for Capital Improvements is set forth in Exhibit VI, Attachment E.  If any Party believes that the method used in determining the A&G Ratio for Capital Improvements results in an unreasonable burden on such Party(ies), such Party(ies) may request that said method used in determining said ratio be submitted to the Auditing Committee for review in accordance with the procedures set out in Sections 22.6.1 through 22.6.4.  
7.12    Excluded from the charges in Section 7.11 are expenses incurred under Section 36.2.  
7.13    The provisions of this Agreement are modified by this Section 7.13.
7.13.1    The Remaining Participants are responsible for the costs of Capital Improvements pertaining to all equipment and facilities directly related to Unit 4 only, common to Units 3 and 4 only and common to all of the Units, invoiced after January 1, 2015, and the Exiting Participants have no Ownership Interest in such Capital Improvements.  The Exiting Participants will have no responsibility for costs of the SNCR/balanced draft project to be placed on Units 1 and 4.  Costs of Capital Improvements invoiced after January 1, 2015, are allocated to the Remaining Participants as follows:
        



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7.13.1.1    For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages:


7.13.1.1.1    PNM:            64.482%
		
	7.13.1.1.2      Farmington:
	8.475%


		
	7.13.1.1.3
	LAC:            7.200%


		
	7.13.1.1.4
	UAMPS:        7.028%


7.13.1.1.5    PNMR-D:        12.815%


7.13.1.2     For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:  


		
	7.13.1.2.1
	PNM:            64.482%


		
	7.13.1.2.2
	Farmington:        8.475%


		
	7.13.1.2.3
	LAC:            7.200%


		
	7.13.1.2.4
	UAMPS:        7.028%


		
	7.13.1.2.5
	PNMR-D:        12.815%




7.13.1.3    For equipment and facilities common to all of the Units in accordance with the following percentages: 


		
	7.13.1.3.1
	PNM:            58.671%


		
	7.13.1.3.2
	TEP:            20.068%


7.13.1.3.3    Farmington:        5.076%
		
	7.13.1.3.4
	LAC:            4.309%


7.13.1.3.5    UAMPS:        4.203%
7.13.1.3.6    PNMR-D:        7.673%


7.13.2    For the period July 1, 2014, through December 31, 2017, the Exiting Participants will pay a charge (the “Demand Charge”) for the use of new Capital Improvements implemented on Unit 4, facilities common to Units 3 and 4, and facilities common to all Units.



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7.13.2.1    The total Demand Charge is six million two hundred thousand dollars ($6,200,000) of which five million three hundred fourteen thousand two hundred eighty-six dollars ($5,314,286) remains unpaid.  The Demand Charge will be paid regardless of the output of Unit 3 or 4.  The Exiting Participants will be invoiced by the Operating Agent for and will pay the unpaid balance of the Demand Charge in monthly amounts of no less than 1/36th of the unpaid balance; provided, the sum of the monthly amounts which would have accrued between January 1, 2015 and the Effective Date will be paid within forty-five (45) days of the Effective Date.  


7.13.2.2    The Exiting Participants will pay the Demand Charge as follows:
7.13.2.2.1    M-S-R:    71.650%
7.13.2.2.2    Anaheim:    25.000%
7.13.2.2.3    SCPPA:    2.800%
7.13.2.2.4    Tri-State:    0.550%
17.13.2.3    The Remaining Participants will be paid the Demand Charge as follows from July 1, 2014 through December 31, 2014:


7.13.2.3.1    PNM:         0.000%
7.13.2.3.2    TEP:        0.000%
7.13.2.3.3    Farmington:    55.6%
7.13.2.3.4    LAC:        22.200%
7.13.2.3.5    UAMPS:    22.200%
7.13.2.3.6    PNMR-D:    0.000%
7.13.2.4    The Remaining Participants will be paid the Demand Charge as follows from January 1, 2015 through December 31, 2017:


7.13.2.4.1    PNM:         0.000% 



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7.13.2.4.2    TEP:         0.000%
7.13.2.4.3    Farmington:    17.24%
7.13.2.4.4    LAC:        22.20%
7.13.2.4.5    UAMPS:    22.20%
7.13.2.4.6    PNMR-D:    38.36%


7.13.2.5    With respect to any Demand Charges paid or received between July 1, 2014 and December 31, 2014, any Exiting Participant that made such a Demand Charge payment and any Remaining Participant that received a Demand Charge payment and did not return it will be credited the amount of that payment or receipt as follows: the amount of any such payment will be proportionately offset against the amount of the Demand Charge payment each such Exiting Participant is obligated to pay under Sections 7.13.2.1 through 7.13.2.4, and the amount of any such receipt by a Remaining Participant will be proportionately offset against the amount of the Demand Charge payment each such Remaining Participant is entitled to receive under Sections 7.13.2.1 through 7.13.2.4.  The Demand Charge payments made by Exiting Participants to the Operating Agent between July 1, 2014, and December 31, 2014, were as follows: M-S-R - $634,614; Anaheim - $221,429; SCPPA - $24,800; and Tri-State - $4,871.  The Demand Charge payments received by the Remaining Participants between July 1, 2014, and December 31, 2014, and not returned to the Operating Agent were as follows: Farmington - $492,457.  For a Remaining  Participant  that returned Demand Charge payments received between July 1, 2014  and  December  31,  2014,  such  Remaining  Participant  will  receive  a  disbursement  from  the  Operating  Agent  constituting  the  Remaining Participant’s entire 



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proportionate share of Demand Charge payments as set forth in Sections 7.13.2.1, 7.13.2.3 and 7.13.2.4.



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	8.0
	WAIVER OF RIGHT TO PARTITION:  


8.1    The Parties accept title to their respective interests in the San Juan Project, water rights, lands, land rights and improvements thereon as tenants in common, and agree that their interests therein shall be held in such tenancy in common for the duration of the term of this Agreement, including any extensions thereof. While this Agreement, including any extensions thereof, remains in force and effect, each Party agrees as follows:
8.1.1    That it hereby waives the right to partition the San Juan Project, water rights, lands, land rights or the improvements built thereon (whether by partitionment in kind or by sale and division of the proceeds thereof), and
8.1.2    That it will not resort to any action at law or in equity to partition (in either such manner) the San Juan Project, water rights, lands, land rights or the improvements built thereon and waives the benefits of all laws that may now or hereafter authorize such partition.  



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9.0    BINDING COVENANTS:  
9.1    Except as otherwise provided in Section 9.3, all of the respective covenants and obligations of each of the Parties set forth and contained in the Project Agreements shall bind and shall be and become the respective obligations of:  
9.1.1    Each Party; 
9.1.2    All mortgagees, trustees and secured parties under all present and future mortgages, indentures and deeds of trust, and security agreements which are or may become a lien upon any of the properties of each Party; 
9.1.3    All receivers, assignees for the benefit of creditors, bankruptcy trustees and referees of a Party; 
9.1.4    All other persons, firms, partnerships or corporations claiming through or under any of the foregoing; and 
9.1.5    Any successors or assigns of any of those mentioned in Sections 9.1.1 to 9.1.4, inclusive, 
and shall be obligations running with the Parties’ rights, titles and interests in the San Juan Project, with all of the rights, titles and interests (if any) of each Party in, to and under this Agreement and with their rights, titles and interests in the water rights, lands, land rights and the improvements thereon.  It is the specific intention of this provision that all of such covenants and obligations shall be binding upon any party which acquires any of the rights, titles and interests of any of the Parties in the San Juan Project, in, to and under this Agreement, and/or in the water rights, lands, land rights or the improvements thereon, and 



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that all of the above-described persons and groups shall be obligated to use such Party’s rights, titles and interests in the San Juan Project, in, to and under this Agreement, and in the water rights, lands, land rights and the improvements thereon, for the purpose of discharging its covenants and obligations under this Agreement.  
9.2    The rights, titles and interests of each Party in the San Juan Project, its rights, titles and interests in, to and under this Agreement and its rights, titles and interests in and to the water rights, lands, land rights and improvements thereon, shall inure to the benefit of its successors and assigns. 
9.3    Any mortgagee, trustee or secured party, or any receiver or trustee appointed pursuant to the provisions of any present or future mortgage, deed of trust, indenture or security agreement creating a lien upon or encumbering the rights, titles or interests of any Party in the San Juan Project, in, to and under this Agreement and/or in the water rights, lands, land rights or the improvements thereon, and any successor thereof by action of law or otherwise, and any purchaser, transferee or assignee of any thereof, shall not be obligated to pay any monies accruing on account of any of the obligations or duties of such Party under this Agreement incurred prior to the taking of possession or the initiation of foreclosure or other remedial proceedings by such mortgagee, trustee or secured party.  
9.4    In the event that any or all of the provisions of this Section 9 shall not be legally effective as to any Party, or its mortgagees, trustees, secured parties, receivers, successors or assigns, then such Party shall not be deemed in violation of this Section 9 by reason thereof.



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9.5    Nothing in this Section 9 or in this Agreement shall be deemed to change any rights, titles or interests to water rights, lands, land rights and the improvements thereon.



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10.0    MORTGAGE AND TRANSFER OF PARTIES’ INTERESTS:  
10.1    The Parties shall have the right at any time and from time to time to mortgage, create or provide for a security interest in or convey in trust their respective rights, titles and interests in the San Juan Project, their respective rights, titles and interests in, to and under a Project Agreement and/or their rights, titles and interests in the water rights, lands, land rights or the improvements to be built thereon to a trustee or trustees under deeds of trust, mortgages or indentures, or to secured parties under a security agreement, as security for their present or future bonds or other obligations or securities, and to any successors or assigns thereof without need for the prior consent of the other Parties, and without such mortgagee, trustee or secured party assuming or becoming in any respect obligated to perform any of the obligations of the Parties.  
10.2    Any mortgagee, trustee or secured party under present or future deeds of trust, mortgages, indentures or security agreements of any of the Parties and any successor or assign thereof, and any receiver, referee, or trustee in bankruptcy or reorganization of any of the Parties, and any successor by action of law or otherwise, and any purchaser, transferee or assignee of any thereof may, without need for the prior consent of the other Parties, succeed to and acquire all the rights, titles and interests of such Party in the San Juan Project, in, to and under the Project Agreements and/or the rights, titles and interests of such Party in the water rights, lands, land rights and improvements thereon, and may take over possession of or foreclose upon said property, rights, titles and interests of such Party.  
        



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10.3    Except as otherwise provided in Sections 10.1, 10.2 or 10.4 or, with respect to a transfer or assignment by a Party to another Party as provided in Section 11, no Party shall transfer or assign its respective rights, titles and interests in the San Juan Project, in, to and under this Agreement and/or in the water rights, land, land rights and the improvements thereon, without the prior written consent of the other Parties, which consent shall not be unreasonably withheld.
10.4    Each Party shall have the right to transfer or assign its respective rights, titles and interests in the San Juan Project, in, to and under this Agreement and/or in the water rights, land, land rights and the improvements thereon, without the need for prior consent of the other Parties, at any time to any of the following:  
10.4.1    To any corporation or other entity acquiring all or substantially all of the property of such Party; or
10.4.2    To any corporation or entity into which or with which such Party may be merged or consolidated; or
10.4.3    To any corporation or entity the stock or ownership of which is wholly owned by a Party; or
10.4.4    To any corporation or other entity which owns all of the outstanding common stock or other ownership interest of a Party (its “Parent”); or
10.4.5    To any corporation or other entity the common stock or other ownership interest of which is wholly owned by the Parent of a Party.
        



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10.5    Except as otherwise provided in Sections 10.1, 10.2 and 9.3, any successor to the rights, titles and interests of a Party in the San Juan Project, to the rights, titles and interests of a Party in, to and under the Project Agreements and/or in the water rights, lands, land rights or improvements thereon shall assume and agree to fully perform and discharge all of the obligations hereunder of such Party, and such successor shall notify the other Parties in writing of such transfer, assignment or merger, and shall furnish to the other Parties evidence of such transfer, assignment or merger.  Any such successor shall specifically agree in writing with the remaining Parties at the time of such transfer, assignment or merger that it will not transfer or assign any rights, titles and interests acquired from the assigning Party without complying with the terms and conditions of Section 11.  
10.6    No Party shall be relieved of any of its obligations and duties to the other Parties by a transfer, assignment or merger under this Section 10 without the express prior written consent of the remaining Parties, which consent shall not be unreasonably withheld.  
10.7    Except as otherwise provided in Section 10.5, any transfer, assignment or merger made pursuant to the provisions of this Section 10 shall not be subject to the terms and conditions set forth and contained in Section 11.  



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11.0    RIGHTS OF FIRST REFUSAL: 
11.1    The purpose of this Section 11 is to set forth the manner in which all existing or future rights of first refusal, pertaining to the transfer of interests in the San Juan Project, shall be exercised.  Except as provided in Section 10, PNM has a right of first refusal with respect to the proposed transfer of any ownership interest in the San Juan Project by any Party and TEP has a right of first refusal with respect to PNM’s proposed transfer of an interest in Unit 1 or Unit 2 and associated common property.  The existence of other rights of first refusal shall be as provided in other appropriate instruments.  Nothing in this Section 11 shall be construed to limit or expand the rights of first refusal of any Party. 
11.2    Except as provided in Section 10, should a Party desire to assign, transfer, convey or otherwise dispose of (hereinafter collectively referred to as “Assign”) its rights, titles and interests in the San Juan Project, or its rights, titles and interests in, to and under the Project Agreements, or its rights, titles and interests in the water rights, lands, land rights or the improvements thereon or any part thereof or interest therein (hereinafter referred to as “Transfer Interest”), to any person, company, corporation or governmental agency (hereinafter referred to as “Outside Party”), the Party desiring to Assign shall first make an offer to sell the Transfer Interest to a Party(ies) having a right of first refusal, on the basis of the applicable amount as set out in either Section 11.2.1 or Section 11.2.2:
11.2.1    Where the Outside Party proposes to purchase for a specified monetary amount, from the Party desiring to Assign, an interest only in the San Juan Project and/or in contract rights, water rights, lands, land rights and improvements 



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associated therewith, the amount of (i) a bona fide written offer from an Outside Party ready, willing and able (subject to obtaining any required regulatory approvals) to purchase the Transfer Interest; or, in the absence of a bona fide written offer, (ii) a purchase price set out in a bona fide purchase and sale agreement between the Party desiring to Assign and an Outside Party ready, willing and able (subject to obtaining any required regulatory approvals) to purchase the Transfer Interest; or
11.2.2    Where the Outside Party proposes to purchase from the Party desiring to Assign, (i) as part of a non-monetary offer (such as in the case of an asset swap) or (ii) when a segregated value for the Transfer Interest is not available (such as in the case of a bundled or packaged sale of assets), or (iii) where the Outside Party proposes to purchase an interest not only in the San Juan Project and/or in contract rights, water rights, lands, land rights and improvements associated therewith, but also in other property of the Party desiring to Assign, the purchase price shall be the fair market value of the Transfer Interest.  As used herein, the term “fair market value” means the amount of money which a purchaser, willing but not obligated to buy the property, will pay to an owner, willing but not obligated to sell it, taking into consideration all of the uses to which the Transfer Interest is adapted and might in reason be applied. 
11.3    At least three (3) months prior to its intended date to Assign, and after its receipt of a bona fide written offer, or execution of a bona fide purchase and sale agreement, 



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of the type described in Section 11.2, the Party desiring to Assign its Transfer Interest shall serve written notice of its intention to do so upon the Party(ies) having a right of first refusal, in accordance with Section 42.  Such notice shall: (i) have attached as an exhibit a copy of the bona fide offer of an Outside Party or of the bona fide purchase and sale agreement between the Outside Party and the Participant desiring to Assign (an “Outside Offer”); and (ii) shall contain a statement of the approximate proposed date to Assign. 
11.4    The Party(ies) having the right of first refusal shall signify its (their) desire to purchase the entire Transfer Interest, or not purchase the entire Transfer Interest, by serving written notice of its (their) intention upon the Participant desiring to Assign pursuant to Section 42 within sixty (60) days after such service pursuant to Section 11.3 of the written notice of intention to Assign.  Failure by a Party to serve notice as provided hereunder within the time period specified shall be conclusively deemed to be notice of its intention not to purchase the Transfer Interest.  
11.5    When intention to purchase the entire Transfer Interest has been indicated by notices duly given hereunder by the Party(ies) desiring to purchase the Transfer Interest, the affected Parties shall thereby incur the following obligations:  
11.5.1    The Party desiring to Assign and a Participant desiring to purchase the Transfer Interest shall be obligated to proceed in good faith and with diligence to obtain all required authorizations and approvals to Assign;  
            



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11.5.2    The Party desiring to Assign shall be obligated to obtain the release of any liens imposed by or through it upon any part of the Transfer Interest and to Assign the Transfer Interest at the earliest practicable date thereafter; and 
11.5.3    A Party desiring to purchase the Transfer Interest shall be obligated to perform all terms and conditions required of it to complete the purchase of the Transfer Interest.  
The purchase of the Transfer Interest shall be fully consummated within six (6) months following the date upon which all notices required to be given under this Section 11 have been duly served, unless the Party is then diligently pursuing applications to appropriate regulatory bodies (if any) for required authorizations to effect such assignment or is then diligently prosecuting or defending appeals from orders entered or authorizations issued in connection with such applications.
11.6    If the intention to purchase the entire Transfer Interest has not been indicated by notices given within the time periods specified in this Section 11 by a Party desiring to purchase the Transfer Interest, the Party desiring to Assign shall be free to Assign all, but not less than all, of its Transfer Interest to the Outside Party that made the Outside Offer, upon the terms and conditions set forth in the Outside Offer.  If such assignment of the entire Transfer Interest to the Outside Party is not completed within three (3) years after the approximate proposed date to Assign specified in the notice given pursuant to Section 11.3, the Party desiring to Assign its Transfer Interest must, unless it is then diligently pursuing its applications to appropriate regulatory bodies (if any) for required authorizations to effect 



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such assignment, or is then diligently prosecuting or defending appeals from orders entered or authorizations issued in connection with such applications, give another complete new right of first refusal to the Party(ies) desiring to purchase pursuant to the provisions of this Section 11, before such Party shall be free to Assign a Transfer Interest to said Outside Party.
11.7    No assignment of a Transfer Interest, whether to another Party or to an Outside Party, shall relieve the assigning Party from full liability and financial responsibility for performance after any such assignment:   (i) of all obligations and duties incurred by such Party prior to such assignment under the terms and conditions of the Project Agreements; and/or (ii) of all obligations and duties provided and imposed after such assignment upon such assigning Party under the terms and conditions of the Project Agreements, unless and until the assignee shall agree in writing with the remaining Parties to assume the obligations and duties of a Party hereunder; provided further, however, that such assignor shall not be relieved of any of its obligations and duties by an assignment under this Section 11, without the express prior written consent of the remaining Parties, which consent shall not be unreasonably withheld.  
11.8    Any transferee, successor or assignee, or any party who may succeed to the Transfer Interest pursuant to this Section 11, shall specifically agree in writing with the remaining Parties at the time of such transfer or assignment that it will not transfer or assign all or any portion of the Transfer Interest so acquired without complying with the terms and conditions of this Section 11.  
        



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11.9    The provisions of Section 11.8 shall not be applicable to any assignment of a Transfer Interest by one Party to another Party, provided that payment in full of such Transfer Interest, as defined in Section 11, has been made by the Party who is the assignee thereof.
11.10    A Party may, for the purpose of financing its interest in pollution control systems and facilities at the San Juan Project, sell, transfer or convey such interests pursuant to the New Mexico Pollution Control Revenue Bond Act, and any such sale, transfer or conveyance shall not be deemed as an assignment, transfer, conveyance or other disposal within the meaning of this Section 11.



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12.0    RIGHTS OF PNM AND TEP IN WATER AND COAL:  
12.1    If, pursuant to the terms and conditions of the Underground Coal Sales Agreement, or the sublease dated August 18, 1980 (as amended to date and as such sublease may be amended from time to time), between Western Coal Company and Utah International, Inc. or their successors (“Sublease”), PNM and TEP succeed to any interest in coal lands, coal leases, water rights, or other property, the rights, titles and interests of PNM and TEP therein shall be held as tenants in common, with each of PNM and TEP having an equal undivided one-half (1/2) interest therein, and such rights, titles and interests shall be subject to all the terms and conditions set forth and contained in this Agreement.



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13.0    SEVERANCE OF IMPROVEMENTS:  
13.1    All facilities, structures, improvements, equipment and property of whatever kind and nature constructed, placed or affixed on the rights-of-way, easements, patented lands, fee lands and leased lands as part of, or as Capital Improvements, to the San Juan Project, as against all parties and persons whomsoever (including, without limitation, any party acquiring any interest in the rights-of-way, easements, patented, fee or leased lands or any interest in or lien, claim or encumbrance against any of such facilities, structures, improvements, equipment and property of whatever kind and nature) shall be deemed to be and remain personal property of the Parties, not affixed to the realty.



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PART III
ENTITLEMENTS TO OUTPUT OF SAN JUAN PROJECT
14.0    ENTITLEMENT TO CAPACITY AND ENERGY:  
14.1    Subject to the provisions of Section 16, the Participants shall be entitled to the Net Effective Generating Capacity of each of Unit 1, Unit 2, Unit 3 and Unit 4 in proportion to their respective Participation Shares.  Each Participant shall be entitled to schedule its Energy up to the Available Operating Capacity. 
14.2    The Operating Agent shall keep the system dispatcher of each Participant advised of the Available Operating Capacity.  
14.3    When a Participant’s request for its share of the Available Operating Capacity necessitates the operation of a Unit, each Participant shall schedule for its account not less than its share of Minimum Net Generation.  If, however, a Participant has scheduled an amount of Energy in excess of its share of the Minimum Net Generation, the other Participants shall be allowed to reduce their scheduled Energy to an amount that will maintain the Unit at the Minimum Net Generation level.  
14.4    The delivery of Energy from the San Juan Project shall be scheduled by each Participant in advance with the Operating Agent and accounted for on the basis of integrated hourly actual generation, all in accordance with any operating procedures which may be established or approved by the Engineering and Operating Committee.  Such operating procedures shall provide for modifying such schedules to meet the needs of day-to-day and hour-by-hour operation, including emergencies on a Participant’s system.  
        



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14.5    The Operating Agent shall, to the extent possible, generate Energy at the San Juan Project in accordance with schedules submitted by each Participant, as such schedules may be revised from time to time, as long as such schedules do not jeopardize the operation of the San Juan Project.  
14.6    The Participants shall revise their schedules in the event of an Operating Emergency or other incident beyond the control of the Operating Agent to reflect the actual Energy available from the San Juan Project during the period of the Operating Emergency or incident.  
14.7    The Energy generated at the San Juan Project shall be controlled within PNM’s Control Area; provided, that such control shall not diminish the rights of any Participant to receive its entitlement of Energy from the San Juan Project.  



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15.0    CAPACITY ALLOCATION OF SWITCHYARD FACILITIES:  
15.1    The electrical capacity in the Switchyard Facilities shall be made available to PNM and TEP in the manner and in the amounts as set forth in Section 6.2.7.  For the purposes of this Agreement, the FC Line shall be considered a part of the Switchyard Facilities.  
15.1.1    The transmission capacity of the FC Line shall be measured at the Four Corners terminal.  PNM and TEP each shall be entitled to fifty percent (50%) of the designated FC Line Capacity.  
15.1.2    The transmission capacity of the FC Line termination and other contract matters concerning the Four Corners Project shall be handled individually by PNM and TEP.  
15.2    The points of attachment to the San Juan 345 kV Switchyard Facilities for the purposes of this Section 15 are:  
No. 1:    TEP/PNM No. 1 345 kV transmission line;
No. 2:    TEP/PNM No. 2 345 kV transmission line;
No. 3:    PNM/TEP Four Corners Generating Plant 345 kV switchyard (through the FC Line); 
No. 4:    PNM’s WW 345 kV transmission line;
No. 5:    PNM’s OJ 345 kV transmission line;
No. 6:    Colorado Public Service Company/Western Area Power Administration/Tri-State Rifle 345 kV transmission line;
            



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No. 7:    Western Area Power Administration-Shiprock 345 kV transmission line.
15.2.1 The Participants collectively shall not schedule more Power and Energy through any of the foregoing individual points of attachment than the established rating of that facility.
15.2.2    The Participants’ individual transmission capacity rights into or out of the Switchyard Facilities attachment points shall be the same as the ownership or contract rights of the Participant(s) in the attached facility up to the limits specified in this Section 15.  
15.2.3    Any transmission capacity in the Switchyard Facilities specified to be available in Section 15.2.1 or otherwise determined to be available by the Engineering and Operating Committee, but not allocated to the individual Participants under Section 15.2.2, shall be declared “excess capacity” by the Engineering and Operating Committee.  The Engineering and Operating Committee shall allocate such excess transmission capacity to PNM or TEP or such Participants having an ownership interest in the Switchyard Facilities, upon request in the amount requested for specified periods of time to the extent and for such time as the Engineering and Operating Committee finds such excess capacity to be available. 



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16.0    USE OF FACILITIES DURING CURTAILMENTS:  
16.1    If the Net Effective Generating Capacity of all Units is reduced because of factors (including, but not limited to, equipment failures, scheduled or unscheduled outages, fuel or fuel deliveries, water supply, air quality limitations) which commonly influence the total output of all Units, each Participant’s entitlement to Capacity during such period shall be reduced in proportion to the percentages specified in Section 6.2.6 during each hour of such curtailment unless otherwise specified in a separate agreement.
16.2    If factors which influence the operation of a Unit cause a curtailment of that Unit, then the capacity entitlement from that Unit for each Participant in that Unit shall be in proportion to the Participant’s Participation Share of that Unit.
16.3    If, because of factors which influence the operation solely of Units 1 and 2, or solely of Units 3 and 4, there shall be a curtailment of Units 1 and 2, or of Units 3 and 4, as the case may be, the curtailment for each Participant in Units 1 and 2, or Units 3 and 4, shall be allocated in proportion to the percentages specified in Sections 6.2.4 and 6.2.5, respectively.
16.4    To the extent that a curtailment results from scarcity of resources and not from mechanical or legal limitations, Participants may agree in writing to modify their schedules to allocate the use of such resources to such Unit(s) or to such times as to make the most efficient use thereof, consistent with Prudent Utility Practice, during the pendency of such curtailment.  Notwithstanding the provisions of Section 23.2, the Operating Agent shall, during such curtailments, account for coal inventory on a Participant by Participant 



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basis.  Upon the conclusion of such curtailment, the provisions of Section 23.2 shall apply to any remaining coal inventory.  
16.5    Curtailment of the transmission capacity in the Switchyard Facilities shall be allocated to the Participants in the manner and in the amounts as set forth in Section 6.2.7.
16.6    No Party shall exercise its rights relating to the San Juan Project so as to endanger or unreasonably interfere with the operation of the San Juan Project or the right of any other Party to use its share of Capacity and Energy from the San Juan Project.  



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17.0    START-UP AND AUXILIARY POWER AND ENERGY REQUIREMENTS:
17.1    Each Participant shall be obligated to provide its Participation Share of the Energy requirements to start up and operate each Unit, and such requirements shall be provided by the Participants based upon the Participant’s percentage of operating costs in accordance with Section 22.1.  Appropriate metering facilities shall be installed to assure measurement of such Energy.  Such requirements for Energy shall be scheduled in advance by the Operating Agent in accordance with operating procedures approved by the Engineering and Operating Committee.



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PART IV
ADMINISTRATION
18.0    COORDINATION COMMITTEE:  
18.1    As a means of securing effective cooperation and interchange of information and of providing consultation on a prompt and orderly basis among the Parties in connection with various administrative and technical problems which may arise from time to time under this Agreement, the Coordination Committee shall remain in existence during the term of this Agreement.  Except as otherwise expressly provided in this Agreement, the Coordination Committee shall have no authority to modify any of the provisions of this Agreement.
18.2    The Coordination Committee shall consist of one representative from each Party who shall be an officer or other duly authorized representative of a Party.  Any of the Parties may designate an alternate or substitute to act as its representative on the Coordination Committee in the absence of the regular representative on the Coordination Committee or to act on specified occasions or with respect to specified matters.  Each Party shall notify the other Parties promptly, in writing, of the designation of its representative and alternate representative on the Coordination Committee and of any subsequent changes in such designations. The chairperson of the Coordination Committee shall be a representative employed by the Operating Agent.
18.3    The Coordination Committee shall have the following functions and responsibilities:
            



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18.3.1    Provide liaison between and among the Parties.
18.3.2    Exercise general supervision over the Engineering and Operating Committee, the Fuels Committee and the Auditing Committee. 
18.3.3    Consider and act upon all matters referred to the Coordination Committee by the Engineering and Operating Committee, the Fuels Committee and the Auditing Committee.
18.4    Any action or determination of the Coordination Committee shall require a vote of the Participants or Remaining Participants in accordance with Sections 18.4.1, 18.4.2, 18.4.3 or 18.4.4.  A Participant’s Coordination Committee representative shall be entitled to vote on all matters except those actions or determinations which relate solely to a Unit or to common property in which such Participant does not have a Participation Share or as provided in Section 35.4.1.  If a Participant’s or Remaining Participant’s right to vote has been suspended pursuant to Section 35.4.1, the requisite majorities for actions or determinations specified in Sections 18.4.1, 18.4.2, 18.4.3 and 18.4.4 shall be adjusted in proportion to the number of Participants or Remaining Participants whose right to vote has not been suspended.  An example of such an adjustment is provided in Exhibit VIII, attached hereto and incorporated herein.   Maintenance scheduling and operation during periods of curtailment of the total San Juan Project are not matters which relate solely to a Unit, but are deemed to be matters affecting all Units.
            



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18.4.1    Except as provided in Sections 18.4.2, 18.4.3 and 18.4.4, any actions or determinations brought before the Coordination Committee shall require the following vote:
(a)    More than a sixty-six and two thirds percent (66 2/3%) majority of the Participation Shares of the Participants in a Unit or common property as defined in Section 6.2; and
(b)    More than a sixty-six and two thirds percent (66 2/3%) majority of the number of individual Participants having a Participation Share in a Unit or common property as defined in Section 6.2. 
18.4.2    Any action or determination of the Coordination Committee related to common property as set forth in Section 6.2.6 and involving an expenditure greater than five million dollars ($5,000,000) shall require the following vote:
(a)    More than an eighty-two percent (82%) majority of the Common Participation Shares of the Participants; and
(b)    A minimum of sixty-six and two thirds percent (66 2/3%) majority of the number of the individual Participants.
18.4.3     Any action or determination of the Coordination Committee regarding any amendment of the CSA, replacement of the CSA with a new agreement or any interim coal pricing agreement related to the CSA (or its successor) shall require the following vote:
        



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(a)    More than an eighty-two percent (82%) majority of the percentages, as set forth in Section 7.13.1.3, of the Remaining Participants; and
(b)    A minimum of sixty-six and two thirds percent (66 2/3%) majority of the number of individual Remaining Participants, as set forth in Section 7.13.1.3.
18.4.4    For purposes of the application of the double voting procedures set out in Sections 18.4.1 and 18.4.2 pertaining to Capital Improvements on all equipment and facilities directly related to Unit 4 only, common to Units 3 and 4 only and common to all of the Units, (i) the percentages and the number of individual Remaining Participants shall be as provided in Section 7.13.1; and (ii) the Exiting Participants shall have no vote.
18.5    The Coordination Committee shall keep written minutes and records of all meetings.  Any action or determination made by the Coordination Committee shall be reduced to writing and shall become effective when signed by the representatives of the Participants or Remaining Participants entitled to vote thereon, representing a voting majority of the members of the Coordination Committee, as defined in Section 18.4; provided, however, in the event of an Operating Emergency, actions or determinations may be made on the basis of oral agreements among duly authorized representatives of the respective Participants or Remaining Participants entitled to vote thereon, and such action or determination subsequently shall be reduced to writing. Coordination Committee 



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representatives may, by prior arrangement with the chairperson of the Coordination Committee, attend a meeting of the Coordination Committee by conference call or video conferencing.  A Coordination Committee representative who is unable to attend a meeting of the Coordination Committee may vote in absentia by delivering to the chairperson of the Coordination Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.
18.6    Except for matters subject to the voting requirements of Section 18.4.3, in the event the Coordination Committee fails to reach agreement on any matter, which such committee is authorized to determine, approve or otherwise act upon after a reasonable opportunity to do so, then the Operating Agent shall be authorized and obligated to take such reasonable and prudent action, consistent with Prudent Utility Practice, as is necessary to the successful and proper operation and maintenance of the San Juan Project, pending the resolution, by arbitration or otherwise, of any such inability or failure to agree.
18.7    In the event the Coordination Committee fails to reach agreement on a matter subject to the voting requirements of Section 18.4.3, then an impasse shall be deemed to exist and the Participant which is a signatory to the CSA then in effect shall have the obligation and the responsibility, consistent with Prudent Utility Practice, to maintain a supply of coal to the San Juan Project.    



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19.0    ENGINEERING AND OPERATING COMMITTEE:  
19.1    The Engineering and Operating Committee shall remain in existence during the term of this Agreement.  Except as expressly provided in this Agreement, the Engineering and Operating Committee shall have no authority to modify any of the provisions of this Agreement. 
19.2    The Engineering and Operating Committee shall consist of up to two representatives from each Party who shall collectively have one vote.  Any of the Parties may designate an alternate or substitute to act as its representative on the Engineering and Operating Committee in the absence of a regular representative on the Engineering and Operating Committee or to act on specified occasions or with respect to specified matters.  Each Party shall notify the other Parties promptly, in writing, of the designation of its representatives and alternate representative on the Engineering and Operating Committee and of any subsequent change in the designation. The chairperson of the Engineering and Operating Committee shall be a representative employed by the Operating Agent.
19.3    The Engineering and Operating Committee shall have the following functions and responsibilities:
19.3.1    Review and approve the following items related to the performance of Operating Work.
19.3.1.1    Capital Improvements and the annual Capital Improvements budget.
19.3.1.2    The annual staffing table.
                



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19.3.1.3    The annual operation and maintenance budget.
19.3.1.4    Such written statements of operating or maintenance procedures as may be submitted to the Engineering and Operating Committee.
19.3.1.5    The planned annual maintenance schedule.
19.3.1.6    The policies for establishing the Emergency Spare Parts inventory.
19.3.1.7    The policies for establishing the inventory for Materials and Supplies.
19.3.1.8    The statistical and administrative reports, budgets and information and other similar records, and the form thereof, to be kept and furnished by the Operating Agent, in accordance with Section 28.3.15 (excluding accounting records used internally by the Operating Agent for the purpose of accumulating financial and statistical data, such as books of original entry, ledgers, work papers and source documents).
19.3.1.9    The determination of Net Effective Generating Capacity, Minimum Net Generation and Net Energy Generation of the San Juan Project, based upon recommendations of the Operating Agent.
19.3.1.10    The principles and procedures for establishing communication channels among Parties.
                



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19.3.1.11    The operating procedures for performance and efficiency testing.
19.3.1.12    The operating procedures for maintaining complete and accurate Capacity and Energy accounting.  
19.3.1.13    The Operating Agent’s estimate and analysis of the total expenditures resulting from an Operating Emergency, as provided in Section 29.7.  
19.3.1.14    The results and expenditures of programs and contracts on environmental control and data collection for which the Operating Agent has contracted.  
19.3.2    Establish procedures for the operation of the San Juan Project during any period of curtailed operations which reduces or may reduce the Net Effective Generating Capacity.
19.3.3    Except for an Operating Emergency, as provided in Section 29, designate a construction agent responsible for the design, construction and acquisition of Capital Improvements.  
19.3.4    Approve the list of transportation and motorized equipment to be purchased or leased by the Operating Agent for use in the performance of Operating Work.
19.3.5    Perform such other functions and responsibilities as may be assigned to it from time to time by the Coordination Committee.  
        



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19.4  Any action or determination of the Engineering and Operating Committee shall require a vote of the Participants or Remaining Participants, in the manner provided for in Sections 18.4.1, 18.4.2 and 18.4.4. A Participant’s Engineering and Operating Committee voting representative shall be entitled to vote on all matters except those actions or determinations which relate solely to a Unit or to common property in which such Participant does not have a Participation Share or as provided in Section 35.4.1.  If a Participant’s or Remaining Participant’s right to vote has been suspended pursuant to Section 35.4.1, the requisite majorities for actions or determinations specified in Sections 18.4.1, 18.4.2 and 18.4.4 shall be adjusted in proportion to the number of Participants or Remaining Participants whose right to vote has not been suspended.  An example of such an adjustment is provided in Exhibit VIII.  Maintenance scheduling and operation during periods of curtailment of the total San Juan Project are not matters which relate solely to a Unit, but are deemed to be matters affecting all Units.
19.5    The Engineering and Operating Committee shall keep written minutes and records of all meetings.  Any action or determination made by the Engineering and Operating Committee shall be reduced to writing and shall become effective when signed by the representatives of the Participants or Remaining Participants entitled to vote thereon, representing a voting majority of the members of the Engineering and Operating Committee, as defined in Section 19.4; provided, however, in the event of an Operating Emergency, actions or determinations may be made on the basis of oral agreements among duly authorized representatives of the respective Participants entitled to vote thereon, and 



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such action or determination subsequently shall be reduced to writing.  Engineering and Operating Committee representatives may, by prior arrangement with the chairperson of the Engineering and Operating Committee, attend a meeting of the Engineering and Operating Committee by conference call or video conferencing. An Engineering and Operating Committee representative who is unable to attend a meeting of the Engineering and Operating Committee may vote in absentia by delivering to the chairperson of the Engineering and Operating Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.
19.6    In the event that less than a requisite majority of the Engineering and Operating Committee is obtained, the matter shall be referred to the Coordination Committee for decision upon the request of any Participant’s or Remaining Participant’s, as applicable, Engineering and Operating Committee representative.
19.7    In the event the Engineering and Operating Committee fails to reach agreement on any matter which such committee is authorized to determine, approve or otherwise act upon after a reasonable opportunity to do so, then the Operating Agent shall be authorized and obligated to take such reasonable and prudent action, consistent with Prudent Utility Practice, as is necessary to the successful and proper operation and maintenance of the San Juan Project, pending the resolution, by arbitration or otherwise, of any such inability or failure to agree.  



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20.0    FUELS COMMITTEE:
20.1    As a means of establishing a centralized forum to facilitate the timely and candid consideration and discussion between all Parties of policies and issues associated with the procurement of coal for the San Juan Project, there is hereby established a Fuels Committee, which shall remain in existence during the term of this Agreement. The Parties do not intend that the operation of the Fuels Committee shall affect the day-to-day fuels-related operational responsibilities of the Operating Agent, except as otherwise specifically provided in this Section 20. The Fuels Committee shall have no authority to modify any of the provisions of this Agreement. 
20.2    The Fuels Committee shall consist of one representative from each Party.  Any of the Parties may, by written notice to the other Parties, designate an alternate or substitute to act as its representative on the Fuels Committee in the absence of the regular representative on the Fuels Committee or to act on specified occasions or with respect to specified matters.  Each Party shall notify the other Parties promptly in writing of the designation of its representative on the Fuels Committee and of any subsequent change in such designation. The chairperson of the Fuels Committee shall be a representative employed by the Participant that is a signatory to the CSA.  The Fuels Committee shall meet regularly, but in no event less than semiannually.  Special meetings shall be called by the chairperson if requested in writing by any three (3) Parties. 
20.3     Subject to Section 20.7, the Fuels Committee shall have the following functions and responsibilities:
            



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20.3.1    To conduct studies, or cause studies to be conducted, regarding criteria pertaining to the acquisition of coal supplies and the negotiation and approval of coal agreements.  Such studies and recommendations may include, but are not limited to:  
20.3.1.1    Annual fuel supply budgets 
20.3.1.2    Coal cost
20.3.1.3    Coal delivery rates and minimum take obligations
20.3.1.4    Coal quality
20.3.1.5    Contract terms
20.3.1.6    Economic requirements
20.3.1.7    Negotiation strategies
20.3.1.8    Potential coal suppliers
provided, however, that prior to any such study being conducted, the Party(ies) desiring that the study be performed shall have made suitable arrangements therefor, including payment arrangements with the provider of the study.  Nothing in this Section 20.3 shall be construed to require the Operating Agent or any Party to undertake any uncompensated or unfunded study which it would not otherwise perform. 
20.3.2    To obtain input from all Parties regarding individual criteria and economic requirements necessary to vote on matters entrusted to the Fuels 



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Committee or to make collective recommendations to the Coordination Committee.
20.3.3    To receive progress reports from and provide recommendations to negotiators acting on behalf of Parties in the negotiation and administration of coal supply and related agreements.  
20.3.5    To provide regular progress reports to the Engineering and Operating and to the Coordination Committees, as requested by such committees.
20.3.6    To establish the amount of coal to be maintained in the Emergency Coal Storage Pile.  
20.3.7    To establish operating procedures for delivery of coal to the Emergency Coal Storage Pile.     
20.3.8 To establish procedures for the determination of Participant Coal Consumption.
20.3.9    To perform such other functions and responsibilities as are identified in Sections 23.4.2.8, and 23.4.2.10.
20.3.10 To perform such other functions and responsibilities as may be assigned to it from time to time by the Coordination Committee. 
20.4    The following special procedures shall apply to all negotiations or discussions with SJCC regarding amendment, interim pricing agreements, termination or succession of the CSA, related agreements, or with any other coal supplier or potential supplier.    No   Fuels   Committee   representative   or   Party   shall   engage   in   bilateral 



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negotiations or discussions concerning coal supply or related matters for the San Juan Project with SJCC or any other coal supplier or potential supplier; provided, however, that nothing herein shall be construed to prevent the Operating Agent or the Participant which is a signatory to the CSA, in the conduct of its day-to-day operational responsibilities, from performing Operating Work, engaging in business contacts and communications with SJCC or other coal suppliers or potential suppliers to the San Juan Project or in the administration of the CSA and related agreements.  
20.4.1    The Participant which is a signatory to the CSA shall be entitled to have at least two (2) representatives present at any such negotiations or discussions.  Remaining Participants not signatories to the CSA or its successors shall have the collective right to have two (2) representatives present at any such negotiations or discussions.  The Remaining Participants may jointly or separately designate representatives, but in no case may the total number of representatives so designated by all of the Remaining Participants exceed two (2).  Any dispute among the Remaining Participants regarding the naming of representatives shall be subject to resolution pursuant to Section 37 and shall not restrict the rights of any other representatives to engage in any ongoing negotiations or discussions.  Representatives shall be designated in writing by the Participant which is a signatory to the CSA and Remaining Participants.  If such representatives are not employees of a Remaining Participant, such fact shall be disclosed in writing to all Parties.  Representatives shall agree in writing to: (i) avoid any conflict of 



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interest that would be detrimental to the operation of the San Juan Project; and (ii) maintain all proprietary information obtained through such negotiations and discussions in confidence.  The form of such confidentiality agreements shall be prepared by the Fuels Committee, and shall be subject to the approval of the Participant that is a signatory to the CSA, such approval not to be unreasonably withheld.  Such confidentiality agreements shall be executed by a Remaining Participant’s Coordination Committee representative or, as appropriate, the person authorized by such Remaining Participant or Representative to execute such documents.  Representatives may be changed by  Remaining Participants by the giving of written notice to all other Parties.   
20.4.2    Representatives shall make regular reports to, coordinate with, and obtain the recommendations of the Fuels Committee regarding the progress of and issues involved in such coal negotiations or discussions.  
20.5    Any proposed action or determination regarding any amendment of the CSA, replacement of the CSA with a new agreement or any interim or other annual coal pricing agreement related to the CSA (or its successor) or any other action or determination of the Fuels Committee shall be submitted to the vote of the representatives of the Remaining Participants on the Fuels Committee.  Any such action or determination shall require the affirmative vote as  established  in  Section  18.4.3,  in  conjunction  with  Section  7.13.1.3,  except  that  if  a  Remaining  Participant’s  right  to  vote  has  been  suspended pursuant to Section 35.4.1,  the requisite majority for actions or determinations 



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specified in Section 18.4.3 shall be adjusted in proportion to the number of Remaining Participants whose right to vote has not been suspended.  An example of such an adjustment is provided in Exhibit VIII.
20.5.1    If, upon such vote, the requisite votes are obtained, the Participant which is a signatory to the CSA then in effect or the Operating Agent, as applicable, shall proceed in accordance with the affirmative vote of the Fuels Committee without further action of any other San Juan Project committee. 
20.5.2    If, upon such vote, the requisite votes are not obtained, the matter giving rise to the vote shall, not later than thirty (30) days after the negative vote of the Fuels Committee, be submitted to the Coordination Committee for its vote in accordance with Section 18.4.3. If the requisite majorities are obtained in the Coordination Committee vote, the Participant which is a signatory to the CSA then in effect or the Operating Agent, as applicable, shall proceed in accordance with the affirmative vote of the Coordination Committee. 
20.5.3    If the requisite votes are not obtained in the Coordination Committee vote, then consistent with Section 18.7, the Participant which is a signatory to the CSA then in effect or the Operating Agent, as applicable, shall have the obligation and the responsibility, consistent with Prudent Utility Practice, to maintain a supply of coal to the San Juan Project. 
20.6    The Fuels Committee shall keep written minutes and records of all meetings.  Any action or determination made by the Fuels Committee shall be reduced to 



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writing and shall become effective when signed by the representatives of the Parties representing a voting majority.  Fuels Committee representatives may, by prior arrangement with the chairperson of the Fuels Committee, attend a meeting of the Fuels Committee by conference call or video.  A Fuels Committee representative who is unable to attend a meeting of the Fuels Committee may vote in absentia by delivering to the chairperson of the Fuels Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile, identifying the matter to be voted on and how the representative desires to vote.
20.7    Nothing in this Section 20 is intended to affect the responsibilities of the Reclamation Oversight Committee or the Reclamation Trust Funds Operating Agent as set out in the Mine Reclamation Agreement; in particular, the Fuels Committee shall have no authority to vote as to matters related to amendments to provisions of the RSA or a new agreement for the performance of reclamation services for disturbance of the SJCC Site Area.  To the extent of any conflict between this Section 20 and the Mine Reclamation Agreement, the provisions of the Mine Reclamation Agreement shall control.  
        



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21.0    AUDITING COMMITTEE:  
21.1    The Auditing Committee shall remain in existence during the term of this Agreement.  The Auditing Committee shall have no authority to modify any of the provisions of this Agreement.
21.2      The Auditing Committee shall consist of one representative from each Party.  Any of the Parties may designate an alternate or substitute to act as its representative on the Auditing Committee in the absence of the regular representative on the Auditing Committee or to act on specified occasions or with respect to specified matters.  Each Party shall notify the other Parties promptly, in writing, of the designation of its representative and alternate representative on the Auditing Committee and of any subsequent changes in such designation.
21.3    The Auditing Committee shall have the following functions and responsibilities under this Agreement:
21.3.1    Review accounting, financial and internal control aspects of Operating Work and Capital Improvements, and implementation of procedures established pursuant to Section 20.3.8, and, not less than every two years, audit the records maintained by the Operating Agent in its performance of Operating Work, Capital Improvements and any other records maintained by the Operating Agent in support of its billings to the Parties.  
21.3.2    Review and approve the format and content of the Operating Agent’s accounting records and reports for Operating Work and Capital Improvements.  
            



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21.3.3    Certify to the Parties, for management purposes and for the use of the Parties only, that the Operating Agent’s results of operations and accounting methods and records, including any allocations for Operating Work and Capital Improvements, are in accordance with the Project Agreements and Accounting Practice.  
21.3.4    Review and make recommendations to the Coordination Committee regarding a Party’s administrative and general expense allowance and other normal loadings when such Party acts as construction agent for Capital Improvements.  
21.3.5    Review and approve the Operating Agent’s cost and expense allocations between (i) electric generation and related functions and (ii) unrelated functions.  
21.3.6    Advise and make recommendations to the Coordination Committee and Operating Agent on matters involving auditing and financial transactions.  
21.3.7    Develop procedures for proper accounting and financial liaison between Parties in connection with the Operating Work and Capital Improvements.
21.3.8    Perform such functions and responsibilities as may be assigned to it from time to time by the Coordination Committee or as otherwise provided in this Agreement.  
21.4      Any action or determination of the Auditing Committee shall require a vote of the voting Participants in accordance with Section 18.4.1.  A Participant’s Auditing Committee representative shall be entitled to vote on all matters except those actions or 



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determinations which relate solely to a Unit or common property in which such Participant does not have a Participation Share except that if a Participant’s right to vote has been suspended pursuant to Section 35.4.1, the requisite majority for actions or determinations specified in Section 18.4.1 shall be adjusted in proportion to the number of Participants whose right to vote has not been suspended.  An example of such an adjustment is provided in Exhibit VIII.
21.5    The Auditing Committee shall keep written minutes and records of all meetings, and any action or determination by the Auditing Committee shall be reduced to writing and shall become effective when signed by the representatives of the Parties entitled to vote thereon, representing a voting majority of the members of the Auditing Committee. Auditing Committee representatives may, by prior arrangement with the chairperson of the Auditing Committee, attend a meeting of the Auditing Committee by conference call or video conferencing. An Audit Committee representative who is unable to attend a meeting of the Audit Committee may vote in absentia by delivering to the chairperson of the Audit Committee, at least twenty-four (24) hours prior to the scheduled commencement of the meeting, a written statement, including by e-mail or facsimile,   identifying the matter to be voted on and how the representative desires to vote.
21.6    In the event less than a requisite majority of the Auditing Committee is obtained, the matter shall be referred to the Coordination Committee for decision upon the request of any Party’s Auditing Committee representative.
        



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21.7    In the event the Auditing Committee fails to reach agreement on a matter which such committee is authorized to determine, approve or otherwise act upon after a reasonable opportunity to do so, then the Operating Agent shall be authorized and obligated to take such reasonable and prudent action, consistent with Prudent Utility Practice, as is necessary to the successful and proper operation and maintenance of the San Juan Project, pending the resolution, by arbitration or otherwise, of any such inability or failure to agree. 
21.8    To the extent practicable, any audit of A&G expenses will be coordinated with audits of A&G expenses under any other San Juan Project-related agreements, including audits of Reclamation A&G Expenses.



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PART V
BUDGETS AND OPERATING EXPENSES
22.0    OPERATION AND MAINTENANCE EXPENSES:  
22.1    The expenses for the operation and maintenance of the San Juan Project in the performance of Operating Work (which, for purposes of this Section 22, and as defined more particularly herein, are referred to as the “O&M Expenses”) shall be apportioned among the Parties, in accordance with the following percentages:  
22.1.1    For Units 1 and 2 and for all equipment and facilities directly related to Units 1 and 2 only, in accordance with the following percentages:  


22.1.1.1    PNM - 50 percent 
22.1.1.2    TEP - 50 percent
22.1.1.3    M‐S‐R - 0 percent
22.1.1.4    Farmington - 0 percent
22.1.1.5    Tri-State - 0 percent
22.1.1.6    LAC - 0 percent
22.1.1.7    SCPPA - 0 percent
22.1.1.8    Anaheim - 0 percent
22.1.1.9    UAMPS - 0 percent
22.1.1.10    PNMR-D – 0 percent    
22.1.2    For Unit 3 and all equipment and facilities directly related to Unit 3 only, in accordance with the following percentages:  


22.1.2.1    PNM - 50 percent
22.1.2.2    TEP - 0 percent
22.1.2.3    M‐S‐R - 0 percent
22.1.2.4    Farmington - 0 percent
22.1.2.5    Tri-State - 8.2 percent
22.1.2.6    LAC - 0 percent
22.1.2.7    SCPPA - 41.8 percent
22.1.2.8    Anaheim - 0 percent  
22.1.2.9    UAMPS - 0 percent
                



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22.1.2.10    PNMR-D – 0 percent


22.1.3    For Unit 4 and for all equipment and facilities directly related to Unit 4 only, in accordance with the following percentages: 


22.1.3.1    PNM - 38.457 percent
22.1.3.2    TEP - 0 percent
22.1.3.3    M‐S‐R - 28.8 percent
22.1.3.4    Farmington - 8.475 percent
22.1.3.5    Tri-State - 0 percent
22.1.3.6    LAC - 7.20 percent
22.1.3.7    SCPPA - 0 percent
22.1.3.8    Anaheim - 10.04 percent  
22.1.3.9    UAMPS - 7.028 percent
22.1.3.10    PNMR-D – 0 percent


22.1.4    For equipment and facilities common to Units 1 and 2 only, in accordance with the following percentages:  


22.1.4.1    PNM - 50 percent
22.1.4.2    TEP - 50 percent
22.1.4.3    M-S-R - 0 percent
22.1.4.4    Farmington - 0 percent
22.1.4.5    Tri-State - 0 percent
22.1.4.6    LAC - 0 percent
22.1.4.7    SCPPA - 0 percent
22.1.4.8    Anaheim - 0 percent  
22.1.4.9    UAMPS - 0 percent
22.1.4.10    PNMR-D – 0 percent
22.1.5    For equipment and facilities common to Units 3 and 4 only, in accordance with the following percentages:  


22.1.5.1    PNM - 44.119 percent
22.1.5.2    TEP - 0 percent
22.1.5.3    M‐S‐R - 14.4 percent
22.1.5.4    Farmington - 4.249 percent
22.1.5.5    Tri-State - 4.1 percent
22.1.5.6    LAC - 3.612 percent
                



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22.1.5.7    SCPPA - 20.9 percent
22.1.5.8    Anaheim - 5.07 percent  
22.1.5.9    UAMPS - 3.55 percent
22.1.5.10    PNMR-D – 0 percent
22.1.6    For the Switchyard Facilities except as otherwise provided in Section 15, in accordance with the following percentages:  
 
22.1.6.1    PNM - 65 percent
22.1.6.2    TEP - 35 percent
22.1.6.3    M‐S‐R - 0 percent
22.1.6.4    Farmington - 0 percent
22.1.6.5    Tri-State - 0 percent
22.1.6.6    LAC - 0 percent
22.1.6.7    SCPPA - 0 percent
22.1.6.8    Anaheim - 0 percent  
22.1.6.9    UAMPS - 0 percent
22.1.6.10    PNMR-D – 0 percent
22.1.7    Except as provided in Exhibit V(g), attached hereto and incorporated herein, for equipment and facilities common to all of the Units, and all San Juan Project expenses not identifiable by Unit and not otherwise listed above, in accordance with the following percentages:
    
22.1.7.1    PNM - 46.297 percent
22.1.7.2    TEP - 19.8 percent
22.1.7.3    M‐S‐R - 8.7 percent
22.1.7.4    Farmington - 2.559 percent
22.1.7.5    Tri-State - 2.49 percent
22.1.7.6    LAC - 2.175 percent
22.1.7.7    SCPPA - 12.71 percent
22.1.7.8    Anaheim - 3.10 percent  
22.1.7.9    UAMPS - 2.169 percent
22.1.7.10    PNMR-D – 0 percent
22.1.8    In the event of a permanent shutdown of either of Unit 1 or Unit 2 prior to the Exit Date, the expenses incurred in connection with the shutdown 



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(which may include removal, salvage, cleanup and protection service) shall be allocated as set forth in Section 22.1.1.  In the event of a permanent shutdown of Unit 3 prior to the Exit Date, said expenses shall be allocated as set forth in Section 22.1.2.  In the event of a permanent shutdown of Unit 4 prior to the Exit Date, said expenses shall be allocated as set forth in Section 22.1.3.  Expenses which are attributable to equipment and facilities common to more than one Unit shall be apportioned in accordance with Section 22.1, as applicable.  Expenses incurred under this Section 22.1.8 shall be minimized insofar as reasonably practicable, and any expenses paid by a Participant under this Section 22.1.8 that would otherwise qualify as costs of initial or interim Decommissioning Work under Sections 4.1 and 4.2 of the Decommissioning Agreement shall be credited against the Participants’ cost responsibilities under the Decommissioning Agreement.
22.1.9    Exhibit V, attached hereto and incorporated herein, is a partial list of equipment and facilities of the San Juan Project for use by the Engineering and Operating Committee as a guideline in determining the allocation of operation and maintenance costs among the Participants.
22.1.10  In areas where the allocation of costs of operation and maintenance of equipment and facilities among the Participants is not clearly defined by Sections 22.1.1 to 22.1.8, the Engineering and Operating Committee shall make a determination of such allocation of costs.
    



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22.1.11  The following shall apply in the event of a declaration of default against a Participant and a suspension of that Participant’s right to receive all or any part of its proportionate share of the Net Effective Generating Capacity, as provided for in Section 35.4.1: those non-defaulting Participant(s) having a Participation Share in each affected Unit, who are entitled to schedule and receive for their accounts  proportionate shares of the Net Effective Generating Capacity of the defaulting Participant, shall bear proportionate shares of the defaulting Participant’s responsibility for expenses of the operation and maintenance of the San Juan Project, as provided in Section 35.5.
22.2    O&M Expenses chargeable to the following FERC Accounts shall be apportioned among the Participants in accordance with Sections 22.1.1, 22.1.2, 22.1.3, 22.1.4, 22.1.5 and 22.1.7, as applicable:
22.2.1    Power Production/Steam Power Generation:    FERC Accounts 500, 502, 505, 506, 507, 509 and 510 through 514 (charged by on-site San Juan Project employees and operations-related departments located off-site); provided, however, that limestone costs (chemicals) chargeable to FERC Account 502 shall be apportioned among the Participants in accordance with Section 23.5.
22.2.2    Administrative and General Expenses directly chargeable to FERC Accounts 920, 921, 923, 926, 930.2, 931 and 935, by on-site San Juan Project employees and by A&G related departments located off-site as set forth in Exhibit VI, Attachment A,  which have not been included as a part of the A&G Ratio or charged to FERC Account 935, 



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in accordance with Section 22.4. Such direct A&G charges must be supported by the Operating Agent and are subject to audit and approval by the Auditing Committee.  If the Auditing Committee is unable to agree on the appropriateness of direct A&G charges, the Auditing Committee shall submit the entire matter to the Coordination Committee.
22.2.3    O&M Expenses chargeable to FERC Account 501 shall be apportioned among the Participants in accordance with Section 23.
22.2.4    The cost of the property insurance for the San Juan Project chargeable to FERC Account 924 and any uninsured loss or expense thereunder and the cost of general liability or workers’ compensation insurance for the San Juan Project chargeable to FERC Account 925 shall be apportioned among the Participants according to Section 22.1.
22.2.5 Costs or revenues chargeable to the following FERC Operating and Non-Operating Accounts: 411.8, 411.9, 412, 421 and 426.
22.3    Power Production Expense chargeable to FERC Account 500 (for employees of PNM’s fuels management department), Non San Juan Project Specific, shall be allocated among all of PNM’s fossil-fueled power plants, including the San Juan Project, based on the percentage of labor charged to each fossil-fueled power plant as a percentage of labor charged to all of PNM’s fossil-fueled power plants.
22.4    The O&M Expenses for the Switchyard Facilities chargeable to FERC Accounts 560 through 573 and FERC Account 935 shall be apportioned among the Participants in accordance with Section 22.1.6.
        



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22.5    The O&M Expenses for the portion of system control and load dispatching expenses (allocated between PNM and the San Juan Project based on the number of megawatts of San Juan Project capacity as a percentage of PNM’s total generating capacity) chargeable to FERC Accounts 556, 560 and 561 shall be apportioned among the Participants in accordance with Section 22.1.7.
22.6    Payroll loads for administrative and general expenses, payroll taxes, injuries and damages and pension and benefits, shall be added to the monthly billings in proportion to the dollars of direct labor billed and apportioned among the Participants in accordance with Sections 22 and 23.  The current methodologies for calculating the A&G Ratio, Payroll Tax Ratio, Injuries and Damages Ratio and Pension and Benefits Ratio are set forth in Exhibit VI (Attachments A, B, C and D thereto), attached hereto and incorporated herein. 
22.6.1    If any Participant believes that the method used in determining A&G Ratio, Payroll Tax Ratio, Injuries and Damages Ratio and Pension and Benefits Ratio, in accordance with Exhibit VI (Attachments A, B, C and D thereto), results in an unreasonable burden on such Participant(s), such Participant(s) may request that said method used in determining said ratios be submitted to the Auditing Committee for review.  After any such request, the Auditing Committee shall review said method and shall endeavor to agree upon whether or not said unreasonable burden does actually exist.  If, after such review, the Auditing Committee determines that the application of said method does result in an unreasonable burden on the Participant,  the  Auditing  Committee  shall  determine  and  recommend  a  modified 



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method to the Coordination Committee to eliminate such unreasonable burden. If, after such review, the Auditing Committee is unable to agree upon whether or not such unreasonable burden does exist or is unable to agree on a modified method for eliminating said unreasonable burden, the Auditing Committee shall submit the entire matter to the Coordination Committee.  
22.6.2    The Coordination Committee shall review the recommendation of the Auditing Committee pursuant to Section 22.6.1.  If, as a result of such review, the Coordination Committee agrees that such unreasonable burden does exist and that a modified method eliminates such unreasonable burden, the Coordination Committee shall adopt said modified method.  
22.6.3    If the Auditing Committee has not submitted a recommended modified method and the Coordination Committee agrees that such unreasonable burden does exist, the Coordination Committee shall endeavor to agree on a modified method.  If, after such review, the Coordination Committee is unable to agree that such unreasonable burden does exist or on a modified method which will eliminate such unreasonable burden, upon request of a Participant, either matter may be submitted to arbitration pursuant to Section 37.
22.6.4    Any modified method adopted by the Coordination Committee or determined through arbitration shall be retroactive for the length of the period of inequity up to a maximum period of three (3) years and shall become effective on the first day following such date of adoption.  
        



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22.7    As soon as possible after the end of each calendar year, the Operating Agent shall calculate the actual ratios for: A&G, payroll tax, injuries and damages, and pension and benefits for such year in accordance with the methodologies described in Exhibit VI (Attachments A, B, C and D thereto). To the extent such expenses are more or less than those already paid by the Participants during said year, the Operating Agent shall bill or credit the Participants for the amount of such difference.  
22.8    At the start of each calendar year, the Operating Agent shall calculate new ratios for: A&G, payroll tax, injuries and damages and pension and benefits.  Such ratios shall be calculated in accordance with the methodologies described in Exhibit VI (Attachments A, B, C and D thereto).  Such ratios may be adjusted to more nearly reflect the anticipated expenses of the current year because of tax legislation, labor contract negotiations or other factors not reflected in the prior year’s costs.  
22.9    The Operating Agent shall bill to the requesting Party(ies) the costs and expenses, including A&G expenses, incurred by the Operating Agent (including, but not limited to, fees of outside legal counsel or consultants, time of in-house legal counsel and other employees and agents of the Operating Agent) in performing tasks requested by a Party in relation to (i) the offering or sale of bonds or other type of security by a Party in connection with the acquisition or ownership of an interest in the San Juan Project; and (ii) the attempted or contemplated sale by a Party of any portion of its ownership interest in the San Juan Project.  The Operating Agent shall establish and maintain appropriate accounting procedures to identify such costs and expenses incurred by the Operating Agent. 



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23.0    FUEL COSTS: 
23.0(a)     For (i) allocation of payment obligations for coal supply, reclamation and CCR disposal under the UG-CSA, the CCBDA, the UG-CSA Termination Agreement and the CCBDA Termination Agreement; and (ii) allocation of any fuel-related payments (other than for coal) accrued through December 31, 2017 and chargeable to FERC Account 501, including limestone, fuel oil, CCR disposal, fuel handling or start-up or auxiliary power and energy, Sections 23.1 through 23.13 shall apply.  
23.0(b)     For payment obligations arising under the CSA and the CCRDA, Sections 23.14 through 23.18 shall apply. 
23.0(c)     All costs and expenses incurred by the Reclamation Trust Funds Operating Agent under the Mine Reclamation Agreement before December 31, 2017 shall be billed to the Participants as Operating Work of the Operating Agent. 
23.1    The quantity of coal delivered to the San Juan Project shall be determined by the belt scales, in accordance with the CSA.
23.2    The Operating Agent shall maintain the Project Coal Inventory wherein ownership shall be apportioned among the Participants in the percentages shown in Section 6.3.  Coal inventory shall be accounted for in FERC Account 151. 
23.3    All Participants acknowledge and recognize the terms and conditions of the Underground Coal Sales Agreement which was entered into by PNM and TEP on behalf of the Participants. Exhibit VII, attached hereto and incorporated herein, contains example 



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“Interim Invoices”, “UG-CSA Invoices”, and “UPS Invoices” prepared and defined pursuant to Section 8 of the Underground Coal Sales Agreement. 
23.4    Monthly costs of the Project Coal Inventory and fuel expense shall be apportioned among and paid for by the Participants on the following basis:        
23.4.1    UG-CSA Invoicing Allocations
In the event that UG-CSA Invoices are rendered and payable pursuant to Section 8.7 (A) of the Underground Coal Sales Agreement, amounts due thereunder shall be allocated and paid for by the Participants as Fixed Fuel Expense and Variable Fuel Expense as described in: Exhibit IX, Fixed Fuel Expense; and Exhibit X, Variable Fuel Expense and as provided below:  
23.4.1.1    Costs that are classified as Fixed Fuel Expense shall be charged to FERC Account 501, or to such FERC Account number as may be applicable in the future if fuel deliveries terminate, and shall be apportioned among and paid for by the Participants in accordance with Common Participation Share. 
23.4.1.2    Costs that are classified as Variable Fuel Expense shall be charged to FERC Account 151 and such costs shall be apportioned among and paid for by the Participants on the basis of Common Participation Share.  Monthly cost for coal withdrawn from Project Coal Inventory (equivalent to total monthly Participant Coal Consumption) shall be credited  to  FERC  Account  151 and charged to FERC Account 501 on an 



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average price basis as determined by dividing the total number of tons of coal in Project Coal Inventory at the beginning of the month, plus the coal delivered during the month, into the total recorded cost in FERC Account 151 and multiplying the cost per ton so derived by the number of tons withdrawn.  The cost for coal withdrawn charged to FERC Account 501 shall be apportioned among and paid for by the Participants on the basis of the percentage that each Participant’s monthly Participant Coal Consumption bears to the total monthly Participant Coal Consumption of all Units. The cost for coal withdrawn thusly credited to FERC Account 151 shall be apportioned among the Participants on the basis of Common Participation Share.
23.4.1.3    Any other Total Monthly Coal Cost not currently classified in Exhibits IX or X as Fixed Fuel Expense or Variable Fuel Expense shall be deemed to be Fixed Expense until reclassified by the Coordination Committee.
23.4.2        Interim Invoicing Allocations
 In the event that Interim Invoices are rendered and payable pursuant to Section 8.7 (B) of the Underground Coal Sales Agreement, such costs shall be allocated and invoiced to the Participants as described below. 
23.4.2.1    The Base Price (“Base Price”) band shall be based on the Minimum Annual Tons.  The annual allocation of the coal tonnage 



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in the Base Price band shall be made among the Participants on the basis of Common Participation Share.  The monthly allocation of the coal tonnage in the Base Price band shall be made among the Participants on the basis of each Participant’s share of Monthly Minimum Tons.  The cost of the monthly Base Price band will be allocated among and paid for by the Participants by multiplying each Participant’s share of Monthly Minimum Tons by the Base Price. 
23.4.2.2    The Incremental Price (“Incremental Price”) band(s) shall be based on (an) annualized band(s) of tons of coal delivered in excess of Minimum Annual Tons.   The cost of the monthly Incremental Price band(s) will be allocated among and paid for by the Participants by multiplying each Participant’s consumption of Incremental Price band coal(s) by the Incremental Price for such band(s). Participants shall only be eligible for allocation of Incremental Price band coal pricing if their monthly Participant Coal Consumption exceeds their share of Monthly Minimum Tons.
23.4.2.3    At the end of each year, the Operating Agent shall reconcile the sum of each Participant’s monthly Interim Invoice-related payments  to  a  properly  allocable  share  of  Base  Price  band  tons,  Incremental  Price  band  or  bands tons, and cost associated with any change in  Project  Coal  Inventory  and  invoice  or  refund  any  such  reconciliation 



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amounts to each Participant. This reconciliation will be exclusive of any year-end true up required pursuant to Section 23.4.2.6.  
23.4.2.4    In the year-end reconciliation process of Section 23.4.2.3, any amount credited by SJCC for tons invoiced but not delivered shall be credited to FERC Account 501 and apportioned to the Participants on the basis of the percentage that each Participant’s annual Incremental Price Band(s) consumption bears to the total annual Incremental Price Band(s) consumption for all Units. Any net consumption of Project Coal Inventory tons shall be charged to FERC Account 501 and apportioned among and paid for by the Participants on the basis of the percentage that each Participant’s annual Incremental Price Band(s) consumption bears to the total annual Incremental Price Band(s) consumption for all Units. The price for such tons shall be determined by dividing the total recorded cost in FERC Account 151 by the total number of tons of coal in Project Coal Inventory, both as recorded on January 1 of said year. The total amount of any such payment for consumed Project Coal Inventory tons shall subsequently be credited to FERC Account 151 and apportioned to the Participants based on Common Participation Share.
In the year-end reconciliation process of Section 23.4.2.3, the costs of any net addition to Project Coal Inventory tons, as invoiced by SJCC, shall be 



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charged to FERC Account 151 and apportioned to and paid for by the Participants based on Common Participation Share.
23.4.2.5    If, at the end of any year, the Operating Agent has collected amounts in excess of those due S JCC pursuant to Section 8.7(B) of the Underground Coal Sales Agreement, but not including any year-end true up required pursuant to Section 23.4.2.6, such over-collection shall be refunded to the Participants. The refund to each Participant shall be an amount equal to the total amount of the over-collection multiplied by the tons each Participant’s Coal Consumption was less than its total annual Monthly Minimum Tons divided by the total amount by which all such Participants’ Coal Consumption was less than their shares of Minimum Annual Tons.
23.4.2.6    The Interim Invoices shall be annually reconciled to invoices prepared pursuant to Section 8.7(A) of the Underground Coal Sales Agreement.  Any adjustment required by this reconciliation, in accordance with Section 8.7(B) of the Underground Coal Sales Agreement, will be passed through to the Participants as correcting invoices and will be apportioned among and paid for by, or credited to, the Participants on the basis of Common Participation Share. 
        



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23.4.2.7    Monthly UPS payments shall be apportioned among and paid for by the Participants on the basis of Common Participation Share 
23.4.2.8    Any other component of Total Monthly Coal Cost which is not classified as Base Price or Incremental Price shall be apportioned among and paid for by the Participants on the basis of Common Participation Share unless otherwise annually approved by the Fuels Committee. 
23.4.2.9    If during any year, payable Interim Invoices cease to be rendered by SJCC pursuant to Section 8.7(B) of the Underground Coal Sales Agreement, the Participants acknowledge and recognize that Interim Invoicing cannot be in effect for a partial year, and that all allocations of Total Monthly Coal Costs for the year shall then be made pursuant to Section 23.4.1. Amounts previously allocated to the Participants pursuant to Section 23.4.2 in the affected year shall be reallocated pursuant to the provisions of Section 23.4.1.
23.4.2.10    The Fuels Committee may terminate allocation of costs to the Participants pursuant to Section 23.4.2 despite the continued receipt of payable Interim Invoices from SJCC, if the Fuels Committee determines that coal cost allocation pursuant to Section 23.4.1 better serves the interests of the San Juan Project. Such termination may only be made 



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upon action of the Fuels Committee pursuant to Section 20.5. In the event of such termination, costs shall continue to be apportioned to and paid for by the Participants pursuant to Section 23.4.2. However, for information purposes, the Operating Agent shall also provide cost allocations to the Participants pursuant to Section 23.4.1. At the end of such year, the amounts paid by the Participants shall be reconciled to those amounts allocated pursuant to Section 23.4.1 for each month of the affected year (Section 23.4.1 allocations being determinative) and the Operating Agent shall invoice or refund any such reconciliation amounts to each Participant. 
23.5    Limestone costs (chemicals) chargeable to FERC Account 502 shall be apportioned among and paid for by the Participants on the basis of the percentage that each Participant’s monthly Participant Coal Consumption bears to the total monthly Participant Coal Consumption of all Units.
23.6    All other fuel-related expenses which are chargeable to FERC Account 501 shall be apportioned among and paid for by the Participants on the following basis:
23.6.1    Variable fuel-related expenses (including, but not limited to ash and gypsum disposal) on the basis of the percentage that each Participant’s monthly Participant Coal Consumption bears to the total monthly Participant Coal Consumption of all Units.
23.6.2    Fixed fuel-related expenses (including, but not limited to fuel handling) on the basis of Common Participation Share.
 



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23.6.3    Fuel oil purchased for use at the San Juan Project is first delivered into one of two storage tanks.  Tank 1 and 2 storage tank feeds Units 1 and 2 and Tank 3 and 4 storage tank feeds Units 3 and 4.  When oil is withdrawn from a storage tank for consumption, it is metered by Unit.  Costs for fuel oil usage shall be separately accounted for by these two storage tanks as follows:  
23.6.3.1    Costs for fuel oil purchases to Tank 1 and 2 shall be charged to FERC Account 151 and such costs shall be apportioned among and paid for by the Units 1 and 2 Participants on the basis of Section 6.2.4.  Monthly cost for fuel oil withdrawn from Tank 1 and 2 shall be credited to FERC Account 151 and charged to FERC Account 501 on an average price basis as determined by dividing the total number of gallons of fuel oil in Tank 1 and 2 at the beginning of the month, plus the fuel oil delivered during the month, into the total recorded cost in FERC Account 151 and multiplying the cost per gallon so derived by the number of gallons withdrawn from Tank 1 and 2. The cost for fuel oil withdrawn from Tank 1 and 2 charged to FERC Account 501 shall be apportioned among and paid for by the Units 1 and 2 Participants first on the basis of the individual Unit metered consumption and then on the basis of Section 6.2.1. The cost for fuel oil withdrawn from Tank 1 and 2 thusly credited to FERC Account 151 shall be apportioned among the Units 1 and 2 Participants on the basis of Section 6.2.4.  



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23.6.3.2    Costs for fuel oil purchases to Tank 3 and 4 shall be charged to FERC Account 151 and such costs shall be apportioned among and paid for by the Units 3 and 4 Participants on the basis of Section 6.2.5.  Monthly cost for fuel oil withdrawn from Tank 3 and 4 shall be credited to FERC Account 151 and charged to FERC Account 501 on an average price basis as determined by dividing the total number of gallons of fuel oil in Tank 3 and 4 at the beginning of the month, plus the fuel oil delivered during the month, into the total recorded cost in FERC Account 151 and multiplying the cost per gallon so derived by the number of gallons withdrawn from Tank 3 and 4.  The cost for fuel oil withdrawn from Tank 3 and 4 charged to FERC Account 501 shall be apportioned among and paid for by the Units 3 and 4 Participants first on the basis of the individual Unit metered consumption and then on the basis of Section 6.2.2 or Section 6.2.3, as applicable. The cost for fuel oil withdrawn from Tank 3 and 4 thusly credited to FERC Account 151 shall be apportioned among the Units 3 and 4 Participants on the basis of Section 6.2.5.
23.7    The Operating Agent shall provide the Participants a monthly written report on the following items related to coal deliveries at the San Juan Project:
23.7.1     Minimum Annual Tons for the year.
23.7.2     Minimum Annual Tons allocated among the Participants.
            



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23.7.3    Total actual coal deliveries by SJCC to the San Juan Project for each month and for the year to date.
23.7.4    Total actual coal deliveries to the San Juan Project for each month and for the year to date, allocated to the Participants.
23.7.5    Total cost and tonnage of inventory allocated to the Participants.  
23.7.6    Fixed Fuel Expense and Variable Fuel Expense totals as allocated to each Participant for each month and for the year to date if UG-CSA Invoicing is, or will be, required for said year pursuant to Section 23.4.1.
23.8    The Operating Agent shall work diligently with SJCC under the terms of the CSA to manage Project Coal Inventory so as to maintain the Emergency Coal Storage Pile at target levels pursuant to Section 20.3.6 and to maintain appropriate working levels of Project Coal Inventory to facilitate San Juan Project Operations.  
23.9    In the event that SJCC defaults in its obligations under the CSAor otherwise fails to maintain deliveries of coal, the Operating Agent may assume or make such arrangements for the assumption of such of SJCC’s operations as permitted by the CSA or may procure, subject to the CSA, an alternate coal supply.  Costs associated with such assumed coal operations or the procurement and supply of alternate coal shall be deemed a part of Total Monthly Coal Cost and, with the costs and expenses of fuel and emission residuals (gypsum) and ash disposal, shall be apportioned between and paid for by the Participants in accordance with: (i) Section 23.4.1 with regard to coal costs; and (ii) Section 23.6.1 with regard to fuel-related costs.
        



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23.10    The monthly costs of fuel allocated among the Participants in accordance with this Section 23 shall be estimated by the Operating Agent as soon as practicable after the end of each month and a preliminary bill shall be presented and paid in the manner set forth in Section 30.3.3.  Adjustments and corrections to the estimated preliminary bill shall be made in the next succeeding month or on the earliest possible billing thereafter.
23.11    In the event of a catastrophic occurrence which results in a sustained outage of a Unit and a determination that an “Uncontrollable Force” exists under the CSA, then in such event, FERC Account 151 will be allocated to the operable and non-operable Units.  The portion of FERC Account 151 allocated to the non-operable Unit(s) shall remain frozen until such time as such Unit(s) is restored to operable condition.  New costs of coal chargeable to FERC Account 151 will be apportioned among the Participants on the basis of the Participants’ Participation Shares in the generating capacity of the operable Units.  At such time as a damaged Unit is restored to operable condition, the frozen portion of Account 151 will be merged into the operable unit(s) portion of Account 151 and to the extent that a Participant is adversely impacted by an incremental increase in the average unit cost of coal an allocation of such incremental cost will be made and the net difference paid by the Participant having a credit balance.
23.12    The accounting practices and billing and accounting principles as stated in this Section 23 are applicable at the present time.  If, however, at a later time these practices or principles are proven to be inadequate or other practices or principles later prove to be more equitable in the opinion of the Auditing Committee, the Coordination Committee, 



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upon the recommendation of the Auditing Committee, may authorize changes and revisions to such practices and principles. 
23.13    Any other fuel-related costs not currently classified in this Section 23 shall be apportioned among and paid for by the Participants on the basis of the percentage that each Participant’s monthly Participant Coal Consumption bears to the total monthly Participant Coal Consumption of all Units until classified by the Coordination Committee.         23.14 Notwithstanding the provisions of Sections 23.1 through 23.13, beginning on January 1, 2016, PNM will supply coal to (i) the Exiting Participants under the provisions of Sections 23.15 through 23.17; and (ii) the Remaining Participants under the provisions of Section 23.18.  PNM will have all cost obligations under the CSA for coal supplied to the Exiting Participants and PNM will have all rights to the Exiting Participants’ inventory relinquished to PNM under Section 23.15.
23.15    The Exiting Participants will relinquish to PNM their Common Participation Shares of Shared Coal Inventory that exist as of January 1, 2016, at the following values: $16.88/ton for coal tons stockpiled on SJCC’s property and $22.69/ton for coal tons stockpiled on the SJGS plant site.  The total sum paid by PNM for Common Participation Shares of Shared Coal Inventory will be allocated as follows:
23.15.1    M-S-R            32.22%
23.15.2    Anaheim         11.48%
23.15.3    SCPPA            47.08%
23.15.4    Tri-State          9.22%


23.16  From January 1, 2016 through the Exit Date, the Exiting Participants will receive coal monthly to meet their Participant Coal Consumption from PNM at a cost of 



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$50/ton in 2016 and 2017.  This $50/ton covers all payment obligations for coal supplied to the Exiting Participants that might otherwise be due under (i) the Restructuring Agreement; (ii) the CSA, including Legacy Costs, taxes and royalties; and (iii) gross receipts taxes under the Refined Coal Supply Agreement or otherwise.  This $50/ton does not include payments for reclamation costs under the RSA or disposal costs under the CCRDA.
23.17 Exiting Participants will not have any take-or-pay or minimum purchase obligations under the CSA; provided, however, the Exiting Participants must comply with the following dispatch requirements.  The Exiting Participants will dispatch their respective shares of the Units to no less than their Minimum Annual Generation.  The Exiting Participants will be billed monthly based on their Participant Coal Consumption.  At the end of each of 2016 and 2017, any Exiting Participant that has not met its Minimum Annual Tonnage Purchase Obligation will be billed at $50/ton for the difference between its actual Participant Coal Consumption and its Minimum Annual Tonnage Purchase Obligation; provided, in the event that at any time during 2016 or 2017 PNM is unable to supply coal to the Exiting Participants as provided in Section 23.16, then the Minimum Annual Tonnage Purchase Obligation will be proportionately reduced to account for any such period of time in which PNM is unable to supply coal.
23.18    For purposes of the calculations in this Section 23.18, PNM’s Common Participation  Share  will  include  the  Exiting  Participants’  Common  Participation  Share, and  PNM’s  Participant  Coal  Consumption  will  include  the  Exiting  Participants’ 



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Participant Coal Consumption.  SJCC will invoice PNM monthly as provided under the CSA.  PNM will invoice each Remaining Participant monthly by Coal Tonnage Component and such Coal Tonnage Component will be paid for as follows:
23.18.1  Pre-existing Stockpile Coal tons as invoiced by SJCC will be allocated by a Remaining Participant’s Common Participation Share as of the Effective Date and will be paid for by each Remaining Participant at the price per ton charged by SJCC in its monthly invoicing to PNM.
23.18.2  Each year, PNM will develop a monthly Tier 1 Tonnage Allocation schedule with SJCC in the annual operating plan process as provided for in Section 7.2 of the CSA.  With input from the Remaining Participants, PNM will develop a monthly allocation by Remaining Participant of such Tier 1 Tons (such individual allocation, its “Tier 1 Tonnage Allocation”).  Such monthly Tier 1 Tonnage Allocation will be paid for by Remaining Participants whether or not their Participant Coal Consumption exceeded their Tier 1 Tonnage Allocation in the month.    Monthly,  for   each  Remaining  Participant,  its  Tier  1  Tonnage  Allocation, net of its invoiced Pre-existing Stockpile Coal for such month will be paid for at the then existing price for Tier 1 Tons under the CSA.  In each of 2016 and 2017, five million six hundred thousand (5,600,000) tons will be allocated by Remaining Participant Share, and then PNM will be allocated an additional one hundred fifty thousand (150,000) tons in each of those years.  In each of 2018 and 2019,  two  million  eight  hundred thousand (2,800,000) tons will be allocated by 



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Remaining Participant Share.  In each of 2020 and 2021, two million eight hundred thousand (2,800,000) tons will be allocated by Remaining Participant Share, and then PNM’s allocation will be reduced by one hundred fifty thousand (150,000) tons in each of those years.  In 2022, one million four hundred thousand (1,400,000) tons will be allocated by Remaining Participant Share.  
23.18.3  To the extent that a Remaining Participant’s Participant Coal Consumption in a month exceeds its Tier 1 Tonnage Allocation for such month, PNM will invoice such Remaining Participant such excess as Tier 2 Tons to be paid for at the then existing price for Tier 2 Tons under the CSA.
23.18.4  Legacy Costs as invoiced monthly by SJCC will be allocated using a Remaining Participant’s Common Participation Share for that year.
23.18.5  Cost for SJCC’s reclamation bond premium invoiced through the CSA will be allocated using a Remaining Participant’s Common Participation Share for that year.
23.18.6  Weight-based taxes will be applied to the tonnages as invoiced by PNM to each Remaining Participant at the then-existing rates applicable to SJCC invoices.
23.18.7  Revenue-based taxes and royalties will be applied to the tonnages and total coal costs as invoiced by PNM to each Remaining Participant at the then-existing rates applicable to SJCC invoices.
    



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23.18.8  In the event of an SJCC environmental force majeure, then Available Pre-existing Stockpile Tons will be allocated in the same manner as Pre-existing Stockpile Coal tons, and Force Majeure Tons will be allocated in the same manner as Tier 1 Tons unless otherwise approved by the Remaining Participants in the Fuels Committee.  Such calculations will be on an annual basis.
23.18.9  Any other costs billed by SJCC under the CSA and not specifically addressed in this Section 23.18 will be apportioned among and paid for by the Remaining Participants on the basis of the Remaining Participant’s Common Participation Share for that year unless otherwise annually approved by the Remaining Participants in the Fuels Committee.


23.18.10 Annual Year-End Reconciliation Process.    
23.18.10.1  At the end of each year, the Operating Agent will reconcile the sum of each Remaining Participant’s monthly CSA-related payments to a properly allocable share of annual Tier 1 Tons, Tier 2 Tons, Pre-existing Stockpile Coal tons, and cost associated with any change in Project Coal Inventory and invoice or refund any such reconciliation amounts to each Remaining Participant.
23.18.10.2  Any net consumption of Project Coal Inventory tons will be charged to FERC Account 501 and apportioned among and paid for by the Remaining Participants on the basis of the percentage that each Remaining  Participant’s  annual  Tier  2  Tons  after  the  reconciliation 



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process bears to the total annual Tier 2 Tons consumption after the reconciliation process for all Units.  The price for such tons will be determined by dividing the total recorded cost in FERC Account 151 by the total number of tons of coal in Project Coal Inventory, both as recorded on January 1 of said year.  The total amount of any such payment for consumed Project Coal Inventory tons will subsequently be credited to FERC Account 151 and apportioned to the Remaining Participants based on the Remaining Participant’s Common Participation Share for that year.
23.18.10.3 The costs of any net addition to Project Coal Inventory tons, as invoiced by SJCC, will be charged to FERC Account 151 and apportioned to and paid for by the Remaining Participants based on the Remaining Participant’s Common Participation Share for that year.
23.18.10.4  If, at the end of any year, the Operating Agent has collected amounts in excess of those due SJCC under the CSA, such over-collection will be refunded to the Remaining Participants. The refund to each Remaining Participant will be an amount equal to the total amount of the over-collection multiplied by the tons each Remaining Participant’s Coal Consumption was less than its total annual Tier 1 Tonnage Allocation divided by the total amount by which all such Remaining Participants’ Coal Consumption was less than their Tier 1 Tonnage Allocation.
        



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23.19    The cost of evaluating a long-term fuel supply for the San Juan Project, approved pursuant to a resolution of the Coordination Committee of May 23, 2014, shall be shared among the Remaining Participants in accordance with the following percentages:    


23.19.1        PNM - 62.708 percent
23.19.2        TEP - 19.8 percent
23.19.3        Farmington - 3.679 percent
23.19.4        LAC - 3.123 percent
23.19.5        UAMPS - 3.017 percent
23.19.6        PNMR-D – 7.673 percent


To the extent that the cost of evaluating a long-term fuel supply for the San Juan Project has been invoiced and paid at a different percentage allocation than that set forth immediately above, the Remaining Participants agree to a true-up of the over- or under- payment to these percentages as of the Effective Date.



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24.0    ANNUAL BUDGETS:  
24.1    Not less than ninety (90) days prior to the beginning of each calendar year, the Operating Agent shall prepare and submit to the Engineering and Operating Committee for its review and approval the proposed capital budget, manpower budget and a budget for the performance of Operating Work for such calendar year.  
24.2    The Engineering and Operating Committee shall approve the budgets described in Section 24.1 in final form not less than thirty (30) days prior to their effective date.  In the event that any such budget is not so approved, the Operating Agent will nevertheless continue to perform Operating Work in a manner consistent with Prudent Utility Practice until such time as a budget has been approved.  
24.3    Any information required from the Participants by the Operating Agent in preparing such proposed budgets will be supplied by the Participants, if possible, within thirty (30) days following a request by the Operating Agent.  
24.4    The Engineering and Operating Committee may at any time during the year approve revisions to the approved capital expenditures budget, manpower budget and a budget for the performance of Operating Work.  



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25.0    PAYMENT OF TAXES:  
25.1    The Participants shall use their best efforts to have any taxing authority imposing any taxes or assessments on the San Juan Project, assess and levy such taxes or assessments directly against each Participant in accordance with its respective Participation Share in the property taxed.
25.2    All taxes or assessments levied against each Participant’s ownership interest in the San Juan Project, excepting those taxes or assessments levied against an individual Participant on behalf of other Participants, shall be the sole responsibility of the Participant upon whom said taxes and assessments are levied.
25.3    If any property taxes and other taxes and assessments are levied and assessed in a manner other than specified in Section 25.1, it shall be the responsibility of the Coordination Committee to establish equitable standard practices and procedures for the apportionment among the Participants of such taxes and assessments and the payment thereof.



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26.0    MATERIALS AND SUPPLIES:  
26.1    The Operating Agent from time to time may increase or reduce the inventory of Materials and Supplies by changing the maximum or the minimum quantities to be maintained in inventory in accordance with the procedures established by the Engineering and Operating Committee.  
26.2    The Operating Agent shall prepare a list of the items for inclusion in Materials and Supplies for the operation and maintenance of each Unit.  The list shall include the estimated cost of each individual item of such Materials and Supplies and specify the maximum and minimum quantity of each such individual item to be maintained in inventory.  The list shall be submitted to the Engineering and Operating Committee by the Operating Agent for review and approval.  
26.3    The Operating Agent shall purchase and take control of Materials and Supplies for inventory, so that the total inventory of Materials and Supplies on hand remains in accordance with the policies established by the Engineering and Operating Committee.
26.4    Materials and Supplies withdrawn from inventory and used in the operation and maintenance of the San Juan Project shall be accounted for as a component of operation and maintenance expense and allocated among the Participants in accordance with Section 22.  
        



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26.5    Materials and Supplies withdrawn from inventory and used in connection with Capital Improvements shall be accounted for as a capital expenditure and allocated among the Participants in accordance with Section 7.
26.6    Materials and Supplies removed from service shall be returned to inventory if reusable, or if junk or obsolete, shall be disposed of by the Operating Agent under the best available terms.  The proceeds, if any, received shall be credited or distributed to the Participants in the same proportion as their Participation Shares therein.  
26.7    A separate Materials and Supplies account and undistributed stores expense account will be established by the Operating Agent in accordance with FERC Accounts.  Such charges and credits so allocated to Materials and Supplies shall be allocated to the Parties as a component of operation and maintenance expense in accordance with Section 22, or as a Capital Improvement in accordance with Section 7, as the case may be.
26.8    The inventory value of any item withdrawn from or returned to Materials and Supplies shall be the average cost of like items in inventory.  



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27.0    EMERGENCY SPARE PARTS:
27.1    The Operating Agent shall prepare a list of the Emergency Spare Parts for each Unit and common facilities.  Such list shall include the estimated costs for each individual item of such Emergency Spare Parts and shall specify the quantity of each such individual item to be maintained in inventory.  Such list shall be submitted to the Engineering and Operating Committee by the Operating Agent for review and approval.  
27.2    The Operating Agent shall purchase Emergency Spare Parts from time to time as replacements for those withdrawn from inventory in accordance with the policies established by the Engineering and Operating Committee.  
27.3    Emergency Spare Parts shall be owned by and the costs thereof shall be allocated between the Participants in accordance with their respective Participation Shares.  
27.4    The Operating Agent shall notify the Participants promptly after Emergency Spare Parts are withdrawn from inventory and shall also notify the Participants of the value of such parts so withdrawn and of the accounting treatment with respect thereto.  



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PART VI
OPERATING AGENT
28.0    OPERATION AND MAINTENANCE:  
28.1    PNM is the Operating Agent, unless replaced in accordance with Section 33.  
28.2    All Parties hereby appoint PNM as their agent, and PNM agrees to undertake, as the agent of the Parties and as principal on its own behalf, the responsibility for the performance of Operating Work in accordance with this Agreement.  
28.3    Subject to the provisions, conditions, limitations and restrictions of this Agreement, the Operating Agent shall:
28.3.1    Perform the Operating Work in accordance with the Project Agreements and Prudent Utility Practice.
28.3.2    Contract for, furnish or obtain the services and studies necessary for performance of Operating Work.  
28.3.3    Arrange for the placement and maintenance of Operating Insurance.  
28.3.4    Execute all contracts in the name of the Operating Agent, acting as principal on its own behalf and as agent for the Parties, in connection with the performance of Operating Work.  
28.3.5    Furnish and train the necessary personnel for performance of Operating Work.  
            



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28.3.6    Have the coal replaced which has been removed from the Emergency Coal Storage Pile at the earliest practical time following resumption of normal coal deliveries.  
28.3.7    Enforce and comply with all contracts entered into for the performance of Operating Work.  
28.3.8    Comply with any and all laws and regulations applicable to the performance of Operating Work.  
28.3.9    Maintain the Operating Account and expend the Operating Funds only in accordance with this Agreement.  
28.3.10  Keep and maintain records of monies expended and received, obligations incurred, credits accrued and contracts entered into in the performance of this Agreement, and make such records available for inspection by the Parties at reasonable times and places.  
28.3.11  Not suffer any liens to remain in effect unsatisfied against the San Juan Project (other than the liens permitted under Section 10.1, for taxes or assessments not yet delinquent, for labor and material not yet delinquent or undetermined charges or liens incidental to the performance of Operating Work); provided, that the Operating Agent shall not be required to pay or discharge any such lien as long as a proceeding shall be pending in which the lawfulness or validity of such lien shall be contested in good faith and which shall operate during 



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the pendency thereof to prevent the collection or enforcement of such lien so contested.  
28.3.12  Recommend minimum notification times and lead times for changing scheduled Energy required for the Participants to the Engineering and Operating Committee for its approval.  
28.3.13  Act as operating representative or agent in connection with the administration and enforcement of the CSA, the CCRDA and, through December 31, 2017, the RSA.
28.3.14  Recommend programs to the Engineering and Operating Committee to make environmental studies and, upon approval of the Engineering and Operating Committee, supervise the performance of such programs.  
28.3.15  Provide the Engineering and Operating Committee with all written statistical and administrative reports, written budgets, information and other records relating to Operating Work which may be necessary to permit such committee to perform its responsibilities under this Agreement.  
28.3.16  Provide the Fuels Committee with all written reports, written budgets, information and other records relating to Operating Work which may be necessary to permit such committee to perform its responsibilities under this Agreement. 
28.3.17  Provide the Auditing Committee with all accounting records, information, reports and other records relating to Operating Work, which may be 



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necessary to permit such committee to perform its responsibilities under this Agreement.  
28.3.18  Perform Operating Work so as to comply with the Water Contract(s) and make such tests and measurements and keep such records as are required by applicable agreements, regulations and statutes.  
28.3.19  Keep the Parties fully and promptly advised of material changes in conditions or other material developments affecting the performance of Operating Work and furnish the Parties with copies of any notices given or received pursuant to the Project Agreements.  
28.3.20  Present claims to any insurer for losses and damages covered by valid and collectible Operating Insurance procured by the Operating Agent directly from the insurer.  Investigate, adjust, settle, decline and defend claims against the Parties arising out of the performance of Operating Work when said claims or portions thereof are not covered by valid and collectible Operating Insurance; provided that the Operating Agent shall obtain the agreement of the Parties, acting through the Coordination Committee, prior to disposing of any claims or combination of claims arising out of the same occurrence which exceeds one hundred thousand dollars ($100,000).  
28.3.21  Assist, as requested, other Parties and their insurers in the investigation, adjustment and settlement of any loss or claim arising out of Operating  Work  for  which  payment  may  be  made  on  account  of  valid  and 



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collectible additional  insurance applicable thereto procured by any such Party; provided, that the Operating Agent may agree (by separate agreement) that a Party procuring any policy or policies of  additional insurance shall have the authority and the responsibility to (i) present, investigate, adjust, settle, decline and defend claims or potential claims covered by said policies in favor of the Parties and against any one or more of said insurers; and (ii) present, investigate, adjust, settle, decline and defend claims against the Parties arising out of the performance of Operating Work when said claims or portions thereof are not covered by said policies; and provided further, that such Party shall obtain the agreement of the Parties, acting through the Coordination Committee, prior to the settlement of any claim or combination of claims arising out of the same occurrence which exceeds one hundred thousand dollars ($100,000).
28.3.22  Notwithstanding anything in Section 28.3.20 and 28.3.21 to the contrary, any Party may at any time, at its own expense, employ its own counsel to assist in investigating, adjusting, settling, declining and defending claims of the types referred to in Sections 28.3.20 and 28.3.21 and the Operating Agent and its employees and counsel shall cooperate fully with such counsel and permit such counsel to participate fully in all of the foregoing activities.  
28.3.23  Keep the Parties fully and promptly informed of any known default under the Project Agreements.  
            



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28.3.24  Determine switching and clearance procedures to be followed by the Participants at the San Juan Project.  
28.3.25  Determine Available Operating Capacity from time to time and make recommendations to the Engineering and Operating Committee regarding items referenced in Section 19.3.1.9.  
28.3.26  Upon the request of a Party, provide such Party, in reasonable quantity without direct charge therefor, a copy or copies of any report, record, list, budget, manual, accounting or billing summary, classification of accounts, or other documents or revisions of any of the foregoing items, all as prepared in accordance with this Agreement.  
28.3.27  In the event of the failure of the Participant which is a signatory to the CSA then in effect to reach agreement on a matter described in Sections 18.7 and 20.5.3,  maintain a supply of coal to the San Juan Project, consistent with Prudent Utility Practice.
28.3.28       Manage the activities of the “designated representative” pursuant to the DR Agreement.
28.3.29       Perform all of the duties and obligations set out in this Agreement as duties and obligations of the Operating Agent.
28.3.30       Through December 31, 2017, perform the duties and obligations of the Reclamation Trust Funds Operating Agent under the Mine Reclamation Agreement.



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28.3.31       Cooperate in the performance of the baseline environmental study and related environmental audits, as provided for in the Restructuring Agreement.
28.4    The Parties shall lend and be properly reimbursed for all necessary and available assistance as may be requested by the Operating Agent in the performance of Operating Work. 
28.5    The Operating Agent shall be the agent of the Parties and shall exercise only such authority as is conferred upon it by this Agreement.  The Operating Agent shall not receive any fee or profit hereunder, unless otherwise agreed unanimously by the Parties. 



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29.0    OPERATING EMERGENCY:  
29.1    In the event of an Operating Emergency, the Operating Agent shall take any and all steps reasonably necessary and required to terminate the Operating Emergency, subject to the provisions of this Section 29.  
29.2    As soon as practicable after the commencement of an Operating Emergency, the Operating Agent shall advise the Participants of the occurrence of the Operating Emergency, its nature and the steps taken or to be taken to terminate the Operating Emergency, including a preliminary estimate of the expenditures required to terminate the Operating Emergency.  
29.3    In the event that the estimated cost to cure an Operating Emergency with respect to any Unit or to any equipment and facilities common to any of the Units does not exceed two hundred and fifty thousand dollars ($250,000), the Operating Agent shall have the authority to expend, in its discretion, no more than two hundred and fifty thousand dollars ($250,000) to terminate such Operating Emergency.
29.4    In the event the Operating Agent determines that the estimated amount required to terminate the Operating Emergency exceeds the amount which it is authorized to expend, the Operating Agent shall immediately notify the affected Parties following such determination.  The Operating Agent shall provide the following information:  
29.4.1 The estimated date when the Operating Emergency can be terminated.  
            



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29.4.2    The person or persons who would perform the work and furnish the materials required to terminate the Operating Emergency.  
29.4.3    The estimated amount of overtime, if any, which would be necessary in order to expedite the termination of the Operating Emergency.  
29.4.4    The costs that are proposed to be capitalized, and salvage realized.  
29.4.5    The costs that are proposed to be charged as maintenance expense.  
29.4.6    The proposed administrative and general expense allowance applicable to such repair or reconstruction.  
29.4.7    Such other information as may be necessary and required by the Engineering and Operating Committee to determine the manner in which the Operating Emergency is to be terminated.  
29.5    The Engineering and Operating Committee shall review and approve the proposed repair or reconstruction, including the estimated cost thereof or shall agree upon an alternative.  
29.6    Costs incurred in terminating an Operating Emergency may be billed to the Parties by the Operating Agent on the basis of its estimate of such costs with adjustment to be made in accordance with Section 29.8 when final cost determination has been made.  
29.7    Following the termination of the Operating Emergency, the Operating Agent shall submit to the Parties a report containing a summary of the costs incurred and expenditures made in connection with the repair or reconstruction and such other information as may be required by the Engineering and Operating Committee.   
        



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29.8    The Operating Agent shall allocate to the Parties the costs incurred or expenditures made in such repair or reconstruction, as follows: (i) costs charged as maintenance expense, in accordance with Section 22; and (ii) any other such repair or reconstruction costs, in accordance with Section 7.  



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30.0    PAYMENT OF EXPENSES BY PARTIES: 
30.1    All amounts required to be advanced by the Parties in accordance with this Agreement shall be made payable to the Operating Account established by the Operating Agent.  The Operating Funds shall be owned by the Parties in proportion to their respective balances therein at any given time, and the Operating Agent in its capacity as such shall not have any right or title therein except to maintain custody of and to disburse the Operating Funds as a conduit between the Parties and those to whom such disbursements shall be made.  
30.2    The Engineering and Operating Committee shall establish a minimum amount for the Operating Funds which will be available to pay for expenditures or obligations incurred by or on behalf of the Parties in accordance with this Agreement.  Such minimum amount of Operating Funds may be revised by the Engineering and Operating Committee at any time.  The minimum amount of the Operating Funds and any increases therein shall be advanced by the Parties in accordance with the percentages set forth in Section 22, and shall be due and payable within fifteen (15) business days following notification of the establishment of the minimum amount to be kept in Operating Funds or the date on which any increase in such amount authorized by the Engineering and Operating Committee shall become effective.  In the event the Engineering and Operating Committee decreases such minimum amount, then each Party shall receive a credit which shall be equal to the product of its percentage, as set forth in Section 22, and the amount of any such decrease.  



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30.3    Each Party shall advance Operating Funds on the basis of notices (hereinafter called bills) submitted by the Operating Agent reflecting such Party’s share of costs and expenses in accordance with this Agreement, as follows:  
30.3.1    Expenses described in Sections 30 and 22 shall be billed in writing as follows:  
30.3.1.1    The payroll costs to be paid to the Operating Agent’s employees for each pay period.  
30.3.1.2    On the 20th day of each month, the total expenses incurred the previous month and described in Section 22 less those expenses billed under Section 30.3.1.1.  
30.3.2    Bills submitted under Section 30.3.1 shall be due and payable within seven (7) business days following receipt of the bill.  
30.3.3    Expenses described in Sections 31 and 23 shall be billed in writing at least ten (10) business days prior to their due date, and funds therefor shall be deposited with the Operating Agent not less than three (3) business days prior to their due date.  If such bills do not have a specific due date, they shall be billed within a reasonable time following their incurrence.  
30.3.4    Expenses described in Sections 7, 26, 27 and 29 shall be billed monthly, except when such expenses exceed the minimum amount in the Operating Funds in which case billing will be made immediately and payable within seven (7) business days following receipt of the bill.  



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30.4    Except as expressly provided herein, nothing in this Agreement shall be deemed to require the Operating Agent to advance its own monies on any other basis than in its role, if any, as a Party.



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31.0    OPERATING INSURANCE:  
31.1    Unless otherwise specified by the Coordination Committee, during the performance of Operating Work, the Operating Agent shall procure and maintain in force, or cause to be procured and maintained in force, policies of Operating Insurance providing coverage against the following risks, hazards and perils:
31.1.1    Risks covered by the standard form of commercial liability insurance, including bodily injury, personal injury and property damage risk, hazards of automobiles liability, contractual liability, contractor’s protective liability and liability for products and completed operations, in an amount not less than twenty-five million dollars ($25,000,000).
31.1.2    Risks covered by the standard form of “all risk” property insurance providing coverage against all risk of loss, except those risks excluded in the standard form of “all risk” property insurance.  Such insurance shall provide boiler and pressure vessel coverage, including reasonable expediting expense.
31.1.3    Risks covered by the standard form of workers’ compensation and employers liability insurance, covering employees of the Operating Agent engaged in the performance of Operating Work, or other compliance by the Operating Agent with requirements of the laws of the State of New Mexico as to such coverage.
31.1.4    Risks covered by the standard form of employee dishonesty bond covering loss of property or funds due to dishonest or fraudulent acts committed by an officer or employee of the Operating Agent.
        



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31.2    Except for Operating Insurance described in Sections 31.1.3 and 31.1.4, each Party shall be a named insured individually and jointly and in accordance with its Participation Share as established in Section 6. Operating Insurance referred to in Section 31.1.1 shall carry cross-liability coverage.
31.3    In the event that another Party’s insurance program affords equal or better coverage on a more favorable cost basis than that available to the Operating Agent, the Parties may agree (by separate agreement) that such insurance program may be utilized to afford all or part of the insurance coverage required by Section 31.1.
31.4    The insurance company used, the insurable values, limits, deductibles, retentions and other special terms, covenants and conditions of the Operating Insurance shall be agreed upon by the Coordination Committee.  
31.4.1    Any deductibles shall be shared by the Parties in accordance with the percentages established in Section 22.1.
31.5    The Operating Agent shall furnish each of the Parties with either a certified copy of each of the policies of Operating Insurance or a certified copy of each of the policy forms of Operating Insurance, together with a line sheet therefor (and any subsequent amendments) naming the insurers and underwriters and the extent of their participation.  When the policies or policy forms of Operating Insurance have been approved in writing by all of the Parties, said policies or policy forms shall not be modified or changed by any Party without the prior written consent of all of the Parties, except for minor and insubstantial 



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changes or modifications, as to which notification shall be given by the Operating Agent to the Parties.  
31.6    Each of the Operating Insurance policies shall be endorsed so as to provide that all named insureds shall be given thirty (30) days notice of cancellation or material change.  
31.7    Operating Insurance policies shall be primary insurance for all purposes and shall be so endorsed.  Any insurance carried by a Party individually shall not participate with the Operating Insurance as respects any loss or claim for which valid and collectible Operating Insurance shall apply.  Such other insurance shall apply solely as respects the individual interest of the Party carrying such other insurance.
31.8    Nothing herein shall prohibit the Operating Agent or any Party from furnishing a policy of Operating Insurance which combines the coverage required by this Agreement with coverage outside the scope of that required by this Agreement.  If the Operating Agent or any Party furnishes a policy of Operating Insurance which combines the coverage required by this Agreement with coverage outside the scope of that required by this Agreement, the Coordination Committee shall agree on the portion of the total premium cost which is allocable to Operating Insurance.  If the Parties are unable to agree on such allocation, the Operating Agent may make an estimated allocation and bill the Parties on the basis thereof, with adjustment to be made when the dispute is resolved.  
31.9    If a Party desires changes in any Operating Insurance policy, such Party shall notify  the  Operating  Agent  and  the  other  Parties  in writing of the desired changes.  Upon 



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agreement of the Coordination Committee to such change, the Operating Agent shall obtain the insurance within sixty (60) days from the date of agreement.  If the Operating Agent is unable to obtain the type of policy or coverage required herein or believed by the Operating Agent to be adequate, then the Operating Agent shall immediately notify the Parties.
31.10    In the event the Coordination Committee is unable to agree upon any matters relating to the Operating Insurance, the Operating Agent, pending the resolution of such disagreement, shall procure or cause to be procured such policies of insurance, consistent with Prudent Utility Practice, as are necessary to protect the Parties against the insurable risks for which Operating Insurance is required.  During any period of negotiations with an insurer, or other negotiations which are pending at the expiration of the period of coverage of an Operating Insurance policy, or in the event an Operating Insurance policy is canceled, the Operating Agent shall renew or bind policies as an emergency measure, or may procure policies of insurance which are identical to those which were canceled, or may to the extent possible secure replacement policies which will provide substantially the same coverage as the policy expiring or canceled.  
31.11    Each Party shall have the right to request that any mortgagee, trustee or secured party be named on all or any of the Operating Insurance policies as loss payees or additional assureds as their interests may appear.  Such request shall be submitted to the Operating Agent specifying the name or names of such mortgagee, trustee or secured party and such additional information as may be necessary or required to permit it to be included on the policies of Operating Insurance.



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31.12    On an annual basis, the Operating Agent shall advise the Parties on the status of insurance coverage for the San Juan Project and shall make appropriate recommendations concerning insurance issues to the Coordination Committee. 



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32.0    SURPLUS OR RETIRED PROPERTY:    
The Operating Agent shall dispose of surplus property or property no longer used or useful in the operation of the San Juan Project and report such disposal to the Participants, both in accordance with practices and procedures established by the Engineering and Operating Committee.  The proceeds from such disposition shall be credited to the Participants in accordance with their Participation Shares.  





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33.0    REMOVAL OF OPERATING AGENT:  
33.1    The Operating Agent shall serve as such during the term of this Agreement unless it resigns as Operating Agent by giving notice to the Parties at least one (1) year in advance of the date of resignation or until receipt by the Operating Agent of notice of its removal as provided in Section 33.2.  
33.2    The Operating Agent may be removed as Operating Agent for any one of the following reasons:
33.2.1    The Operating Agent may be removed by action of the Coordination Committee if, in the judgment of the Coordination Committee (voting as provided for in Section 18.4), the best interests of the San Juan Project require that a new Operating Agent be selected.  Any Party seeking a Coordination Committee determination to remove the Operating Agent shall provide to the Operating Agent and to all of the Parties a written statement, detailing the reasons why, in the judgment of the initiating Party, the Operating Agent should be removed.  Within thirty (30) days after receipt by the Operating Agent of this written statement, the Operating Agent shall prepare and serve upon all of the Parties its response which shall contain a detailed rebuttal of the allegations made in the initiating statement.  Within the same thirty (30) day period, any other Party may also prepare and serve upon the Operating Agent and the Parties a statement responding to the allegations in the initiating statement.   Within twenty (20) days after service of all such response  statements,  the  Coordination  Committee  shall  meet  to  consider  what 



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action, if any, to take with regard to the removal of the Operating Agent.  If, pursuant to this Section 33.2.1, the Coordination Committee removes the Operating Agent, such removal shall be effective upon the date established by the Coordination Committee.  If the Operating Agent or any Party is dissatisfied with the action of the Coordination Committee, it shall have the right to seek arbitration under Section 37, but no demand for arbitration shall stay the decision of the Coordination Committee to remove the Operating Agent.
33.2.2    If, pursuant to the provisions of Section 34, it is determined that the Operating Agent is in default of its obligations under this Agreement, the Operating Agent may be removed by written notice given by any Party under Section 34.1.2, which notice shall state the effective date of the removal of the Operating Agent.
33.2.3    Notwithstanding the pendency of any actions to remove the Operating Agent, the Operating Agent shall continue in good faith to exercise its obligations as Operating Agent.
33.3    Prior to the effective date of a resignation of the Operating Agent, or prior to the date of removal of the Operating Agent in accordance with Section 33.2, the Coordination Committee shall by written agreement designate a new Operating Agent, which may, but need not, be a Party.  The Coordination Committee may designate an interim Operating Agent pending selection of a permanent Operating Agent.  Acceptance by the new Operating Agent of its appointment as such shall constitute its agreement to perform the obligations of the Operating Agent under this Agreement. 



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34.0    DEFAULTS BY OPERATING AGENT:  
34.1    The following provisions shall apply solely in regard to violations or allegations of violations of this Agreement by the Operating Agent on the basis of which removal of the Operating Agent is sought:  
34.1.1    In the event any Party shall be of the opinion that an action taken or failed to be taken by the Operating Agent constitutes a violation of this Agreement, it may give written notice thereof to the Operating Agent and the other Parties, together with a statement of the basis for its opinion.  Thereupon, the Operating Agent may prepare a statement of the reasons justifying its action or failure to take action.  If agreement in settling the dispute is not reached between the Operating Agent and such Party which gave such notice, then the matter shall be submitted to arbitration in the manner provided in Section 37.  During the continuance of the arbitration proceedings, the Operating Agent may continue such action taken or failed to be taken in the manner it deems most advisable and consistent with this Agreement.  
34.1.2    If it is determined that the Operating Agent is violating this Agreement, then the Operating Agent shall act with due diligence to end such violation and shall, within thirty (30) days or within such lesser time following the determination as may be prescribed in the determination, take action or commence action in good faith to terminate such violation.  In the event that the complaining 
Party is of the opinion that the Operating Agent has not taken such action to correct, 



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or to commence action to correct, the violation within such allowed period, the complaining Party shall be entitled to submit the question of the Operating Agent’s good faith action to terminate such violation to arbitration as provided in Section 37.  If it is determined that the Operating Agent has not acted with due diligence or good faith to terminate such violation, it shall be deemed to be in default and shall be subject to removal, after the arbitration determination, within fifteen (15) days after receipt of notice executed by the complaining Party in accordance with Section 42.  
34.1.3    The provisions of Section 35, excepting Sections 35.8 and 35.9, shall not apply to disputes as to whether or not an action or non-action of the Operating Agent, in its capacity as Operating Agent, is a violation or default under this Agreement.  



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PART VII
DEFAULTS, LIABILITY AND ARBITRATION
35.    DEFAULTS:  
35.1    Each Party shall pay all monies and carry out all other performances, duties and obligations agreed to be paid or performed by it pursuant to all of the terms and conditions set forth and contained in the Project Agreements, and a default by any Party in the covenants and obligations to be by it kept and performed pursuant to the terms and conditions set forth and contained in any of the Project Agreements shall be an act of default under this Agreement.  A default under the Mine Reclamation Agreement or the Decommissioning Agreement is not a default under this Agreement.  If a Party breaches a performance obligation under Sections 4.3 or 5 of the Restructuring Agreement, which provisions are incorporated in Sections 7.13.1 and 23 of this Agreement, the non-defaulting Parties’ remedies shall be as provided in this Agreement.   A default under any other section of the Restructuring Agreement shall not be a default under this Agreement, irrespective of whether it is incorporated in this Agreement, and remedies for such a default shall be as provided in the Restructuring Agreement.
35.2    In the event of a default by a Party in any of the terms and conditions of this Agreement to be performed by that Party, the following shall apply:
35.2.1    The Operating Agent shall give a written notice of the default to the defaulting Party and the other Parties in accordance with Section 35.2.2.
            



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35.2.2    The notice of default shall specify the existence, nature and extent of the default.  Upon receipt of the notice of default, the defaulting Party shall immediately take all steps necessary to cure the default as promptly and completely as possible.
35.3    In the event that any Party shall dispute an asserted default by it, then such Party shall pay the disputed payment or perform the disputed obligation, but may do so under protest. The protest shall be in writing, shall accompany the disputed payment or precede the performance of the disputed obligation(s), and shall specify the reason upon which the protest is based.  Copies of such protest shall be mailed by such Party to all other Parties and to the Operating Agent.  Payments not made under protest shall be deemed correct, except to the extent that periodic or annual audits may reveal over or under payment by a Party or may necessitate adjustments.  In the event it is determined by arbitration, pursuant to the provisions of this Agreement or otherwise, that the protesting Party is entitled to a refund of all or any portion of a disputed payment or payments, or is entitled to the reasonable equivalent in money of non-monetary performance of a disputed obligation theretofore made, then, upon such determination, the non-protesting Party(ies) shall reimburse such amount to the protesting Party, together with interest thereon at the rate of ten percent (10%) per annum, or the maximum legal rate of interest, whichever is lesser, from the date of payment or of the performance of a disputed obligation to the date of reimbursement.
        



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35.4    In the event a default shall continue for a period of ten (10) days or more after the notice given by the Operating Agent in accordance with Section 35.2 without having been cured by the defaulting Participant, or without such defaulting Party having commenced or continued action in good faith to cure such default, the following shall apply:
35.4.1    If the defaulting Party has failed to cure such default or to commence such good faith action during said ten (10) day period, the Operating Agent shall make a written report to the Engineering and Operating Committee concerning the status of the default and shall, on the next working day after such ten (10) day period, notify the defaulting Party in writing that the Operating Agent intends to declare the defaulting Party in default under the Project Agreements unless there is a prompt cure of the default.  Seven (7) days after the giving of such notice to the defaulting Party, the Operating Agent shall make a second written report to the Engineering and Operating Committee concerning the status of the default and the efforts, if any, of the defaulting Party to cure the default.  If, within seven (7) additional days, the defaulting Party has neither cured nor reasonably commenced to cure the default, the Operating Agent shall declare the defaulting Party in default under the Project Agreements and shall provide written notification of the declaration of default to the defaulting Party and to the Engineering and Operating Committee.  Thereafter, and for so long as the default is not remedied and the declaration of default is not revoked by the Operating Agent, all rights of the 



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defaulting Party under the Project Agreements shall be suspended, including the right to vote on all committees and to receive all or any part of its proportionate share of the Net Effective Generating Capacity.
35.4.2    Within seventeen (17) days after the notice by the Operating Agent, as provided for in Section 35.2, the Operating Agent shall prepare special operating procedures for approval by the Engineering and Operating Committee that will apply during the period of suspension under Section 35.4.1.  Upon approval by the Engineering and Operating Committee, the Operating Agent shall provide notice to each Party of such special procedures.  These special procedures shall include:
35.4.2.1    A tabulation in form similar to Section 6.2 of the percentages of costs to be borne by the non-defaulting Parties pursuant to Section 35.5;
35.4.2.2    Billing and accounting of such costs;
35.4.2.3    Dispatch and scheduling of the defaulting Party’s proportionate share of Net Effective Generating Capacity; and
35.4.2.4    Any other items required for the optimal use of the San Juan Project and the mitigation of damages by the non-defaulting Parties.
35.4.2.5    If the Operating Agent proposes to broker all or a portion of the defaulting Party’s proportionate share of Net Effective Generating Capacity on behalf of one or more non-defaulting Parties, the form of such an agreement shall be incorporated in such procedures.



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35.4.3    Within twenty (20) days after the declaration of a default, as provided for in Section 35.4.1, the defaulting Party and the non-defaulting Parties shall convene a meeting to address the defaulting Party’s situation and its intentions with regard to curing its default.  The defaulting Party shall promptly prepare a cure plan for approval by the members of the Coordination Committee entitled to vote thereon.  The cure plan shall address the defaulting Party’s plan to cure the default and restore itself to full participation as an owner of the San Juan Project.  The Coordination Committee, by vote of the members of the Coordination Committee entitled to vote thereon, will monitor the defaulting Party’s compliance with the terms and conditions of the cure plan and if it appears to the Coordination Committee that the defaulting Party is or will be unable to comply with the terms of an approved cure plan, the Coordination Committee shall consider what actions may be required to address such inability, including, but not limited to, directing the Operating Agent to take such actions as may be appropriate.  It is the intent of the Parties that any defaults shall be cured on as expeditious a basis as reasonably possible. 
35.4.4    A demand for arbitration of an asserted default pursuant to Section 37 shall not stay the suspension of the rights of the defaulting Party, but in the event that the board of arbitrators shall determine that the asserted default did not in fact exist or occur, the arbitrators shall specify a method of fully and fairly compensating the Party which, under Section 35.4.1, was denied the right to vote on committee 



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actions and to receive all or any part of its proportionate share of the Net Effective Generating Capacity.
35.5    During any period when the suspension provided for in Section 35.4.1 is in effect, the non-defaulting Party(ies) having a Participation Share in the affected Unit or Units: (i) shall bear a proportionate share of all expenses, including but not limited to, the operation and maintenance costs, insurance costs, fuel costs, capital expenditures and other expenses otherwise payable by the defaulting Party under the Project Agreements, including any obligations related to common equipment and facilities, based upon the relation of the Participation Share of each such non-defaulting Party(ies) to the Participation Shares of all non-defaulting Parties in the specific Unit or Units; and (ii) shall be entitled to schedule and receive for their accounts their proportionate share of the Net Effective Generating Capacity of the defaulting Party. 
35.6    In connection with its cure of the default, the defaulting Party shall pay promptly upon demand to the non-defaulting Party(ies) the total amount of money (and/or the reasonable equivalent in money of non-monetary performance) paid and/or made by such non-defaulting Party(ies) pursuant to Section 35.5 in order to cure any default by the defaulting Party, together with interest thereon at the rate of ten percent (10%) per annum, or the maximum legal rate of interest, whichever is the lesser, from the date of the expenditure of such money (or the making of such other performance) by the non-defaulting Party(ies), to the date of such reimbursement by the defaulting Party, or such greater amount as may be otherwise provided in the Project Agreements.  Any payment obligation of the 



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defaulting Party shall be reduced by mitigation measures undertaken by the non-defaulting Parties; provided, however, that the payment obligations of the defaulting Party shall not be reduced by any profits or gains achieved by the non-defaulting Parties as the result of taking a proportionate share of the Net Effective Generating Capacity due to the default of the defaulting Party.
35.7    The suspension of a defaulting Party shall be terminated and its full rights under the Project Agreements restored when the default(s) have been cured and all compensable costs incurred by the non-defaulting Party(ies) hereunder have been paid by the defaulting Party or other arrangements acceptable to the non-defaulting Party(ies) have been made.
35.8    No waiver by a non-defaulting Party of its rights with respect to a default under this Agreement, or with respect to any other matter arising in connection with this Agreement, shall be effective unless the non-defaulting Party(ies) waive in writing their respective rights and any such waiver shall not be deemed to be a waiver with respect to any subsequent default or matter.  No delay short of the statutory period of limitations in asserting or enforcing any right hereunder shall be deemed a waiver of such right.
35.9    The rights and remedies provided in this Agreement shall be in addition to the rights and remedies of the Parties as set forth and contained in any other Project Agreement or any rights and remedies the Parties have in law or equity.



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36.0    LIABILITY: 
36.1    Except for any judgment debt for damage resulting from Willful Action and except to the extent any judgment debt is collectible from valid insurance, and subject to the provisions of Sections 36.1.1, 36.4, 36.5, 36.6 and Section 37, each Party hereby extends to all other Parties, their directors, members of their governing bodies, officers and employees, its covenant not to execute, levy or otherwise enforce a judgment obtained against any of them, including recording or effecting a judgment lien, for any direct, indirect, or consequential loss, damage, claim, cost, charge or expense, whether or not resulting from the negligence of such Party, its directors, members of its governing body, officers, employees or any person or entity whose negligence would be imputed to such Party from (i) Operating Work, the design and construction of Capital Improvements or the use or ownership of the San Juan Project or (ii) the performance or nonperformance of the obligations of any Party under any of the Project Agreements, other than the obligation to pay any monies becoming due.  
36.1.1    In the event any insurer providing insurance refuses to pay any judgment obtained by a Party against any other Party, its directors, members of its governing body, officers or employees on account of liability referred to in Section 36.1, the Party, its directors, members of its governing body, officers or employees against whom the judgment is obtained shall, at the request of the prevailing Party and in consideration for the covenant granted in Section 36.1, execute such documents as may be necessary to effect an assignment of its 



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contractual rights against the nonpaying insurer and thereby give the prevailing Party the opportunity to enforce its judgment directly against such insurer.  In no event when a judgment debt is collectible from valid insurance shall the Party obtaining the judgment execute, levy or otherwise enforce the judgment (including recording or effecting a judgment lien) against the Party, its directors, members of its governing body, officers or employees against whom the judgment was obtained.
36.1.2    To the extent that Section 41‐3‐5, New Mexico Statutes Annotated, 1978 compilation (as such section may be amended), shall be applicable and for the purpose of relieving each Party, its directors, members of its governing body, officers and employees of any liability to make contribution to other non‐Party tortfeasors, the foregoing covenant not to execute hereby effects a reduction of all injured Parties’ damages recoverable against all other non‐Party tortfeasors to the extent of the pro rata share (as referred to in Section 41‐3‐5, New Mexico Statutes Annotated, 1978 compilation, as such section may be amended) of the other Parties, their directors, members of their governing bodies, officers and employees.
36.1.3    Each Party agrees, upon request by any other Party, to make, execute and deliver any and all documents or take such other action as may reasonably be required to effectuate the intent of this Section 36.1.
36.2    Except as provided in Sections 36.4, 36.5 and 36.6, the costs and expenses of discharging all work liability imposed upon one or more of the Parties, for which payment is not made by insurance, shall be allocated among the Parties in proportion to 



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their respective Participation Shares in the property giving rise to the work liability.  Work liability is defined as liability of one or more Parties for any loss, damage, claim, cost, charge or expense of any kind or nature (including direct, indirect or consequential) suffered or incurred by any party other than a Party, whether or not resulting or to result in the future from the negligence of any Party, its directors, members of its governing body, officers, employees or any other person or entity whose negligence would be imputed to such Party, that has resulted or may result in the future from (i) performance or nonperformance of the work herein described, (ii) operation, maintenance, use or ownership of the San Juan Project, and (iii) past or future performance or nonperformance of the obligations of any Party under any of the Project Agreements.
36.3    If it cannot be determined which property gave rise to work liability, the allocation for discharging costs and expenses associated therewith shall be as specified in Section 22.1.7.  
36.4    Except for liability resulting from Willful Action (which subject to the provisions of Section 36.6 shall be the responsibility of the willfully acting Participant), any Party whose electric customer shall have a claim or bring an action against any other Party for any death, injury, loss or damage arising out of or in connection with electric service to such customer caused by the operation or failure of operation of the San Juan Project or any portion thereof shall indemnify and hold harmless such other Party, its directors, members of its governing body, officers and employees from and against any liability for such death, injury, loss or damage.
        



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36.5    Each Party shall be responsible for any damage, loss, claim, cost, charge or expense that is not covered by insurance and results from its own Willful Action as defined in Section 5.57.2 and shall indemnify and hold harmless the other Parties, their directors, members of their governing bodies, officers and employees, from any such damage, loss, claim, cost, charge or expense.
36.6    Except as provided in Section 36.5, the aggregate liability of any Party to all other Parties for Willful Action not covered by insurance shall be determined as follows:  
36.6.1    All such liability for damages, losses, claims, costs, charges or expenses of such Party shall not exceed ten million dollars ($10,000,000) per occurrence.  Each Party extends to each other Party, its directors, members of its governing body, officers and employees its covenant not to execute, levy or otherwise enforce a judgment against any of them for any such aggregate liability in excess of ten million dollars ($10,000,000) per occurrence.
36.6.2    A claim based on Willful Action must be perfected by filing suit in a court of competent jurisdiction within three (3) years after the Willful Action occurs.  All claims made thereafter relating to the same Willful Action shall be barred by this Section 36.6.2.  The award to each nonwillfully acting Party from each Participant determined to have committed Willful Action shall be determined as follows:  (i) Each Party who successfully files suit for remuneration shall receive the lesser of (a) its final judgment awarded (or settlement made) or (b) its pro rata Participation Share of the ten million dollar ($10,000,000) maximum recovery 



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established in Section 36.6.1; (ii) When all pending suits are resolved, those Parties who were awarded judgments or reached settlements but whose claims were not fully satisfied pursuant to Section 36.6.2(i) shall be entitled to participate in any remaining portion of the ten million dollar ($10,000,000) maximum recovery limit, based upon the ratio of the unsatisfied portion of such Party’s judgment or settlement to the total unsatisfied portion of all such judgments and settlements.  Such participation shall be limited to the Parties’ unsatisfied judgments or settlements.
36.7    The provisions of this Section 36 shall not be construed so as to relieve any insurer of its obligation to pay any insurance proceeds in accordance with the terms and conditions of valid and collectible insurance policies.
36.8    If a court of competent jurisdiction determines upon a challenge by a Party or third party that the provisions of Section 56-7-1, New Mexico Statutes Annotated, 1978 Compilation, as amended, are applicable to this Agreement, the Parties agree that any agreement to indemnify contained in this Agreement shall be enforced only to the extent it requires the indemnitor to indemnify or hold harmless the indemnitee, including its officers, employees or agents, against liability, claims, damages, losses or expenses, including attorney’s fees, only to the extent that the liability, damages, losses or costs are caused by, or arise out of, the acts or omissions of the indemnitor or its officers, employees or agents.  
        



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36.9    The Parties agree that the aggregate liability limit of ten million dollars ($10,000,000) referenced in Sections 36.6.1 and 36.6.2 may be determined in the future to be inappropriate and shall, at the request of any Party, make a good faith effort to evaluate and, if appropriate, revise said limit.  



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37.0    ARBITRATION:  
37.1    If a dispute between or among any of the Parties (which term, for purposes of this Section 37, shall be deemed to include the Operating Agent) should arise in relation to the performance or nonperformance of any obligation under this Agreement, any Party(ies) may call for submission of the dispute to arbitration, which call shall be binding upon all of the other affected Party(ies).  Disputes arising under the Mine Reclamation Agreement and the Decommissioning Agreement shall be resolved pursuant to the dispute resolution provisions of those agreements.  Disputes arising under Sections 4.3 or 5 of the Restructuring Agreement, which provisions are incorporated into Sections 7.13.1 and 23 of this Agreement, shall be resolved pursuant to the dispute resolution provisions of this Agreement.  Any other disputes arising under the Restructuring Agreement shall be resolved pursuant to the dispute resolution provisions of the Restructuring Agreement.
37.2    The Party(ies) calling for arbitration shall give written notice to all other Parties, setting forth in such notice in adequate detail the entity(ies) against whom relief is sought, the nature of the dispute, the amount or amounts, if any, involved in such dispute, and the remedy sought by such arbitration proceedings.  Within twenty (20) days after receipt of such notice, any other Party(ies) involved may, by written response to the first Party(ies), as well as the other Party(ies), submit its or their own statement of the matter at issue and set forth in adequate detail additional related matters or issues to be arbitrated.  Thereafter, the Party(ies) first submitting its or their notice of the matter at issue shall have 



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ten (10) days in which to submit a written rebuttal statement, copies of which shall be provided to all other Parties.
37.3    Within ten (10) days following delivery of the last written submittal pursuant to Section 37.2, the affected Party(ies), acting through their respective representatives, shall meet for the purpose of selecting arbitrators.  Each affected Party, or group of Parties, representing one side of the dispute, shall designate an arbitrator.  The arbitrators so selected shall meet within twenty (20) days following their selection and shall select additional arbitrator(s), the number of which additional arbitrators shall be one (1) less than the total number of arbitrators selected by the affected Parties.  If the arbitrators selected by the affected Parties, as herein provided, shall fail to select such additional arbitrator(s) within said twenty (20) day period, then the arbitrators shall request from the American Arbitration Association (or similar organization if the American Arbitration Association should not exist at the time) a list of arbitrators who are qualified and eligible to serve as hereinafter provided.  The arbitrators selected by the affected Parties shall take turns striking names from the list of arbitrators furnished by the American Arbitration Association, and the last name(s) remaining on said list shall be the additional arbitrator(s).  All arbitrators shall be persons skilled and experienced in the field which gives rise to the dispute, and no person shall be eligible for appointment as an arbitrator who is an officer or employee of any of the Parties to the dispute or is otherwise interested in the matter to be arbitrated.
37.4    Except as otherwise provided in this Section 37 or otherwise agreed by the Parties to the dispute, the arbitration shall be governed by the rules and practices of the 



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American Arbitration Association (or rules and practices of a similar organization if the American Arbitration Association should not exist at that time) from time to time in force, except that if such rules and practices, as modified herein, shall conflict with New Mexico Rules of Civil Procedure or any other provisions of New Mexico law then in force which are specifically applicable to arbitration proceedings, such New Mexico laws shall govern.
37.5    Included in the issues which may be submitted to arbitration pursuant to this Section 37 is the issue of whether the right to arbitrate a particular dispute is permitted under the Project Agreements.
37.6    The arbitrators shall hear evidence submitted by the respective Parties or group or groups of Parties and may call for additional information, which additional information shall be furnished by the Party having such information.  The decision of a majority of the arbitrators shall be binding upon all the Parties and shall be based on the provisions of the Project Agreements and New Mexico law.
37.7    This agreement to arbitrate shall be specifically enforceable and the award of the arbitrators shall be final and binding upon the Parties to the extent provided by the laws of the State of New Mexico.  Any award may be filed with the clerk of any court having jurisdiction over the Parties or any of them against whom the award is rendered, and, upon such filing, such award, to the extent permitted by the laws of the jurisdiction in which said award is filed, shall be specifically enforceable or shall form the basis of a declaratory judgment or other similar relief.
        



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37.8    Each Party or group of Parties shall be responsible for the fees and expenses of the arbitrator selected by that Party or group of Parties, unless the decision of the arbitrators shall specify some other apportionment of such fees and expenses.  The fees and expenses of the neutral arbitrators shall be shared among the affected Parties equally, unless the decision of the arbitrators shall specify some other apportionment of such fees and expenses.  All other expenses and costs of the arbitration, including attorney fees, shall be borne by the Party incurring the same.
37.9    In the event that any Party(ies) shall attempt to institute or to carry out the provisions herein set forth in regard to arbitration, and such Party(ies) shall not be able to obtain a valid and enforceable arbitration decree, such Party(ies) shall be entitled to seek legal remedies in a court having jurisdiction in the premises, and the provisions in this Section 37 referring to arbitration decisions shall then be deemed applicable to final decisions of such court.



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PART VIII
RETIREMENT AND RECONSTRUCTION
38.0    DESTRUCTION, DAMAGE OR CONDEMNATION OF A UNIT:  
38.1    If all, or substantially all, of a Unit is destroyed, damaged or condemned, then the Participants with Participation Shares in that Unit by unanimous agreement may elect to repair or reconstruct the damaged, destroyed or condemned Unit in such a manner as to restore the Unit to substantially the same general character or use as the original, or to such other character or use as the Participants may then mutually agree.  In the event of such election, it shall be the obligation of the Participants to pay for the costs of such repair or reconstruction in accordance with the Participation Shares of the respective Participants in such Unit, and, upon completion thereof, the Participants’ rights, titles and interests therein shall be as provided in this Agreement.  The retirement of Units 2 and 3 shall not be within the scope of this Section 38.
38.2    Failure to reach unanimous agreement as provided in Section 38.1 shall be deemed to be an election not to repair or reconstruct the damaged, destroyed or condemned Unit, in which event the proceeds from any insurance or from any award shall be distributed to the Participants in accordance with their respective Participation Shares in such Unit.  The facilities not destroyed, damaged or condemned shall be disposed of by the Participants in a manner to be mutually agreed upon, and the proceeds from such disposition shall be distributed in accordance with the Participation Shares of the respective Participants in such Unit.   Nothing in this section shall be  deemed  to  preclude  any  Participant  or  group  of 



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Participants in the Unit from agreeing to repair, reconstruct or replace the damaged, destroyed or condemned Unit.  
38.3     In the event that less than substantially all of a Unit is destroyed, damaged or condemned, then it shall be the obligation of the Participants having a Participation Share in such Unit to repair or reconstruct such Unit.  Each Participant shall be obligated to pay its proportionate share of the costs of such repair or reconstruction in accordance with Section 6.2.  
38.4    In the event that any common equipment and/or facility is destroyed, damaged or condemned, then it shall be the obligation of the Participants having a Participation Share in such common equipment and/or facilities to repair or reconstruct such damaged, destroyed or condemned equipment and/or facilities.  Each Participant shall be obligated to pay its proportionate share of the costs of such repair or reconstruction in accordance with Section 6.2.



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39.0    RIGHTS OF PARTICIPANTS UPON TERMINATION:  
39.1     In the event the Participants by unanimous agreement abandon, retire or otherwise terminate or suspend operation of the San Juan Project prior to the termination of this Agreement, the facilities forming the San Juan Project shall be disposed of by the Participants in a manner to be unanimously agreed upon and the proceeds from such disposition shall be distributed to the Participants in accordance with their respective Participation Shares. 



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40.0    DECOMMISSIONING OF THE PROJECT:    
40.1    The Participants acknowledge the appropriateness of incorporating in a future amendment to this Agreement, or in another appropriate contractual instrument, provisions which address the decommissioning of the San Juan Project and/or of one or more Units.  It is recognized, however, that the resolution of issues associated with San Juan Project decommissioning will require protracted study.  The Participants therefore agree to establish a task force or other forum for the careful and deliberate consideration of decommissioning issues so that these issues may be addressed and resolved in a timely manner.  The Operating Agent shall propose to the Participants a methodology and a schedule for addressing decommissioning issues.
40.2    In recognition of, and in order to implement Section 40.1, upon the effective date of the Decommissioning Agreement, the decommissioning of the San Juan Project shall be governed by the Decommissioning Agreement.  



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PART IX
MISCELLANEOUS PROVISIONS
41.0    RELATIONSHIP OF PARTIES:
41.1    The covenants, obligations and liabilities of the Parties are intended to be several and not joint or collective, and nothing herein contained shall ever be construed to create an association, joint venture, trust or partnership, or to impose a trust or partnership covenant, obligation or liability on or with regard to any one or more of the Parties.  Each Party shall be individually responsible for its own covenants, obligations and liabilities as herein provided.  No Party or group of Parties shall be under the control of or shall be deemed to control any other Party or the Parties as a group.  No Party shall be the agent of or have a right or power to bind any other Party without its express written consent, except as expressly provided herein.  
41.2    The Parties hereby elect to be excluded from the application of Subchapter “K” of Chapter 1 of Subtitle “A” of the Internal Revenue Code of 1986, or such portion or portions thereof as may be permitted or authorized by the Secretary of the Treasury or its delegate insofar as such subchapter, or any portion or portions thereof, may be applicable to the Parties hereunder. 



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42.0    NOTICES:  
42.1    Any notice, demand or request provided for in this Agreement, or served, given or made in connection with it, shall be deemed properly served, given or made (i) when delivered personally or by prepaid overnight courier, with a record of receipt, (ii) the fourth day if mailed by certified mail, return receipt requested, or (iii) the day of transmission, if sent by facsimile or electronic mail during regular business hours or the day after transmission, if sent after regular business hours (provided however, that such facsimile or electronic mail shall be followed on the same day or next business day with the sending of a duplicate notice, demand or request by a nationally recognized prepaid overnight courier with record of receipt), to the persons specified below:


42.1.1    Public Service Company of New Mexico
Attn: Vice President, PNM Generation
2401 Aztec NE, Bldg. A
Albuquerque, NM 87107


With a copy to:
    
Public Service Company of New Mexico
c/o Secretary
414 Silver Ave. SW
Albuquerque, New Mexico  87102


42.1.2    Tucson Electric Power Company
88 E. Broadway Blvd.
MS HQE901
                
Tucson, Arizona  85701
Attn: Corporate Secretary


42.1.3    City of Farmington
c/o City Clerk
800 Municipal Drive 
                



163                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






Farmington, NM  87401


With a copy to:
Farmington Electric Utility System
Electric Utility Director
101 North Browning Parkway
Farmington, NM 87401


42.1.4    M-S-R Public Power Agency
c/o General Manager
1231 11th Street
Modesto, CA  95354


42.1.5    Southern California Public Power Authority
c/o Executive Director
1160 Nicole Court
Glendora, CA  91740


42.1.6    City of Anaheim
c/o City Clerk
200 South Anaheim Boulevard
Anaheim, CA  92805


With a copy to:


Public Utilities General Manager
201 South Anaheim Boulevard
Suite 1101
Anaheim, CA 92805


42.1.7    Incorporated County of 
Los Alamos, New Mexico
c/o County Clerk
1000 Central Ave.
Suite 240
Los Alamos, NM  87544


with a copy to:


Incorporated County of 
Los Alamos, New Mexico
c/o Utilities Manager
                



164                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






1000 Central Ave.
Suite 130
Los Alamos, NM  87544


42.1.8    Utah Associated Municipal Power Systems
c/o General Manager
155 North 400 West
Suite 480
Salt Lake City, UT 84103
                
42.1.9    Tri-State Generation and Transmission
Association, Inc.
c/o Chief Executive Officer
1100 West 116th Avenue
Westminster, CO 80234
Or P. O. Box 33695
Denver, CO  80233


For purposes of overnight courier service, Tri-State’s address is:


Tri-State Generation and Transmission Association, Inc.
c/o Chief Executive Officer
3761 Eureka Way
Frederick, CO 80516


42.1.10    PNMR Development and Management Corporation
c/o Corporate Secretary
PNM Resources, Inc.
Corporate Headquarters
414 Silver Avenue SW
Albuquerque, NM 87158-1245


42.2    A Party may, at any time or from time to time, by written notice to the other Parties, change the designation or address of the person so specified as the one to receive notices pursuant to this Agreement.  
42.3    The Operating Agent shall provide to each Party a copy of any material notice, demand or request given or received by it in connection with the San Juan Project. 



165                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






43.0     OTHER PROVISIONS:  
43.1    Each Party agrees, upon request by another Party, to make, execute and deliver any and all documents reasonably required to implement the terms of this Agreement.  
43.2    No Party shall be considered to be in default in the performance of any of the obligations hereunder (other than obligations of a Party to pay costs and expenses) if failure of performance shall be due to uncontrollable forces.  The term “uncontrollable forces” shall mean any cause beyond the control of the Party affected, including but not limited to failure of facilities, flood, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance, labor dispute, sabotage or terrorism, restraint by court order or public authority, or failure to obtain approval from a necessary governmental authority which by exercise of due diligence and foresight such Party could not reasonably have been expected to avoid and which by exercise of due diligence it shall be unable to overcome.  Nothing contained herein shall be construed so as to require a Party to settle any strike or labor dispute in which it may be involved.  Any Party rendered unable to fulfill any obligation by reason of uncontrollable forces shall exercise due diligence to remove such inability with all reasonable dispatch.  
43.3    The captions and headings appearing in this Agreement are inserted merely to facilitate reference and shall have no bearing upon the interpretation of the provisions hereof.  
        



166                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






43.4    This Agreement is made under and shall be governed by the laws of the State of New Mexico, without regard to conflicts of law principles.  
43.5    The covenants and obligations set forth and contained in this Agreement are to be deemed to be independent covenants, not dependent covenants, and the obligation of a Party to perform all of the obligations and covenants to be by it kept and performed is not conditioned on the performance by another Party of all of the covenants and obligations to be kept and performed by it.  
43.6    In the event that any of the terms or conditions of this Agreement, or the application of any such term or condition to any person or circumstance, shall be held invalid by any court having jurisdiction in the premises, the remainder of this Agreement, and the application of such terms or conditions to persons or circumstances other than those as to which it is held invalid, shall not be affected thereby.  
43.7    All costs or expenses, including all taxes that the Operating Agent is required to pay (but not specifically referred to in other sections of this Agreement), which are incurred by the Operating Agent in connection with the performance of its obligations under this Agreement and which are not specifically allocated to the Parties in accordance with this Agreement shall be equitably allocated among the Parties in a manner to be established by the Coordination Committee.  
43.8    Should a change in circumstances, economic factors, or basic technology occur which results or may result in a substantial increase or decrease in the benefits to or expenses incurred by a Party, including the Operating Agent, which such change was not 



167                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






within the reasonable contemplation of the Parties at the time of the execution of this Agreement, the Parties, including the Operating Agent, shall negotiate in good faith in order that an appropriate and equitable adjustment shall be made in the reimbursement of the Operating Agent and in the allocation of expenses among the Parties.  Such adjustment shall be fair and equitable as to both the Operating Agent and the other Parties.  
 43.9    The execution of this Agreement shall not affect any rights or obligations of the Parties which shall have accrued prior to or coincident with the effective date of this Agreement, including any obligation to pay money or take other actions in accordance with the Original San Juan PPA, the Amended and Restated San Juan PPA, the UG-CSA, the Co-Tenancy Agreement, the Operating Agreement, the Restructuring Agreement, the Decommissioning Agreement, the Mine Reclamation Agreement, the UG-CSA Termination Agreement, the CCBDA Termination Agreement or any other San Juan Project-related agreement.
43.10  Except as provided in Sections 35.1 and 37.1, to the extent of any conflict between this Agreement and the Restructuring Agreement, the provisions of the Restructuring Agreement shall control.



168                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






44.0    EXECUTION IN COUNTERPARTS:
44.1    This Agreement may be executed in any number of counterparts, and each executed counterpart shall have the same force and effect as an original instrument as if all the Parties to the aggregated counterparts had signed the same instrument.  Any signature page of this Agreement may be detached from any counterpart thereof without impairing the legal effect of any signatures thereon and may be attached to any other counterpart of this Agreement identical in form thereto but having attached to it one or more additional pages.  Electronic or pdf signatures have the same effect as an original signature.





169                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






45.0    AMENDMENTS:
45.1    Except as provided in Section 45.2, this Agreement may be amended only by written instrument executed by all of the Parties with the same formality as this Agreement.
45.2    The Coordination Committee, by unanimous vote, may amend any one or more of the exhibits attached to this Agreement.  In the event of any such action by the Coordination Committee, a copy of the new exhibit shall be attached to this Agreement to replace the old or superseded exhibit, without the necessity of formally amending this Agreement.  Any such action shall not affect other provisions of this Agreement, including other exhibits thereto.





170                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






IN WITNESS WHEREOF, the Parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31st day of July, 2015.  


PUBLIC SERVICE COMPANY
OF NEW MEXICO


                    
By_/s/ Chris M. Olson ___________________
    Its__Vice President Generation__________




TUCSON ELECTRIC POWER COMPANY
    
                    
By___________________________________
    Its_________________________________






THE CITY OF FARMINGTON, NEW MEXICO




By______________________________________
    Its____________________________________




M-S-R PUBLIC POWER AGENCY






By______________________________________
    Its____________________________________




THE INCORPORATED COUNTY OF LOS ALAMOS, 
    NEW MEXICO




By______________________________________
    Its____________________________________







                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






IN WITNESS WHEREOF, the Parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31st day of July, 2015.  


PUBLIC SERVICE COMPANY
OF NEW MEXICO


                    
By___________________________________
    Its_________________________________




TUCSON ELECTRIC POWER COMPANY
    
                    
By _/s/_Mark Mansfield _________________
    Its __VP Energy Resources _________  __




THE CITY OF FARMINGTON, NEW MEXICO




By______________________________________
    Its____________________________________




M-S-R PUBLIC POWER AGENCY






By______________________________________
    Its____________________________________




THE INCORPORATED COUNTY OF LOS ALAMOS, 
    NEW MEXICO




By______________________________________
    Its____________________________________









171                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






IN WITNESS WHEREOF, the Parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31st day of July, 2015.  


PUBLIC SERVICE COMPANY
OF NEW MEXICO


                    
By___________________________________
    Its_________________________________




TUCSON ELECTRIC POWER COMPANY
    
                    
By___________________________________
    Its_________________________________






THE CITY OF FARMINGTON, NEW MEXICO




By _/s/_Robert Mayes______________________
    Its__ City Manager______________________




M-S-R PUBLIC POWER AGENCY






By______________________________________
    Its____________________________________




THE INCORPORATED COUNTY OF LOS ALAMOS, 
    NEW MEXICO




By______________________________________
    Its____________________________________







171                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






IN WITNESS WHEREOF, the Parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31st day of July, 2015.  


PUBLIC SERVICE COMPANY
OF NEW MEXICO


                    
By___________________________________
    Its_________________________________




TUCSON ELECTRIC POWER COMPANY
    
                    
By___________________________________
    Its_________________________________






THE CITY OF FARMINGTON, NEW MEXICO




By______________________________________
    Its____________________________________




M-S-R PUBLIC POWER AGENCY






By__/s/_Martin Hopper_____________________
    Its___ General Manager__________________




THE INCORPORATED COUNTY OF LOS ALAMOS, 
    NEW MEXICO




By______________________________________
    Its____________________________________







171                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






IN WITNESS WHEREOF, the Parties, by their duly authorized representatives, have caused this Agreement to be made as of this 31st day of July, 2015.  


PUBLIC SERVICE COMPANY
OF NEW MEXICO


                    
By___________________________________
    Its_________________________________




TUCSON ELECTRIC POWER COMPANY
    
                    
By___________________________________
    Its_________________________________






THE CITY OF FARMINGTON, NEW MEXICO




By______________________________________
    Its____________________________________




M-S-R PUBLIC POWER AGENCY






By______________________________________
    Its____________________________________




THE INCORPORATED COUNTY OF LOS ALAMOS, 
    NEW MEXICO




By ___/s/ Kristin Henderson__________________
    Its ___Council Chair______________________







171                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






SOUTHERN CALIFORNIA PUBLIC POWER 
    AUTHORITY




By_/s/ Fred Mason_________________________
    Its __President______________________________




CITY OF ANAHEIM




By______________________________________
    Its____________________________________




UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS




By______________________________________
    Its____________________________________




TRI-STATE GENERATION AND TRANSMISSION
    ASSOCIATION, INC.




By______________________________________
    Its____________________________________




PNMR DEVELOPMENT AND MANAGEMENT CORPORATION




By ________________________________________
    Its_______________________________________







172                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






SOUTHERN CALIFORNIA PUBLIC POWER 
    AUTHORITY




By______________________________________
    Its____________________________________




CITY OF ANAHEIM
APPROVED AS TO FORM:
MICHAEL R.W. HOUSTON, CITY ATTORNEY
By:  __/s/_Dukku Lee_______________    BY _________/s/ Alison M. Kott 7-27-15___
Dukku Lee                     Alison M. Kott, Assistant City Attorney
Public Utilities General Manager




UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS




By______________________________________
    Its____________________________________




TRI-STATE GENERATION AND TRANSMISSION
    ASSOCIATION, INC.




By______________________________________
    Its____________________________________




PNMR DEVELOPMENT AND MANAGEMENT CORPORATION




By ________________________________________
    Its_______________________________________







172                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






SOUTHERN CALIFORNIA PUBLIC POWER 
    AUTHORITY




By______________________________________
    Its____________________________________




CITY OF ANAHEIM




By______________________________________
    Its____________________________________




UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS




By__/s/ Douglas Hunter_____________________
    Its__ General Manager____________________




TRI-STATE GENERATION AND TRANSMISSION
    ASSOCIATION, INC.




By______________________________________
    Its____________________________________




PNMR DEVELOPMENT AND MANAGEMENT CORPORATION




By ________________________________________
    Its_______________________________________







172                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






SOUTHERN CALIFORNIA PUBLIC POWER 
    AUTHORITY




By______________________________________
    Its____________________________________




CITY OF ANAHEIM




By______________________________________
    Its____________________________________




UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS




By______________________________________
    Its____________________________________




TRI-STATE GENERATION AND TRANSMISSION
    ASSOCIATION, INC.




By __/s/_Micheal McInnes__________________
    Its___ CEO                              _____________




PNMR DEVELOPMENT AND MANAGEMENT CORPORATION




By ________________________________________
    Its_______________________________________







172                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






SOUTHERN CALIFORNIA PUBLIC POWER 
    AUTHORITY




By______________________________________
    Its____________________________________




CITY OF ANAHEIM




By______________________________________
    Its____________________________________




UTAH ASSOCIATED MUNICIPAL POWER SYSTEMS




By______________________________________
    Its____________________________________




TRI-STATE GENERATION AND TRANSMISSION
    ASSOCIATION, INC.




By______________________________________
    Its____________________________________




PNMR DEVELOPMENT AND MANAGEMENT CORPORATION




By ___/s/ Elisabeth Eden_______________________
    Its_ President, Chief Executive Officer and Treasurer





                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






STATE OF NEW MEXICO    )
  )ss.
COUNTY OF BERNALILLO )




The foregoing instrument was acknowledged before me on this _30th_ day of June, 2015, by _Chris M. Olson___, _____VP, Generation________________ of Public Service Company of New Mexico, a New Mexico corporation, on behalf of the corporation.  




/s/ Patricia A. Salls        
Notary Public




My commission expires:


September 14, 2018








STATE OF ARIZONA    )
)ss.
COUNTY OF     PIMA        )




The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of Tucson Electric Power Company, an Arizona corporation, on behalf of the corporation.  




                    
Notary Public




My commission expires:


                









                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






STATE OF NEW MEXICO    )
  )ss.
COUNTY OF BERNALILLO )




The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of Public Service Company of New Mexico, a New Mexico corporation, on behalf of the corporation.  




                    
Notary Public




My commission expires:


                








STATE OF ARIZONA    )
)ss.
COUNTY OF     PIMA        )




The foregoing instrument was acknowledged before me on this _1st __ day of _July____, 2015, by _Mark____________, _Mansfield__________________ of Tucson Electric Power Company, an Arizona corporation, on behalf of the corporation.  




/s/ Cheryl T. Gottshall        
Notary Public




My commission expires:


       June 30, 2018    









173                                       Restructuring Amendment 7/31/2015




EXECUTION VERSION
 






STATE OF NEW MEXICO    )
)ss.
COUNTY OF SAN JUAN    )




The foregoing instrument was acknowledged before me on this _1st__ day of _July____, 2015, by _Robert Mayes_______________, _City Manager__________ of The City of Farmington, New Mexico, a New Mexico municipal corporation, on behalf of the municipal corporation.  




     /s/ Melody A. Coyner    
Notary Public




My commission expires:


05/29/19        






STATE OF CALIFORNIA       )
   )ss.
COUNTY OF __________________)




The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of M-S-R Public Power Agency, a California joint powers agency, on behalf of said joint powers agency.  




                    
Notary Public




My commission expires:


                









174                                       Restructuring Amendment 7/31/2015








CALIFORNIA ALL-PURPOSE ACKNOWLEDGMENT                CIVIL CODE § 1189


	
	
	A notary public or other officer completing this certificate verifies only the identity of the individual who signed the document to which this certificate is attached, and not the truthfulness, accuracy, or validity of that document.






State of California                )
County of   ____Amador___________________)
On __July 27, 2015_________before me, _________Lynn V. Verhagen, Notary Public______________ ,            Date                    Here Insert Name and Title of the Officer    
personally appeared _______Martin R. Hopper______________________________________________
Name(s) of Signer(s)
____________________________________________________________________________________


who proved to me on the basis of satisfactory evidence to be the person(s) whose name(s) is/are 
subscribed to the within instrument and acknowledged to me that he/she/they executed the same in 
his/her/their authorized capacity(ies), and that by his/her/their signature(s) on the instrument the person(s), 
or the entity upon behalf of which the person(s) acted, executed the instrument.


I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.
WITNESS my hand and official seal.




Signature_/s/ Lynn V. Verhagen_________
Signature of Notary Public






     Place Notary Seal Above
-----------------------------------------------------------------OPTIONAL----------------------------------------------------------
Though this section is optional, completing this information can deter alteration of the document or 
fraudulent reattachment of this form to an unintended document.


Description of Attached Document
Title or Type of Document:___Restructuring Agreement_________  Document Date: ___7/27/15______
Number of Pages: ___177____ Signer(s) Other Than Named Above: 
______________________________Capacity(ies) Claimed by Signer(s)


	
		
	□Signer's Name:_____________________
	□Signer's Name:_____________________

	□Corporate Officer ___ Title(s):_________
	□Corporate Officer ___ Title(s):_________

	□Partner -         □Limited    □General
	□Partner -         □Limited    □General

	□Individual    □Attorney in Fact
	□Individual    □Attorney in Fact

	□Trustee    □Guardian or Conservator
	□Trustee    □Guardian or Conservator

	□Other: ____________________________
	□Other: ____________________________

	Signer Is Representing: _______________
	Signer Is Representing: _______________

	__________________________________
	__________________________________











©2014 National Notary Association ·www.NatlonalNotary.org • 1-800-US NOTARY (1-800-876-6827)   Item #5907









STATE OF NEW MEXICO        )
)ss.
COUNTY OF     LOS ALAMOS    )




The foregoing instrument was acknowledged before me on this _28th__ day of July, 2015, by ____Kristin Henderson_______, ____Council Chair___________ of The Incorporated County of Los Alamos, New Mexico, a New Mexico Class H County, on behalf of said county.  




/s/ Melissa A. Salmon    
Notary Public




My commission expires:


__January 07, 2018    








STATE OF CALIFORNIA        )
)ss.
COUNTY OF     ________________    )




The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of Southern California Public Power Authority, a California joint powers agency, on behalf of said joint powers agency.  




                    
Notary Public




My commission expires:


                











175                                       Restructuring Amendment 7/31/2015






CALIFORNIA ALL-PURPOSE ACKNOWLEDGMENT                
CIVIL CODE § 1189


State of California                )


County of   ____Los Angeles___________________)


On __July 16, 2015_________before me, _________Salpi Ortiz, a notary public________________ ,
Date                    Here Insert Name and Title of the Officer    


personally appeared _______Fred Mason___________________________________
Name(s) of Signer(s)
____________________________________________________________________________________
who proved to me on the basis of satisfactory evidence to be the person(s) whose name(s) is/are subscribed to the within instrument and acknowledged to me that he/she/they executed the same in his/her/their authorized capacity(ies), and that by his/her/their signature(s) on the instrument the person(s), or the entity upon behalf of which the person(s) acted, executed the instrument.


I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.


WITNESS my hand and official seal.




Signature_/s/ Salpi Ortiz_________
Signature of Notary Public
 Place Notary Seal Above
-----------------------------------------------------------------OPTIONAL----------------------------------------------------------
Though this section is optional, completing this information can deter alteration of the document or fraudulent reattachment of this form to an unintended document.


Description of Attached Document
Title or Type of Document:_________________________  Document Date: _______________
Number of Pages: _______ Signer(s) Other Than Named Above: ______________________________


Capacity(ies) Claimed by Signer(s)


	
		
	□Signer's Name:_____________________
	□Signer's Name:_____________________

	□Corporate Officer ___ Title(s):_________
	□Corporate Officer ___ Title(s):_________

	□Partner -         □Limited    □General
	□Partner -         □Limited    □General

	□Individual    □Attorney in Fact
	□Individual    □Attorney in Fact

	□Trustee    □Guardian or Conservator
	□Trustee    □Guardian or Conservator

	□Other: ____________________________
	□Other: ____________________________

	Signer Is Representing: _______________
	Signer Is Representing: _______________

	__________________________________
	__________________________________









©2013 National Notary Association ·www.NatlonalNotary.org • 1-800-US NOTARY (1-800-876-6827)   Item #5907

`










CALIFORNIA ALL-PURPOSE ACKNOWLEGEMENT             CIVIL CODE #1189




	
	
	A notary public or other officer completing this certificate verifies only the identity of the individual who signed the document to which this certificate is attached, and not the truthfulness, accuracy, or validity of that document.






STATE OF CALIFORNIA    )
)ss.
COUNTY OF ORANGE    )




On   July 27, 2015 before me,  Annie DeSouza  , Notary  Public, personally 
Appeared _DUKKU LEE_ who proved to me on the basis of satisfactory evidence to be the person(s) whose name(s) is/are subscribed to the within instrument and acknowledged to me that he/she/they executed the same in his/her/their authorized capacity(ies), and that by his/her/their signature(s) on the instrument the person(s), or the entity upon behalf of which the person(s) acted, executed the instrument.


I certify under PENALTY OF PERJURY under the laws of the State of California that the foregoing paragraph is true and correct.






WITNESS my hand and official seal.


___/s/ Annie DeSouza___




[SEAL]



`










STATE OF CALIFORNIA    )
)ss.
COUNTY OF ORANGE    )






The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of the City of Anaheim, a California municipal corporation, on behalf of the said municipal corporation.  




                    
Notary Public




My commission expires:


                








STATE OF UTAH        )
)ss.
COUNTY OF SALT LAKE    )




The foregoing instrument was acknowledged before me on this _30th_ day of July, 2015, by _Douglas Hunter_________, __General Manager_________ of Utah Associated Municipal Power Systems, a political subdivision of the State of Utah, on behalf of said entity.  




/s/ Andrea Miller        
Notary Public




My commission expires:


June 15, 2019    





`
176                                       Restructuring Amendment 7/31/2015








STATE OF COLORADO    )
)ss.
COUNTY OF     ADAMS    )




The foregoing instrument was acknowledged before me on this _22___ day of July, 2015, by ___Micheal S. McInnes_____, _     CEO____________________ of Tri-State Generation and Transmission Association, Inc., a Colorado cooperative corporation, on behalf of the said cooperative corporation.  




/s/ Penny L. McLaughlin    
Notary Public




My commission expires:


September 11, 2018    




STATE OF NEW MEXICO    )
  )ss.
COUNTY OF BERNALILLO )




The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of PNMR Development and Management Corporation, a New Mexico corporation, on behalf of the corporation.  




                    
Notary Public




My commission expires:


                













177                                       Restructuring Amendment 7/31/2015








STATE OF COLORADO    )
)ss.
COUNTY OF     ADAMS    )




The foregoing instrument was acknowledged before me on this ____ day of ________, 2015, by ________________________, _____________________ of Tri-State Generation and Transmission Association, Inc., a Colorado cooperative corporation, on behalf of the said cooperative corporation.  




                    
Notary Public




My commission expires:


                




STATE OF NEW MEXICO    )
  )ss.
COUNTY OF BERNALILLO )




The foregoing instrument was acknowledged before me on this _30th_ day of _June_, 2015, by ___Elisabeth Eden____, ____President, CEO and Treasurer__ of PNMR Development and Management Corporation, a New Mexico corporation, on behalf of the corporation.  




/s/ Marcella Kercher        
Notary Public




My commission expires:


12/19/2015        











`
                                       Restructuring Amendment 7/31/2015








REFERENCES TO EXHIBITS IN
PARTICIPATION AGREEMENT


Exhibit No.        References in Agreement         Subject Matter
I            §§ 2.10, 6.1                Real Property 
II            § 5.24                    Annual Minimum Coal
III            §§ 5.44, 6.5                Switchyard Facilities
IV            §§ 6.2, 6.2.8                Ownership of Equipment
V            §§ 22.1.7, 22.1.9            O&M of Equipment
VI            §§ 7.11, 22.2.2, 22.6, 22.6.1, 22.7, 22.8
A&G Expenses
VII            § 23.3                    Coal Allocation and Billing
VIII            §§ 18.4, 19.4, 20.5, 21.4        Adjustment of Voting
IX            §§ 5.19, 23.4.1, 23.4.1.3        Fixed Fuel Expense
X            §§ 5.55, 23.4.1, 23.4.1.3        Variable Fuel Expense





















EXHIBIT I









EXHIBIT I




This Exhibit I to the Restructuring Amendment Amending and Restating the Amended and Restated San Juan Project Participation Agreement contains a map of the San Juan Project Generating Station site and the River Weir site, showing Parcels A, B, C, C-1 D, E and F, the parcels of real property underlying the San Juan Project and River Weir sites.  Also included in the Exhibit are property descriptions and separate maps showing Parcels A through F. PNM and TEP each has a one-half undivided ownership interest in the parcels described as Parcels A, B, C, D, E and F; and PNM and TEP each has a one-half leasehold interest in Parcel C-1.



Exh. I - 1






PARCEL A


The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:


Section 16:    SW 1/4
Section 20:    NE 1/4, N 1/2 SE 1/4, SW 1/4SE 1/4
Section 21:    NW 1/4 NW 1/4
Section 29:    NE 1/4




PARCEL B


The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:


Section 19:    SE 1/4 SW 1/4, SW 1/4 SE 1/4 
Section 20:    E 1/2 NW 1/4, NE 1/4 SW 1/4
Section 29:    NW 1/4, N 1/2 SW 1/4
Section 30:    NE 1/4, E 1/2 NW 1/4, N 1/2 SE 1/4




PARCEL C


That part of Lot 6 in Section 4 and of Lot 5 in Section 3, Township 29 North, Range 15 West, N.M.P.M., San Juan County, New Mexico, described as follows:


Beginning at a point which is 772.69 feet, South 88o12’03” East from Northwest Corner of Lot 6:


Thence, S. 55o50’29” E., 205.55 feet; thence, N. 78o21’34” E., 457.06 feet; thence N. 88o29’07” E., 746.61 feet; thence, S. 25o38’00” W., 1,177.50 feet; thence, N. 54o32’00” W., 1,291.70 feet; thence, N. 32o1’00” E., 372.20 feet to the point of beginning. Containing 21.039 acres, more or less.




PARCEL C-1




A tract of land situated adjacent to the southerly side of the San Juan River in Sections 3, 4, 9 and 10, Township 29 North, Range 15 West, N.M.P.M., San Juan County, New Mexico, and more particularly described as follows:


    



Exh. I - 2






Beginning at point A, from which the corner common to Sections 33 and 34, T.30 N., R. 15 W., and Sections 4 and 3, T. 29 N., R 15 W., bears N. 06o09’45” E., 4,966.7 feet; thence N. 49o00’00” E., 351.95 feet to point B located on the approximate centerline of the San Juan River; thence along the centerline of the River S. 50o44’26” E., 268.63 feet to point C; thence continuing along the centerline of the River, S. 41o18’31” E., 263.59 feet to point D; thence S. 21o12’40” E., 678 feet to point E; thence S. 51o00’00” W., 209 feet to point F; thence N. 39o00’00” W., 1,160.00 feet to the point of beginning; containing 9.376 acres, more or less.


PARCEL D


The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:


Section 17:    SE 1/4 SW 1/4, S1/2 SE 1/4


PARCEL E


The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:


Section 19:    SE 1/4 SE 1/4
NE 1/4 SE 1/4
E 1/2 NW 1/4 SE 1/4
S 1/2 S 1/2 SE 1/4 NE 1/4


Section 20:    SE 1/4 SW 1/4
SW 1/4 SW 1/4
NW 1/4 SW 1/4
S 1/2 SW 1/4 SW 1/4 NW 1/4


Containing 235 acres, more or less. 


PARCEL F


The following portions of Township 30 North, Range 15 West, N.M.P.M., San Juan County, New Mexico:


Section 20:    SE 1/4 SE 1/4



Exh. I - 3










Exh. I - 4










Exh. I - 5










Exh. I - 6










Exh. I - 7










Exh. I - 8










Exh. I - 9










Exh. I - 10




























EXHIBIT II













EXHIBIT II  
EXHIBIT H TO UNDERGROUND COAL SALES AGREEMENT 
SAN JUAN STATION MINIMUM DELIVERIES2003-2017


	
			
	Column 1
	Column 2
	Column 3

	Year
	Minimum Annual Tons
	Annual Processing Tons

	2003
	5,600,000
	5,480,500

	2004
	5,600,000
	5,480,500

	2005
	5,600,000
	5,126,000

	2006
	5,600,000
	5,126,000

	2007
	5,600,000
	5,126,000

	2008
	5,600,000
	5,118,000

	2009
	5,600,000
	4,810,000

	2010
	5,600,000
	4,810,000

	2011
	5,600,000
	4,810,000

	2012
	5,600,000
	4,810,000

	2013
	5,600,000
	4,500,000

	2014
	5,600,000
	4,500,000

	2015
	5,600,000
	3,860,000

	2016
	5,600,000
	3,860,000

	2017
	5,600,000
	1,086,500

	 
	84,000,000
	68,503,500






Note:  The UG-CSA will be terminated upon the effective date of this Agreement.

Exh. II - 1




























EXHIBIT III











EXHIBIT III 


SAN JUAN PROJECT SWITCHYARD FACILITIES


Material List 


	
		
	Phase I – Project (DWG, ED-54, ED-55)

	QUANTITY
	DESCRIPTION

	5
	345 kV Circuit Breakers – (G.E. A.T.B.’s)

	16
	345 kV Motor Operated Disconnect Switches with Stands

	 
	 

	2
	345 kV S&C Circuit Switches with Stands

	Lot
	Strain Bus and Fittings

	Lot
	Rigid Bus and Fittings

	4
	Line Deadend Towers

	5
	Intermediate Bus Towers

	1
	Start-Up Transformers 345/12.47/4.16 kV, 24/32/40 MVA

	1
	Set of 4.16 kV Switchgear

	1
	4.16 kV Start-Up Cable Run into Plant

	2
	4.16 kV Station Service Transformers

	1
	Set of 12.45 kV Switchgear

	3
	12.47 kV Zig-Zag Grounding Transformer

	6
	345 kV PCM Potential Transformers with Stands (Bus #1, Bus #2)

	6
	345 kV Bus Lightning Arresters with Stands

	 
	 

	1
	Control House 40’ x 72’

	2
	Sets of Batteries & Chargers, 125 v and 48 v

	1
	Microwave Tower

	Lot
	Cable Troughs, Equipment Controls, Breaker Failure Relaying, Fault Recorder

	Lot
	Metering – Indication, Billing and Telemetry Transducers

	Lot
	Switchyard Foundations, Fencing, Grading, Grounding

	 
	 

	1
	Line Trap (FC Line)

	1
	345 kV PCM Potential Transformer/Coupling Capacitor with Stand

	3
	345 kV Line Lightning Arresters with Stands

	Lot
	Line Relaying, Carrier, Microwave

	1
	345-69-12470 Transformer

	1
	345/230-12470 Transformer, 230 yard

	1
	Reactor – 12.47 kV, 345 yard





Exh. III - 1










	
		
	Phase 2 – Project  (DWG. SK-135)

	QUANTITY
	DESCRIPTION

	4
	345 kV Circuit Breakers

	3
	345 kV Motor Operated Disconnect Switches with Stands

	 
	 

	Lot
	Strain Bus and Fittings

	Lot
	Rigid Bus and Fittings

	1
	Intermediate Bus Tower

	Lot
	Cable Troughs, Equipment Controls, Breaker Failure Relaying

	Lot
	Metering – Indication, Billing and Telemetry Transducers

	Lot
	Switchyard Foundations, Grounding

	 
	 

	Phase 3 – Project (DWG. SK-316)

	3
	345 kV Circuit Breakers

	6
	345 kV Motor Operated Disconnect Switches with Stands

	Lot
	Strain Bus and Fittings

	Lot
	Rigid Bus and Fittings

	1
	Line Deadend Tower

	2
	Intermediate Bus Towers

	Lot
	Cable Troughs, Equipment Controls, Breaker Failure Relaying

	Lot
	Metering – Indication, Billing and Telemetry Transducers

	Lot
	Switchyard Foundations and Grounding

	 
	 

	Phase 3 – Project (DWG. SK-317)

	2
	345 kV Circuit Breakers

	4
	345 kV Motor Operated Disconnect Switches with Stands

	Lot
	Strain Bus and Fittings

	Lot
	Rigid Bus and Fittings

	1
	Intermediate Bus Tower

	Lot
	Switchyard Foundations, Grounding









Exh. III - 2






























EXHIBIT IV











EXHIBIT IV(a)




FACILITIES AND EQUIPMENT SPECIFIC 
TO SAN JUAN UNIT NO. 1


Ownership


	
						
	PNM -
	50
	%
	TEP -
	50
	%

	M-S-R -
	0
	%
	Farmington -
	0
	%

	Tri-State -
	0
	%
	LAC-
	0
	%

	SCPPA -
	0
	%
	Anaheim -
	0
	%

	PNMR-D
	0
	%
	UAMPS -
	0
	%






		
	1.
	Turbine Generator




		
	2.
	Condenser




		
	3.
	Condensate and Feedwater System




		
	a.
	Condensate Pumps


		
	b.
	Feedwater Heaters


		
	c.
	Boiler Feed Pumps


		
	d.
	Storage Tanks




		
	4.
	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks




		
	5.
	Forced Draft Fans and Primary Air Fans




		
	6.
	Precipitator




		
	7.
	Stack and Stack Monitoring System




		
	8.
	Cooling Tower




		
	9.
	Circulating Water Pumps




		
	10.
	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers




		
	11.
	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment.)




		
	12.
	Fly Ash System



Exh. IV - 1








EXHIBIT IV(a)
(continued)




		
	13.
	Building HVAC System




		
	14.
	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant




		
	15.
	Emergency Diesel Generator




		
	16.
	Electrical and Control Systems




		
	17.
	SSR Protection System




		
	18.
	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen





Exh. IV - 2








EXHIBIT IV(b)




FACILITIES AND EQUIPMENT SPECIFIC 
TO SAN JUAN UNIT NO. 2


Ownership


	
						
	PNM -
	50
	%
	TEP -
	50
	%

	M-S-R -
	0
	%
	Farmington -
	0
	%

	Tri-State -
	0
	%
	LAC -
	0
	%

	SCPPA -
	0
	%
	Anaheim -
	0
	%

	PNMR-D -
	0
	%
	UAMPS -
	0
	%








		
	1.
	Turbine Generator




		
	2.
	Condenser




		
	3.
	Condensate and Feedwater System




		
	a.
	Condensate Pumps


		
	b.
	Feedwater Heaters


		
	c.
	Boiler Feed Pumps


		
	d.
	Storage Tanks




		
	4.
	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks




		
	5.
	Forced Draft Fans and Primary Air Fans




		
	6.
	Precipitator




		
	7.
	Stack and Stack Monitoring System




		
	8.
	Cooling Tower




		
	9.
	Circulating Water Pumps




		
	10.
	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers




		
	11.
	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment.)




		
	12.
	Fly Ash System



Exh. IV - 3








EXHIBIT IV(b)
(continued)




		
	13.
	Building HVAC System




		
	14.
	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant




		
	15.
	Emergency Diesel Generator




		
	16.
	Electrical and Control Systems




		
	17.
	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen





Exh. IV - 4








EXHIBIT IV(c)




FACILITIES AND EQUIPMENT SPECIFIC 
TO SAN JUAN UNIT NO. 3


Ownership


	
						
	PNM -
	50
	%
	TEP -
	0
	%

	M-S-R -
	0
	%
	Farmington -
	0
	%

	Tri-State -
	8.2
	%
	LAC -
	0
	%

	SCPPA -
	41.8
	%
	Anaheim -
	0
	%

	PNMR-D
	0
	%
	UAMPS -
	0
	%






		
	1.
	Turbine Generator




		
	2.
	Condenser




		
	3.
	Condensate and Feedwater System




		
	a.
	Condensate Pumps


		
	b.
	Feedwater Heaters


		
	c.
	Boiler Feed Pumps


		
	d.
	Storage Tanks




		
	4.
	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks




		
	5.
	Forced Draft Fans and Primary Air Fans




		
	6.
	Precipitator




		
	7.
	Stack and Stack Monitoring System




		
	8.
	Cooling Tower




		
	9.
	Circulating Water Pumps




		
	10.
	Main, Unit Auxiliary 3A and 3B Transformers*




		
	11.
	Bottom Ash System including:  Hopper, Dewatering Tank, Setting Tank, Surge Tank, Storage Tank, and Pump House




		
	12.
	Fly Ash System



Exh. IV - 5








EXHIBIT IV(c)
(continued)




		
	13.
	Building HVAC System




		
	14.
	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System 




		
	15.
	Emergency Diesel Generator




		
	16.
	Electrical and Control Systems




		
	17.
	Fuel Oil Ignitor Heaters and Unit Specific Piping




		
	18.
	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen




		
	19.
	Coal Reclaim Hoppers, Feeders, Feeder Belts, Belt Scales, Fire Protection System, and 3C Conveyor to the Secondary Crusher Building




		
	20.
	SSR Protection System




		
	21.
	Auxiliary Steam Header Piping System:




		
	a.
	Including the Unit Specific Branch Line to the Reheat System


		
	b.
	Not included is the Branch Line to the Chemical Plant




































		
	         *
	PNM and TEP each owns a 50% interest in the main unit transformer



Exh. IV - 6








EXHIBIT IV(d)




FACILITIES AND EQUIPMENT SPECIFIC 
TO SAN JUAN UNIT NO. 4


Ownership


	
						
	PNM -
	38.457
	%
	TEP -
	0
	%

	M-S-R -
	28.8
	%
	Farmington -
	8.475
	%

	Tri-State -
	0
	%
	LAC -
	7.2
	%

	SCPPA -
	0
	%
	Anaheim -
	10.04
	%

	PNMR-D
	0
	%
	UAMPS -
	7.028
	%






		
	1.
	Turbine Generator




		
	2.
	Condenser




		
	3.
	Condensate and Feedwater System




		
	a.
	Condensate Pumps


		
	b.
	Feedwater Heaters


		
	c.
	Boiler Feed Pumps


		
	d.
	Storage Tanks




		
	4.
	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks




		
	5.
	Forced Draft Fans and Primary Air Fans




		
	6.
	Precipitator




		
	7.
	Stack and Stack Monitoring System




		
	8.
	Cooling Tower




		
	9.
	Circulating Water Pumps




		
	10.
	Main, Unit Auxiliary 4A and 4B Transformers




		
	11.
	Bottom Ash System including:  Hopper, Dewatering Tank, Setting Tank, Surge Tank, Storage Tank, and Pump House




		
	12.
	Fly Ash System



Exh. IV - 7








EXHIBIT IV(d)
(continued)




		
	13.
	Building HVAC System




		
	14.
	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System 




		
	15.
	Emergency Diesel Generator




		
	16.
	Electrical and Control Systems




		
	17.
	Fuel Oil Ignitor Heaters and Unit Specific Piping




		
	18.
	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen




		
	19.
	Coal Reclaim Hoppers, Feeders, Feeder Belts, Belt Scales, Fire Protection System, and 3D Conveyor to the Secondary Crusher Building




		
	20.
	Auxiliary Steam Header Piping System:




		
	a.
	Including the Unit Specific Branch Line to the Reheat System


		
	b.
	Not included is the Branch Line to the Chemical Plant









Exh. IV - 8








EXHIBIT IV(e)




FACILITIES AND EQUIPMENT SPECIFIC 
TO SAN JUAN UNITS NO. 1 AND 2


Ownership


	
						
	PNM -
	50
	%
	TEP -
	50
	%

	M-S-R -
	0
	%
	Farmington -
	0
	%

	Tri-State -
	0
	%
	LAC -
	0
	%

	SCPPA -
	0
	%
	Anaheim -
	0
	%

	PNMR-D
	0
	%
	UAMPS -
	0
	%








		
	1.
	Bearing Cooling Water System




		
	2.
	Bottom Ash Dewatering Facility including: Dewatering Tank, Settling Tank, Surge Tank, Storage Tank, and Pump House




		
	3.
	Demineralizer System including: Clarifier, Storage Tanks, and Sump Pump 




		
	4.
	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization)




		
	5.
	Premix Tank Facility (This was the wastewater neutralizer facility and is now operated as part of the Water Management System.)




		
	6.
	Instrument Air system, except Unit Piping




		
	7.
	Chemical Feed System, except Unit Piping




		
	a.
	Condensate and Feedwater System


		
	b.
	Boiler


		
	c.
	Bearing Cooling Water System


		
	d.
	Cooling Tower Systems


		
	e.
	Chlorination System




		
	8.
	Plant Air System, except Unit Piping




		
	9.
	Sootblowing Air System, except Unit Piping




		
	10.
	Hydrogen Storage System, except Unit Piping





Exh. IV - 9








EXHIBIT IV(e)
(continued)




		
	11.
	Coal Handling Reclaim Systems A and B including: Hoppers, Feeders, Reclaim Conveyors, Belt Scales, and Sprinkler System




		
	12.
	Coal Tripper System south of column, Line 12 including Dust Collection System




		
	13.
	Turbine Lube Oil Storage and Transfer System




		
	14.
	Control Room, Equipment Rooms, and Associated HVAC System




		
	15.
	Turbine Crane south of column, Line 12




		
	16.
	Fuel Oil, Ash, and Water Pipe Racks




		
	17.
	Boiler Fill System for Units 1 and 2




		
	18.
	All spare parts common to either unit




		
	19.
	SO2 Backup Scrubber-Absorber Transformer




		
	20.
	SAR Multiplexer Control System





Exh. IV - 10








EXHIBIT IV(f)




FACILITIES AND EQUIPMENT SPECIFIC 
TO SAN JUAN UNITS NO. 3 AND 4


Ownership


	
						
	PNM -
	44.119
	%
	TEP -
	0
	%

	M-S-R -
	14.4
	%
	Farmington -
	4.249
	%

	Tri-State -
	4.1
	%
	LAC -
	3.612
	%

	SCPPA -
	20.9
	%
	Anaheim -
	5.07
	%

	PNMR-D
	0
	%
	UAMPS -
	3.55
	%






1.    Bearing Cooling Water System


2.    Demineralizer System: including Sump Pumps, Filter Beds, and Storage Tanks


		
	3.
	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization except Ignitor Heaters and Unit Specific Piping)




		
	4.
	Wastewater Neutralizer Facility (This facility is operated as part of Water Management System.)




5.    Instrument Air System except Unit Piping 


6.    Chemical Feed System except Unit Piping


		
	a.
	Condensate and Feedwater System


		
	b.
	Boiler


		
	c.
	Bearing Cooling Water System


		
	d.
	Cooling Tower Systems


		
	e.
	Chlorination System




7.    Plant Air System except Unit Piping


8.    Sootblowing Air System except Unit Piping


9.    Start-Up Transformers and Nonseg Bus to Units 3 and 4 Switchgear


10.    Hydrogen Storage System except Unit Piping


11.    Coal Tripper System Serving Units 3 and 4 including Dust Collection Systems

Exh. IV - 11








EXHIBIT IV(f)
(continued)




12.    Turbine Lube Oil Storage and Transfer System


13.    Control Room, Equipment Rooms, and Associated HVAC System


14.    Boiler Fill System for Units 3 and 4


		
	15.
	Auxiliary Cooling Systems including Auxiliary Cooling Tower No. 1 and Pumps, but excepting No. 4 Tower Pumps and Piping which is Unit Specific




16.    CO2 Storage System


17.    Start-Up Boiler Feed Pump


18.    Turbine Bay Crane north of column, Line 12


19.    Fuel Oil, Ash, and Water Pipe Racks


20.    Fire Water Booster and Jockey Pumps


21.    Halon Fire Protection System


22.    Cooling Tower Multiplex Control System


23.    All spare parts common to either unit



























Exh. IV - 12








EXHIBIT IV(g)




FACILITIES AND EQUIPMENT 
COMMON TO ALL FOUR SAN JUAN UNITS


Ownership


	
						
	PNM -
	46.29
	%
	TEP -
	19.8
	%

	M-S-R -
	8.7
	%
	Farmington -
	2.559
	%

	Tri-State -
	2.49
	%
	LAC -
	2.175
	%

	SCPPA -
	12.71
	%
	Anaheim -
	3.10
	%

	PNMR-D
	0
	%
	UAMPS -
	2.169
	%








		
	1.
	River and Raw Water System including:




		
	a.
	Diversion and intake structures, including all equipment and pump building. 


		
	b.
	Raw Water line to reservoir.


		
	c.
	Reservoir, pump buildings, and all equipment.


		
	d.
	Raw water lines to plant yard.


		
	e.
	All above and underground fire protection system to each vendor supplied or unit specific fire protection system.




2.    Auxiliary Boiler


3.    SO2 Removal System except Absorbers


NOTE: The new SO2 Absorber Feed System is being placed in-service to replace the SO2 Chemical Plant previously used by the Project. The SO2 Chemical Plant facilities will be retired in place and will be salvaged or decommissioned at a later date. Section 3.1 describes the new SO2 Absorber Feed System while Section 3.2 describes the old SO2 Chemical Plant.


3.1    SO2 Absorber Feed System


		
	a.
	Limestone Handling System


		
	b.
	Limestone Preparation System


		
	c.
	Dewatering System


		
	d.
	Gypsum Stack Out System





Exh. IV - 13








EXHIBIT IV(g)
(continued)




3.2    SO2 Chemical Plant


		
	a.
	Double effect evaporator train systems.


		
	b.
	Fly ash filter system.


		
	c.
	Absorber product and feed tanks.


		
	d.
	Condensate collection, storage, and transfer systems.


		
	e.
	Soda ash storage, mixing, and distribution systems.


		
	f.
	Sulfate purge system including: crystallizers, centrifuges, evaporators, and salt cake system.


		
	g.
	Sulfuric acid plant system including storage tanks and load out system. 


		
	h.
	Auxiliary. No. 2 cooling tower, pumps, and systems.




4.    Spare-Main Transformer 345/24 kV for all units.


5.    Maintenance, Office, and Warehousing Facilities


6.    Chemical Laboratory


7.    Coal and Ash Handling Control Facilities


8.    Roads and grounds such as fencing, yard lighting, guard facilities, drainage, and dikes.


9.    Potable Water System


		
	10.
	Environmental Monitoring systems including Air, Water, and Ground. Excludes Stack Monitoring Systems which are unit specific.




11.    Transportation such as trucks, cars, and dozers (not otherwise charged).


12.    Water Management System


		
	a.
	Wastewater Recovery System -- Northside




		
	1.
	Reverse osmosis system including lime/soda softening clarifier system. 


		
	2.
	Brine concentrator Nos. 4 and 5.


		
	3.
	Process pond No. 3 and pump system


		
	4.
	North evaporation ponds 1, 2, and 3.





Exh. IV - 14








EXHIBIT IV(g)
(continued)




		
	b.
	SO2 Waste Treatment System -- Southside




		
	1.
	Process ponds 1A, 1 B, 2 and pumping system.


		
	2.
	Premix tank and clarifier system.


		
	3.
	Oxidation towers.


		
	4.
	Brine concentrator Nos. 2 and 3.


		
	5.
	South evaporation ponds Nos. 1, 2, 3, 4, and 5.




		
	c.
	Data Acquisition System


		
	d.
	Solid Waste Disposal Pit


		
	e.
	Coal pile runoff pond




		
	13.
	Coal Transfer Facilities from the Reclaim Conveyors to the Head-End of Plat Belts 4A and 4B and Dust Suppression Systems




		
	14.
	Maintenance Bay Facilities including: Bay Bridge Crane, all Offices, and Support Facilities




15.    Sewage Treatment Facilities


		
	16.
	On each of Units 1 and 2, the Chemical Plant 165-pound Control Valve, and Branch Line from the Unit Specific 650-pound Rehear Steam Line




		
	17.
	On each of Units 3 and 4, the Chemical Plant Branch Steam Line from the Unit Specific Auxiliary Steam Header System



























Exh. IV - 15








EXHIBIT IV(h)




SAN JUAN PROJECT 
SWITCHYARD FACILITIES 


Cost Allocation (%)


	
							
	 
	

Installed Cost
	Replacements/Improvements
Betterments
	 

	 
	PNM
	TEP
	PNM
	TEP
	 

	345 kV Bus 1 & 3 (East Bus)
	50
	50
	50
	50
	 

	             Bus 2 (West Bus)


	50
	50
	50
	50
	 

	Circuit Breakers


	 
	 
	 
	 
	 

	06582 (345/230)
	50
	50
	50
	50
	 

	5482
	50
	50
	50
	50
	 

	04382 (OJO)


	50
	50
	50
	50
	 

	12982 (McKinley)
	50
	50
	50
	50
	 

	11882
	50
	50
	50
	50
	 

	10782 (Unit 4)


	50
	50
	50
	50
	 

	09882 (McKinley)
	58.33
	41.67
	62.5
	37.5
	 

	8782
	54.16
	45.84
	56.25
	43.75
	 

	07682 (Unit 3)
	50
	50
	50
	50
	 

	 
	 
	 
	 
	 
	 

	15282 (Four Comers)
	50
	50
	50
	50
	 

	14182
	50
	50
	50
	50
	 

	13082 (Unit 2)
	50
	50
	50
	50
	 

	 
	 
	 
	 
	 
	 

	18582 (West Mesa)
	50
	50
	50
	50
	 

	17482
	50
	50
	50
	50
	 

	16382 (Unit 1)
	50
	50
	50
	50
	 

	20782
	50
	50
	50
	50
	 

	 
	 
	 
	 
	 
	 

	Shunt Reactors


	 
	 
	 
	 
	 

	Ojo
	100
	0
	100
	0
	 

	McKinley 1
	5.36
	94.64
	5.36
	94.64
	 

	McKinley 2
	16.67
	83.33
	25
	75
	 

	WW (BA)
	100
	0
	100
	0
	 







Exh. IV - 16








EXHIBIT IV(h)
(continued)




	
						
	 
	

Installed Cost
	Replacements/Improvements
Betterments
	 

	 
	PNM
	TEP
	PNM
	TEP
	 

	Transformers


	 
	 
	 
	 
	 

	Station Aux. No. 2
     400 MVA, 345/230-12.5 
	100
	0
	100
	0
	 

	Station Aux. No. 1
     345/4.16-12.5 
	50
	50
	50
	50
	 

	Station Aux. No. 3
     90 MVA, 345/69-12.5
	50
	50
	50
	50
	 

	 
	 
	 
	 
	 
	 

	Future Facilities


345/69/12 kV
	



66.67
	



33.33
	



66.67
	



33.33
	 

	2-345 kV Bkrs (Durango)
	50
	50
	50
	50
	 

	 
	 
	 
	 
	 
	 

	Lower Voltage


230 kV Control Hse
	



83.33
	



16.67
	



83.33
	



16.67
	 

	230/69 kV Trf
	66.67
	33.33
	66.67
	33.33
	 

	Shiprock 230 kV line


	100
	0
	100
	0
	 







Exh. IV - 17






























EXHIBIT V













EXHIBIT V(a)




FACILITIES AND EQUIPMENT 
SPECIFIC TO SAN JUAN UNIT NO. 1


Operation and Maintenance Costs


	
						
	PNM -
	50
	%
	TEP -
	50
	%

	M-S-R -
	0
	%
	Farmington -
	0
	%

	Tri-State -
	0
	%
	LAC -
	0
	%

	SCPPA -
	0
	%
	Anaheim -
	0
	%

	PNMR-D
	0
	%
	UAMPS -
	0
	%






		
	1.
	Turbine Generator




		
	2.
	Condenser




		
	3.
	Condensate and Feedwater System




		
	a.
	Condensate Pumps


		
	b.
	Feedwater Heaters


		
	c.
	Boiler Feed Pumps


		
	d.
	Storage Tanks




		
	4.
	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks




		
	5.
	Forced Draft Fans and Primary Air Fans




		
	6.
	Precipitator




		
	7.
	Stack and Stack Monitoring System




		
	8.
	Cooling Tower




		
	9.
	Circulating Water Pumps




		
	10.
	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers




		
	11.
	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment)




		
	12.
	Fly Ash System





Exh. V - 1








EXHIBIT V(a)
(continued)




		
	13.
	Building HVAC System




		
	14.
	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant




		
	15.
	Emergency Diesel Generator




		
	16.
	Electrical and Control Systems




		
	17.
	SSR Protection System




		
	18.
	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen





Exh. V - 2








EXHIBIT V(b)




FACILITIES AND EQUIPMENT 
SPECIFIC TO SAN JUAN UNIT NO. 2


Operation and Maintenance Costs


	
						
	PNM -
	50
	%
	TEP -
	50
	%

	M-S-R -
	0
	%
	Farmington -
	0
	%

	Tri-State -
	0
	%
	LAC -
	0
	%

	SCPPA -
	0
	%
	Anaheim -
	0
	%

	PNMR-D
	0
	%
	UAMPS -
	0
	%








		
	1.
	Turbine Generator




		
	2.
	Condenser




		
	3.
	Condensate and Feedwater System




		
	a.
	Condensate Pumps


		
	b.
	Feedwater Heaters


		
	c.
	Boiler Feed Pumps


		
	d.
	Storage Tanks




		
	4.
	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks




		
	5.
	Forced Draft Fans and Primary Air Fans




		
	6.
	Precipitator




		
	7.
	Stack and Stack Monitoring System




		
	8.
	Cooling Tower




		
	9.
	Circulating Water Pumps




		
	10.
	Main, Start-Up, Unit Auxiliary, and SO2 Scrubber Transformers




		
	11.
	Bottom Ash System (Up to but not including Dewatering Tank or Ash Water Pump building and equipment) 




		
	12.
	Fly Ash System



Exh. V - 3








EXHIBIT V(b)
(continued)




		
	13.
	Building HVAC System




		
	14.
	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the 650-pound Reheat Steam Line and Desuperheater from the Plant Main Steam Line but not including the 165-pound Control Valve and Branch Line to the Chemical Plant




		
	15.
	Emergency Diesel Generator




		
	16.
	Electrical and Control Systems




		
	17.
	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen





Exh. V - 4








EXHIBIT V(c)




FACILITIES AND EQUIPMENT 
SPECIFIC TO SAN JUAN UNIT NO. 3


Operation and Maintenance Costs


	
						
	PNM -
	50
	%
	TEP -
	0
	%

	M-S-R -
	0
	%
	Farmington -
	0
	%

	Tri-State -
	8.2
	%
	LAC -
	0
	%

	SCPPA -
	41.8
	%
	Anaheim -
	0
	%

	PNMR-D
	0
	%
	UAMPS -
	0
	%








		
	1.
	Turbine Generator




		
	2.
	Condenser




		
	3.
	Condensate and Feedwater System




		
	a.
	Condensate Pumps


		
	b.
	Feedwater Heaters


		
	c.
	Boiler Feed Pumps


		
	d.
	Storage Tanks




		
	4.
	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks




		
	5.
	Forced Draft Fans and Primary Air Fans




		
	6.
	Precipitator




		
	7.
	Stack and Stack Monitoring System




		
	8.
	Cooling Tower




		
	9.
	Circulating Water Pumps




		
	10.
	Main, Unit Auxiliary 3A and 3B Transformers




		
	11.
	Bottom Ash System including:  Hopper, Dewatering Tank, Setting Tank, Surge Tank, and Pump House




		
	12.
	Fly Ash System



Exh. V - 5








EXHIBIT V(c)
(continued)




		
	13.
	Building HVAC System




		
	14.
	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the Reheat Steam Line from the Auxiliary Steam Header




		
	15.
	Emergency Diesel Generator




		
	16.
	Electrical and Control Systems




		
	17.
	Fuel Oil Ignitor Heaters and Unit Specific Piping




		
	18.
	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen




		
	19.
	SSR Protection System




		
	20.
	Auxiliary Steam Header Piping System:




		
	a.
	Including the Unit Specific Branch Line to the Reheat System


		
	b.
	Not included is the Branch Line to the Chemical Plant











Exh. V - 6








EXHIBIT V(d)




FACILITIES AND EQUIPMENT 
SPECIFIC TO SAN JUAN UNIT NO. 4


Operation and Maintenance Costs


	
						
	PNM -
	38.457
	%
	TEP -
	0
	%

	M-S-R -
	28.8
	%
	Farmington -
	8.475
	%

	Tri-State -
	0
	%
	LAC -
	7.2
	%

	SCPPA -
	0
	%
	Anaheim -
	10.04
	%

	PNMR-D
	0
	%
	UAMPS -
	7.028
	%








		
	1.
	Turbine Generator




		
	2.
	Condenser




		
	3.
	Condensate and Feedwater System




		
	a.
	Condensate Pumps


		
	b.
	Feedwater Heaters


		
	c.
	Boiler Feed Pumps


		
	d.
	Storage Tanks




		
	4.
	Boiler including: Air Heaters, Pulverizers, Bunkers, Feeders and Blowdown Tanks




		
	5.
	Forced Draft Fans and Primary Air Fans




		
	6.
	Precipitator




		
	7.
	Stack and Stack Monitoring System




		
	8.
	Cooling Tower




		
	9.
	Circulating Water Pumps




		
	10.
	Main, Unit Auxiliary 4A and 4B Transformers




		
	11.
	Bottom Ash System including:  Hopper, Dewatering Tank, Setting Tank, Surge Tank, and Pump House




		
	12.
	Fly Ash System



Exh. V - 7








EXHIBIT V(d)
(continued)




		
	13.
	Building HVAC System




		
	14.
	SO2 Absorbers, Scrubbers, Transfer Pumps, Booster Fans, and Flue Gas Reheat System including the Reheat Steam Line from the Auxiliary Steam Header 




		
	15.
	Emergency Diesel Generator




		
	16.
	Electrical and Control Systems




		
	17.
	Fuel Oil Ignitor Heaters and Unit Specific Piping




		
	18.
	Unit Specific Piping for all Air Systems, Chemical Feed Systems, and Hydrogen




		
	19.
	Auxiliary Steam Header Piping System:




		
	a.
	Including the Unit Specific Branch Line to the Reheat System


		
	b.
	Not included is the Branch Line to the Chemical Plant









Exh. V - 8








EXHIBIT V(e)




FACILITIES AND EQUIPMENT 
COMMON TO SAN JUAN UNITS NO. 1 AND 2


Operation and Maintenance Costs


	
						
	PNM -
	50
	%
	TEP -
	50
	%

	M-S-R -
	0
	%
	Farmington -
	0
	%

	Tri-State -
	0
	%
	LAC -
	0
	%

	SCPPA -
	0
	%
	Anaheim -
	0
	%

	PNMR-D
	0
	%
	UAMPS -
	0
	%








		
	1.
	Bearing Cooling Water System except Unit Piping




		
	2.
	Bottom Ash Dewatering Facility including: Dewatering Tank, Settling Tank, Surge Tank, Storage Tank, and Pump House




		
	3.
	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization)




		
	4.
	Instrument Air System, except Unit Piping




		
	5.
	Chemical Feed System, except Unit Piping




		
	a.
	Condensate and Feedwater System


		
	b.
	Boiler


		
	c.
	Bearing Cooling Water System


		
	d.
	Cooling Tower Systems


		
	e.
	Chlorination System




		
	6.
	Plant Air System, except Unit Piping




		
	7.
	Sootblowing Air System, except Unit Piping




		
	8.
	Hydrogen Storage System, except Unit Piping




		
	9.
	Coal Tripper System including Dust Collection System




		
	10.
	Turbine Lube Oil Storage and Transfer System




		
	11.
	Control Room, Equipment Rooms, and Associated HVAC System



Exh. V - 9








EXHIBIT V(e)
(continued)




		
	12.
	SO2 Backup Scrubber-Absorber Transformer




		
	13.
	Turbine Crane south of column, Line 12




		
	14.
	Fuel Oil, Ash, and Water Pipe Racks




		
	15.
	Boiler Fill System 




		
	16.
	SAR Multiplexer Control System





Exh. V - 10








EXHIBIT V(f)




FACILITIES AND EQUIPMENT 
COMMON TO SAN JUAN UNITS NO. 3 AND 4


Operation and Maintenance Costs


	
						
	PNM -
	44.119
	%
	TEP -
	0
	%

	M-S-R -
	14.4
	%
	Farmington -
	4.249
	%

	Tri-State -
	4.1
	%
	LAC-
	3.612
	%

	SCPPA -
	20.9
	%
	Anaheim -
	5.07
	%

	PNMR-D
	0
	%
	UAMPS -
	3.55
	%








1.    Bearing Cooling Water System except Unit Piping


		
	2.
	Fuel Oil System (Fuel Oil for Ignition and Flame Stabilization except Ignitor Heaters and Unit Specific Piping)




3.    Instrument Air System except Unit Piping 


4.    Chemical Feed System except Unit Piping


		
	a.
	Condensate and Feedwater System


		
	b.
	Boiler


		
	c.
	Bearing Cooling Water System


		
	d.
	Cooling Tower Systems


		
	e.
	Chlorination System




5.    Plant Air System except Unit Piping


6.    Sootblowing Air System except Unit Piping


7.    Start-Up Transformers and Nonseg Bus to Units 3 and 4 Switchgear


8.    Hydrogen Storage System except Unit Piping


9.    Coal Tripper System including Dust Collection Systems


10.    Turbine Lube Oil Storage and Transfer System


11.    Control Room, Equipment Rooms, and Associated HVAC System

Exh. V - 11








EXHIBIT V(f)
(continued)




12.    Boiler Fill System 


		
	13.
	Auxiliary Cooling Systems including Auxiliary Cooling Tower No. 1 and Pumps, but excepting No. 4 Tower Pumps and Piping which is Unit Specific




14.    CO2 Storage System except Unit Piping


15.    Start-Up Boiler Feed Pump except Unit Piping


16.    Turbine Bay Crane north of column, Line 12


17.    Fuel Oil, Ash, and Water Pipe Racks


18.    Fire Water Booster and Jockey Pumps


19.    Halon Fire Protection System


20.    Cooling Tower Multiplex Control System



Exh. V - 12








EXHIBIT V(g)




FACILITIES AND EQUIPMENT 
COMMON TO ALL FOUR SAN JUAN UNITS


Operation and Maintenance Costs


	
						
	PNM -
	46.297
	%
	TEP -
	19.8
	%

	M-S-R -
	8.7
	%
	Farmington -
	2.559
	%

	Tri-State -
	2.49
	%
	LAC -
	2.175
	%

	SCPPA -
	12.71
	%
	Anaheim -
	3.10
	%

	PNMR-D
	0
	%
	UAMPS -
	2.169
	%








		
	1.
	River and Raw Water System including:




		
	a.
	Diversion and intake structures, including all equipment and pump building. 


		
	b.
	Raw Water line to reservoir.


		
	c.
	Reservoir, pump buildings, and all equipment.


		
	d.
	Raw water lines to plant yard.


		
	e.
	All above and underground fire protection system to each vendor supplied or unit specific fire protection system.




2.    Auxiliary Boiler


3.    SO2 Removal System except Absorbers


NOTE:  In April 1998 the new SO2 Absorber Feed System went in-service and replaced the SO2 Chemical Plant previously used by the Project. The SO2 Chemical Plant facilities are retired in place and will be salvaged or decommissioned at a later date. Section 3.1 describes the new SO2 Absorber Feed System while Section 3.2 describes the old SO2 Chemical Plant.


3.1    SO2 Absorber Feed System


		
	a.
	Limestone Handling System


		
	b.
	Limestone Preparation System


		
	c.
	Dewatering System


		
	d.
	Gypsum Stack Out System





Exh. V - 13








EXHIBIT V(g)
(continued)




3.2    SO2 Chemical Plant


a.    Double effect evaporator train systems.
b.    Fly ash filter system.
c.    Absorber product and feed tanks.
d.    Condensate collection, storage, and transfer systems.
e.    Soda ash storage, mixing, and distribution systems.
		
	f.
	Sulfate purge system including: crystallizers, centrifuges, evaporators, and salt cake system.


g.    Sulfuric acid plant system including storage tanks and load out system. 
h.    Auxiliary No. 2 cooling tower, pumps, and systems.


4.    Spare-Main Transformer 345/24 kV for all units.


5.    Maintenance, Office, and Warehousing Facilities


6.    Chemical Laboratory


7.*    Coal and Ash Handling Control Facilities


8.    Roads and grounds such as fencing, yard lighting, guard facilities, drainage, and dikes.


9.    Potable Water System


		
	10.
	Environmental Monitoring systems including Air, Water, and Ground. Excludes Stack Monitoring Systems which are unit specific.




11.    Transportation such as trucks, cars, and dozers (not otherwise charged).


12.    Water Management System


		
	a.
	Wastewater Recovery System -- Northside




		
	1.
	Neutralization system including premix tank, neutralization tank, clarifier/thickener, and pumps.


		
	2.
	Reverse osmosis system including lime/soda softening clarifier system. 


		
	3.
	Brine concentrator Nos. 4 and 5.


		
	4.
	Process pond No. 3 and pump system.


		
	5.
	North evaporation ponds 1, 2, and 3.



Exh. V - 14








EXHIBIT V(g)
(continued)




		
	b.
	 SO2 Waste Treatment System -- Southside




		
	1.
	Process ponds 1A, 1B, 2 and pumping system.


		
	2.
	Premix tank and clarifier system.


		
	3.
	Oxidation towers.


		
	4.
	Brine concentrator Nos. 2 and 3.


		
	5.
	South evaporation ponds Nos. 1, 2, 3, 4, and 5. 




		
	c.
	Data Acquisition System


		
	d.
	Solid Waste Disposal Pit


		
	e.
	Coal pile runoff pond




		
	13.*
	Coal Handling Equipment -- all equipment from all reclaim hoppers ending at the chutes to the tripper conveyors. This includes: hoppers. feeders. feeder belts, reclaim conveyors, plant conveyors, belt scales, fire protection systems, dust suppression systems, magnetic separators, all electrical and controls, and heating and ventilation systems.




		
	14.
	Maintenance Bay Facilities including: Bay Bridge Crane, all Offices, and Support Facilities




15.    Sewage Treatment Facilities


		
	16.
	All Demineralizer Systems including: Clarifier, Storage Tanks, Sump Pumps, Filter Beds, and Control Systems.




		
	17.
	The Chemical Plant 165-pound Control Valve and Branch Line from each of Units 1 and 2 Unit Specific 650-pound Reheat Steam Line.




		
	18.
	The Chemical Plant Branch Steam Line from (but not including) the Unit Specific Auxiliary, Steam Header System on each of Units 3 and 4.


















*Maintenance Only

Exh. V - 15








EXHIBIT V(h)




FACILITIES AND EQUIPMENT 
COMMON TO ALL FOUR SAN JUAN UNITS


Operation Costs Only




	
		
	PNM
	 

	M-S-R
	 

	TEP
	Variable split based on generation by unit

	Farmington
	 

	Tri-State
	 

	LAC
	 

	SCPPA
	 

	Anaheim
	 

	UAMPS
PNMR-D
	 








1.    Coal and Ash Handling Control Facilities


2.    Coal Handling Equipment


All equipment from all reclaim hoppers ending at the chutes to the tripper conveyors. This includes: hoppers, feeders, feeder belts, reclaim conveyors, plant conveyors, belt scales, fire protection systems, dust suppression systems, magnetic separators, all electrical and control, and heating and ventilation systems.



Exh. V - 16








EXHIBIT V(i)




SWITCHYARD FACILITIES AND EQUIPMENT 


OPERATION AND MAINTENANCE COSTS




	
		
	PNM - 65%
	TEP - 35%























Exh. V - 17






























EXHIBIT VI













San Juan Operating Agreement
Exhibit VI-Attachment A






A&G RATIO APPLICABLE TO OPERATION AND MAINTENANCE FOR THE SAN JUAN GENERATING STATION (“SJGS”)


The Operating Agent determines, in accordance with Accounting Practice, the appropriate A&G expense incurred for the benefit of the SJGS and to be billed to the SJGS as follows:


1.    A&G expenses directly chargeable by on-site San Juan Project employees as set forth in Section 22.2.2;


2.    A&G expenses directly chargeable by A&G related departments located off-site as set forth in Section 22.2.2; and


3.    Indirect A&G expenses included in the development of the A&G ratio.


Except as set forth in Section 22.0, individuals located off-site must either charge their time and expenses direct to the SJGS or be included in the A&G pool in the development of the A&G Ratio. Costs incurred for the same purpose must be either all charged direct to the SJGS or all be included in the A&G pool, e.g., all staff persons within the same department must either charge direct to the SJGS or to the A&G pool.


		
	A.
	The Operating Agent conducts an A&G study every three years. However, periodic reviews will be performed to determine if significant organizational changes have occurred that may require the Operating Agent to conduct an A&G study on a basis more frequently than three years.  This study determines the appropriate amount of indirect A&G expense to utilize in the development of the A&G Ratio described below.  




The FERC A&G accounts included in the A&G study are:  920, 921, 923, 930.2, 931 and 935.  


Background


The responsibility for the SJGS resides in the Operating Agent’s Bulk Power Business Unit.  The A&G expenses charged to this Business Unit are derived from two areas.  The first component is an allocation of A&G expenses from the Operating Agent’s Corporate Office to the Bulk Power Business Unit.  These allocations are based on pre-determined methodologies.  The second component of costs are A&G expenses that are directly charged to the Bulk Power Business Unit.  Note:  Any A&G expenses charged directly to the SJGS are excluded from the determination of the A&G Ratio and are not subject to the A&G Ratio.



Exh. VI-1








A questionnaire is sent to all managers that have A&G charges to the Bulk Power Business Unit to determine what percentage of their A&G expenses should be included in the development of the A&G Ratio. 


The percentages derived from the questionnaires are then applied to the actual A&G amounts charged to the Bulk Power Business Unit for the study year.  Amounts are split between labor and other.  


		
	B.
	Labor Ratios for Payroll Taxes (FERC Account 408), Injuries and Damages (FERC Account 925) and Pension and Benefits (FERC Account 926) (See Exhibit VI Attachments B, C and D) are applied to the labor portion of the A&G determined above.   




		
	C.
	Other costs included in the development of the A&G Ratio are Depreciation of General Plant (FERC Account 403), Property Insurance (FERC Account 924) and Property Taxes (FERC Account 408) for the Operating Agent’s headquarters buildings and energy management facility and Amortization of Computer Software (FERC Account 404) for certain software applications that provide benefit to the SJGS. 




The portion of the costs related to the Operating Agent’s headquarters buildings included in the development of the A&G Ratio are derived by applying certain ratios obtained from the A&G study questionnaires. The costs included in the A&G Ratio for the Operating Agent’s energy management facility are based on the number of MW of SJGS capacity as a percentage of the Operating Agent’s total generating capacity.  In addition, ratios for determining the amount of software costs to include in the A&G Ratio are based on the specific software application.  For example, if the Operating Agent installed a new payroll system, the amount of costs for this system that would be included in the A&G Ratio calculation would be based on the number of employees at the SJGS as a percent of the Operating Agent’s total employees.  The Operating Agent reviews each specific software application to determine the method for assigning the appropriate amount of costs to be included in the A&G Ratio calculation.  


The A&G ratio shall be applied to the following SJGS costs:


		
	1) 
	Labor charged to the operation and maintenance expenses included in Sections 22.2.1, 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement.  Such labor dollars are utilized as the denominator in the calculation of the A&G Ratio described below.




The A&G Ratio shall be derived annually based on the preceding year’s experience, as set forth herein unless otherwise agreed to by the participants.  The A&G Ratio will be adjusted to actuals at year-end and the adjustment will be used in the computation of the A&G Ratio for the following year.
A&G Ratio  =  A/B



Exh. VI - 2








Where A = Administrative and general expense chargeable to FERC Accounts 920, 921,
923, 930.2, 931 and 935, including Labor Ratios for Payroll Taxes (FERC Account 408), Injuries and Damages (FERC Account 925) and Pension and Benefits (FERC Account 926) plus other related costs for the Operating Agent’s headquarters buildings and energy management facility for Property Taxes FERC Account (408), Depreciation of General Plant FERC Account (403), and Property Insurance FERC Account (924) plus amortization of certain Computer Software costs charged to FERC Account (404). 


B = Total SJGS operation and maintenance labor paid and accrued excluding labor expenses chargeable to FERC accounts 920 through 935 inclusive.  


Note:  Any modifications to the methodology utilized for calculating the A&G Ratio described above shall be developed by the San Juan Auditing Committee and approved by the San Juan Coordination Committee.

Exh. VI - 3








San Juan Operating Agreement
Exhibit VI-Attachment B




PAYROLL TAX RATIO FOR THE SAN JUAN GENERATING STATION (“SJGS”)




The Payroll Tax Ratio shall be applied to the following SJGS costs:


		
	1) 
	Labor charged to operation and maintenance expenses included in Sections 22.2.1, 22.2.2, 22.2.4, 22.2.5 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement.


		
	2) 
	Labor charged to other primary accounts including, but not limited to, FERC Accounts 107, 108, 163, 183, 186 and 188.




The Payroll Tax Ratio shall be determined annually on the basis of the Operating Agent’s preceding years experience adjusted for known changes to comply with regulations applicable to Social Security and Unemployment Compensation as set forth herein unless otherwise agreed to by the participants.  The Payroll Tax Ratio will be adjusted to actuals at year-end and the adjustment will be used in the computation of the ratio for the following year.


Payroll Tax Ratio  =  T/P


Where T = The Operating Agent’s total payroll tax expense chargeable to FERC Account 408.


P =   The Operating Agent’s total base labor paid and accrued, less wages paid for time-off allowances plus accruals for time-off allowances.




		
	Notes:  (1)
	Base labor is defined as an employee’s hourly rate times the number of hours worked plus an accrual for time-off allowances.  In addition, base labor also includes overtime pay and special pay.




		
	(2) 
	    Time-off allowances are defined as vacation, illness and holiday time.




(3)    Special pay is defined as any other compensation an employee receives that is not part of his/her regular base pay.  Examples include employee recognition awards as well as results based pay, the Operating Agent’s bonus pay plan.


(4)    Any modifications to the methodology utilized for calculating the Payroll Tax Ratio described above shall be developed by the San Juan Auditing Committee and approved by the San Juan Coordinating Committee.

Exh. VI - 4








 San Juan Operating Agreement
Exhibit VI-Attachment C




INJURIES AND DAMAGES RATIO FOR THE 
SAN JUAN GENERATING STATION (“SJGS”)


The Injuries and Damages Ratio shall be applied to the following SJGS costs:


		
	1) 
	Labor charged to operation and maintenance expenses included in Sections 22.2.1, 22.2.2, 22.2.4, 22.2.5 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement.


		
	2) 
	Labor charged to other primary accounts including, but not limited to, FERC Accounts 107, 108, 163, 183, 186 and 188.




The Injuries and Damages Ratio shall be determined annually on the basis of the Operating Agent’s preceding year’s experience as set forth herein unless otherwise agreed to by the participants.  The Injuries and Damages Ratio will be adjusted to actuals at year-end and the adjustment will be used in the computation of the ratio for the following year.


Injuries and Damages Ratio  =  I/P


		
	Where I =  
	The Operating Agent’s total injuries and damages expense chargeable to FERC Account 925, including payroll taxes, and pension and benefits  on labor chargeable to FERC Account 925.  The amount of payroll taxes and pension and benefits to be added are based on the ratios included in Exhibit VI, Attachments B and D, respectively.  Note:  Any injuries and damages expense charged direct to the SJGS are excluded from the determination of the Injuries and Damages Ratio.




P =  The Operating Agent’s total base labor paid and accrued, less wages paid for time-off allowances plus accruals for time-off allowances less special pay and wages charged direct to FERC Account 925.  


		
	Notes:  (1)
	Special pay is defined as any other compensation an employee receives that is not part of his/her regular base pay.  Examples include employee recognition awards as well as results based pay, the Operating Agent’s bonus pay plan.




(2)    Any modifications to the methodology utilized for calculating the Injuries and Damages Ratio described above shall be developed by the San Juan Auditing Committee and approved by the San Juan Coordination Committee.



Exh. VI - 5








San Juan Operating Agreement
Exhibit VI-Attachment D




PENSION AND BENEFITS RATIO FOR THE
 SAN JUAN GENERATING STATION (“SJGS”)




The Pension and Benefits Ratio shall be applied to the following SJGS costs:


		
	1) 
	Labor charged to operation and maintenance expenses included in Sections 22.2.1, 22.2.2, 22.2.4, 22.2.5 22.3, 22.4, 22.5 and 23.3.3 of the San Juan Project Participation Agreement.


		
	2) 
	Labor charged to other primary accounts including, but not limited to, FERC Accounts 107, 108, 163, 183, 186 and 188.




The Pension and Benefits Ratio shall be determined annually on the basis of the Operating Agent’s preceding year’s experience as set forth herein unless otherwise agreed to by the participants.  The Pension and Benefits Ratio will be adjusted to actuals at year-end and the adjustment will be used in the computation of the ratio for the following year.


Pension and Benefits Ratio  =  B/P


Where B =  The Operating Agent’s total  pension and benefits expense chargeable to FERC Account 926, including payroll taxes, and injuries and damages on labor chargeable to FERC Account 926.  The amount of payroll taxes and injuries and damages to be added are based on the ratios included in Exhibit VI, Attachments B and C, respectively.


P  =  The Operating Agent’s total base labor paid and accrued, less wages paid for time-off allowances plus accruals for time-off allowances, less overtime, part-time, special pay not eligible for pension and benefits and wages charged direct to FERC Account 926. 


		
	Notes:  (1)
	Special pay is defined as any other compensation an employee receives that is not part of his/her regular base pay.  Examples include employee recognition awards as well as results based pay, the Operating Agent’s bonus pay plan. Employee recognition awards are not eligible for pension and benefit loadings.


(2)    Any modifications to the methodology utilized for calculating the Pension and Benefits Ratio described above shall be developed by the San Juan Auditing Committee and approved by the San Juan Coordination Committee.







Exh. VI - 6








San Juan Operating Agreement
Exhibit VI−Attachment E




CAPITALIZED A&G RATIO APPLICABLE TO CAPITAL PROJECTS FOR THE SAN JUAN GENERATING STATION (“SJGS”)


The Operating Agent determines the appropriate A&G expense incurred for the benefit of the SJGS and to be billed to the SJGS as follows:


		
	A.
	The Operating Agent conducts an A&G study every three years. However, periodic reviews will be performed to determine if significant organizational changes have occurred that may require the Operating Agent to conduct an A&G study on a basis more frequently than three years.  This study determines the appropriate amount of indirect A&G expense to utilize in the development of the Capitalized A&G Ratio described below.  




The FERC A&G accounts included in the A&G study are:  920, 921, 923, 930.2, 931 and 935.  


Background


The responsibility for the SJGS resides in the Operating Agent’s Bulk Power Business Unit.  The A&G expenses charged to this Business Unit are derived from two areas.  The first component is an allocation of A&G expenses from the Operating Agent’s Corporate Office to the Bulk Power Business Unit.  These allocations are based on pre-determined methodologies.  The second component of costs are A&G expenses that are directly charged to the Bulk Power Business Unit.  Note:  Any A&G expenses charged directly to the SJGS are excluded from the determination of the Capitalized A&G Ratio.  Two Capitalized A&G Ratios are calculated, one for major construction projects (Projects greater than $10,000,000) and one for minor construction projects (Projects less than $10,000,000). 


A questionnaire is sent to all managers that have A&G charges to the Bulk Power Business Unit to determine what percentage of their A&G expenses are capital-related and should be included in the development of the Capitalized A&G Ratios. Amounts are split between labor and other.


		
	B.
	Labor Ratios for Payroll Taxes (FERC Account 408), Injuries and Damages (FERC Account 925) and Pension and Benefits (FERC Account 926) (see Exhibit VI Attachments B, C and D) are applied to the labor portion of the A&G determined above.




The Capitalized A&G Ratios, shall be applied to all SJGS construction costs except for long-term leased transportation and motorized equipment.  The total amount of these construction dollars are utilized as the denominator in the calculation of the A&G Ratio described below.



Exh. VI - 7








Capitalized  A&G   Ratio  =  A/B


Where A = Administrative and general expense chargeable to FERC Accounts 920, 921, 923, 930.2, 931 and 935, including Labor Ratios for Payroll Taxes (FERC Account 408), Injuries and Damages (FERC Account 925) and Pension and Benefits (FERC Account 926) as categorized separately in the A&G questionnaire for major and minor construction expenditures for the study period. 


B = Total SJGS capital project amounts for the Bulk Power Business Unit as categorized between major and minor construction projects for the study period chargeable to FERC Accounts 107 and 108. 




Note:  Any modifications to the methodology utilized for calculating the A&G Ratio described above shall be developed by the San Juan Auditing Committee and approved by the San Juan Coordination Committee.



Exh. VI - 8






























EXHIBIT VII

































 
Example “Interim Invoice” 

Exh. VII-1








Exh. VII-2










Exh. VII-3










Exh. VII-4










Exh. VII-5






























Example  “UG-CSA Invoice”  

Exh. VII-6










Exh. VII-7










Exh. VII-8










Exh. VII-9










Exh. VII-10










Exh. VII-11










Exh. VII-12










Exh. VII-13










Exh. VII-14










Exh. VII-15










Exh. VII-16










Exh. VII-17










Exh. VII-18










Exh. VII-19










Exh. VII-20










Exh. VII-21










Exh. VII-22










Exh. VII-23










Exh. VII-24


























Example “UPS Invoice”

Exh. VII-25












Exh. VII-26
































EXHIBIT VIII









EXHIBIT VIII




Proportional Adjustment of Voting Requirements
in Case of a Default and Suspension of the Rights of a Party or Participant
to Vote Pursuant to Section 35.4.1.


Example Calculation Based on Hypothetical Ownership Percentages:




In the following table, Participant D with Participation Shares in Units 3 and 4 is assumed to be the defaulting Participant. Participation Shares for Voting and Number of Participants for Voting are shown under original or pre-default conditions and are then adjusted as provided in Sections 18.4, 19.4, 20.5, and 21.4 after the right of Participant D to vote is suspended pursuant to Section 35.4.1. 


Participation Shares for voting pursuant to Sections 18.4.1(a), 18.4.2(a), and 18.4.3(a) are adjusted as follows:
    
For Units:


The Adjusted Participation Share for a Participant = (That Participant’s Participation Share)/(The sum of the Participation Shares of all non-defaulting Participants in the affected Unit) 


For Common Facilities:


Adjustments related to common facilities shall be proportional to any differing Participation Shares between Units. The above formula would be applied to each Unit and then summed and normalized over the applicable common facilities. Because San Juan Units are of unequal ratings, the normalization will be in proportion to each Unit’s rating rather than the even fractions in the example below where equally sized units were used for simplicity. 


The numbers of Participants used for voting purposes pursuant to the requirements of Sections 18.4.1(b), 18.4.2(b), and 18.4.3(b) are adjusted by subtracting the number of defaulting Participants from the total number of Participants voting under those Sections. 



Exh. VIII - 1










	
							
	Unit or Facility
	Original Participation Shares for Voting: §18.4.1(a), §18.4.2(a), and §18.4.3(a)
	Original Number of Participants for Voting Purposes: §18.4.1(b), §18.4.2(b), and §18.4.3(b)
	Adjusted Participation Shares for Voting - §18.4.1(a), §18.4.2(a), and §18.4.3(a)
	Adjusted Number of Participants for Voting Purposes - §18.4.1(b), §18.4.2(b), and §18.4.3(b)

	Unit 1
	 
	2
	 
	2

	Participant A
	50.00
	%
	 
	50.00
	%
	 

	Participant B
	50.00
	%
	 
	50.00
	%
	 

	Unit 2
	 
	2
	 
	2

	Participant A
	50.00
	%
	 
	50.00
	%
	 

	Participant B
	50.00
	%
	 
	50.00
	%
	 

	Unit 3
	 
	4
	 
	3

	Participant A
	20.00
	%
	 
	28.57%1
	

	 

	Participant B
	20.00
	%
	 
	28.57
	%
	 

	Participant C
	30.00
	%
	 
	42.86
	%
	 

	Participant D
	30.00
	%
	 
	0.00
	%
	 

	Unit 4
	 
	5
	 
	4

	Participant A
	10.00
	%
	 
	12.50%2
	

	 

	Participant B
	10.00
	%
	 
	12.50
	%
	 

	Participant C
	20.00
	%
	 
	25.00
	%
	 

	Participant D
	20.00
	%
	 
	0.00
	%
	 

	Participant E
	40.00
	%
	 
	50.00
	%
	 

	Unit 1 & 2 Common
	 
	2
	 
	2

	Participant A
	50.00
	%
	 
	50.00
	%
	 

	Participant B
	50.00
	%
	 
	50.00
	%
	 




















_____________________________
1Computed on Unit 3 Participation Shares as follows: (Participant A) / (Participant A + Participant B + Participant C) = 20%/(20%+20%+30%) = 28.57%
2Computed on Unit 4 Participation Shares as follows: (Participant A) / (Participant A + Participant B + Participant C + Participant E) = 10%/(10%+10%+20%+40%) = 12.50%

Exh. VIII - 2










	
							
	Unit 3 & 4 Common
	 
	5
	 
	4

	Participant A
	15.00
	%
	 
	20.536%3
	

	 

	Participant B
	15.00
	%
	 
	20.536%%
	

	 

	Participant C
	25.00
	%
	 
	33.928
	%
	 

	Participant D
	25.00
	%
	 
	0.00
	%
	 

	Participant E
	20.00
	%
	 
	25.000
	%
	 

	Plant Common
	 
	5
	 
	4

	Participant A
	32.50
	%
	 
	35.268%4
	

	 

	Participant B
	32.50
	%
	 
	35.268
	%
	 

	Participant C
	12.50
	%
	 
	16.964
	%
	 

	Participant D
	12.50
	%
	 
	0.00
	%
	 

	Participant E
	10.00
	%
	 
	12.500
	%
	 


















_____________________________
3Computed on Unit 3 and Unit 4 Common Participation Shares as follows: Unit 3 Contribution = (Participant A) / (Participant A + Participant B + Participant C) = 
20%/(20%+20%+30%) = 28.571%; Unit 4 Contribution = (Participant A) / (Participant A + Participant B + Participant C + Participant E) = 10%/(10%+10%+20%+40%) = 12.500%.


Unit 3 & 4 Common = (Unit 3 Rating)/(Sum of Unit 3 and Unit 4 Ratings) * (Unit 3 Contribution) + (Unit 4 Rating)/(Sum of Unit 3 and Unit 4 Ratings) * (Unit 4 Contribution) = 1/2 (28.271%) + 1/2 (12.500%) = 20.536%


4Computed on Plant Common Participation Shares as follows: Unit 1 Contribution = (Participant A) / (Participant A + Participant B) = 50%/(50%+50%) = 50.000%; Unit 2 Contribution = (Participant A) / (Participant A + Participant B) = 50%/(50%+50%) = 50.000%. Unit 3 Contribution = (Participant A) / (Participant A + Participant B + Participant C) = 20%/(20%+20%+30%) = 28.571%; Unit 4 Contribution = (Participant A) / (Participant A + Participant B + Participant C + Participant E) = 
10%/(10%+10%+20%+40%) = 12.500%. Plant Common = (Unit 1 Rating)/(Plant 
Rating) * (Unit 1 Contribution) + (Unit 2 Rating)/(Plant Rating) * (Unit 2 Contribution) + (Unit 3 Rating)/(Plant Rating) * (Unit 3 Contribution) + (Unit 4 Rating)/(Plant Rating) * (Unit 4 Contribution) = 1/4 (50.000%) + 1/4 (50.000%) + 1/4 (28.571%) + (1/4 (12.5000%) = 35.268%



Exh. VIII - 3




































EXHIBIT IX











EXHIBIT IX
FIXED FUEL EXPENSE


SAN JUAN UNDERGROUND COAL SALES AGREEMENT (As Amended)


SECTION 7.3
Reclamation. (Any applicable post-expiration or post-termination reclamation costs described in said section.)


SECTION 8.2(A)
Base CIE Amount


SECTION 8.2(C)
Reimbursable Operating Costs enumerated in Exhibit “F” Paragraph I(1) 


SECTION 8.2(D)
Administration Element


SECTION 8.2(E)
That part of CIE Reconciliation Amount associated with Base CIE or Non-SJCC Base CIE


SECTION 8.3(A)
Processing CIE Amount


SECTION 8.3(C)
Processing Administration Element


SECTION 8.3(D)
Processing CIE Reconciliation Amount


SECTION 8.5(A):
Other Reclamation (These are reclamation costs associated with former activities to supply surface-mined coal.)


SECTION 8.5(B)
Substitute REI


SECTION 8.5(C)
Payment of the Utility Payment Stream


SECTION 8.5(D)
Payments under the Ute ROW


SECTION 8.5(E)

Exh. IX - 1










Other Miscellaneous Costs


SECTION 8.5(F)
Dispute Costs


COAL SALES AGREEMENT BUY OUT AGREEMENT


SECTION 4.4:
Payment of SJCC Costs


    
TRANSPORTATION AGREEMENT BUYOUT AGREEMENT


SECTION 3.4:
Payment of SJTC Costs


Any costs allocated as Fixed Fuel Expense pursuant to Section 23.4.1.3 of this Agreement.


Applicable taxes and royalties on the above items shall be deemed Fixed Fuel Expense.


Capitalized Terms used in this Exhibit, not otherwise defined in this Agreement, are as defined in the above captioned agreements.

Exh. IX - 2


































EXHIBIT X


EXHIBIT X
VARIABLE FUEL EXPENSE








SAN JUAN UNDERGROUND COAL SALES AGREEMENT (As Amended)


SECTION 8.2(B)
Incremental CIE Amount


SECTION 8.2(C)
Reimbursable Operating Costs except those enumerated in Exhibit “F” Paragraph I(1) and only those reclamation costs directly associated with disturbance attributable to the underground mine.


SECTION 8.2(E)
That part of CIE Reconciliation Amount associated with Incremental CIE or Non-SJCC Incremental CIE


SECTION 8.3(B)
Reimbursable Processing Costs


SECTION 8.4
Non-SJCC Coal and Alternate Coal Costs




Capitalized Terms used in this Exhibit, not otherwise defined in this Agreement, are as defined in the above captioned agreements.