exv10w91






Exhibit 10.91




SA 1926 DTIA Consumers-METC Version: 0.0.0 Effective: 9/1/2010




			
	 	 	 
	Midwest ISO
	 	Second Revised Service Agreement No. 1926
	FERC Electric Tariff,
	 	Superseding First Revised Service Agreement No. 1926
	Fifth Revised Volume No. 1	 	 






Amendment and Restatement of the




April 1, 2001



DISTRIBUTION-TRANSMISSION

INTERCONNECTION AGREEMENT



by and between



Michigan Electric Transmission Company, LLC



as Transmission Provider and



Consumers Energy Company



as Local Distribution Company



	 	 	 

	Issued by: Stephen G. Kozey, Issuing Officer

	 	Effective: September 1, 2010
	Issued on: August 31, 2010
	 	 






 









 






TABLE OF CONTENTS




	 	 	 
	ARTICLE 1.	 	Definitions

	ARTICLE 2.	 	Operational Requirements

	ARTICLE 3:	 	Operation and Maintenance

	ARTICLE 4.	 	Supervisory Control and Data Acquisition, SCADA

	ARTICLE 5.	 	Revenue Metering

	ARTICLE 6.	 	Protective Relaying and Control

	ARTICLE 7.	 	Planning and Obligation to Serve

	ARTICLE 8.	 	Transmission Service Level

	ARTICLE 9.	 	New Construction and Modification

	ARTICLE 10.	 	Access to Facilities

	ARTICLE 11.	 	Notifications and Reporting

	ARTICLE 12.	 	Safety

	ARTICLE 13.	 	Environmental Compliance and Procedures

	ARTICLE 14.	 	Billings and Payment

	ARTICLE 15.	 	Applicable Regulations and Interpretation

	ARTICLE 16.	 	Force Majeure

	ARTICLE 17.	 	Indemnification

	ARTICLE 18.	 	Insurance

	ARTICLE 19.	 	Several Obligations

	ARTICLE 20.	 	Confidentiality

	ARTICLE 21.	 	Breach, Default and Remedies

	ARTICLE 22.	 	Term







 









 






	 	 	 
	ARTICLE 23.	 	Assignment/Change in Corporate Identity

	ARTICLE 24.	 	Subcontractors

	ARTICLE 25.	 	Dispute Resolution

	ARTICLE 26.	 	Miscellaneous Provisions

	 
	EXHIBIT 1.	 	Interconnection Points (Substations) Addendum 5, Final 06/10/10

	EXHIBIT 2.	 	Contact Information for Local Distribution Company’s
Representatives and Transmission Provider’s Representatives

	EXHIBIT 3.	 	Special Manufacturing Contracts Influenced by Transmission
System

	EXHIBIT 4.	 	Metering Specifications

	EXHIBIT 5.	 	Respective Ownership of Substation Facilities Since August 7,
2007

	EXHIBIT 6.	 	Jointly Owned Assets — Ownership by Percent of Major Equipment
Addendum 5, Final 06/10/10







Amendment and Restatement of the

DISTRIBUTION TRANSMISSION INTERCONNECTION AGREEMENT




     
This Amendment and Restatement of the April 1, 2001 Distribution Transmission
Interconnection Agreement (“Agreement”) is entered into April 29, 2002, by and between the
Michigan Electric Transmission Company, LLC, a Michigan corporation (“Transmission
Provider”), having a place of business at 27175 Energy Way, Novi, Michigan 48377, and Consumers
Energy Company (“Local Distribution Company”), a Michigan company, doing business in Michigan and
having a place of business at One Energy Plaza, Jackson, Michigan, 49201. Transmission Provider and
Local Distribution Company are individually referred to herein as a “Party” and collectively as
“Parties.” This Agreement amends, restates and completely replaces the April 1, 2001
Distribution Transmission Interconnection Agreement between the Parties, effective on the date
indicated above.


 









 











     WHEREAS, Transmission Provider requires access to parts of Local Distribution Company’s
assets, and Local Distribution Company requires access to parts of Transmission Provider’s assets;
and



     WHEREAS, the Parties have agreed to execute this mutually acceptable Agreement in order to
provide interconnection of the Local Distribution Company with the Transmission Provider and to
define the continuing rights,
responsibilities, and obligations of the Parties with respect to the use of certain of their own
and the other Party’s property, assets, and facilities.


NOW, THEREFORE, in consideration of their respective commitments set forth herein, and intending to
be legally bound hereby, the Parties covenant and agree as follows:




ARTICLE 1. Definitions




     Wherever used in this Agreement with initial capitalization, the following terms shall have
the meanings specified or referred to in this Article 1.




	1.1	 	Administrative Committee means the committee established pursuant to Article 6 of the
Operating Agreement dated April 1, 2001, as amended and restated, between Local Distribution
Company and Transmission Provider.






	1.2	 	Agreement means this Interconnection Agreement between Local Distribution
Company and Transmission Provider, including all attachments hereto, as the same may be
amended, supplemented, or modified in accordance with its terms






	1.3	 	Black Start Capability shall mean a generating unit that is capable of starting
without an outside electrical supply.






	1.4	 	Black Start Plan shall mean a plan utilizing Black Start Capability designed and
implemented by the Transmission Provider in conjunction with its interconnected generation and
distribution customers, Distribution System Control, other electric systems, its Security
Coordinator and ECAR, to energize portions of the Transmission System which are de-energized
as a result of a widespread system disturbance.






	1.5	 	Commission shall mean the Michigan Public Service Commission (MPSC), or its
successor.






	1.6	 	Confidential Information shall have the meaning set forth in Section 20.1 hereof.




 









 












	1.7	 	Control Area shall mean an electric system, bounded by interconnection metering and
telemetry. Generation within the Control Area is directed to operate in a manner prescribed
by guidelines established by ECAR and NERC and in accordance with Good Utility Practice to (a)
maintain scheduled interchange with other Control Areas, (b) maintain the operating frequency
and (c) provide sufficient generating capacity to maintain operating reserves.






	1.8	 	Distribution System shall mean the equipment and facilities and the Interconnection
Equipment owned by the Local Distribution Company and used to deliver power and energy to end
users including transformers, switches, and feeders rated at Nominal Voltage of 138 kilovolts
(kV) or less.






	1.9	 	Distribution System Control shall mean the entity that has the ability and the
obligation to operate the Distribution System Control Area to ensure that the aggregate
electrical demand and energy requirements of the load is met at all times, taking into account
scheduled and reasonably expected unscheduled outages of system elements.






	1.10	 	Distribution System Control Area shall mean a Control Area whose load and generation,
and other bulk power supply points are integrated by the Transmission System.






	1.11	 	Distribution System Control Center shall mean the electric Distribution System
Control Center(s) that is/are responsible for monitoring and controlling the Distribution
System in real time.






	1.12	 	Distribution Transformer shall mean an electrical transformer which, generally, has
its secondary low-side windings rated at Nominal Voltage of less than 138 kV.






	1.13	 	Due Diligence shall mean the exercise of good faith efforts to perform a required act
on a timely basis and in accordance with Good Utility Practice using the necessary technical
and personnel resources.






	1.14	 	ECAR is an acronym, which stands for the East Central Area Reliability coordination
agreement. This is the Agreement under which Transmission Providers, who are signatories of
the agreement, establish regional coordination practices and guides to govern the electric
coordinated operation and reliability of the East Central Region of North America.






	1.15	 	Effective Date shall mean the closing date as defined in the Membership Interests
Purchase Agreement between the Parties.




 









 












	1.16	 	Eligible Customer shall have the same meaning as that term is defined under the
Transmission Provider’s OATT on file with the FERC.






	1.17	 	Emergency means a condition or situation that in the reasonable good faith
determination of the affected Party in accordance with Good Utility Practice contributes to an
existing or imminent physical threat of danger to life or a significant threat to health,
property or the environment.






	1.18	 	Extended Outage shall mean an Unplanned Outage, in which facilities are automatically
removed from service (typically by relay-action operating circuit breakers), with a duration
of more than two (2) minutes.






	1.19	 	FERC shall mean the Federal Energy Regulatory Commission or its successor
federal agency.
	 
	1.20	 	Force Majeure shall have the meaning set forth under Article 16 hereof.






	1.21	 	Forced Outage shall mean an Unplanned Outage, in which facilities are removed from
service by operator intervention and not automatically such as by relay-action operating
circuit breakers.






	1.22	 	Good Utility Practice shall mean 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 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. Good Utility Practice is not intended to be
limited to the optimum practice, method, or act to the exclusion of all others, but rather
includes all acceptable practices, methods, or acts generally accepted in the region.






	1.23	 	Governmental Authority shall mean any foreign, federal, state, local or other
governmental regulatory or administrative agency, court, commission, department, board, or
other governmental subdivision, legislature, rulemaking board, tribunal, arbitrating body, or
other governmental authority; provided such entity possesses valid jurisdictional authority to
regulate the Parties and the terms and conditions of this Agreement.
	 
	1.24	 	ISO means Independent System Operator.






	1.25	 	Interconnection Equipment shall mean all the equipment that is necessary for the
interconnection of the Distribution System to the Transmission




 









 






	 	 	System which is located at the substations listed in Exhibit 1 hereto as it may be revised
from time to time.






	1.26	 	Interconnection Point(s) shall mean the point(s) at which the Distribution System is
connected to the Transmission System, as set forth in Exhibit 1 hereto as it may be revised
from time to time.






	1.27	 	Interconnection Service shall mean the services provided by the Transmission Provider
for the interconnection of the Distribution System with the Transmission System.
Interconnection Service does not include the right to transmission service on the Transmission
System, which service shall be obtained in accordance with the provisions of the Transmission
Provider’s OATT.






	1.28	 	Interconnection Standards shall be those standards provided by the Transmission
Provider to the Local Distribution Company to establish and maintain interconnection operation
in compliance with standards of NERC, ECAR, applicable state or federal regulations or by
mutual agreement of the Parties.






	1.29	 	Interest Rate shall mean an annual percentage rate of interest equal to the lesser of
(a) the prime rate published by the Wall Street Journal (which represents the base rate on
corporate loans posted by at least 75% of the nation’s banks) on the date due, plus 2%, or (b)
the highest rate permitted by law.






	1.30	 	Jointly Owned Assets shall mean those assets in which the Transmission Provider and
Local Distribution Company have undivided ownership interests. Due to the nature of substation
designs, many of the supporting substation assets (e.g., station batteries, fence, control
houses, ground grid, yard stone, steel structures, and some protective relay equipment) cannot
be separated by ownership and the Parties share in the ownership of such assets. The
respective ownership of such assets by substation is shown in Exhibit 6.






	1.31	 	Knowledge shall mean actual knowledge of the corporate officers or managers of the
specified Person charged with responsibility for the particular function as of the Effective
Date of this Agreement, or, with respect to any certificate delivered pursuant to the
Agreement, the date of delivery of the certificate.






	1.32	 	Least-Cost shall mean the lowest Transmission System and Distribution System facility
costs, over the life of the facility, to accommodate an improvement need while adequately
providing for reliability, operating, and maintenance requirements.




 









 












	1.33	 	Local Distribution Company shall mean Consumers Energy Company and its successors
and assigns.






	1.34	 	Local Distribution Company Provided Services shall mean those services provided by
the Local Distribution Company for the Transmission Provider by mutual agreement or contract.






	1.35	 	Local Distribution Company’s Representative shall be that person(s) identified
as the point of contact for day-to-day operations of the Distribution System, identified
in Section 2.3.






	1.36	 	Momentary Outage shall mean a Distribution or Transmission System (in whole or in
part) interruption in service with a duration of two (2) minutes or less.






	1.37	 	Momentary Outage Event shall mean one or more Momentary Outages within any
60-minute period that are attributable to the same root cause.






	1.38	 	NERC shall mean the North American Electric Reliability Council or its successor.






	1.39	 	Network Security shall mean the ability of the Transmission System to withstand
sudden disturbances such as unforeseen conditions, electric short circuits or unanticipated
loss of system elements consistent with reliability principles used to design, plan, operate,
and assess the actual or projected reliability of an electric system that are established by
any Governmental Authority, NERC or ECAR and which are implemented by Transmission Provider or
required of Transmission Provider in compliance with Security Coordinator directives.






	1.40	 	Network Security Condition shall mean a condition or situation in which, in the
reasonable good faith determination of Transmission Provider, Network Security is not
satisfied or is threatened.






	1.41	 	Nominal Voltage shall mean an accepted standard voltage level offered by the
Transmission Provider, at various points on the Transmission System, including but not limited
to 120 kV, 138 kV and 345 kV.






	1.42	 	Normal System Condition shall mean any operating conditions of the Transmission
System other than an Emergency or Network Security Condition.






	1.43	 	Open Access Transmission Tariff or OATT shall mean the Open Access
Transmission Tariff of the Transmission Provider on file with the FERC.
	 
	1.44	 	Operating Committee means the committee established pursuant to Section 6.4.3 of the Operating Agreement dated April 1, 2001, as




 









 






	 	 	amended and restated, between Local Distribution Company and Transmission Provider.
	 
	1.45	 	Party or Parties shall have the meaning set forth in the introductory paragraph of this Agreement.






	1.46	 	Person shall mean any individual, partnership, limited liability company, joint
venture, corporation, trust, unincorporated organization, or governmental entity or any
department or agency thereof.
	 
	1.47	 	Planned Outage shall mean action by (i) Local Distribution Company or Transmission
Provider to take its equipment, facilities or systems out of service, partially or completely,
to perform work on specific components that is scheduled in advance and has a predetermined
start date and duration pursuant to the procedures set forth in Sections 3.9.1, 3.9.2, and
3.9.4. Planned Outage shall not include the construction of new facilities or system
elements, the modification of existing facilities or system elements addressed in Article 9,
which includes, but is not limited to, activities associated with the construction of third
party facilities or with the modifications required to accommodate third party facilities.
	 
	1.48	 	Planning Committee means the committee established pursuant to Section 6.4.3
of the Operating Agreement dated April 1, 2001, as amended and restated, between Local
Distribution Company and Transmission Provider.
	 
	1.49	 	Protective Relay is a device which detects abnormal power system conditions
and, in response, initiates automatic control action
	 
	1.50	 	Protective Relay System is a group of Protective Relays and associated sensing
devices and communications equipment that detects system abnormalities and performs automatic
control action to mitigate or reduce adverse effects of such abnormalities.
	 
	1.51	 	Qualified Personnel shall mean individuals trained for their positions in
accordance with Good Utility Practice.
	 
	1.52	 	RTO means Regional Transmission Organization.
	 
	1.53	 	Regulated Substance means any contaminant, hazardous waste, hazardous substance,
hazardous constituent, or toxic substance, as defined in the Comprehensive Environmental
Response, Compensation, and Liability Act (CERCLA), 42 USC 9601 et seq, Resource Conservation
and Recovery Act (RCRA), 42 USC 6901 et seq, Toxic Substances Control Act (TSCA), 15 USC 2601
et seq, The Michigan Natural




 









 






	 	 	Resources and Environmental Protection Act (MCLA 324.101 et seq); or any other similar
statutes now or hereafter in effect.
	 
	1.54	 	Release shall mean, spill, leak, discharge, dispose of, pump, pour, emit, empty,
inject, leach, dump, or allow to escape into or through the environment.
	 
	1.55	 	Revenue Quality Metering System shall mean a system which includes current and
voltage instrument transformers, secondary wiring, test switches, meter transducer(s), meter
and loss compensation as set forth in Article 5.
	 
	1.56	 	RTU — Remote Terminal Units shall mean a device connected by a communication system
to one or more master computers with appropriate software placed at various locations to
collect data and perform remote control. It may also perform intelligent autonomous control
of electrical systems and report the results back to the master computer(s).
	 
	1.57	 	Security Coordinator shall mean a NERC-approved entity that provides the security
assessment and emergency operations coordination for one or more Control Areas or transmission
providers and which has operational authority under NERC standards over the Transmission
Provider.
	 
	1.58	 	Steady-State Voltage shall mean the value of a voltage after all transients have
decayed to a negligible value. The root-mean-square value in the steady-state does not vary
with time.
	 
	1.59	 	Supervisory Control and Data Acquisition (SCADA) shall mean a system that provides
data acquisition, supervisory control and alarm display and control from remote field
locations to control centers.
	 
	1.60	 	Transmission Provider shall mean the Michigan Electric Transmission Company, LLC
and its successors and assigns.
	 
	1.61	 	Transmission Provider’s Representative(s) shall be that person(s) identified
as the point for contact for day-to-day operations of the Transmission System,
identified in Section 2.3.
	 
	1.62	 	Transmission System shall mean all the facilities of the Transmission Provider that
perform a “Transmission” function, as defined in Section 1.1 of the Easement Agreement between
the Parties, dated April 29, 2002, as modified by Section 3.4 of this Agreement.
	 
	1.63	 	Transmission System Operations Center(s) shall mean the electric Transmission
System control center(s) that is/are responsible for monitoring and controlling the
Transmission System in real time.




 









 






	1.64	 	Unplanned Outage shall mean action by Local Distribution Company or
Transmission Provider to take its equipment, facilities or systems out of service, partially
or completely, due to an unanticipated failure, when such removal from service was not
scheduled in accordance with Sections 3.9.1, 3.9.2, and 3.9.4. Such removal from service
may be automatic such as by relay-action operating circuit breakers or by operator
intervention. Momentary interruptions are excluded from the definition of Unplanned Outages.
Unplanned Outages include Forced Outages as well as Extended Outages.





ARTICLE 2. Operational Requirements





	2.1	 	Subject to the terms and conditions of this Agreement, Transmission Provider shall provide
Local Distribution Company Interconnection Service for each Interconnection Point identified
in Exhibit 1, from the Effective Date for the term of this Agreement.






	2.2	 	The Interconnection Points between the Transmission System and Distribution System are
listed in Exhibit 1. It shall be the Transmission Provider’s responsibility to annually
prepare an addendum to this exhibit that shows all new or modified interconnections. The
original Exhibit 1 and all addendums shall be retained for future reference.






	2.3	 	Local Distribution Company’s Representatives and Transmission Provider’s Representatives are
listed in Exhibit 2, as may be modified from time to time by either Party, giving written
notice of changes regarding its Representative(s) to the other Party.
	 
	2.4	 	Interconnection Standards






	2.4.1	 	The Interconnection Point(s) shall be established and maintained in accordance with Good
Utility Practice and the applicable NERC, Federal, State, OATT and ECAR standards and policies
for Transmission Provider service to Local Distribution Company.






	2.4.2	 	Reactive Power. Transmission Provider and Local Distribution Company recognize and
agree that they have a mutual responsibility for maintaining voltage at the Interconnection
Points. Transmission Provider is responsible for maintaining Transmission System voltage as
listed in Sections 8.1, 8.2 and 8.3 and reasonably compensating for reactive power losses
resulting from transmission service. The Local Distribution Company is responsible for
controlling Distribution System voltage and compensating for Distribution System reactive
power losses and reactive power consumed by retail customers. The Local Distribution Company
may use a combination of static and dynamic reactive resources at




 









 






	 	 	various locations around the Transmission Provider’s system. The Local Distribution
Company’s and the Transmission Provider’s SCADA systems shall be used to determine the net
exchange of reactive power on a total interconnections basis. For those distribution
substations where there are no SCADA facilities in place the reactive flows shall be
determined from SCADA data on the connecting lines in conjunction with computer load flow
simulations. At load levels below 90% of peak the system should be designed such that the
average power factor for the sum of all Interconnection Points is between 90% lagging and 90%
leading (“peak” as used here shall refer to a current year’s maximum MW load for the Local
Distribution Company). For load levels above 90% of peak the power factor should be at 98%
(lagging or leading), or better. If the power factor falls below this minimum the Planning
Committee shall review available options and determine the best method of addressing any
resulting system problems.






	2.5(a) 	 The Local Distribution Company shall comply with Transmission
Provider’s reasonable operating requirements or switching procedures. The Local
Distribution Company shall verbally notify the Transmission Provider if the Local
Distribution Company is unable to comply with this Section at any time during the term of
the Agreement.






	(b)	 	The Transmission Provider shall comply with Local Distribution Company’s reasonable
operating requirements or switching procedures. The Transmission Provider shall verbally
notify the Local Distribution Company if the Transmission Provider is unable to comply with
this Section at any time during the term of the Agreement.






	2.6	 	Local Distribution Company shall comply with the requests, orders, directives and
requirements of Transmission Provider in its role of implementing the directives of the
Security Coordinator. Any such requests, orders, directives or requirements of Transmission
Provider must be (a) issued in accordance with Good Utility Practice, (b) not unduly
discriminatory, (c) otherwise in accordance with applicable tariffs or applicable federal,
state or local laws, (d) in conformance with NERC operating procedures, and (e) reasonably
necessary to maintain the integrity of the Transmission System.






	2.7	 	Load Shedding






	 	2.7.1	 	Local Distribution Company shall comply, as part of a Control Area program,
with installation of automatic underfrequency load shedding equipment and maintain
compliance with the standards set forth in NERC and ECAR operating standards and
policies at Transmission Provider’s expense.




 









 












	 	2.7.2	 	The Transmission Provider may direct the Local Distribution
Company to shed load to maintain the reliability and integrity of the Transmission
System, in accordance with the OATT. The Transmission Provider and the Local
Distribution Company will comply with MPSC directives and will endeavor to minimize
the impact on the Local Distribution Company customers.






	2.8	 	Not a Reservation for Transmission Service






	 	2.8.1	 	Local Distribution Company, or an Eligible Customer under the OATT, shall be
responsible for making arrangements under the OATT for transmission and any ancillary
services associated with the delivery of capacity and/or energy purchased or produced by
the Local Distribution Company, which services shall not be provided under this
Agreement.






	 	2.8.2	 	Local Distribution Company and Transmission Provider make no guarantees to the
other under this Agreement with respect to transmission service that is available under
the Transmission Provider’s OATT or any other tariff under which transmission service
may be available in the region. Nothing in this Agreement shall constitute an express
or implied representation or warranty with respect to the current or future availability
of transmission service. Should the Parties enter into an arrangement under the OATT
or another tariff, any terms in this Interconnection Agreement that may be in conflict
with that tariff shall be subordinate to the terms of that tariff.





ARTICLE 3. Operation and Maintenance





	3.1	 	The Operating Committee shall develop specific methods and procedures with respect to Local
Distribution Company’s and Transmission Provider’s systems covering at least, but not limited
to, the following areas: safety, voltage control, outage planning and implementation,
service restoration, emergency operations procedures, frequency controls, environmental
matters, and maintenance planning and execution.






	3.2	 	Exhibit 5 reflects ownership changes since August 7, 2007. Exhibit 5 Wiring Diagrams (WDs)
will be updated continuously in each Party’s Drawing Management System (DMS) which is shared
between the Parties and approved by both Parties at least annually when Exhibit 6 is updated
to show changes in ownership. For purpose of this Section 3.2, such submission and approval
of changes shall be in writing consistent with Section 11.1. For current ownership
(reflecting ownership changes since August 7, 2007), see the WDs in the DMS. The original
Exhibit 5 WDs and all updates will be retained for future reference.




 









 












	3.3	 	All operation and maintenance activities will be the financial responsibility of the owning
Party. All operation and maintenance activities on Jointly Owned Assets will be under the
direction and control of the Party that owns the greater percentage of the major equipment at
that location. In the case where both Parties own an equal share the Local Distribution
Company shall have such direction and control. The Parties’ respective share of
responsibility for the costs of all operation and maintenance activities on Jointly Owned
Assets shall be the same percentage as the percentage of major equipment owned by the Party in
that substation as set forth in Exhibit 6 and its subsequent addendums. All
generation-related assets owned by the Local Distribution Company in a substation will be
included as a part of the Local Distribution Company’s assets in making this calculation.
Responsibilities related to third-party owned generation-related assets will be split
according to the nominal operating voltage at the point of connection of the generation
circuit. At 120kV and above the third-party generation-related assets will be included as a
part of the Transmission Provider’s assets for purposes of making this calculation. Below 120
kV the third-party generation-related assets will be included as a part of the Local
Distribution Company’s assets for purposes of making this calculation. Major equipment shall
be defined as main power transformers, 23 kV, 46 kV, 138 kV, and 345 kV circuit breakers,
power system regulators and reclosers, and 46 kV and 138 kV capacitor banks. (Any three-phase
installation of such equipment shall count as a single unit). Exhibit 6 will be updated with
an addendum at least annually by the Transmission Provider and approved in writing by the
Local Distribution Company to show all changes in equipment ownership in the joint
substations. The original Exhibit 6 and all addendums will be retained for future reference.
In those substations where each Party owns assets each Party shall be financially responsible
for its appropriate share of station power energy usage.






	3.4	 	The Parties agree that the principles upon which the initial identification was made of
facilities as being either Transmission or Distribution (See the definitions of “Transmission”
and “Distribution” in Section 1.1 of the Amended and Restated Easement Agreement dated April
29, 2002 between the Parties) shall continue to be applied for the future unless modification
is agreed to by both Parties. Should future system modifications result in the
reclassification of assets, the Parties agree to convey ownership of those assets to the
appropriate Party. However, no such reclassification shall affect how the other Sections of
this Agreement are applied until there is a change in ownership of the facilities involved and
until any related changes are made to this Agreement and its exhibits. Upon such a change in
ownership, the Planning Committee shall revise Exhibits 6 and/or 7 when needed to reflect the
change in ownership. The conveyed facilities shall be priced at 1.18 times the seller’s
net plant value but in any case shall not be less than zero dollars (i.e. no payment from




 









 






	 	 	seller to purchaser will occur as a result of net plant value being less than zero). As
used herein, ”net plant value” shall mean the asset’s original cost depreciated according to
the seller’s accepted accounting method. In addition, should either Party plan to abandon or
otherwise take out of service any facilities which could be of use as part of the other
Party’s system, it shall offer to convey to the other Party such facilities before they are
taken out of service under the same pricing formula outlined above. All types of conveyances
discussed in this paragraph shall be subject to the following conditions:






	 	(a)	 	The Planning Committee shall within 12 months of the Effective Date of this
Agreement develop appropriate timeframes and procedures for accomplishing such
conveyances.






	 	(b)	 	At least 12 months (or as close as feasible to 12 months) before implementing
system modifications which would result in such a conveyance, the Party planning to do
such modifications shall notify the other Party of such plans. The other Party, if it
wishes, shall then have 2 months within which to propose an alternative modification
which is consistent with Good Utility Practice, which would reduce or eliminate the need
for conveyances, and which would cost the Party seeking to do the modifications no more
than the originally proposed modification. If such an alternative is provided in a
timely manner, the Party proposing to do the modification shall consider the alternative
and shall not unreasonably refuse to pursue the alternative instead of the original
proposal.






	 	(c)	 	Possible impediments to timely conveying the property in question (e.g.
difficulty in getting release from the conveyor’s indenture) shall be referred to the
Administrative Committee. The Administrative Committee is authorized to modify the
requirements of this Section with regard to such a specific proposed modification
however it deems appropriate in light of the possible impediment and other
circumstances.






	3.5	 	Each Party shall operate any equipment that might reasonably be
expected to have impact on the operations of the other Party in a safe and efficient manner
and in accordance with all applicable federal, state, and local laws, NERC operating
practices, and Good Utility Practice, and otherwise in accordance with the terms of this
Agreement. Each Party shall comply with the reasonable requests, orders, directives and
requirements of the other Party, which are authorized under this Agreement.




 









 












	3.6(a) 	 	 Without limiting the generality of Section 3.5, Local Distribution Company shall own,
operate and maintain its Distribution System in a manner in accordance with Good Utility
Practice to prevent degradation of voltage or services of the Transmission System. The Local
Distribution Company shall be responsible for the costs to repair or replace the Distribution
System and Local Distribution Company’s Interconnection Equipment.






	3.6(b) 	 	 Without limiting the generality of Section 3.5, Transmission Provider shall own, operate
and maintain its Transmission System in a manner in accordance with Good Utility Practice to
prevent degradation of voltage or services of Local Distribution Company’s Distribution
System. The Transmission Provider shall be responsible for the costs to repair or replace
the Transmission System and Transmission Provider’s Interconnection Equipment.






	3.6(c) 	 	 Without limiting the generality of Section 3.5, Local Distribution Company or Transmission
Provider, as appropriate pursuant to Section 3.3 hereof, shall operate and maintain Jointly
Owned Assets in a manner in accordance with Good Utility Practice to prevent degradation of
voltage or services to either Party.






	3.7(a) 	 	 Except during an Emergency, Local Distribution Company shall not, without prior
Transmission Provider authorization, operate any Transmission Provider circuit, including
transformer, line or bus elements. Local Distribution Company shall retain the right to
operate Transmission Provider equipment during an Emergency for imminent personnel safety
threat, to prevent damage to equipment or to maintain the integrity of the Distribution
System. When practical, prior to operation of such equipment, Local Distribution Company
shall provide notice to the Transmission Provider. The Local Distribution Company shall not
operate any Transmission System circuit if upon notice the Transmission Provider expressly
refuses to grant permission to the Local Distribution Company. Within five (5) working days of
such Emergency, Local Distribution Company shall provide written explanation of such Emergency
to Transmission Provider.






	3.7(b) 	 	 Except during an Emergency, Transmission Provider shall not, without prior Local
Distribution Company authorization, operate any Local Distribution Company circuit, including
transformer, line or bus elements. Transmission Provider shall retain the right to operate
Local Distribution Company equipment, during an Emergency for imminent personnel safety
threat, to prevent damage to equipment or to maintain the integrity of the Transmission
System. When practical, prior to operation of such equipment, Transmission Provider shall
provide notice to Local Distribution Company. Transmission Provider shall not operate any
Distribution System circuit. If upon notice the Local Distribution Company




 









 






	 	 	expressly refuses to grant permission to the Transmission Provider. Within five (5) working
days of such Emergency, Transmission Provider shall provide written explanation of such
Emergency to Local Distribution Company.






	3.7(c) 	 	 In an Emergency, joint facilities shall be operated by the Party able to first respond
with Qualified Personnel.






	3.8	 	Local Distribution Company and Transmission Provider shall design,
install, test, calibrate, set, and maintain their respective Protective Relay equipment in
accordance with Good Utility Practice, applicable federal, state or local laws and this
Agreement, as set forth in Article 6 hereof. In the case of jointly owned relaying
equipment, the Party having direction and control pursuant to Section 3.3 hereof shall
design, install, calibrate, set, and maintain Protective Relay equipment in accordance with
Good Utility Practice. Without limiting the generality of Section 3.5(c) above, costs for
such work will be split between the Companies on a
predetermined ownership percentage basis as set forth in the then-current version of Exhibit
6.






	3.9(a) 	 	 If Transmission Provider reasonably determines that (i) any of Local
Distribution Company’s Interconnection Equipment fails to perform in a manner in accordance
with Good Utility Practice or this Agreement, or (ii) Local Distribution Company has failed
to perform proper testing or maintenance of its Interconnection Equipment in accordance with
Good Utility Practice or this Agreement, Transmission Provider shall give Local Distribution
Company written notice to take corrective action. Such written notice shall be provided by
Transmission Provider to Local Distribution Company’s Representative as soon as practicable
upon such determination. If Local Distribution Company fails to initiate corrective action
promptly, and in no event later than seven (7) days after the delivery of such notification,
and if in Transmission Provider’s reasonable judgment leaving Local Distribution Company’s
Distribution System connected with Transmission System would create an Emergency or Network
Security Condition, Transmission Provider may, with as much prior verbal notification to
Local Distribution Company and Distribution System Control as practicable, open only the
Interconnection Point(s) needing corrective action connecting the Local Distribution Company
and Transmission Provider until appropriate corrective actions have been completed by Local
Distribution Company, as verified by Transmission Provider. Prior to taking such action,
Transmission Provider shall give appropriate consideration to the needs of the Local
Distribution Company’s end-use customers. Transmission Provider’s judgment with regard to
an interruption of service under this paragraph shall be made in accordance with Good Utility
Practice and subject to Section 3.1 hereto. In the case of such interruption, Transmission
Provider shall immediately




 









 






	 	 	confer with Local Distribution Company regarding the conditions causing such interruption and
its recommendation concerning timely correction thereof. Both Parties shall act promptly to
correct the condition leading to such interruption and to restore the connection.






	3.9(b) 	 	 If Local Distribution Company reasonably determines that (i) any of
Transmission Provider’s Interconnection Equipment fails to perform in a manner in accordance
with Good Utility Practice or this Agreement, or (ii) Transmission Provider has failed to
perform proper testing or maintenance of its Interconnection Equipment in accordance with
Good Utility Practice or this Agreement, Local Distribution Company shall give Transmission
Provider written notice to take corrective action. Such written notice shall be provided
by Local Distribution Company to Transmission Provider’s Representative as soon as
practicable upon such determination. If Transmission Provider fails to initiate corrective
action promptly, and in no event later than seven (7) days after the delivery of such
notification, and if in Local Distribution Company’s reasonable judgment leaving Transmission
System connected with Local Distribution Company’s Distribution System would create an
Emergency, Local Distribution Company may, with as much prior verbal notification to
Transmission Provider and Distribution System Control as practicable, open only the
Interconnection Point(s) needing corrective action connecting the Transmission Provider and
Local Distribution Company until appropriate corrective actions have been completed by
Transmission Provider, as verified by Local Distribution Company. Local Distribution
Company’s judgment with regard to an interruption of service under this paragraph shall be
made in accordance with Good Utility Practice and subject to Section 3.1 hereto. In the
case of such interruption, Local Distribution Company shall immediately confer with
Transmission Provider regarding the conditions causing such interruption and its
recommendation concerning timely correction thereof. Both Parties shall act promptly to
correct the condition leading to such interruption and to restore the connection.
	 
	3.10	 	Outages






	 	3.10.1	 	Outage Authority and Coordination. In accordance with Good
Utility Practice, each Party may, in close cooperation with the other, remove from
service its system elements that may impact the other Party’s system as necessary to
perform maintenance or testing or to replace installed equipment. Absent the
existence of an Emergency, the Party scheduling a removal of a system element from
service will schedule such removal on a date mutually acceptable to both Parties, in
accordance with Good Utility Practice.




 









 












	 	3.10.2	 	The Parties shall coordinate inspections, Planned Outages, and maintenance of their
respective equipment, facilities and systems so as to minimize the impact on the availability,
reliability and security of both Parties’ systems and operations when the outage is likely to
have a materially adverse impact on the other Party’s system or the Local Distribution
Company’s end-use customers. Subject to the confidentiality provisions of Article 20, on or
before October 1 of each year during the term hereof, the Parties shall exchange non-binding
Planned Outage schedules for the following calendar year, which shall be developed and
followed in accordance with Good Utility Practice, for the Distribution System and
Transmission System. The Parties shall communicate the outage schedules as promptly as
possible, provided that in no event shall such schedule be provided less than fifteen (15)
days prior to a Planned Outage. The Parties shall keep each other updated regarding any
changes to such schedules.
	 
	 	3.10.3	 	Unplanned Outages






	 	3.10.3.1	 	Distribution System Unplanned Outage. In the event of an Unplanned Outage
of a system element of the Distribution System adversely affecting the Transmission
System, the Local Distribution Company will act in accordance with Good Utility Practice
to promptly restore that system element to service unless the Local Distribution Company
obtains concurrence from the Transmission Provider that some deferral is reasonable, and
this concurrence shall not be unreasonably withheld. The Local Distribution Company
shall plan and maintain its Distribution System such that the average length of
distribution system outages having a direct impact on the Transmission System shall not
exceed 166 minutes per event on an annual basis. For any year in which the average
outage duration exceeds this limit, the Local Distribution Company shall develop a plan
to improve the outage restoration process and reduce outages and shall obtain the
Transmission Provider’s concurrence with this plan. Within forty-eight hours (48) of
the beginning of any Unplanned Outage, the Local Distribution Company shall provide the
Transmission Provider with a restoration plan.
	 
	 	3.10.3.2	 	Transmission System Unplanned Outage. In the event of an Unplanned Outage
of a system element of the Transmission System adversely affecting the Local
Distribution Company’s Distribution System, the




 









 






	 	 	 	Transmission Provider will restore the system to normal as soon as possible unless
the Transmission Provider obtains concurrence from the Local Distribution Provider
that some deferral is reasonable, and this concurrence shall not be unreasonably
withheld. The Transmission Provider shall plan and maintain its Transmission System
such that the average length of Transmission System outages having a direct impact on
customers of the Local Distribution Company shall not exceed 166 minutes on an annual
basis. For any year in which the average outage duration exceeds this limit, the
Transmission Provider shall develop a plan to improve the outage restoration process
and reduce outages and shall obtain the Local Distribution Company’s concurrence with
this plan. Within forty-eight hours (48) of the beginning of any Unplanned Outage
the Transmission Provider shall provide the Local Distribution Company with a
restoration plan. For any 138 kV system outage it is expected that the system will
be restored to its normal configuration within seven (7) days; for any 345 kV system
outage it is expected that the system will be restored to its normal configuration
within thirty (30) days. If it is expected that any Unplanned Outage will exceed
these limits the Transmission Provider shall provide the Local Distribution Company
with detailed information on measures being taken to minimize the outage time.






	 	3.10.4	 	Planned Outages






	 	3.10.4.1	 	Distribution System Planned Outage. In the event of a Planned Outage of a
system element of the Distribution System adversely affecting the Transmission System, the
Local Distribution Company will act in accordance with Good Utility Practice to promptly
restore that system element to service in accordance with its schedule for the work that
necessitated the Planned Outage.
	 
	 	3.10.4.2	 	Transmission System Planned Outage. The Transmission Provider shall review
all Transmission System Planned Outages with the Local Distribution Company. In the
event of a Planned Outage of a system element of the Transmission System adversely
affecting the Local Distribution Company’s Distribution System, the Transmission Provider
will act in accordance with Good Utility Practice to promptly restore that system element
to




 









 






	 	 	 	service in accordance with its schedule for the work that necessitated the
Planned Outage.






	3.11	 	The Parties shall use best efforts in accordance with Good Utility Practice to coordinate
operations in the event of any Forced or Planned Outage that affects the other Party’s system.






	3.12	 	Black Start Plan Participation. In accordance with Good Utility Practice, Local
Distribution Company agrees to participate in Transmission Provider’s Black Start Plan for the
Distribution System and the Transmission System, as well as any verification testing.






	3.13	 	The Parties shall notify and make available in a timely manner, electric system modeling
information necessary for the other Party to monitor, analyze, and protect its facilities in a
real time environment, no less than 30 days prior to the energization of new or reconfigured
network facilities.





ARTICLE 4. Supervisory Control and Data Acquisition, SCADA





	4.1	 	If the Transmission Provider chooses to operate its own SCADA system, or to make
modifications or additions to the existing system, the following terms and conditions of
this Article 4 will apply.






	4.2	 	Interconnection Points containing SCADA and communications equipment installed prior to April
1, 2001, shall be considered to satisfy the terms and conditions of this article. For those
Interconnection Points that existed prior to April 1, 2001 that did not contain SCADA and
communications equipment, and for new Interconnection Points installed after April 1, 2001
where SCADA and communications equipment is necessary for and requested by the Transmission
Provider to perform monitoring, state estimation and contingency analysis, the Local
Distribution Company shall install and operate such equipment at the Transmission Provider’s
expense. Each Interconnection Point or other mutually agreeable location with SCADA and
communications equipment shall have one dedicated communications path to the Local
Distribution Company’s control center for the RTU data. The cost of the dedicated
communications path and general use station phone shall be shared on an equal basis.
Additional data paths and communications equipment requested, either emanating from the
substation, the Local Distribution Company’s control center, or the Transmission Provider’s
control center, will be at the expense of the requestor. This data and status information
may be real time or with a time delay mutually acceptable to the Parties. The method of
providing this data and control will be via an industry standard protocol such as
Inter-Control Center Protocol (ICCP) or other method agreed to by the




 









 






	 	 	Parties. Such data may include, but not be limited to megawatts, megavars, voltage,
amperes, device status, interchange schedule error, and communication system status.






	4.3	 	The Transmission Provider reserves the right at its expense, to require, for new, or modified
Local Distribution Company Interconnection Points, installation of a Transmission Provider’s
RTU or installation of a dual port RTU to provide data and control directly to the
Transmission Provider within the Local Distribution Company’s substation. The Local
Distribution Company will assist in furnishing desired inputs for the Transmission Provider’s
RTU.






	4.4	 	The operating metering system shall consist of instantaneous values of MW, MVAR, and
voltage.






	 	4.4.1	 	Values shall be inputted to a RTU or comparable communication device for
communication with the Party having Control Area responsibility.






	 	4.4.2	 	Transducers may utilize the voltage transformers and current transformer
secondary circuits also utilized by the revenue metering equipment for a particular
interconnection. In such case, the performance criteria listed in Exhibit 4 of the
Agreement, Metering Specifications, for the voltage transformers and the current
transformers, shall apply. Relaying class voltage transformers and or current
transformers shall not be utilized unless mutually agreed between all the owners of the
metering equipment and the Local Distribution Company.






	 	4.4.3	 	Transducers shall have maximum 0.3% inaccuracy. Transducers shall be field
calibrated as necessary but at least once every ten (10) years and documentation shall
be retained showing the calibration results until next calibration.






	 	4.4.4	 	Telemetry shall be maintained and calibrated such that overall
inaccuracy of MW, MVAR, and voltage values is less than 1.0% of full scale.






	4.5	 	To the extent new RTUs and associated communications equipment is to be installed, the Local
Distribution Company shall install or facilitate installation of the RTU and associated
communications equipment as soon as practicable, provided that installation shall be
accomplished within a time period of no more than 270 days following notice by Transmission
Provider or prior to commissioning of any new Interconnection Points.




 









 











ARTICLE 5. Revenue Metering





	5.1	 	Transmission Provider shall own, operate, test and maintain any metering equipment at the
Interconnection Points, as required by this Article 5 not including any metering equipment
owned by the Local Distribution Company for use in metering its end-use customers.
Transmission Provider and Local Distribution Company agree that, as to all Interconnection
Points in existence as of the Effective Date, no new or different metering equipment or
arrangements shall be required. For existing Interconnection Points where low-side metering
exists without loss compensation, the Parties will agree to adjust the metering data in such a
manner to account for any real power losses between the location of the meter and the
Interconnection Point. To the extent existing metering equipment is replaced and when new
metering equipment is installed at Interconnection Points in existence as of the Effective
Date, such replacements or installations shall meet the standards set in Section 5.2.
Transmission Provider shall provide, install, own, operate, test and maintain the new metering
equipment located at the Interconnection Points.






	5.2	 	The Revenue Quality Metering System shall consist of all instrument transformers (current and
voltage), secondary wiring, test switches, and meter(s) required to determine the metering
values for record for any given metering point.






	 	5.2.1	 	Metering shall be form 9, 3-element for 4-wire systems and form 5, 2-element for
3-wire systems.






	 	5.2.2	 	Meters shall measure, at a minimum, megawatt hours and megavar hours and have
bi-directional capability, where applicable. All measured values shall have individual
outputs where applicable and a minimum 35-day interval data recording capability for
each measured value.






	 	5.2.3	 	Whenever feasible, any new metering facilities shall be located at the same
physical location as the Interconnection Point. If it is not reasonable to have the
metering facilities and the Interconnection Point at the same physical location, the
metering data will be adjusted to account for real power losses between the location of
the meter and the Interconnection Point.






	 	5.2.4	 	Transmission Provider shall maintain records that demonstrate compliance
with all meter tests and maintenance conducted in accordance with Good Utility
Practice for the life of the




 









 






	 	 	 	Interconnection Point. Local Distribution Company shall have reasonable access to the
records.






	 	5.2.5	 	For installations where the metering is performed using loss compensation, the factory
certified test results of the power transformer, if available, including load, no-load losses
and calculated meter loss calculations, shall be recorded in a written record. Local
Distribution Company shall have reasonable access to the records.






	 	5.2.6	 	Transmission Provider shall maintain records of the factory certified test results, or the
utility test shop test results, showing compliance of the meters with the applicable metering
test standards.






	 	5.2.7	 	Transmission Provider’s Metering equipment shall be tested by Transmission Provider at its
own expense not less than once every year, unless an extension of the testing cycle is agreed
upon by the Parties. The accuracy of such metering equipment shall be maintained by
Transmission Provider in accordance with applicable regulatory standards. At the request of
either Party, special tests shall be made. If any special meter test discloses the metering
device to be registering within acceptable limits of accuracy as specified herein, then the
Party requesting such special meter test shall bear the expense thereof. Otherwise, the
expense of such test shall be borne by the owner.
Representatives of either Party shall be afforded opportunity to be present at all routine
or special tests and upon occasions when any readings for purposes of settlements hereunder
are taken from meters not producing an automatic record.






	 	5.2.8	 	If, as a result of any test, any meter shall be found to be registering more than two (2)
percent above or below one hundred (100) percent of accuracy, the account between the Parties
hereto shall be corrected for a period equal to one-half of the elapsed time since the last
prior test, according to the percentage of inaccuracy so found, except that if the meter shall
have become defective or inaccurate at a reasonably ascertainable time since the last prior
test of such meter, the correction shall extend back to such time. No meter shall be left in
service if found to be more than two (2) percent above or below one hundred (100) percent of
accuracy. Should metering equipment at any time fail to register, the energy delivered shall
be determined from the best available data. All meters shall be kept under seal, such seals
to be broken only when the meters are to be tested or adjusted.




 









 












	 	5.2.9	 	Test switches shall be installed to allow independent testing and/or replacement
of each meter and transducer utilizing the secondary circuit so as not to interrupt the
operation of other devices utilizing the secondary circuit.






	 	5.2.10	 	In substations where an RTU or other remote data collecting and telecommunication
device is present, meters shall have form C, 3-wire outputs with programmable values
determined by the Transmission Provider for bi-directional MWHs and MVARs.






	 	5.2.11	 	In the event an interconnection meter needs replacement or repair, a representative
from Local Distribution Company shall be given a reasonable opportunity to be present
during such repair or replacement.





ARTICLE 6. Protective Relaying and Control





	6.1	 	Transmission Provider and the Local Distribution Company shall, in
accordance with Good Utility Practice, coordinate, review and approve all new Protective
Relaying equipment, including equipment settings, Protective Relay schemes, drawings, and
functionality associated with each Interconnection Point. Protective Relaying equipment
and schemes installed before the date of this agreement shall be considered to satisfy the
terms and conditions of this Article 6. When existing equipment or schemes are replaced or
when new equipment or schemes are installed per this Article 6 or in association with new
Interconnection Points, then the terms and conditions of Article 6 shall apply. Each Party
shall incur the expense for the work on its system.






	6.2	 	To the extent that there is generation on the Distribution System which, in the reasonable
judgment of either Party, may contribute material amounts of current to a fault on the
Transmission System, the Local Distribution Company shall have and enforce standards to ensure
the provision, installation and maintenance of relays, circuit breakers, and all other devices
necessary to promptly remove any fault contribution of such generation to any short circuit
occurring on the Transmission System and not otherwise isolated by the Transmission Provider
equipment. Such standards will be included in the Local Distribution Company’s connection
requirements for generation. Transmission Provider and Local Distribution Company shall not
be responsible for protection of such generation.






	6.3	 	Transmission Provider shall own, operate, maintain and test those Protective Relay
Systems that control their breakers or equivalent protective devices. Local
Distribution Company shall own, operate, maintain, and test those Protective Relay
Systems that control their




 









 






	 	 	breakers or equivalent protective devices governed by this Article 6. The Parties shall
maintain, and, as necessary, upgrade their respective Protective Relay Systems and shall
provide the other Party with access to available copies of operation and maintenance manuals
and test records for all relay equipment upon request. The Transmission Provider will
provide protective relay settings for the relays that control breakers or equivalent
protective devices owned by the Local Distribution Company that also protect Transmission
Provider’s equipment. The Local Distribution Company will review and apply the settings.






	6.4	 	The owner (Transmission Provider or Local Distribution Company) of the line will provide the
relay communication channel necessary for line protection at its expense. Owner will
participate with other Party to test communication schemes upon request without charge.






	6.5	 	The Parties shall test their respective relays associated with the Interconnection Points for
correct calibration and operation. Parties shall coordinate design, installation,
operation, and testing of Protective Relay schemes to insure that such relays operate in a
coordinated manner so as to not cause adverse operating conditions on the other Party’s
system.






	6.6	 	Local Distribution Company shall be responsible for Protective Relay maintenance, calibration
and functional testing of relay systems that protect Local Distribution Company’s equipment
associated with the Interconnection Points and that protect Transmission Provider from Local
Distribution Company’s Interconnection Equipment to the extent such calibration and testing
are in accordance with Good Utility Practice. All such maintenance and testing must be
performed by Qualified Personnel selected by the Local Distribution Company. In addition,
Local Distribution Company shall allow Transmission Provider to conduct visual inspection of
all Protective Relays and associated maintenance records directly related to the
interconnection. Related maintenance and operational records shall be maintained by the
Local Distribution Company in accordance with Good Utility Practice. Upon completion of
Protective Relay calibration testing and relay functional testing, Local Distribution Company
shall make available copies of test reports and related records for review by Transmission
Provider upon request. Local Distribution Company shall review test reports and document
that Protective Relay System’s tests and settings, as shown on such test reports, have been
done in accordance with the equipment’s specifications and Good Utility Practice.






	6.7(a) 	 	 As Transmission Provider’s system protection requirements change, Transmission Provider
will upgrade its Protective Relaying System in accordance with Good Utility Practice. If
these upgrades affect the serviceability and acceptability of the Protective Relaying Systems
on the




 









 






	 	 	Interconnection Equipment which may be installed, owned, and operated by Local Distribution
Company, the Local Distribution Company must upgrade its Protective Relay Systems at its
expense (unless such modifications are required in association with the addition of
generation to the system in which case Section 9.8 shall apply) as necessary to bring them
into compatibility with that installed by Transmission Provider. Transmission Provider shall
give Local Distribution Company notice of such upgrade as soon as practicable prior to the
anticipated date of such upgrade. Any proposed protective system upgrades shall be reviewed
by the Planning Committee in accordance with Section 7.3 (vi) hereof.






	6.7(b) 	 	 As Local Distribution Company’s system protection requirements change, Local Distribution
Company will upgrade its Protective Relaying System in accordance with Good Utility Practice.
If these upgrades affect the serviceability and acceptability of the Protective Relaying
Systems on the Interconnection Equipment which may be installed, owned, and operated by
Transmission Provider, Transmission Provider must upgrade its Protective Relaying Systems at
its expense (unless such modifications are required in association with the addition of
generation to the system in which case Section 9.8 shall apply) as necessary to bring them
into compatibility with that installed by Local Distribution Company. Local Distribution
Company shall give Transmission Provider notice of such upgrade as soon as practicable prior
to the anticipated date of such upgrade. Any proposed protective system upgrades shall be
reviewed by the Planning Committee in accordance with Section 7.3 (vi) hereof.






	6.8	 	Local Distribution Company shall provide necessary space to install or expand relay panels
for substation system protection if requested by Transmission Provider. Any incremental
costs required to accommodate such request shall be the responsibility of the Transmission
Provider.






	6.9	 	Transmission Provider shall provide the necessary space to install or expand relay panels for
substation system protection if requested by Local Distribution Company. Any incremental
costs required to accommodate such request shall be the responsibility of the Local
Distribution Company.






	6.10	 	Each Party will provide access to the other to fault recorder, sequence of events and relay
information such as dial up access of digital relays.





ARTICLE 7. Planning and Obligation to Serve





	7.1	 	Adequacy Obligation. Subject to applicable regulatory approvals,
including adherence to Least-Cost planning requirements and principles, adherence to
applicable NERC, ECAR or other regional reliability council




 









 






	 	 	or successor organization’s reliability requirements, and all other applicable operating
reliability criteria and subject to the oversight and direction of the appropriate RTO or
ISO, the Transmission Provider shall operate, maintain, plan and construct its Transmission
System in accordance with Good Utility Practice in order to:






	 	(i)	 	deliver on a reliable basis the projected capacity and energy needs
of all loads served by the Local Distribution Company’s Distribution System and
dependent upon the Transmission Provider’s facilities for delivery of such energy to
the Distribution System;
	 
	 	(ii)	 	provide needed support to the Local Distribution Company where a
transmission addition is the Least-Cost electric solution to an improvement need,
including but not limited to, the reliability needs of the Local Distribution Company;
and
	 
	 	(iii)	 	deliver energy from both existing and new generating facilities
connected to and dependent upon Transmission Provider’s transmission of such
energy






	7.2	 	With regard to planning and construction of projects which affect Local Distribution Company
and Local Distribution Company’s load-serving area, the Parties shall develop methods and
procedures covering at least the following areas:






	 	(i)	 	coordination between short-term and long-term distribution and
transmission planning;
	 
	 	(ii)	 	developing and sharing computer simulation models needed to
support Transmission Provider and Local Distribution Company planning activities;
	 
	 	(iii)	 	coordination of permitting (including local and state approvals) and
siting;
	 
	 	(iv)	 	engineering and scheduling of new projects;
	 
	 	(v)	 	construction and inspection standards;
	 
	 	(vi)	 	information-sharing and priority-setting; and
	 
	 	(vii)	 	health and safety issues.






	7.3	 	With respect to Local Distribution Company’s load-serving area, the Planning Committee, shall:




 









 












	 	(i)	 	implement the methods and procedures developed pursuant to
Section 7.2;
	 
	 	(ii)	 	review planning studies and reports regarding projects needed or
proposed for the area in the next five (5) years, or as determined by the Planning
Committee;
	 
	 	(iii)	 	recommend additional studies or evaluation of plans;
	 
	 	(iv)	 	follow Least-Cost planning principles in recommending specific
projects;
	 
	 	(v)	 	at least once every year, prepare a planning report which shall
include in priority order a list of projects proposed by either Party for the next
year, the estimated costs of such projects, and the timetable for such projects,
including the in-service date; and
	 
	 	(vi)	 	review proposed programmatic changes to the electric system,
including protective system upgrades






	7.4	 	If the Parties agree upon the need for any such project, they shall cooperate and
coordinate in seeking all necessary regulatory approvals for such project. Transmission
Provider shall coordinate and cooperate with Local Distribution Company with respect to all
communications and commitments to municipal, county, and state agencies involved in such
project.






	7.5	 	If Local Distribution Company proposes construction of a transmission project and
Transmission Provider does not agree that such project is needed, Local Distribution
Company shall have the right to petition an appropriate RTO, ISO or applicable regulatory
agency for a declaratory ruling on whether the proposed project is needed pursuant to
Transmission Provider’s public-utility duty to plan and construct a reliable, adequate
Transmission System.
	 
	7.6	 	Load Growth and Reliability Needs. Transmission Provider is obligated to
plan and install any Transmission System components that may be necessary, as determined by
a Least-Cost planning process in accordance with Section 7.1 and consistent with the
established and consistently applied reliability criteria of the Parties, to accommodate
Local Distribution Company’s planned load growth and planned reliability improvements.
Transmission Provider will construct new
interconnections to Local Distribution Company facilities in accordance with Transmission
Provider’s planning criteria, other agreements in effect between the Parties, and Good
Utility Practice. Transmission Provider shall bear the responsibility for such planning
and installing in accordance




 









 






	 	 	with this Article 7. Transmission Provider’s obligations under this Section 7.6 shall
include the planning and installation of any new Interconnection Points that may be
necessary to accommodate Local Distribution Company’s planned load growth and planned
reliability improvements. Recovery of the cost of such additions shall be in accordance with
the OATT or other applicable tariff.






	7.7	 	Local Distribution Company shall be the first point of contact and the wire-services
provider for end-use customers.






	7.8	 	Transmission Provider shall annually submit to Local Distribution Company, no later
than February 1 of each year:






	 	(i)	 	Transmission Provider’s plans covering the next five (5) years, or
as determined by the Planning Committee, for installing Transmission System components
that may be necessary to accommodate Local Distribution Company’s planned load growth
and reliability improvements as described in Section 7.6. Transmission Provider’s
plans shall include, but not be limited to, cost estimates and installation schedules
for Transmission System components, and shall provide specific detail sufficient to
allow Local Distribution Company to compare Transmission Provider’s plans with Local
Distribution Company’s in-service requirements to meet its planned load growth and
reliability needs.






	 	(ii)	 	A description of any changes to the Local Distribution Company’s
Distribution System that may be needed to accommodate Transmission Provider’s
plans set forth in Section 7.8(i) will be requested by the Transmission Provider.






	 	(iii)	 	Projected voltage levels under Normal System Conditions and
Transmission Provider’s FERC 715 Planning criteria conditions at anticipated annual
peak load and 80% of anticipated annual peak load for each Interconnection Point
with planned additions for the next five (5) years, or as determined by the Planning
Committee.






	7.9	 	Local Distribution Company shall annually submit to Transmission Provider,






	 	(a)	 	no later than December 1 of each year, the most recent actual
summer and winter demands in megawatts (MW) and megavars (Mvar) for all
Interconnection Points connected to the Transmission System at the time of the
Transmission Provider’s most recent seasonal system peaks (Transmission Provider must
provide the Local Distribution Company the day and hour of such peak no later than
September 1); and




 









 












	 	(b)	 	no later than February 1 of each year:






	 	(i)	 	annual peak demand forecasts in MW for each Local
Distribution Company Interconnection Point to the Transmission System for
the next five (5) years, or as determined by the Planning Committee,
together with corresponding projected power factors; and






	 	(ii)	 	planned facility (new Interconnection Points) connections
to the Transmission System for the next five (5) years, or as determined by
the Planning Committee.





ARTICLE 8. Transmission Service Level





	8.1	 	Subject to applicable regulatory approvals, including adherence to Least-
Cost planning requirements and principles, adherence to applicable NERC, ECAR or other
regional reliability council or successor
organization’s reliability requirements, and all other applicable operating reliability
criteria and subject to the oversight and direction of the appropriate RTO or ISO, the
Transmission Provider shall operate, maintain, plan and construct its Transmission System
in accordance with Good Utility Practice to provide the following service levels:






	 	(i)	 	A minimum Steady-State Voltage of 0.97 Per Unit (PU) at all
Interconnection Points with Local Distribution Company with all influential
Transmission Provider facilities in service (no contingency conditions);
	 
	 	(ii)	 	A minimum Steady-State Voltage of 0.92 PU at all Interconnection
Points with the Local Distribution Company influenced by one or more Transmission
Provider facilities out of service (contingency conditions);
	 
	 	(iii)	 	A maximum Steady-State Voltage of 1.05 PU at all
Interconnection Points with the Local Distribution Company during all operating conditions;
	 
	 	(iv)	 	An adequate Transmission System that shall not load Local
Distribution Company facilities above normal ratings during peak load conditions
with all influential Transmission Provider facilities in service (no contingency
conditions);
	 
	 	(v)	 	An adequate Transmission System that shall not load Local
Distribution Company facilities above emergency ratings during





 









 





	 	 	 	peak load conditions with one or more influential Transmission Provider facilities out of
service (contingency conditions);
	 
	 	(vi)	 	On a three-year rolling average, experience no more than 0.357
Momentary Outage Events per 138 kV line protective zone (system average) and 0.743 Momentary
Outage Events per 345 kV line protective zone (system average) per year. As used in this
Article 8 the term “year” shall mean calendar year; and the term “line protective zone” is
illustrated and defined as follows: Any given electrical fault on a transmission line will
trip specific circuit breakers in a normally functioning system. All of the possible line
fault locations that will trip these specific circuit breakers constitute the same line
protective zone. Physically, a line protective zone consists of the conductors located
between the current transformers that provide sensing to trip the circuit breakers for a line
fault;
	 
	 	(vii)	 	Experience no more than three (3) Momentary Outage Events on any given 138 kV line protective zone and two (2) Momentary Outage Events on any given 345 kV
line protective zone per year;
	 
	 	(viii)	 	On a three-year rolling average, experience no more than 0.21 Unplanned Outages per
138 kV line protective zone (system average) and 0.18 Unplanned Outages per 345 kV line
protective zone (system average) per year;
	 
	 	(ix)	 	Experience no more than four (4) Unplanned Outages on any
given 138 kV line protective zone and three (3) Unplanned Outages on any given 345 kV
line protective zone per year;
	 
	 	(x)	 	Should the Transmission Provider fail to meet any of the
requirements of Section 8.1(vi) or 8.1(viii) by more than 10% two years in a row, the
Transmission Provider shall pay, as liquidated damages and not as a penalty, to the Local
Distribution Company, an amount equal to one half of one percent (0.5%) of the annual revenue
paid by the Local Distribution Company under the applicable transmission tariff; such
liquidated damages amount shall be based upon the revenue received in the second year of such
failure. Such liquidated damages amount shall be increased by one half of a percent (0.5%)
for each additional 10% by which the Transmission Provider fails to meet the any of the given
outage targets, up to a maximum of 4.0% of the annual revenue. Outage events affecting 15% or
more of transmission line protective zones within a 24-hour period will not be counted toward
the requirements of Section 8.1.




 









 






	 	 	 	If transmission service does not meet the requirements of this Article 8, Transmission
Provider shall present an action plan acceptable to the Local Distribution Company within
sixty (60) days of non-compliance of this Article 8 to restore transmission service to the
minimum standards as described in this Article 8 in a timely manner. Should the
Transmission Provider fail to correct the deficiency(s) within one year of notification
from the Local Distribution Company, the Local Distribution Company shall have the right to
take corrective action at the
Transmission Provider’s expense. The Local Distribution Company shall defer taking such
actions for corrective measures normally requiring longer than one year to complete,
provided the Transmission Provider is diligently pursuing such measures.






	8.2	 	Should the Michigan Public Service Commission (MPSC) adopt service quality standards that the
Local Distribution Company must meet that are more stringent than current historical
performance; and should the transmission service level provided by the Transmission Provider
directly or indirectly influence the Local Distribution Company’s ability to meet such
standards, the Local Distribution Company will promptly notify the Transmission Provider of
such proposal and the Transmission Provider shall have an opportunity to participate either as
a party or in cooperation with the Distribution Company, in any related MPSC hearings or
proceedings. Subject to the foregoing and to any required approval by FERC, the Transmission
Provider shall be responsible for meeting its proportional share of the adopted service
quality standard and for any penalties that might be assessed if the standards are not met.






	8.3	 	Transmission Provider shall be responsible for those compensable disruptions/interruptions
caused by the Transmission Provider’s Transmission System to those Local Distribution
Company customers under Special Manufacturing Contracts in existence at the time of
execution of this document as set forth in Exhibit 3, including any contractual payments
due.





ARTICLE 9. New Construction and Modification





	9.1	 	Subject to this Article 9, Transmission Provider may construct additional
Transmission System elements or modify the existing Transmission System and Local
Distribution Company may construct additional Distribution System elements or modify the
existing Distribution System. All such modifications and construction provided for herein,
shall be conducted in accordance with Good Utility Practice and all applicable NERC and ECAR
Standards. The Party that modifies the system elements or constructs new system elements is
obligated to maintain the




 









 






	 	 	transmission, distribution and communications capabilities of the other Party in accordance
with Good Utility Practice to avoid or minimize any adverse impact on the other Party. The
Parties shall look to the operating history of the Local Distribution Company in the relevant
geographic area prior to the Effective Date of this Agreement, where available, in
determining what constitutes Good Utility Practice.






	9.2	 	Notwithstanding the foregoing, no modifications to or new construction of facilities or
access thereto, including but not limited to rights-of-way, fences, and gates, shall be made
by either Party which might reasonably be expected to have a material effect upon the other
Party with respect to operations or performance under this Agreement, without providing the
other Party with sufficient information regarding the work prior to commencement to enable
such Party to evaluate the impact of the proposed work on its operations. The information
provided must be of sufficient detail to satisfy reasonable Transmission Provider or Local Distribution Company review and operational requirements. Each Party shall use
reasonable efforts to minimize any adverse impact on the other Party.








	9.3	 	If any Party intends to install any new facilities, equipment, systems, or circuits or any
modifications to existing or future facilities, equipment, systems or circuits that could
reasonably be expected to have a material effect upon the operation of the other Party, the
Party desiring to perform said work shall, in addition to the requirements of Section 9.2,
provide the other Party with drawings, plans, specifications and other necessary documentation
for review at least 60 days prior to the start of the construction of any such installation.
This notice period shall not apply to modifications or new installations made to resolve or
prevent pending Emergency or Network Security Conditions.






	9.4	 	The Party reviewing any drawings, plans, specifications, or other necessary documentation for
review shall promptly review the same and provide any comments to the performing Party no
later than 30 days prior to the start of the construction of any installation. Unless system
modifications are required in association with the addition of generation to the system (in
which case Section 9.8 hereof shall apply) all such reviews shall be performed at no cost to
either Party. The performing Party shall incorporate all requested modifications to the
extent required in accordance with Good Utility Practice and compliance with this Agreement.






	9.5	 	Within 180 days following placing in-service of any modification or construction subject
to this Article 9, the Party initiating the work shall provide “as built” drawings, plans
and related technical data to the other Party. Approval or review of any document
referenced herein shall not




 









 






	 	 	relieve the initiating Party of its responsibility for the design or construction of any
proposed facility, nor shall it subject the other Party to any liability, except with respect
to the confidentiality provisions of Article 20.






	9.6	 	Each Party shall, at its own expense, have the right to inspect or observe all maintenance
activities, equipment tests, installation work, construction work, and modification work to
the facilities of the other Party that could have a material effect upon the facilities or
operations of the first Party.






	9.7	 	Construction and installation of any facility shall meet all or exceed all environmental
permitting requirements, reviews or approvals as required by Federal, State or local law prior
to the installation of such facilities. The Parties agree to coordinate environmental
permitting related
activities such as site review for regulated resources, permit application and project
oversight (e.g. monitoring as applicable).






	9.8	 	Whenever system modifications are required to connect generating facilities to either the
Local Distribution Company’s or the Transmission Provider’s system it is expected that the
party installing the generating facilities will normally be responsible for much or all of the
associated costs. The Parties agree to cooperate in sharing information regarding such
projects and to individually make arrangements with the party adding the generation to obtain
payment of all related costs as appropriate.





ARTICLE 10. Access to Facilities





	10.1	 	The Parties hereby agree to provide each other reasonable access to their respective property
as may be necessary and appropriate to enable each Party to operate and maintain its
respective facilities and equipment on such property. Such right of access shall be
provided in a manner so as not to unreasonably interfere with either Party’s ongoing business
operations, rights, and obligations.






	10.2	 	Each Party shall provide the other Party keys, access codes or other access methods necessary
to enter the other Party’s facilities to exercise rights under this Agreement. Access shall
only be granted to Qualified Personnel.





ARTICLE 11. Notifications and Reporting





	11.1	 	Unless otherwise provided, any notice required to be given by either Party to the other
Party in connection with this Agreement shall be given in writing: (a) personally; (b) by
facsimile transmission (if sender thereafter




 









 






	 	 	sends such notice to recipient by any of the other methods provided in this Section 11.1; (c)
by registered or certified U.S. mail, return receipt requested, postage prepaid; or (d) by
reputable overnight carrier, with acknowledged receipt of delivery; or (e) any other method
mutually agreed by the Parties in writing. Notice shall be deemed given on the date of
receipt personally. Notice sent by facsimile shall be deemed given on the date the
transmission is confirmed by sender’s facsimile machine, so long as the facsimile is sent on
a business day during normal business hours of the recipient. Otherwise, the notice shall
be deemed given on the next succeeding business day. Notice provided by mail or overnight
courier shall be deemed given at the date of acceptance or refusal of acceptance shown on
such receipt.






	11.2	 	Notice to the Transmission Provider shall be to the Transmission Provider’s
Representative, at the addresses identified in Exhibit 2. Notice to the Local Distribution
Company shall be to the Local Distribution Company’s Representative, at the addresses
identified in Exhibit 2.






	11.3	 	Each Party shall provide prompt notice describing the nature and extent of the condition, the
impact on operations, and all corrective action, to the other Party of any Emergency or
Network Security Condition which may be reasonably anticipated to affect the other Party’s
equipment, facilities or operations. Either Party may take reasonable and necessary action,
both on its own and the other Party’s system, equipment, and facilities, to prevent, avoid or
mitigate injury, danger, damage or loss to its own equipment and facilities, or to expedite
restoration of service; provided however, that the Party taking such action shall give the
other Party prior notice, if at all possible, before taking any action on the other Party’s
system, equipment, or facilities.






	11.4	 	In the event of an Emergency or Network Security Condition contemplated by Section 11.3, each
Party shall provide the other with such information, documents, and data necessary for
operation of the Transmission System and Distribution System, including, without limitation,
such information which is to be supplied to any Governmental Authority, NERC, ECAR, or
Transmission System Operations Center or Distribution System Control Center.






	11.5	 	In order to continue interconnection of the Distribution System and Transmission System, each
Party shall promptly provide the other Party with all relevant information, documents, or data
regarding the Distribution System and the Transmission System that would be expected to affect
the Distribution System or Transmission System, and which is reasonably requested by NERC,
ECAR, or any Governmental Authority.




 









 












	11.6	 	For routine maintenance and inspection activities on either Parties system that will require
major equipment or system outages, and could impact the other Party’s system, the Party
performing the same shall provide the other Party with not less than seventy-two (72) hours
prior notice, if practicable; provided that the provisions of Section 3.9 remain applicable to
the outages, and said notice is in addition to, and does not substitute for, the requirements
of Section 3.9 (maintenance and inspection activities in generating plant substations require
20 working days notification).






	11.7	 	Transmission Provider shall notify Local Distribution Company prior to entering Local
Distribution Company’s facilities for routine measurements, inspections and meter reads in
accordance with the requirements of Section 11.6. Local Distribution Company shall notify
Transmission Provider prior to entering Transmission Provider’s facilities, including
switchyards, for routine maintenance, operations, measurements, inspections and meter reads,
in accordance with the requirements of Section 11.6.






	11.8	 	Each Party shall provide prompt verbal notice to the other Party of any system alarm that
applies to the other Party’s equipment, unless the system alarm is automatically sent to
the other Party.






	11.9	 	Each Party shall provide a report or a copy of the data from a system events recorder,
SCADA system sequence of events or digital fault recorder that applies to the other
Party’s equipment.






	11.10	 	Each Party agrees to immediately notify the other Party verbally, and then in writing, of
any labor dispute or anticipated labor dispute of which its management has actual Knowledge
that might reasonably be expected to affect the operations of the other Party with respect to
this Agreement.





ARTICLE 12. Safety





	12.1	 	Each Party agrees that all work performed by either Party that may
reasonably be expected to affect the other Party shall be performed in accordance with Good
Utility Practice and all applicable laws, regulations, safety standards, practices and
procedures and other requirements pertaining to the safety of Persons or property,
(including, but not limited to those of the Occupational Safety and Health Administration,
the National Electrical Safety Code and those developed or accepted by Transmission Provider
and Local Distribution Company for use on their respective systems) when entering or working
in the other Party’s property or facilities or switching area. A Party performing work
within the boundaries of the other Party’s facilities must abide by the safety rules
applicable to the site.




 









 












	12.2	 	Each Party shall be solely responsible for the safety and supervision of its own employees,
agents, representatives, and subcontractors.






	12.3	 	Transmission Provider shall immediately report any injuries that occur while working on the
Local Distribution Company’s property or facilities or switching area to appropriate agencies
and the Local Distribution Company’s Site Representative. Local Distribution Company shall
immediately report any injuries that occur while working on the Transmission Provider’s
property or facilities or switching area to appropriate agencies and the Transmission
Provider’s Site Representative. Each Party will provide the other with its
clearing/tagging/lockout procedures. For clearances requested or initiated by the Local
Distribution Company on the Local Distribution Company’s equipment that utilizes the
Transmission Provider’s equipment as an isolation device, Local Distribution Company
procedures shall govern. For clearances requested or initiated by the Transmission Provider
on the Transmission Provider’s’ equipment that utilizes the Local Distribution Company’s
equipment as an isolation device, Transmission Provider procedures shall govern. Under no
circumstances shall either Party remove the other Party’s protective tags without proper
authorization.





ARTICLE 13. Environmental Compliance and Procedures





	13.1	 	Release Prevention and Response. Each Party shall notify the other Party,
verbally within 24 hours upon discovery of any Release of any Regulated Substance caused by
the Party’s operations or equipment that impacts the property or facilities of the other
Party, or which may migrate to, or adversely impact the property, facilities or operations of
the other Party and shall promptly furnish to the other Party copies of any reports filed with
any governmental agencies addressing such events. Such verbal notification shall be followed
by written notification within five (5) days. The Party responsible for the Release of any
Regulated Substance on the property or facilities of the other Party, or which may migrate to,
or adversely impact the property, facilities or operations of the other Party shall be
responsible for: (1) the cost and completion of reasonable remediation or abatement activity
for that Release, and; (2) required notifications to governmental agencies and submitting of
all reports or filings required by environmental laws for that Release. Advance written
notification (except in Emergency situations, in which verbal, followed by written
notification, shall be provided as soon as practicable) shall be provided to the other Party
by the Party responsible for any remediation or abatement activity on the property or
facilities of the other Party, or which may adversely impact the property, facilities, or
operations of the other Party. Except in Emergency situations such remediation or abatement




 









 






	 	 	activity shall be performed only with the consent of the Party owning the affected
property or facilities.






	13.2	 	The Parties agree to coordinate, to the extent necessary, the preparation
of site plans, reports, environmental permits, clearances and
notifications required by federal and state law or regulation, including but not limited to
Spill Prevention, Control and Countermeasures (SPCC), Storm Water Pollution Prevention
Plans (SWPP), Act 451 Part 31 Part 5 Rules, CERCLA, EPCRA, TSCA, soil erosion and
sedimentation control plans (SESC) or activities, wetland or other water-related permits,
threatened or endangered species reviews or management and archeological clearances or
notifications required by any regulatory agency or competent jurisdiction. Notification
of permits applied for and/or received will occur in a timeframe manner suitable to the
interests of both Parties.





ARTICLE 14. Billings and Payment





	14.1	 	Any invoices payable under this Agreement shall be provided to the other Party under this
Agreement during the preceding month. Invoices shall be prepared within a reasonable time
after the first day of each month. Each invoice shall delineate the month in which services
were provided, shall fully describe the services rendered and shall be itemized to reflect the
services performed or provided. The invoice shall be paid within twenty (20) days of the
invoice date, or the first business day thereafter if the payment date falls on other than a
business day. All payments shall be made in immediately available funds payable to the
other Party, or by wire transfer to a bank of the Party being paid, provided that payments
expressly required by this Agreement to be mailed shall be mailed in accordance with Section
14.2.






	14.2	 	Any payments required to be made by Local Distribution Company under this Agreement shall be
made to Transmission Provider at the following address:




Michigan Electric Transmission Company, LLC

P.O. Box 673971 Detroit,

MI 48267-3971





	 	 	Any payments required to be made by Transmission Provider under this Agreement shall be
made to Local Distribution Company at the following address:




 









 










Consumers Energy Company

One Energy Plaza

Jackson, MI 49201

Attention: Treasurer





	14.3	 	The rate of interest on any amount not paid when due shall be equal to the Interest Rate in
effect at the time such amount became due. Interest on delinquent amounts shall be
calculated from the due date of the invoice to the date of the payment. When payments are
made by mail, invoices shall be considered as having been paid on the date of receipt by the
other Party. Nothing contained in this article is intended to limit either Party’s remedies
under Article 21 of this Agreement.






	14.4	 	Payment of an invoice shall not relieve the paying Party from any responsibilities or
obligations it has under this Agreement, nor shall such payment constitute a waiver of any
claims arising hereunder.






	14.5	 	If all or part of any bill is disputed by a Party, that Party shall promptly pay the amount
that is not disputed and provide the other Party a reasonably detailed written explanation of
the basis for the dispute pursuant to Article 26. While the dispute is being resolved, the
Parties shall continue to provide services and pay all invoiced amounts not in dispute.
Following resolution of the dispute, the prevailing Party shall be entitled to receive the
disputed amount, as finally determined to be payable, along with interest accrued at the
Interest Rate through the date on which payment is made, within ten (10) business days of such
resolution.






	14.6	 	Subject to the Confidentiality provisions of Article 20, within two (2) years following a
calendar year, during normal business hours, Local Distribution Company and Transmission
Provider shall have the right to audit each other’s accounts and records pertaining to
transactions under this Agreement that occurred during such calendar year at the offices where
such accounts and records are maintained; provided that the audit shall be limited to those
portions of such accounts and records that reasonably relate to the services provided to the
other Party under this Agreement for said calendar year. The Party being audited shall be
entitled to review the audit report and any supporting materials. To the extent that audited
information includes Confidential Information, the auditing Party shall keep all such
information confidential pursuant to Article 20.






	14.7	 	Neither Party shall be responsible for the other Party’s costs of collecting amounts due
under this Agreement, including attorney fees and expenses and the expenses of arbitration.






 











 





ARTICLE 15. Applicable Regulations and Interpretation





	15.1	 	Each Party’s performance under this Agreement is subject to the condition that all requisite
governmental and regulatory approvals for such performance are obtained in form and substance
satisfactory to the other Party in its reasonable judgment. Each Party shall exercise Due
Diligence and shall act in good faith to secure all appropriate approvals in a timely
fashion.
	 
	15.2	 	This Agreement and all rights, obligations, and performances of the Parties hereunder, are
subject to present or future state or federal laws, regulations, or orders properly issued by
state or federal bodies having jurisdiction. When not in conflict with or pre-empted by Federal
law, this
Agreement shall be interpreted pursuant to the laws of the State of Michigan,
exclusive of its conflicts of law principles.





ARTICLE 16. Force Majeure





	16.1	 	An event of Force Majeure means any act of God, labor disturbance, act of the public enemy,
war, insurrection, riot, fire, storm or flood, explosion, breakage or accident to machinery or
equipment, any curtailment, order, regulation or restriction imposed by governmental military or
lawfully established civilian authorities, or any other cause beyond a Party’s reasonable control.
A Force Majeure event does not include an act of negligence or intentional wrongdoing.
	 
	16.2	 	If either Party is rendered unable, wholly or in part, by Force Majeure, to carry out its
obligations under this Agreement, then, during the continuance of such inability, the obligation
of such Party shall be suspended except that Transmission Provider’s and Local Distribution
Company’s obligation under Section 16.3 of this Agreement to provide protection shall not be
suspended. The Party relying on Force Majeure shall give written notice of Force Majeure to the
other Party as soon as practicable after such event occurs. Upon the conclusion of Force
Majeure, the Party heretofore relying on Force Majeure shall, with all reasonable
dispatch, take all necessary steps to resume the obligation previously suspended.
	 
	16.3	 	Any Party’s obligation to make payments already owing shall not be suspended by Force
Majeure.





 









 





ARTICLE 17. Indemnification And Limitation on Liability





	17.1	 	Each Party shall at all times assume all liability for, and shall indemnify and save the
other Party harmless from any and all damages, losses, claims, demands, suits, recoveries, costs,
legal fees, expenses for injury to or death of any Person or Persons whomsoever, or for any loss,
destruction of or damage to any property of third persons, firms, corporations or other entities
that occurs on its own system and that arises out of or results from, either directly or
indirectly, its own facilities or facilities controlled by it, unless caused by the sole
negligence, or intentional wrongdoing, of the other Party.
	 
	17.2	 	EXCEPT AS SET FORTH IN SECTION 8.3, NEITHER PARTY SHALL BE LIABLE TO THE OTHER FOR ANY
SPECIAL, INCIDENTAL, EXEMPLARY, PUNITITIVE OR CONSEQUENTIAL DAMAGES SUCH AS, BUT NOT LIMITED TO,
LOST PROFITS, REVENUE OR GOOD WILL, INTEREST, LOSS BY REASON OF SHUTDOWN OR NON-OPERATION OF
EQUIPMENT OR MACHINERY, INCREASED EXPENSE OF OPERATION OF EQUIPMENT OR MACHINERY, COST OF
PURCHASED OR
REPLACEMENT POWER OR SERVICES OR CLAIMS BY CUSTOMERS, WHETHER SUCH LOSS IS BASED ON CONTRACT,
WARRANTY, NEGLIGENCE, STRICT LIABILITY OR OTHERWISE.





ARTICLE 18. Insurance





	18.1	 	The Parties agree to maintain, at their own cost and expense, the following insurance
coverages for the life of this Agreement in the manner and amounts, at a minimum, as set
forth below:






	 	(a)	 	Workers’ Compensation Insurance in accordance with all applicable State, Federal, and
Maritime Law.
	 
	 	(b)	 	Employer’s Liability insurance in the amount of $1,000,000 per accident.
	 
	 	(c)	 	Commercial General Liability or Excess Liability Insurance in the amount of
$25,000,000 per occurrence.
	 
	 	(d)	 	Automobile Liability Insurance for all owned, non-owned, and hired vehicles in the
amount of $5,000,000 each accident.






	2.	 	A Party may, at its option, [A] be an approved self-insurer by the State of Michigan for the
insurances required in 1.(a) and (d); and [B] maintain such deductibles and/or retentions
under the insurance required in 1.(b) and (c) as is maintained by other similarly situated
companies engaged in a similar business. The Parties agree that all amounts of self-insurance,
retentions and/or deductibles are the responsibility of, and shall be borne by, the Party whom
makes such an election.




 









 






	3.	 	Within fifteen (15) days of the Effective Date and thereafter when requested, in writing, but
not more than once every 12 months, during the term of this Agreement (including any
extensions) each Party shall provide to the other Party properly executed and current
certificates of insurance or evidence of approved self-insurance status with respect to all
insurance required to be maintained by such Party under this Agreement.
Certificates of insurance shall provide the following information:






	 	(a)	 	Name of insurance company, policy number and expiration date.
	 
	 	(b)	 	The coverage maintained and the limits on each, including the amount of deductibles or
retentions, which shall be for the account of the Party maintaining such policy.
	 
	 	(c)	 	The insurance company shall endeavor to provide thirty (30) days prior written notice
of cancellation to the certificate holder.





ARTICLE 19. Several Obligations





	19.	 	Except where specifically stated in this Agreement to be otherwise, the duties, obligations and
liabilities of the Parties are intended to be several and not joint or collective. Nothing
contained in this Agreement shall ever be construed to create an association, trust, partnership,
or joint venture or to impose a trust or partnership duty, obligation or liability or agency
relationship on or with regard to either Party. Each Party shall be individually and severally
liable for its own obligations under this Agreement.





ARTICLE 20. Confidentiality





	20.1(a)	 	“Confidential Information” shall mean any confidential, proprietary or trade
secret information of a plan, specification, pattern, procedure, design, device, list concept,
policy or compilation relating to the present or planned business of a Party, which is designated
in good faith as Confidential by the Party supplying the information, whether conveyed orally,
electronically, in writing, through inspection or otherwise. Confidential Information shall
include, without limitation, all information relating to a Party’s technology, research and
development, business affairs, and pricing, customer-specific load data that constitutes a trade
secret, and any information supplied by either of the Parties to the other prior to the execution
of this Agreement.




 









 












	 	(b)	 	General. Each Party will hold in confidence any and all Confidential
Information unless (1) compelled to disclose such information by judicial or
administrative process or other provisions of law or as otherwise provided for in
this Agreement, or (2) to meet obligations imposed by FERC or by a state or other
federal entity or by membership in NERC or ECAR (including other Transmission
Providers). Information required to be disclosed under (b)(1) or (b)(2) above, does
not, by itself, cause any information provided by Local Distribution Company to
Transmission Provider to lose its confidentiality. To the extent it is necessary for
either Party to release or disclose such information to a third party in order to
perform that Party’s obligations herein, such Party shall advise said third party of
the confidentiality provisions of this Agreement and use its best efforts to require
said third party to agree in writing to comply with such provisions. Transmission
Provider will develop and file with FERC standards of conduct relating to the sharing
of a market-related Confidential Information with and by Transmission Provider
employees.
	 
	 	(c)	 	Term: During the term of this Agreement, and for a period of three (3) years
after the expiration or termination of this Agreement, except as otherwise provided in this
Article 20, each Party shall hold in confidence and shall not disclose to any Person
Confidential Information.
	 
	 	(a)	 	Standard of Care: Each Party shall use at least the same standard of care to
protect Confidential Information it receives as that it uses to protect its own
Confidential Information from unauthorized disclosure, publication or dissemination.






	20.2	 	Scope: Confidential Information shall not include information that the receiving Party
can demonstrate: (1) is generally available to the public other than as a result of disclosure by
the receiving Party (2) was in the lawful possession of the receiving Party on a non-confidential
basis prior to receiving it from the disclosing Party; or (3) was supplied to the receiving Party
without restriction by a third party, who, to the Knowledge of the receiving Party, after due
inquiry was under no obligation to the disclosing Party to keep such information confidential; (4)
was independently developed by the receiving Party without reference to Confidential Information of
the disclosing Party; (5) is, or becomes, publicly known, through no wrongful act or omission of
the receiving Party or breach of this Agreement; or (6) is required, in accordance with Section
20.1(b) of this Agreement, to be disclosed by any federal or state government or agency or is
otherwise required to be disclosed by law or subpoena, or is necessary in any legal proceeding
establishing rights and obligations under this Agreement. Information designated as




 









 






	 	 	Confidential Information will no longer be deemed confidential if the Party that
designated the information as confidential notifies the other Party that it no longer is
confidential.
	 
	20.3	 	Order of Disclosure. If a court or a government agency or entity with the right power,
and apparent authority to do so requests or requires either Party, by subpoena, oral deposition,
interrogatories, requests for production of documents, administrative order, or otherwise, to
disclose Confidential Information, that Party shall provide the other Party with prompt notice of
such request(s) or requirement(s) so that the other Party may seek an appropriate protective order
or waive compliance with the terms of this Agreement. The notifying Party shall have no obligation
to oppose or object to any attempt to obtain such production except to the extent requested to do
so by the disclosing Party and at the disclosing Party’s expense. If either Party desires to object
or oppose such production, it must do so at its own expense. The disclosing Party may request a
protective order to prevent any Confidential Information from being made public. Notwithstanding
the absence of a protective order or waiver, the Party may disclose such Confidential Information
which, in the opinion of its counsel, the Party is legally compelled to disclose. Each Party will
use reasonable effort to obtain reliable assurance that confidential treatment will be accorded any
Confidential Information so furnished.
	 
	20.4	 	Use of Information or Documentation. Each Party may utilize information or
documentation furnished by the disclosing Party and subject to Section 20.1 in any proceeding
under Article 26 or in an administrative agency or court of competent jurisdiction addressing any
dispute arising under this Agreement, subject to a confidentiality agreement with all participants
(including, if applicable, any arbitrator) or a protective order.
	 
	20.5	 	Remedies Regarding Confidentiality. The Parties agree that monetary damages by
themselves will be inadequate to compensate a Party for the other Party’s breach of its
obligations under this article. Each Party accordingly agrees that the other Party is entitled to
equitable relief, by way of injunction or otherwise, if it breaches or threatens to breach its
obligations under this article.





ARTICLE 21. Breach, Default and Remedies





	21.1	 	General. A breach of this Agreement (“Breach”) shall occur upon the failure by a
Party to perform or observe a material term or condition of this Agreement. A default of this
Agreement (“Default”) shall occur upon




 









 






	 	 	the failure of a Party in Breach of this Agreement to cure such Breach in accordance with
Section 21.4.
	 
	21.2	 	Events of Breach. A Breach of this Agreement shall include:






	 	(a)	 	The failure to pay any amount when due;
	 
	 	(b)	 	The failure to comply with any material term or condition of this Agreement,
including but not limited to any material Breach of a representation, warranty or
covenant made in this Agreement;
	 
	 	(c)	 	A Party’s abandonment of its work or the facilities contemplated in this Agreement;
	 
	 	(d)	 	If a Party: (1) becomes insolvent; (2) files a voluntary petition in bankruptcy under
any provision of any federal or state bankruptcy law or shall consent to the filing of any
bankruptcy or reorganization petition against it under any similar law; (3) makes a general
assignment for the benefit of its creditors; or (4) consents to the appointment of a
receiver, trustee or liquidator;
	 
	 	(e)	 	Failure of either Party to provide information or data to the other Party as required
under this Agreement, provided the Party entitled to the information or data under this
Agreement requires such information or data to satisfy its obligations under this
Agreement.






	21.3	 	Continued Operation. Except as specifically provided in this Agreement, in the event
of a Breach or Default by either Party, the Parties shall continue to operate and maintain, as
applicable, facilities and appurtenances that are reasonably necessary for the Transmission
Provider to operate and maintain the Transmission System, or the Local Distribution Company to
operate and maintain the Distribution System, in a safe and reliable manner.
	 
	21.4	 	Cure and Default. Upon the occurrence of an event of Breach, the non-Breaching Party,
when it becomes aware of the Breach, shall give written notice of the Breach to the Breaching
Party and to any other Person a Party to this Agreement identifies in writing to the other Party
in advance. Such notice shall set forth, in reasonable detail, the nature of the Breach, and where
known and applicable, the steps necessary to cure such Breach. Upon receiving written notice of
the Breach hereunder, the Breaching Party shall have thirty (30) days, to cure such Breach. If the
breach is such that it cannot be cured within thirty (30) days, the Breaching Party will commence
in good faith all steps as are reasonable and appropriate to cure the Breach within such thirty
(30) day time period and thereafter diligently pursue such action to




 









 






	 	 	completion. In the event the Breaching Party fails to cure the Breach, or to commence
reasonable and appropriate steps to cure the Breach, within thirty (30) days of becoming
aware of the Breach, the Breaching Party will be in Default of the Agreement. In the event
of a Default, the non-Defaulting Party has the right to take whatever action at law or
equity as may be permitted under this Agreement.
	 
	21.5	 	Right to Compel Performance. Notwithstanding the foregoing, upon the occurrence of an
event of Default, the non-Defaulting Party shall be entitled to Commence an action to require the
Defaulting Party to remedy such Default and specifically perform its duties and obligations
hereunder in accordance with the terms and conditions hereof, and exercise such other rights and
remedies as it may have in equity or at law.





ARTICLE 22. Term





	22.1	 	Term. This Agreement shall become effective as of the Effective Date and shall
continue in full force and effect so long as any Interconnection Point is connected to the
Transmission System, except that it may be terminated by mutual agreement of the Parties.
	 
	22.2	 	Material Adverse Change.






	 	(a)	 	In the event of a material change in law or regulation that adversely affects, or may
reasonably be expected to adversely affect, either
Party’s performance under this Agreement, including but not limited to the following:






	 	(i)	 	this Agreement is not accepted for filing by the FERC without material
modification or condition;
	 
	 	(ii)	 	NERC or ECAR prevents, in whole or in part, either Party from performing any
provision of this Agreement in accordance with its terms; or
	 
	 	(iii)	 	The FERC, the United States Congress, any state, or any federal or state
regulatory agency or commission implements any change in any law, regulation, rule or
practice which materially affects or is reasonably expected to materially affect
either Party’s ability to perform under this Agreement.






	 	 	 	The Parties will negotiate in good faith any amendment or amendments to the Agreement
necessary to adapt the terms of this Agreement to such change in law or regulation,
and the




 









 






	 	 	 	Transmission Provider shall file such amendment or amendments with FERC.
	 
	 	(b)	 	If the Parties are unable to reach agreement on any such amendments, then the Parties
shall continue to perform under this Agreement to the maximum extent possible, taking all
reasonable steps to mitigate any adverse effect on each other resulting from the Event. If
the Parties are unable to reach agreement on any such amendments, Transmission Provider
shall have the right to make a unilateral filing with FERC to modify this Agreement
pursuant to Section 205 of the Federal Power Act and Local Distribution Company shall have
the right to make a unilateral filing with FERC to modify this Agreement pursuant to
Section 206 of the Federal Power Act. Each Party shall have the right to protest any such
filing by the other Party and to participate fully in any proceeding before FERC.






	22.3	 	Survival. The applicable provisions of this Agreement shall continue in effect after
expiration, cancellation or termination hereof to the extent necessary to provide for final
billings, billing adjustments and the determination and enforcement of liability and
indemnification obligations arising from acts or events that occurred while this Agreement was in
effect.





ARTICLE 23. Assignment/Change in Corporate Identity





	23.1	 	Transmission Provider Assignment Rights. Transmission Provider may not assign this
Agreement or any of its rights, interests, or obligations hereunder without the prior written
consent of Local Distribution Company, which consent shall not be unreasonably withheld; provided
however, that Transmission Provider may assign this Agreement or any of its rights or obligations
hereunder without the prior consent of Local Distribution Company and may assign this Agreement to
any entity(ies) in connection with a merger, consolidation, or reorganization, provided that the
surviving entity(ies) or assignee owns the Transmission System, agrees in writing to be bound by
all the obligations and duties of Transmission Provider provided for in this Agreement and the
assignee’s creditworthiness is equal to or higher than that of Transmission Provider.
	 
	23.2	 	Local Distribution Company Assignment Rights. Local Distribution Company may not
assign this Agreement or any of its rights, interests or obligations hereunder without the prior
written consent of Transmission Provider, which consent shall not be unreasonably withheld;
provided however, that Local Distribution Company may, without the consent of Transmission
Provider, and by providing prior reasonable notice under the




 









 






	 	 	circumstances to Transmission Provider, assign, this Agreement to any entity(ies) in
connection with a merger, consolidation, or reorganization, provided that the surviving
entity(ies) or assignee owns the Local Distribution Company, agrees in writing to be bound by
all the obligations and duties of Local Distribution Company provided for in this Agreement
and the assignee’s creditworthiness is equal to or higher than that of Local Distribution
Company.
	 
	23.3	 	Assigning Party to Remain Responsible. Any assignments authorized as provided for in
this article will not operate to relieve the Party assigning this Agreement or any of its rights,
interests or obligations hereunder of the responsibility of full compliance with the requirements
of this Agreement unless (a) the other Party consents, such consent not to be unreasonably
withheld, and (b) the assignee agrees in writing to be bound by all of the obligations and duties
of the assigning Party provided for in this Agreement.
	 
	23.4	 	This Agreement and all of the provisions hereof are binding upon, and inure to the benefit
of, the Parties and their respective successors and permitted assigns.





ARTICLE 24. Subcontractors





	24.1	 	Nothing in this Agreement shall prevent the Parties from utilizing the services of
subcontractors as they deem appropriate; provided, however, the Parties agree that, where
applicable, all said subcontractors shall comply with the terms and conditions of this Agreement.
	 
	24.2	 	Except as provided herein, the creation of any subcontract relationship shall not relieve the
hiring Party of any of its obligations under this Agreement. Each Party shall be fully responsible
to the other Party for the acts and/or omissions of any subcontractor it hires as if no subcontract
had been made. Any obligation imposed by this Agreement upon the
Parties, where applicable, shall be equally binding upon and shall be construed as
having application to any subcontractor.
	 
	24.3	 	No subcontractor is intended to be or shall be deemed a third-party beneficiary of this
Agreement.
	 
	24.4	 	The obligations under this Article 26 shall not be limited in any way by any limitation on
subcontractor’s insurance.
	 
	24.5	 	Each Party shall require its subcontractors to comply with all federal and state laws
regarding insurance requirements and shall maintain standard and ordinary insurance coverages.




 









 











ARTICLE 25. Dispute Resolution



Any dispute between the parties arising out of or relating to this Contract or the breach thereof
shall be brought to the Administrative Committee. If the Administrative Committee can resolve the
dispute, such resolution shall be reported in writing to and shall be binding upon the Parties. If
the Administrative Committee cannot resolve the dispute within a reasonable time, the senior
officer of Local Distribution Company or the senior officer of Transmission Provider may, by
written notice to the senior officer of the other Party and the members of the Administrative
Committee, withdraw the matter from consideration by the Administrative Committee and submit the
same for resolution to the senior officers of the Parties. If the senior officers of the Parties
agree to a resolution of the matter, such resolution shall be reported in writing to, and shall be
binding upon, the Parties; but if said senior officers fail to resolve the matter within five (5)
Business Days after its submission to them, then the Parties agree to try in good faith to settle
the dispute by mediation administered by the American Arbitration Association under its Commercial
Mediation Rules before resorting to litigation.




ARTICLE 26. Miscellaneous Provisions





	26.1	 	This Agreement shall constitute the entire Agreement between the Parties hereto relating to
the subject matter hereof. In all other respects, special contracts or superseding rate schedules
shall govern Transmission
Provider’s transmission service to Local Distribution Company.
	 
	26.2	 	No failure or delay on the part of Transmission Provider or Local
Distribution Company in exercising any of its rights under this Agreement, no partial
exercise by either Party of any of its rights under this Agreement, and no course of dealing
between the Parties shall constitute a waiver of the rights of either Party under this
Agreement. Any waiver shall be effective only by a written instrument signed by the Party
granting such waiver, and such shall not operate as a waiver of, or estoppel with respect
to, any subsequent failure to comply therewith.
	 
	26.3	 	Nothing in this Agreement, express or implied, is intended to confer on any other Person
except the Parties hereto any rights, interests, obligations or remedies hereunder.
	 
	26.4	 	In the event that any clause or provision of this Agreement or any part hereof shall be
held to be invalid, void, or unenforceable by any court or Governmental Authority of competent
jurisdiction, said holding or action shall be strictly construed and shall not affect the
validity or effect of any other provision hereof, and the Parties shall endeavor in good faith
to




 









 






	 	 	replace such invalid or unenforceable provisions with a valid and enforceable
provision which achieves the purposes intended by the Parties to the greatest extent
permitted by law.
	 
	26.5	 	The article and section headings herein are inserted for convenience only and are not to be
construed as part of the terms hereof or used in the interpretation of this Agreement.
	 
	26.6	 	In the event an ambiguity or question of intent or interpretation arises, this Agreement
shall be construed as if drafted jointly by the Parties and no presumption or burden of proof
shall arise favoring or disfavoring any Party by virtue of authorship of any of the provisions of
this Agreement.
Any reference to any federal, state, local, or foreign statute or law shall be deemed also
to refer to all rules and regulations promulgated thereunder, unless the context requires
otherwise. The word “including” in this
Agreement shall mean including without limitation.
	 
	26.7	 	This Agreement may be executed in one or more counterparts, each of which shall be deemed
an original.
	 
	26.8	 	Each Party shall act as an independent contractor with respect to the provision of
services hereunder.




 









 










IN WITNESS WHEREOF, Transmission Provider and Local Distribution Company have caused this
instrument to be executed by their duly authorized representatives as of the day and year first
above written.




	 	 	 	 	 
	 	CONSUMERS ENERGY COMPANY

 	 
	 	By: 	/s/ Richard J. Ford 
	 
	 	 	Name:  	Richard J. Ford 	 
	 	 	Title:  	VP - Energy Delivery	APVD AS TO FORM
	 
	 
	 	 	 	 	 
	 	MICHIGAN ELECTRIC TRANSMISSION COMPANY, LLC

 	 
	 	By:  	/s/
Daniel J. Oginsky 

	 
	 	 	Name:  	Daniel J. Oginsky 	 
	 	 	Title:  	Secretary 	 
	 




 











 





EXHIBIT 1 — Interconnection Points (Substations) Addendum 5, Final 06/10/10




Substation




	 	 	 

	1

	 	Abbe
	2

	 	Acme (CWIP)
	3

	 	Alcona
	4

	 	Alder Creek
	5

	 	Alger
	6

	 	Algoma
	7

	 	Alma
	8

	 	Almeda
	9

	 	Alpena
	10

	 	Alpine
	11

	 	Amber
	12

	 	American Bumper
	13

	 	Arthur (6/06)
	14

	 	Aubil Lake
	15

	 	Backus
	16

	 	Bagley
	17

	 	Bangor
	18

	 	Baraga (12/07)
	19

	 	Bard Road
	20

	 	Barnum Creek
	21

	 	Barry
	22

	 	Bass Creek
	23

	 	Batavia
	24

	 	Bay Road
	25

	 	Bayberry
	26

	 	Beals Road
	27

	 	Becker
	28

	 	Beecher
	29

	 	Begole
	30

	 	Bell Road
	31

	 	Bennington
	32

	 	Beveridge
	33

	 	Bilmar
	34

	 	Bingham
	35

	 	Black River
	36

	 	Blackman
	37

	 	Blackstone
	38

	 	Blinton
	39

	 	Blue Water
	40

	 	Bluegrass
	41

	 	Boardman






 









 






	 	 	 

	42

	 	Boxboard
	43

	 	Bricker
	44

	 	Brickyard
	45

	 	Briggs & Stratton
	46

	 	Broadmoor
	47

	 	Bronco
	48

	 	Broughwell
	49

	 	Buck Creek
	50

	 	Buick Stewart
	51

	 	Bullock
	52

	 	Busch Road (02/08)
	53

	 	Calhoun
	54

	 	Camelot Lake
	55

	 	Campbell 138
	56

	 	Canal
	57

	 	Cannon
	58

	 	Carpenter Rd (8/06)
	59

	 	Carter
	60

	 	Cedar Springs
	61

	 	Cement City
	62

	 	Chase
	63

	 	Cheesman
	64

	 	Chicago
	65

	 	Churchill
	66

	 	Clare
	67

	 	Claremont
	68

	 	Clearwater
	69

	 	Cleveland
	70

	 	Club
	71

	 	Cobb
	72

	 	Cochran
	73

	 	Cole Creek
	74

	 	Colony Farm
	75

	 	Convis
	76

	 	Cork Street
	77

	 	Cornell
	78

	 	Cottage Grove
	79

	 	Covert
	80

	 	Cowan Lake
	81

	 	Crahen (10/07)
	82

	 	Croton
	83

	 	David
	84

	 	Dean Road
	85

	 	Deja
	86

	 	Delaney
	87

	 	Delhi






 









 






	 	 	 

	88

	 	Denso Jackson
	89

	 	Derby
	90

	 	Dorr Corners
	91

	 	Dort
	92

	 	Dow Corning
	93

	 	Dowling
	94

	 	Drake Road
	95

	 	Duffield Rd
	96

	 	Dupont
	97

	 	Duquite
	98

	 	Dutton
	99

	 	East Paris
	100

	 	East Tawas
	101

	 	Easton
	102

	 	Edenville
	103

	 	Ellis
	104

	 	Emmet
	105

	 	Englishville
	106

	 	Eureka
	107

	 	Farr Road
	108

	 	Felch Road
	109

	 	Filer City
	110

	 	Fillmore
	111

	 	Forty Fourth Street
	112

	 	Foundry
	113

	 	Four Mile
	114

	 	Gaines (5/06)
	115

	 	Gallagher
	116

	 	Garfield
	117

	 	Gaylord
	118

	 	Geddes (04/08)
	119

	 	Gleaner
	120

	 	Grand Blanc BOC
	121

	 	Gray Road (CWIP)
	122

	 	Greenwood
	123

	 	Grey Iron
	124

	 	Grodi Road
	125

	 	Grout
	126

	 	Hackett
	127

	 	Hagadorn
	128

	 	Hager Park
	129

	 	Halsey
	130

	 	Haring
	131

	 	Harvard Lake (06/09)
	132

	 	Hazelwood
	133

	 	Hemphill






 









 






	 	 	 

	134

	 	Hendershot
	135

	 	Higgins
	136

	 	Hillman Cogen
	137

	 	Hodenpyl
	138

	 	Holland Road
	139

	 	Hotchkiss
	140

	 	HSC
	141

	 	Hubbard Lake (12/07)
	142

	 	Hubbardston Road (CWIP)
	143

	 	Hudsonville
	144

	 	Hughes Road
	145

	 	Hull Street
	146

	 	Iosco
	147

	 	Island Road
	148

	 	Jamestown
	149

	 	Karn 138
	150

	 	Kentwood
	151

	 	Keystone
	152

	 	Kinderhook (05/07)
	153

	 	Kipp Road
	154

	 	Kraft
	155

	 	Lafayette
	156

	 	Laundra (05/07)
	157

	 	Lawndale
	158

	 	Layton
	159

	 	Leoni
	160

	 	Letts Road
	161

	 	Lewiston
	162

	 	Lindbergh
	163

	 	Livingston Peaker
	164

	 	Lovejoy
	165

	 	Ludington
	166

	 	Malleable (decomm 10/07)
	167

	 	Manlius
	168

	 	Marquette
	169

	 	McGulpin
	170

	 	MCV
	171

	 	Meadowbrooke
	172

	 	Mecosta
	173

	 	Michigan
	174

	 	Michigan Power (MPLP)
	175

	 	Milham
	176

	 	Mio
	177

	 	Monitor
	178

	 	Moore Road
	179

	 	Morrow






 









 






	 	 	 

	180

	 	Mullins
	181

	 	Neff Road
	182

	 	Nineteen Mile Road
	183

	 	North Belding
	184

	 	North Corunna
	185

	 	Northern Fibre
	186

	 	Nugent Sand
	187

	 	Oakland
	188

	 	Oceana
	189

	 	Orr Road (07/09)
	190

	 	Packard
	191

	 	Palisades
	192

	 	Parr Road
	193

	 	Parshallville
	194

	 	Pasadena
	195

	 	Pavilion
	196

	 	Pettis Road
	197

	 	Pigeon River/Rondo
	198

	 	Pingree (10/08)
	199

	 	Piston Ring
	200

	 	Plaster Creek
	201

	 	Plymouth Street
	202

	 	Plum (CWIP)
	203

	 	Plywood
	204

	 	Port Calcite
	205

	 	Port Sheldon
	206

	 	Porter
	207

	 	Portsmouth
	208

	 	Price Road (09/07)
	209

	 	Progress Street
	210

	 	Race Street
	211

	 	Raisin
	212

	 	Ransom
	213

	 	Renaissance
	214

	 	Rice Creek
	215

	 	Riggsville
	216

	 	Rivertown
	217

	 	Riverview
	218

	 	Rockport/Presque Isle
	219

	 	Roedel Road
	220

	 	Rogue River (06/07)
	221

	 	Saginaw River
	222

	 	Samaria
	223

	 	Sanderson
	224

	 	Savidge
	225

	 	Scott Lake






 









 






	 	 	 

	226

	 	Seamless East/Seamless
	227

	 	Solar (CWIP)
	228

	 	Sonoma (5/06)
	229

	 	Spaulding
	230

	 	Spruce Road
	231

	 	Stacey
	232

	 	Stamping Plant
	233

	 	Steelcase
	234

	 	Stonegate
	235

	 	Stover
	236

	 	Stronach
	237

	 	Summerton
	238

	 	Thetford 138
	239

	 	Tihart
	240

	 	Tinsman
	241

	 	Tippy
	242

	 	Titus Lake
	243

	 	Trillium (06/07)
	244

	 	Trowbridge
	245

	 	Twelfth Street
	246

	 	Twilight
	247

	 	Twining
	248

	 	Upjohn
	249

	 	Van Atta
	250

	 	Van Buren (06/08)
	251

	 	Vanderbilt
	252

	 	Vernon
	253

	 	Verona
	254

	 	Vevay
	255

	 	Viking Lincoln
	256

	 	Vrooman
	257

	 	Wackerly
	258

	 	Warner
	259

	 	Warren
	260

	 	Washtenaw
	261

	 	Wayland
	262

	 	Weadock
	263

	 	Wealthy Street
	264

	 	West Fenton (05/07)
	265

	 	Wexford
	266

	 	White Lake
	267

	 	White Road
	268

	 	Whiting
	269

	 	Whittemore
	270

	 	Willard
	271

	 	Withey Lake (5/06)
	272

	 	Zeeland






 









 







EXHIBIT 2 — Contact Information For Local Distribution Company’s Representatives and Transmission



Provider’s Representatives



Local Distribution Company




Consumers Energy Company

4000 Clay Ave SW, PO Box 201

Grand Rapids, MI 49501-0201




Attn: Executive Manager of System Planning and Control




Transmission Provider




Michigan Electric Transmission Company, LLC:

27175 Energy Way

Novi, MI 48377




Attn:   Legal Department — Contracts







 









 








EXHIBIT 3




SPECIAL MANUFACTURING CONTRACTS INFLUENCED BY TRANSMISSON SYSTEM




	 	 	 	 	 	 	 	 	 
	 	 	 	 	PAYMENT PER DISRUPTION EVENT
	CUSTOMER	 	SUBSTATION	 	INTERRUPTION	 	VOLTAGE SAG
	GM

	 	BUICK STEWART
	 	$	150,000	 	 	NOT APPLICABLE
	 

	 	MALLEABLE
	 	$	150,000	 	 	NOT APPLICABLE
	 

	 	FLORENCE ST.
	 	$	150,000	 	 	NOT APPLICABLE
	 

	 	GRAND BLANC BOC
	 	$	100,000	 	 	NOT APPLICABLE
	 

	 	GREY IRON
	 	$	150,000	 	 	NOT APPLICABLE
	 

	 	STAMPING PLANT
	 	$	100,000	 	 	NOT APPLICABLE
	 
	 	 	 	 	 	 	 	 
	DELPHI

	 	HOLLAND RD.
	 	$	150,000	 	 	NOT APPLICABLE






NOTES FOR GM & DELPHI:





	 	1.	 	NO PAYMENTS FOR VOLTAGE SAGS.
	 
	 	2.	 	CUMULATIVE ANNUAL PAYMENT IS CAPPED AT $3,000,000.
	 
	 	3.	 	INITIAL TERM OF GM AND DELPHI CONTRACTS EXPIRE IN 2005.
	 
	 	4.	 	CONTRACTS MAY BE EXTENDED TO 2010 BY MUTUAL AGREEMENT.





	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	 	 	EVENT #
	DOW CORNING
	 	CARTER	 	$	(15,000	)	 	$	(15,000	)	 	no events
	 
	 	 	 	$	15,000	 	 	 	0	 	 	1st /yr
	 
	 	 	 	$	15,000	 	 	$	15,000	 	 	2nd/yr
	 
	 	 	 	$	55,000	 	 	NOT APPLICABLE	 	 	3rd/yr
	 
	 	 	 	 	 	 	 	 	 	 	 	 
	DOW CORNING
	 	DOW CORNING	 	$	(25,000	)	 	$	(25,000	)	 	no events
	 
	 	 	 	$	25,000	 	 	 	0	 	 	1st /yr
	 
	 	 	 	$	35,000	 	 	$	25,000	 	 	2nd/yr
	 
	 	 	 	$	105,000	 	 	NOT APPLICABLE	 	 	3rd/yr
	 
	 	 	 	 	 	 	 	 	 	 	 	 
	HEMLOCK
	 	HSC	 	$	(40,000	)	 	$	(20,000	)	 	no events
	SEMICONDUCTOR
	 	 	 	$	40,000	 	 	 	0	 	 	1st /yr
	 
	 	 	 	$	60,000	 	 	$	20,000	 	 	2nd/yr
	 
	 	 	 	$	150,000	 	 	NOT APPLICABLE	 	 	3rd/yr
	 
	 	 	 	 	 	 	 	 	 	 	 	 
	HEMLOCK
	 	SILICON	 	NOT APPLICABLE	 	 	$	(15,000	)	 	no events
	SEMICONDUCTOR
	 	 	 	NOT APPLICABLE	 	 	 	0	 	 	1st /yr
	 
	 	 	 	NOT APPLICABLE	 	 	 	0	 	 	2nd/yr
	 
	 	 	 	NOT APPLICABLE	 	 	 	0	 	 	3rd/yr
	 
	 	 	 	NOT APPLICABLE	 	 	$	15,000	 	 	4th/yr






NOTES FOR DOW CORNING & HEMLOCK SEMICONDUCTOR:





	 	1.	 	IF NO EVENTS IN A YEAR, PAYMENT IS MADE TO CONSUMERS.
	 
	 	2.	 	MAXIMUM # OF PAYABLE EVENTS/YR IS 3 FOR INTERRUPTIONS & 1 FOR SAGS.
	 
	 	3.	 	WEATHER RELATED EVENTS ARE NOT PAYABLE.




 









 











EXHIBIT 4 — Metering Specifications




Performance criteria:





	 	1.	 	Meters shall meet or exceed the latest version of ANSI C12.16 (Standard
for Solid State Electricity Meters) specifications for solid state metering.
	 
	 	2.	 	Current transformers used for metering shall meet or exceed an accuracy
class of 0.3%. Secondary connected burdens shall not exceed rated burden of any
current transformer. Current transformers shall comply with most current applicable
ANSI Standards including C57.13 (IEEE Standard Requirements for Instrument
Transformers) and C12.11 (Instrument Transformers for Revenue Metering 10 kV BIL
through 350 kV BIL). Meter installations shall comply with manufacturer’s accuracy
and burden class information on the nameplate of each device.
	 
	 	3.	 	Voltage transformers used for metering shall meet or exceed an accuracy
class of 0.3%. Secondary connected burdens shall not exceed rated burden of any
voltage transformer. Voltage transformers shall comply with most current applicable
ANSI Standards including C57.13 (IEEE Standard Requirements for Instrument
Transformers), and C12.11 (Instrument Transformers for Revenue Metering 10 kV BIL
through 350 kV BIL). Meter installations shall comply with manufacturer’s accuracy
and burden class information on the nameplate of each device.
	 
	 	4.	 	PT secondary circuits shall have a disconnect switch installed which
provides a visible air gap for worker safety, and which allows for attachment of a
protective safety tag.




 









 






EXHIBIT 5



For ownership changes since August 7, 2007, refer to the drawings in each Party’s Drawing
Management System (DMS), as discussed in Section 3.2 of this Agreement.



The WDs of the following substations have been revised since the last update (Addendum 2):




	 	 	 
	Consumers Energy (CE)
	 	Michigan Electric Transmission Company (METC)

	Alma

	 	HSC
	Bard Road
	 	 
	Beals Road
	 	 
	Beecher
	 	 
	Black River
	 	 
	Bullock
	 	 
	Claremont
	 	 
	Cobb
	 	 
	Cornell
	 	 
	Croton
	 	 
	Delhi
	 	 
	Dort
	 	 
	Felch Road
	 	 
	Four Mile
	 	 
	Hemphill
	 	 
	Lawndale
	 	 
	Milham
	 	 
	North Belding
	 	 
	Rice Creek
	 	 
	Riggsville
	 	 
	Riverview
	 	 
	Saginaw River
	 	 
	Spaulding
	 	 
	Stover
	 	 
	Verona
	 	 
	Weadock
	 	 
	Wealthy Street
	 	 
	Wexford
	 	 
	Whiting
	 	 






 









 





EXHIBIT 6 - Jointly Owned Assets Ownership by Percent of Major Equipment Addendum 5 — Final
06/10/10




Substations

Jointly Owned Assets

Percentage Split by Major Equipment Count




	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Generation	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Owned by	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Local	 	 	 	 	 	Last
	 	 	 	 	 	 	 	 	 	 	Distribution	 	Third-Party	 	Revision
	Substation Name	 	Distribution	 	Transmission	 	Company	 	Assets	 	Date
	Alma
	 	 	66.67	 	 	 	33.33	 	 	 	 	 	 	 	 	 	 	 	10/24/03	 
	Bard Road
	 	 	41.67	 	 	 	58.33	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	Batavia
	 	 	63.64	 	 	 	36.36	 	 	 	 	 	 	 	 	 	 	 	10/24/03	 
	Beals Road
	 	 	84.62	 	 	 	15.38	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	Beecher
	 	 	82.05	 	 	 	17.95	 	 	 	 	 	 	 	 	 	 	 	07/23/04	 
	Bingham
	 	 	91.67	 	 	 	8.33	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	Black River1
	 	 	68.00	 	 	 	24.00	 	 	 	 	 	 	 	8.00	 	 	 	06/10/10	 
	Blackstone
	 	 	72.00	 	 	 	28.00	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	Bullock
	 	 	76.00	 	 	 	24.00	 	 	 	 	 	 	 	 	 	 	 	11/20/08	 
	Claremont
	 	 	68.00	 	 	 	32.00	 	 	 	 	 	 	 	 	 	 	 	05/01/02	 
	Cobb Plant
	 	 	47.22	 	 	 	25.00	 	 	 	27.78	 	 	 	 	 	 	 	05/01/02	 
	Cornell
	 	 	68.42	 	 	 	31.58	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 








 




			
	Changes, relative to previous revisions (addendums), are shown in bold type.
	 
	1 	 	 At 120kV and above, third-party related assets will be included as part of the
Transmission Provider’s assets for purposes of making this calculation. Also, the third-party
may share in the financial responsibility associated with O&M activities.







 









 








	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Generation	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Owned by	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Local	 	 	 	 	 	Last
	 	 	 	 	 	 	 	 	 	 	Distribution	 	Third-Party	 	Revision
	Substation Name	 	Distribution	 	Transmission	 	Company	 	Assets	 	Date
	Croton
	 	 	54.54	 	 	 	31.82	 	 	 	13.64	 	 	 	 	 	 	 	06/10/10	 
	Delhi
	 	 	61.90	 	 	 	38.10	 	 	 	 	 	 	 	 	 	 	 	10/24/03	 
	Dort22
	 	 	69.57	 	 	 	30.43	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	Emmet
	 	 	92.31	 	 	 	7.69	 	 	 	 	 	 	 	 	 	 	 	05/01/02	 
	Eureka
	 	 	88.89	 	 	 	11.11	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	Felch Road
	 	 	83.33	 	 	 	16.67	 	 	 	 	 	 	 	 	 	 	 	03/31/06	 
	Four Mile
	 	 	73.33	 	 	 	26.67	 	 	 	 	 	 	 	 	 	 	 	03/16/06	 
	Gaylord
	 	 	44.44	 	 	 	44.44	 	 	 	11.12	 	 	 	 	 	 	 	11/20/08	 
	Halsey
	 	 	76.92	 	 	 	23.08	 	 	 	 	 	 	 	 	 	 	 	10/24/03	 
	Hemphill
	 	 	65.52	 	 	 	34.48	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	HSC
	 	 	40.00	 	 	 	60.00	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	Iosco
	 	 	83.33	 	 	 	16.67	 	 	 	 	 	 	 	 	 	 	 	05/30/07	 
	Lawndale
	 	 	82.35	 	 	 	17.65	 	 	 	 	 	 	 	 	 	 	 	05/01/02	 
	Marquette
	 	 	75.00	 	 	 	25.00	 	 	 	 	 	 	 	 	 	 	 	05/01/02	 








 




			
	Changes, relative to previous revisions (addendums), are shown in bold type.
	 
	2	 	Third-party may share in the financial responsibility associated with O&M activities.




 









 










	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Generation	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Owned by	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Local	 	 	 	 	 	Last
	 	 	 	 	 	 	 	 	 	 	Distribution	 	Third-Party	 	Revision
	Substation Name	 	Distribution	 	Transmission	 	Company	 	Assets	 	Date
	McGulpin3
	 	 	60.00	 	 	 	40.00	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	Mecosta
	 	 	87.50	 	 	 	12.50	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	Milham
	 	 	75.00	 	 	 	25.00	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	Moore Road43
	 	 	64.65	 	 	 	10.00	 	 	 	 	 	 	 	25.35	 	 	 	08/07/07	 
	Morrow1,2
	 	 	66.67	 	 	 	23.33	 	 	 	6.67	 	 	 	3.33	 	 	 	11/20/08	 
	North Belding
	 	 	66.67	 	 	 	33.33	 	 	 	 	 	 	 	 	 	 	 	10/24/03	 
	Oakland
	 	 	87.50	 	 	 	12.50	 	 	 	 	 	 	 	 	 	 	 	10/24/03	 
	Ransom
	 	 	88.89	 	 	 	11.11	 	 	 	 	 	 	 	 	 	 	 	01/05/05	 
	Rice Creek
	 	 	92.86	 	 	 	7.14	 	 	 	 	 	 	 	 	 	 	 	10/24/03	 
	Riggsville
	 	 	75.00	 	 	 	25.00	 	 	 	 	 	 	 	 	 	 	 	11/20/08	 
	Riverview
	 	 	93.75	 	 	 	6.25	 	 	 	 	 	 	 	 	 	 	 	10/24/03	 
	Saginaw River
	 	 	57.89	 	 	 	42.11	 	 	 	 	 	 	 	 	 	 	 	11/20/08	 
	Spaulding
	 	 	60.00	 	 	 	40.00	 	 	 	 	 	 	 	 	 	 	 	03/31/06	 
	Stover
	 	 	85.71	 	 	 	14.29	 	 	 	 	 	 	 	 	 	 	 	11/20/08	 








 




			
	Changes, relative to previous revisions (addendums), are shown in bold type.
	 
	3	 	At 120kV and above, third-party related assets will be included as part of the
Transmission Provider’s assets for purposes of making this calculation. Also, the third-party may
share in the financial responsibility associated with O&M activities.
	 
	2	 	Third-party may share in the financial responsibility associated with O&M activities.
	 
	3	 	Below 120kV the third-party related assets will be included as part of the Local
Distribution Company’s
assets for purposes of making this calculation. Also, the third-party may share in the financial
responsibility associated with O&M activities.




 









 










	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Generation	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Owned by	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Local	 	 	 	 	 	Last
	 	 	 	 	 	 	 	 	 	 	Distribution	 	Third-Party	 	Revision
	Substation Name	 	Distribution	 	Transmission	 	Company	 	Assets	 	Date
	Stronach52
	 	 	66.67	 	 	 	33.33	 	 	 	 	 	 	 	 	 	 	 	05/24/04	 
	Tihart
	 	 	73.33	 	 	 	26.67	 	 	 	 	 	 	 	 	 	 	 	01/31/05	 
	Tippy
	 	 	33.33	 	 	 	66.67	 	 	 	 	 	 	 	 	 	 	 	11/13/02	 
	Twining
	 	 	76.92	 	 	 	23.08	 	 	 	 	 	 	 	 	 	 	 	05/01/02	 
	Verona
	 	 	60.87	 	 	 	39.13	 	 	 	 	 	 	 	 	 	 	 	03/31/06	 
	Weadock
	 	 	35.14	 	 	 	24.32	 	 	 	40.54	 	 	 	 	 	 	 	03/16/06	 
	Wealthy Street
	 	 	86.11	 	 	 	13.89	 	 	 	 	 	 	 	 	 	 	 	03/16/06	 
	Wexford
	 	 	93.75	 	 	 	6.25	 	 	 	 	 	 	 	 	 	 	 	06/10/10	 
	White Lake
	 	 	81.25	 	 	 	18.75	 	 	 	 	 	 	 	 	 	 	 	10/24/03	 
	Whiting
	 	 	31.58	 	 	 	31.58	 	 	 	36.84	 	 	 	 	 	 	 	08/07/07	 








 




			
	Changes, relative to previous revisions (addendums), are shown in bold type.
	 
	2	 	Third-party may share in the financial responsibility associated with O&M activities.