Document:

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.exv10w92

Exhibit 10.92

			
	 	 	 
	Midwest ISO
	 	Fourth Revised Service Agreement No. 1756
	FERC Electric Tariff, Fourth Revised Volume No. 1
	 	Superseding Third Revised Service Agreement No. 1756
	 
	 	Public Version

AMENDED AND RESTATED

GENERATOR INTERCONNECTION AGREEMENT

entered into by the

Midwest Independent Transmission System Operator, Inc.

Michigan Electric Transmission Company

and Consumers Energy Company

			
	 	 	 
	Issued by: Steven G. Kozey, Issuing Officer
	 	Effective: April 22, 2010
	Issued on: April 21, 2010	 	 

 

 

Original Sheet No. 1

Amended and Restated

GENERATOR INTERCONNECTION AGREEMENT

by and among

Michigan Electric Transmission Company, LLC

and

Consumers Energy Company

and the

Midwest Independent Transmission System Operator, Inc.

 

 

Original Sheet No. 2

Amended and Restated

GENERATOR INTERCONNECTION AGREEMENT

by and among

Michigan Electric Transmission Company, LLC,

Consumers Energy Company

and the

Midwest Independent Transmission System Operator, Inc.

	 	 	 	 	 

	ARTICLE 1 - DEFINITIONS
	 	 	6	 
	 
	 	 	 	 
	ARTICLE 2 - TERM OF AGREEMENT
	 	 	10	 
	 
	 	 	 	 
	2.1 Effective Date
	 	 	10	 
	2.2 Term
	 	 	10	 
	2.3 Termination
	 	 	10	 
	2.4 Regulatory Filing
	 	 	10	 
	2.5 Survival
	 	 	10	 
	 
	 	 	 	 
	ARTICLE 3 - INTERCONNECTION SERVICE
	 	 	11	 
	 
	 	 	 	 
	3.1 Scope of Service
	 	 	11	 
	3.2 Third-Party Actions
	 	 	12	 
	 
	 	 	 	 
	ARTICLE 4 - INTERCONNECTION ASSETS
	 	 	12	 
	 
	 	 	 	 
	4.1 Reservation of Rights to Interconnection Assets
	 	 	12	 
	4.2 Modifications
	 	 	12	 
	4.3 As-Built Drawings
	 	 	12	 
	 
	 	 	 	 
	ARTICLE 5 - OPERATIONS
	 	 	13	 
	 
	 	 	 	 
	5.1 General
	 	 	13	 
	5.2 Transmission Provider and Transmission Owner Obligations
	 	 	13	 
	5.3 Consumers Obligations
	 	 	13	 
	5.4 Jointly Owned Assets
	 	 	13	 
	5.5 Access Rights
	 	 	14	 
	5.6 Switching and Tagging Rules
	 	 	14	 
	5.7 Black Start Participation
	 	 	14	 
	5.8 Reactive Power
	 	 	14	 
	5.9 System Security
	 	 	14	 
	5.10 Consumers Voltage Regulation
	 	 	15	 
	5.11 Protection and System Quality
	 	 	15	 
	5.12 Outages, Interruptions, and Disconnection
	 	 	16	 
	5.13 Operating Expenses
	 	 	18	 
	 
	 	 	 	 
	ARTICLE 6 - MAINTENANCE
	 	 	19	 
	 
	 	 	 	 
	6.1 Transmission Owner’s Obligations
	 	 	19	 
	6.2 Consumers’ Obligations
	 	 	19	 
	6.3 Jointly Owned Assets
	 	 	19	 
	6.4 Access Rights
	 	 	19	 
	6.5 Maintenance Expenses
	 	 	20	 
	6.6 Coordination
	 	 	20	 

 

 

Original Sheet No. 3

	 	 	 	 	 

	6.7 Inspections and Testing
	 	 	20	 
	6.8 Right to Observe Testing
	 	 	20	 
	6.9 Secondary Systems
	 	 	20	 
	6.10 Observation of Deficiencies
	 	 	20	 
	 
	 	 	 	 
	ARTICLE 7 - EMERGENCIES
	 	 	21	 
	 
	 	 	 	 
	7.1 Obligations
	 	 	21	 
	7.2 Notice
	 	 	21	 
	7.3 Immediate Action
	 	 	21	 
	7.4 Transmission Provider’s and Transmission Owner’s Authority
	 	 	21	 
	7.5 Consumers’ Authority
	 	 	22	 
	7.6 Audit Rights
	 	 	22	 
	 
	 	 	 	 
	ARTICLE 8 - SAFETY
	 	 	22	 
	 
	 	 	 	 
	8.1 General
	 	 	22	 
	8.2 Environmental Releases
	 	 	22	 
	 
	 	 	 	 
	ARTICLE 9 - METERING
	 	 	22	 
	 
	 	 	 	 
	9.1 General
	 	 	22	 
	9.2 Costs of Administering Metering Assets
	 	 	23	 
	9.3 Testing of Metering Assets
	 	 	23	 
	9.4 Metering Data
	 	 	23	 
	9.5 Communications
	 	 	24	 
	 
	 	 	 	 
	ARTICLE 10 - FORCE MAJEURE
	 	 	24	 
	 
	 	 	 	 
	ARTICLE 11 - INFORMATION REPORTING
	 	 	25	 
	 
	 	 	 	 
	ARTICLE 12 - PAYMENTS AND BILLING PROCEDURES
	 	 	25	 
	 
	 	 	 	 
	12.1 Invoices
	 	 	25	 
	12.2 Payments
	 	 	25	 
	12.3 Interest Charges
	 	 	26	 
	12.4 Disputes
	 	 	26	 
	 
	 	 	 	 
	ARTICLE 13 - ASSIGNMENT
	 	 	26	 
	 
	 	 	 	 
	ARTICLE 14 - INDEMNITY AND INSURANCE
	 	 	27	 
	 
	 	 	 	 
	14.1 Indemnity
	 	 	27	 
	14.2 Insurance
	 	 	27	 
	 
	 	 	 	 
	ARTICLE 15 - LIMITATION ON LIABILITY
	 	 	28	 
	 
	 	 	 	 
	ARTICLE 16 - BREACH, CURE AND DEFAULT
	 	 	28	 
	 
	 	 	 	 
	16.1 General
	 	 	28	 
	16.2 Events of Breach
	 	 	28	 
	16.3 Continued Operation
	 	 	29	 
	16.4 Cure and Default
	 	 	29	 
	16.5 Right to Compel Performance
	 	 	30	 
	 
	 	 	 	 
	ARTICLE 17 - CONFIDENTIALITY
	 	 	30	 

 

 

Original Sheet No. 4

	 	 	 	 	 

	ARTICLE 18 -AUDIT RIGHTS
	 	 	31	 
	 
	 	 	 	 
	ARTICLE 19 - DISPUTES
	 	 	31	 
	 
	 	 	 	 
	ARTICLE 20 - NOTICES
	 	 	31	 
	 
	 	 	 	 
	ARTICLE 21 - MISCELLANEOUS
	 	 	32	 
	 
	 	 	 	 
	21.1 Amendments
	 	 	32	 
	21.2 Binding Effect
	 	 	32	 
	21.3 Counterparts
	 	 	32	 
	21.4 Entire Agreement
	 	 	32	 
	21.5 Governing Law
	 	 	32	 
	21.6 Headings Not To Affect Meaning
	 	 	33	 
	21.7 Waivers
	 	 	33	 
	21.8 Termination of Predecessor Interconnection Agreement
	 	 	33	 
	 
	 	 	 	 
	EXHIBITS
	 	 	 	 
	EXHIBIT A Consumers Generation Resources
	 	 	34	 
	EXHIBIT B Interconnection Assets
	 	 	37	 
	EXHIBIT B Table 1
	 	 	38	 
	EXHIBIT C Generator Connections located in Consumers’ Distribution System
	 	 	65	 
	EXHIBIT C Consumers Energy Generator Connections Covered under Other Interconnection Agreements
	 	 	65	 

 

 

Original Sheet No. 5

Amended and Restated

GENERATOR INTERCONNECTION AGREEMENT

     THIS Amended AND RESTATED GENERATOR INTERCONNECTION AGREEMENT(the “Agreement”) is made and
entered into as of March 18th, 2010 by and among Michigan Electric Transmission Company,
LLC, a limited liability company with offices at 27175 Energy Way Novi, Michigan (herein referred
to as “METC” or “Transmission Owner”), Consumers Energy Company, a Michigan corporation with
offices at One Energy Plaza, Jackson, Michigan (herein referred to as “Consumers” or
“Interconnection Customer”), and the Midwest Independent Transmission System Operator, Inc., a
non-profit, non-stock corporation organized and existing under the laws of the State of Delaware
(herein referred to as “Midwest ISO” or “Transmission Provider”). Transmission Provider, Consumers
and Transmission Owner each may be referred to individually as a “Party,” or collectively as the
“Parties.” This Agreement amends, restates and replaces the July 24, 2008 Amendment and Restatement
of the Generator Interconnection Agreement between the Transmission Owner, Transmission Provider
and Consumers, effective on the Effective Date provided for below in Section 2.1.

WITNESSETH:

     WHEREAS, Consumers owns and operates several electric generating assets (herein referred to as
a Unit when discussing one of them, or as Generation Resources when referring to all of them) as
described in Article 1. The Unit names and generating capability ratings of the Generation
Resources are set forth in Exhibit A to this Agreement. Each Unit in the list is currently in
commercial operation; and

     WHEREAS, Transmission Provider has functional control of the operation of the Transmission
System, as defined in Article 1 of this Agreement, and is responsible for providing transmission
and interconnection service on the transmission facilities under its functional control; and

     WHEREAS, Transmission Owner owns or operates the Transmission System, whose operations are
subject to the functional control of the Transmission Provider, to which the Consumers’ Units are
interconnected, as set forth in this Agreement; and

     WHEREAS, it is necessary for Consumers’ Units to remain interconnected with the Transmission
System (as defined in Article 1), in order for said Units to continue to operate; and

     WHEREAS, the revised and restated Agreement is not intended to affect METC’s and Consumer’s
obligations to each other with regard to the following agreements:

     WHEREAS, Consumers and Transmission Owner have entered into an Operating Agreement, dated as
of April 1, 2001, as amended and restated, (herein referred to as the “Operating Agreement”) that
defines the operating responsibilities of the Transmission Owner with respect to the Transmission
System and the obligations, rights and responsibilities of Consumers to provide ancillary services
and to operate its Generation Resources in a manner

 

 

Original Sheet No. 6

that will not unduly interfere with the provision of Transmission Services by the Transmission
Owner; and

     WHEREAS, Consumers, Transmission Owner and Transmission Provider have entered into a Purchase
and Sale Agreement for Ancillary Services, dated as of April 1, 2001, as amended and restated, that
sets forth the terms and conditions under which Consumers shall use its Generation Resources to
provide ancillary services to the Transmission Owner and Transmission Provider; and

     WHEREAS, the Parties are willing to maintain the interconnection of Consumers’ Generation
Resources with the Transmission System under the terms and conditions contained herein.

     NOW, THEREFORE, in consideration of and subject to the mutual covenants contained herein, the
Parties hereto agree as follows:

ARTICLE 1

DEFINITIONS

1.1 Whenever used in this Agreement, appendices, and attachments hereto, the following terms
shall have the following meanings:

     “Black Start Capability” shall mean a generating Unit that is capable of starting
without an outside electrical supply. Said Units are specified in Exhibit A.

     “Black Start Plan” shall mean a plan utilizing Black Start Capability designed and
implemented by the Transmission Provider or Transmission Owner 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.

     “Black Start Service” shall mean the provision of service needed to energize a defined
portion of the Transmission Owner’s Transmission System, including the start up of the Generation
Resources and/or other generators, in accordance with the Transmission Provider’s or Transmission
Owner’s Black Start Plan when local power from the Transmission System is unavailable or
insufficient.

     “Commission” shall mean the Federal Energy Regulatory Commission, or any successor
agency.

     “Connection Point” shall be the point where Consumers’ Interconnection Assets connect
to Transmission Owner’s Interconnection Assets, as described in Exhibit B of this Agreement.

     “Consumers’ Incremental Cost” shall mean Consumers’ actual hourly replacement cost of
energy on Consumers’ Generation Resources, whether that energy is (a) produced by generation owned
by or under contract to Consumers or (b) purchased from a third party.

 

 

Original Sheet No. 7

     “Consumers’ Interconnection Assets” shall mean the assets identified as belonging to
Consumers in Exhibit B of this Agreement and all other assets that are necessary or desirable to
interconnect a Unit to the Transmission System reliably and safely, including all connection,
switching, transmission, distribution, safety, and communication assets, protective assets,
Telemetry and Monitoring Assets that Consumers owns or operates and maintains.

     “Consumers’ System” shall mean the assets owned, controlled and operated by Consumers
that are used to provide service to its customers.

     “ECAR” stands for the East Central Area Reliability council or a successor group.

     “Emergency” shall mean any system condition that requires automatic or immediate manual action
to prevent or limit the loss of transmission assets or generation supply that could adversely
affect the reliability of Transmission System or Consumers’ System or the systems to which either
Party is directly or indirectly connected.

     “Generation Resources” shall mean the assets used for the production of electric
energy, which are owned and operated by Consumers and directly or indirectly connected to the
Transmission System pursuant to this Agreement.

     “Good Utility Practice” shall mean any of the practices, methods and acts engaged in
or approved by a significant proportion 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 to be acceptable practices, methods or
acts generally accepted in the region.

     “Governmental Authority” shall mean any federal, state, local or municipal
governmental body; any governmental, regulatory or administrative agency, commission, body or other
authority exercising or entitled to exercise any administrative, executive, judicial, legislative,
policy, regulatory or taxing authority or power; or any court or governmental tribunal.

     “Hazardous Substances” shall mean any chemicals, materials or substances defined as or
included in the definition of “hazardous substances”, “hazardous wastes”, “hazardous materials”,
“hazardous constituents”, “restricted hazardous materials”, “extremely hazardous substances”,
“toxic substances”, “contaminants”, “pollutants”, “toxic pollutants” or words of similar meaning
and regulatory effect under any applicable Environmental Law, or any other chemical, material or
substance, exposure to which is prohibited, limited or regulated by any applicable Environmental
Law. For purposes of this Agreement, the term “Environmental Law” shall mean federal, state, and
local laws, regulations, rules, ordinances, codes, decrees, judgments, directives, or judicial or
administrative orders relating to pollution or protection of the environment, natural resources or
human health and safety.

     “IEEE” is an acronym, which stands for the Institute of Electrical and Electronic
Engineers.

 

 

Original Sheet No. 8

     “Interconnection Assets” shall mean, collectively, Transmission Owner’s
Interconnection Assets and Consumers’ Interconnection Assets, or the specific Interconnection
Assets of either the Transmission Owner or Consumers, as the case may be.

     “Jointly Owned Assets” shall mean those assets in which Consumers and Transmission
Owner have undivided ownership interests. Due to the nature of substation designs, many of the
supporting substation assets (e.g., station batteries, fencing, control houses, ground grid, yard
stone, steel structures and some protective relay assets) 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 B hereto.

     “Metering Assets” shall mean the assets required to provide acceptably accurate
metering of the interconnection power and energy output from the Unit and the standby power and
energy usage of the Unit. Said Metering Assets typically includes but is not limited to, metering
accuracy potential and current transformers, transducers, primary connections, secondary
connections, secondary potential and current circuits and conduit, telephone lines and access to
said Metering Assets, if necessary. The transducers used shall be capable of providing Megawatthour
and Megavarhour data.

     “Midwest ISO” shall mean the Midwest Independent Transmission System Operator, Inc.,
or its successor.

     “Midwest ISO Tariff” shall mean the Open Access Transmission, Energy and Operating
Reserve Markets Tariff on file with the Commission as it may be amended or superseded from time to
time.

     “Monitoring Assets” shall mean the assets required to determine (a) the sequence of
events for the operation of protective assets during an electrical fault, (b) the location and
characteristics of an electrical fault and (c) the quality of power provided at the Point of
Receipt.

     “NERC” is an acronym that stands for the North American Electric Reliability Council,
including any successor thereto or any regional reliability council thereof. This reliability
council oversees the development and publication of operating policies, engineering planning
principles and guides and support information to provide guidance to the regional reliability
councils and to promote electric system reliability.

     “Point of Receipt” shall be the point at which capacity and energy is provided by
Consumers, as described in Exhibit B of this Agreement.

     “Reactive Design Limitations” shall mean the reactive power capability designed into
the Unit, which were consistent with reactive power capability specifications in place when the
Unit was constructed.

     “Secondary Systems” shall mean control or power circuits that operate below 600 volts,
AC or DC, including, but not limited to, any hardware, control or protective devices, cables,
conductors, electric conduits and raceways, secondary assets panels, transducers, batteries,
chargers, and voltage and current transformers.

 

 

Original Sheet No. 9

     “Switching and Tagging Rules” shall mean the written documents describing the
switching and tagging procedures of Transmission Owner and Consumers, as they may be amended.

     “System Operator” is a generic term used to describe the individuals responsible for
the integrity or the operational control of the Transmission System and any successor thereto.

     “System Protection Assets” shall mean the assets required to protect (a) the
Transmission System, the systems of others connected to the Transmission System, and Transmission
Owner’s customers from faults occurring at the Unit, and (b) the Unit from faults occurring on the
Transmission System or on the systems of others to which the Transmission System is directly or
indirectly connected.

     “Telemetry Equipment” shall mean the assets, identified by Transmission Owner, that
are required to provide the necessary, real-time telemetry of Unit operations and status, as
required by Transmission Owner, for remote monitoring and control purposes. This typically includes
but is not limited to, remote terminal units, distributed terminal units, telemetry signal inputs,
fiber optic communication connections, transducers, pulse multipliers, isolation amplifiers, analog
inputs, digital inputs, metering pulsed accumulator inputs, power supply, dedicated telephone data
line to remote terminal units, telephone modem, telephone switching, interface terminal strips for
landing signal inputs/outputs. Telemetry Equipment may be located at Consumers’ Unit and or at
Transmission Owner’s assets.

     “Transmission Owner” shall mean Michigan Electric Transmission Company, LLC or its
successor.

     “Transmission Owner’s Interconnection Assets” shall mean the assets identified as
belonging to Transmission Owner in Exhibit B of this Agreement and all other assets that are
necessary or desirable to interconnect the Generation Resources to the Transmission System reliably
and safely, including all connection, switching, transmission, distribution, safety, and
communication assets, protective assets, Metering, Telemetry and Monitoring Assets and all
improvements, additions or extensions to the Transmission System owned or operated and maintained
by the Transmission Owner and that are attributable to or necessitated by the Generation Resources.

     “Transmission Provider” shall mean the Midwest ISO.

     “Transmission System” shall mean the facilities owned by the Transmission Owner and
controlled or operated by the Transmission Provider or Transmission Owner that are used to provide
transmission service under the Midwest ISO Tariff.

     “Transmission Service” shall include both Point-To-Point Transmission Service and
Network Integration Transmission Service provided under the Midwest ISO Tariff.

     “Unit” shall mean each of Consumers’ electric generating assets, or group of
generating assets having common Interconnection Assets, covered by this Agreement and identified
generally in the first “Whereas” clause and Exhibit A of this Agreement and more specifically
identified in the “as built” drawings provided to Transmission Owner in accordance

 

 

Original Sheet No. 10

with Section 4.3 of this Agreement, together with the other property, assets, and assets owned
and/or controlled by Consumers on the Consumers’ side of the Connection Point.

ARTICLE 2

TERM OF AGREEMENT

2.1 Effective Date

     This Agreement shall become effective on the date designated by the Commission in its order
accepting this Agreement for filing (the “Effective Date”).

2.2 Term

     This Agreement shall become effective as provided in Section 2.1 above and, unless terminated
as provided below, shall continue in full force and effect until a mutually agreed termination
date, but no later than the date on which all of the Generation Resources cease commercial
operation.

2.3 Termination

     In the event that Transmission Owner joins a Regional Transmission Organization (“RTO”) which
requires use of its own FERC-approved interconnection and operating agreement, this Agreement shall
terminate on the effective date of such new interconnection and operating agreement between
Consumers and the RTO, except to the extent necessary to resolve billing and other outstanding
matters related to service rendered under this Agreement as specified in Section 2.5.

2.4 Regulatory Filing

     Transmission Provider shall file this Agreement with the Commission as a Service Agreement
under the Midwest ISO Tariff, within the meaning of 18 C.F.R. Part 35. Consumers and Transmission
Owner agree to cooperate with Transmission Provider with respect to such filing and to provide any
information, including the rendering of testimony reasonably requested by Transmission Provider,
needed to comply with applicable regulatory requirements.

2.5 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.

 

 

Original Sheet No. 11

ARTICLE 3

INTERCONNECTION SERVICE

3.1 Scope of Service

     In the event future changes in either (a) design or operation of any Unit, (b) Consumers’
requirements or (c) Transmission Provider’s or Transmission Owner’s requirements resulting from the
Unit’s parallel operation with the Transmission System later necessitate additional Interconnection
Assets or modifications to the then existing Interconnection Assets herein, the Parties shall
undertake such additions and modifications as may be necessary. Before undertaking such future
additions or modifications, the Parties shall consult, develop plans and coordinate schedules of
activities, including the making of necessary amendments to this Agreement (including its
Appendices) and/or entering into new agreements, so as to insure continuous and reliable operation
of the Interconnection Assets. The cost of such additions or modifications to the Interconnection
Assets shall be borne by Consumers unless otherwise agreed upon at the time. The ownership,
operation and maintenance responsibilities for any such future additions or modifications shall be
made consistent with the responsibilities allocated in this Agreement.

     3.1.1 Except as otherwise provided under Sections 5.8 and 5.9 of this Agreement, neither
Transmission Provider nor Transmission Owner shall have an obligation under this Agreement to pay
Consumers any wheeling or other charges for electric power and/or energy transferred through
Consumers’ assets or for power or ancillary services provided by Consumers under this Agreement for
the benefit of the Transmission System.

     3.1.2 Except as otherwise provided under this Agreement, neither Transmission Provider nor
Transmission Owner shall have an obligation under this Agreement to make arrangements or pay
under applicable tariffs for transmission and ancillary services associated with the delivery of
electricity and ancillary electrical products produced by the Unit.

     3.1.3 Except as otherwise provided under this Agreement, neither Transmission Provider nor
Transmission Owner shall have an obligation under this Agreement to procure electricity and
ancillary electrical products to satisfy Consumers’ station power needs or other related
requirements.

     3.1.4 Except as otherwise provided under this Agreement, neither Transmission Provider nor
Transmission Owner shall have an obligation under this Agreement to make arrangements under
applicable tariffs for transmission, losses, and ancillary services associated with the use of
the Transmission System for the delivery of electricity and ancillary electrical products to the
Unit.

     3.1.5 Transmission Provider makes no representations to Consumers regarding the availability
of Transmission Service on the Transmission System, and Consumers agrees that the availability of
Transmission Service on the Transmission System may not be inferred or implied from Transmission
Provider’s or Transmission Owner’s execution of this Agreement. Consumers will obtain Transmission
Service on the Transmission System under a separate agreement between the Parties and in accordance
with the provisions of the Midwest ISO Tariff.

 

 

Original Sheet No. 12

3.2 Third-Party Actions

     Consumers acknowledges and agrees that, from time to time during the term of this Agreement,
other persons may develop, construct and operate, or acquire and operate generating assets in the
Transmission Provider’s service territory, and construction or acquisition and operation of any
such assets, and reservations by any such persons of Transmission Service under the Midwest ISO
Tariff may adversely affect the Unit and the availability of Transmission Service for the Unit’s
electric output. Consumers acknowledges and agrees that Transmission Provider has no obligation
under this Agreement to disclose to Consumers any information with respect to third-party
developments or circumstances, including the identity or existence of any such person or other
assets, beyond what Transmission Provider customarily provides to other similarly situated
generators, except as may be required under Article 4 of this Agreement and elsewhere in this
Agreement. Consumers and Transmission Provider make no guarantees to the other under this Agreement
with respect to Transmission Service that is available under the Midwest ISO Tariff.

ARTICLE 4

INTERCONNECTION ASSETS

4.1 Reservation of Rights to Interconnection Assets

     Except as provided in Section 5.2 hereof, each Party reserves to itself the ownership,
operation and maintenance of its Interconnection Assets and all improvements, additions or
extensions to its Interconnection Assets under this Agreement which are attributable to or
necessitated by the interconnection of the Unit.

4.2 Modifications

     Either Party may undertake modifications to its assets. In the event a Party plans to
undertake a modification that may be expected to impact the other Party’s assets, that Party shall
provide the other Party with sufficient information regarding such modification, including, without
limitation, the notice required in accordance with Article 11 of this Agreement so that the other
Party can evaluate the potential impact of such modification prior to commencement of the work. The
Party desiring to perform such work shall provide the relevant drawings, plans, and specifications
to the other Party at least ninety (90) days in advance of commencement of the work or such shorter
period upon which the Parties may agree, which agreement will not unreasonably be withheld or
delayed.

4.3 As-Built Drawings

     Upon execution of this Agreement, Consumers shall provide to Transmission Provider and
Transmission Owner current interconnection drawings and system diagrams for each of its Units,
unless the Parties agree that such drawings are not necessary. Subject to the requirements of
Article 17 of this Agreement, not later than ninety (90) days after completion of any addition to
or modification of the assets of any of said Units that may reasonably be expected to affect the
Transmission System, Consumers shall issue revised “as built” drawings to Transmission Provider and
Transmission Owner.

 

 

Original Sheet No. 13

ARTICLE 5

OPERATIONS

5.1 General

The Parties agree that they shall comply with the Operating Agreement, then-existing (or amended)
applicable manuals, standards, and guidelines of Transmission Provider, NERC, ECAR, or any
successor agency assuming or charged with similar responsibilities related to the operation and
reliability of the North American electric interconnected transmission grid. To the extent that
this Agreement does not specifically address or provide the mechanisms necessary to comply with
such Operating Agreement, Transmission Provider, NERC or ECAR manuals, standards, or guidelines,
the Parties hereby agree that each Party shall provide to the other Parties all such information as
may reasonably be required to comply with such Operating Agreement, manuals, standards, or
guidelines and shall operate, or cause to be operated, their respective assets in accordance with
such Operating Agreement, manuals, standards, or guidelines.

5.2 Transmission Provider and Transmission Owner Obligations

     Transmission Provider and Transmission Owner shall operate and control the Transmission System
and other Transmission Owner assets in a safe and reliable manner (a) in accordance with
Transmission Provider’s and Transmission Owner’s applicable operational and/or reliability
criteria, protocols, and directives (which include those of NERC and ECAR), (b) the Operating
Agreement and (c) in accordance with the provisions of this Agreement. From time to time, Consumers
will control and operate four (4) 345 kV synchronizing circuit breakers (Nos. 28H9, 28R8, 32F7 and
32H9 in the Hampton Substation) to connect or disconnect the Karn 3 or Karn 4 Units, as the case
may be, from the Transmission System. The Parties may agree from time to time that Consumers, under
the direction of the Transmission Provider or Transmission Owner, will operate certain other
Interconnection Assets of the Transmission Owner.

5.3 Consumers Obligations

     Consumers shall operate and control its Generation Resources in a safe and reliable manner in
accordance with (a) Consumers’ applicable operational and/or reliability criteria, protocols, and
directives (which shall include those of NERC and ECAR), the Operating Agreement and (c) the
provisions of this Agreement.

5.4 Jointly Owned Assets

          Operation of Jointly Owned Assets at the electric substations where Interconnection Facilities
are located will be under the direction and control of the Party with more than fifty percent (50%)
of the major equipment at each such location, unless otherwise agreed by the Parties hereto. Said
Party shall operate the Jointly Owned Assets in a manner consistent with Good Utility Practice and
the provisions of Sections 5.2 and 5.3 above, as appropriate. Each Party’s respective share of
responsibility for the costs of operation of Jointly Owned Assets shall be the same percentage as
the percentage of major equipment

 

 

Original Sheet No. 14

owned by such Party in that substation, as set forth in Exhibit B and its subsequent addendum’s.
The respective ownership of substation facilities is shown in the Wiring Diagrams for each of the
electrical substations at which Consumers’ Generation Resources are connected to the Transmission
System (see Exhibit B), reflecting ownership changes through July 24, 2008. The Wiring Diagrams
(WDs) will be updated continuously in each Party’s Drawing Management System (DMS) which is shared
between the Parties. For current ownership (reflecting ownership changes since July 24, 2008), see
the WDs in the DMS. For purposes of this Agreement, major equipment is defined as (a) main power
transformers, (b) 23 kV, 46 kV, 138 kV and 345 kV circuit breakers, (c) power system regulators and
reclosers and (d) 46 kV and 138 kV capacitor banks (any three-phase installation of such equipment
shall count as one unit of equipment). Exhibit B shall be updated with an addendum at least
annually by the Transmission Owner, and approved in writing by all Parties at least annually, to
show all changes in equipment and the effects of such changes on the determination of Jointly Owned
Asset percentages. For purposes of this Section 5.4, such submission and approval of changes shall
be in writing consistent with Section 21.1. In the case where each Party hereto owns exactly fifty
percent (50%) of the major equipment at any specific location, the Transmission Owner shall assume
the responsibility for direction and control of the operation activities as such location. In those
substations where each Party hereto owns assets, each Party shall be responsible for its
appropriate share, as set forth in Exhibit B hereto, of station power energy usage and expense.

5.5 Access Rights

     The Parties shall provide each other such access rights as may be necessary for either Party’s
performance of its respective operational obligations under this Agreement; provided that,
notwithstanding anything stated herein, a Party performing operational work within the boundaries
of the other Party’s assets must abide by the rules applicable to that site.

5.6 Switching and Tagging Rules

     The Parties shall abide by their respective Switching and Tagging Rules for obtaining
clearances for work or for switching operations on assets. The Parties will adopt mutually
agreeable Switching and Tagging Rules prior to the effective date of this Agreement.

5.7 Black Start Participation

     In accordance with Good Utility Practice, Consumers agrees to participate in Transmission
Owner’s Black Start Plan, as well as any verification testing. Nothing in this Agreement obligates
a particular Unit to provide Black Start Service.

5.8 Reactive Power

     The supply and absorption of reactive power is dealt with in the Purchase and Sale Agreement
for Ancillary Services among the Parties hereto.

5.9 System Security

 

 

Original Sheet No. 15

     During an Emergency on the Transmission System or on an adjacent transmission system, the
System Operator has the authority to direct Consumers to increase or decrease real power production
(measured in MW) and/or reactive power production (measured in MVAR), within the design and
operational limitations of any of Consumers’ Generation Resources in service at the time, in order
to maintain security on the Transmission System. In the event of such a declaration of an
Emergency, determinations: (a) that the Transmission System security is in jeopardy, and/or (b)
that there is a need to increase or decrease reactive power production, even if real power
production is adversely affected, will be made solely by the System Operator or his designated
representative. Each Unit operator will honor System Operator’s orders and directives concerning
said Unit’s real power and/or reactive power output within design and operational limitations of
the Unit’s equipment in service at the time, such that the security of the Transmission System is
maintained. Transmission Provider and Transmission Owner shall restore the Transmission System
conditions to normal to alleviate any such Emergency, in accordance with Good Utility Practice.
Consumers will be compensated by Transmission Provider or Transmission Owner for increasing or
decreasing the real power output of any of its Units as directed by the System Operator to support
the Transmission System during an Emergency by the payment of (a) Consumers’ Incremental Cost
associated with such increase or decrease in real power output or (b) at such other rate filed by a
Party and approved by the Commission including any existing tariff or rate schedule which has been
filed by the Transmission Provider, Transmission Owner or Consumers. Similarly, if the Transmission
Provider or Transmission Owner requests any of Consumers’ Units to provide or absorb reactive power
that would be outside of the Unit’s Reactive Design Limitations, requiring the Unit’s real power
output to be reduced to obtain the desired reactive power, the Transmission Provider or
Transmission Owner shall compensate Consumers at the real power rate discussed in the preceding
sentence, to the extent that the Unit had to reduce real power output to operate within its
Reactive Design Limitations, unless otherwise provided in another agreement or tariff on file with
the Commission.

5.10 Consumers Voltage Regulation

     Consumers shall have sufficient voltage regulation at each Unit to maintain an acceptable
voltage level for the equipment at the Unit during periods of time that the Unit’s generation is
off line.

5.11 Protection and System Quality

     Consumers shall, at its expense, install, maintain, and operate System Protection Assets,
including such protective and regulating devices as are identified by order, rule or regulation of
any duly constituted regulatory authority having jurisdiction, or as are otherwise necessary to
protect personnel and assets and to minimize deleterious effects to Transmission Provider’s or
Transmission Owner’s electric service operation arising from the Unit. Transmission Owner shall
install any such protective or regulating devices that may be required on Transmission Owner’s
assets in connection with the operation of the Unit at Consumers’ expense.

     5.11.1 Requirements for Protection. In compliance with applicable NERC, ECAR and Transmission
Provider’s and Transmission Owner’s requirements, Consumers shall provide, own, and maintain
relays, circuit breakers and all other devices necessary to promptly remove any fault contribution
of the Unit to any short circuit occurring on the Transmission System not

 

 

Original Sheet No. 16

otherwise isolated by Transmission Owner’s assets. Such protective assets shall include, without
limitation, a disconnecting device or switch with visible blade disconnect and load interrupting
capability to be located between the Unit and the Transmission System at an accessible, protected,
and satisfactory site selected upon mutual agreement of the Parties. The present integrated system
provides for fault clearing at the generation substations. Unit protection may not be able to
detect all short circuits, but the Parties agree that no other arrangements shall be required.
Consumers shall be responsible for protection of the Unit and Consumers’ other associated assets
from such conditions as negative sequence currents, over- or under-frequency, sudden load
rejection, over- or under-voltage, and generator loss-of-field. Consumers shall be solely
responsible for provisions to disconnect the Unit and Consumers’ other associated assets when any
of the disturbances described above occur on the Transmission System.

     5.11.2 System Power Quality. Consumers’ facilities and equipment shall not cause excessive
voltage flicker nor introduce excessive distortion to the sinusoidal voltage or current waves.
Power output from and input to the Unit shall be in accordance with the power quality standards
contained in IEEE Standards 141 — Recommended Practice for Electrical Power Distribution for
Industrial Plants (voltage flicker) and 519 — Recommended Practices and Requirements for Harmonic
Control in Electric Power Systems (harmonics). Consumers’ facilities and equipment have been
designed and constructed in accordance with then-existing standards so as not to cause excessive
voltage excursions nor cause the voltage to drop below or rise above the range maintained by
Transmission Provider or Transmission Owner in the absence of Consumers’ facilities and equipment
at the time the Unit first went into service.

     5.11.3 Inspection. Subject to the confidentiality provisions set forth in Article 17,
Transmission Provider and Transmission Owner shall have the right, but shall have no obligation or
responsibility to (a) observe Consumers’ tests and/or inspection of any of Consumers’ protective
assets directly connected to the Transmission System or interfacing with Transmission Owner’s
protective assets, (b) review the settings of any of Consumers’ protective assets; and (c) review
Consumers’ maintenance records relative to Consumers’ protective assets. Transmission Provider
and Transmission Owner may exercise the foregoing rights from time to time as deemed necessary by
Transmission Provider or Transmission Owner upon reasonable notice to Consumers. However, the
exercise or non-exercise by Transmission Provider or Transmission Owner of any of the foregoing
rights of observation, review or inspection shall be construed neither as an endorsement or
confirmation of any aspect, feature, element, or condition of the Unit or Consumers’ protective
assets or the operation thereof, nor as a warranty as to the fitness, safety, desirability, or
reliability of same.

5.12 Outages, Interruptions, and Disconnection

     5.12.1 Outage Authority and Coordination. In accordance with Good Utility Practice, each Party
may, in close cooperation with the other and upon providing notice per Section 20.2, remove from
service its assets that may impact the other Party’s assets as necessary to perform maintenance or
testing or to install or replace assets. Absent the existence or imminence of an Emergency, the
Party scheduling a removal of a facility from service will schedule such removal on a date mutually
acceptable to both Parties. Further, the Transmission Provider and Transmission Owner shall use
their best efforts to coordinate the scheduling of maintenance on Transmission Owner’s
Interconnection Assets to coincide with

 

 

Original Sheet No. 17

Consumers scheduled maintenance on its Units that may be impacted by maintenance on Transmission
Owner’s Interconnection Assets.

     5.12.2 Outage Restoration.

          5.12.2.1 Unplanned Outage. In the event of an unplanned outage of a Party’s facility
that adversely affects the other Party’s assets, the Party that owns or controls the facility
out of service will use commercially reasonable efforts to promptly restore that facility to
service.

          5.12.2.2 Planned Outage. In the event of a planned outage of a Party’s facility that
adversely affects the other Party’s assets, the Party that owns or controls the facility out
of service will use commercially reasonable efforts to promptly restore that facility to
service and in accordance with its schedule for the work that necessitated the planned
outage.

     5.12.3 Interruption. If at any time, in Transmission Provider’s or Transmission Owner’s
reasonable judgment, the continued operation of the Unit would cause an Emergency, Transmission
Provider or Transmission Owner may curtail, interrupt, or reduce energy delivered from the Unit to
the Transmission System until the condition which would cause the Emergency is corrected.
Transmission Provider or Transmission Owner shall give Consumers as much notice as is reasonably
practicable of Transmission Provider’s or Transmission Owner’s intention to curtail, interrupt, or
reduce energy delivery from the Unit in response to a condition that would cause an Emergency and,
where practicable, allow suitable time for the Parties to remove or remedy such condition before
any such curtailment, interruption, or reduction commences. In the event of any curtailment,
interruption, or reduction, Transmission Provider or Transmission Owner shall promptly
confer with Consumers regarding the conditions that gave rise to the curtailment, interruption, or
reduction, and Transmission Provider or Transmission Owner shall give Consumers
Transmission Provider’s or Transmission Owner’s recommendation, if any, concerning the timely
correction of such conditions. Transmission Provider or Transmission Owner shall promptly cease
the curtailment, interruption, or reduction of energy delivery when the condition that would cause
the Emergency ceases to exist.

     5.12.4 Disconnection.

     5.12.4.1 Disconnection after Agreement Terminates. Upon termination of the
Agreement, Transmission Provider or Transmission Owner may disconnect Consumers’ Generation
Resources from the Transmission System in accordance with a plan for disconnection upon
which the Parties agree.

     5.12.4.2 Disconnection in Event of Emergency. Subject to the provisions of Subsection
5.12.4.3 of this Agreement, Transmission Provider, Transmission Owner or Consumers shall
have the right to disconnect the Unit without notice if, in Transmission Provider’s,
Transmission Owner’s or Consumers’ sole opinion, an Emergency exists and immediate
disconnection is necessary to protect persons or property from damage or interference
caused by Consumers’ interconnection or lack of proper or properly operating protective
devices. For purposes of this Subsection 5.12.4.2, protective devices may be deemed by
Transmission Provider

 

 

Original Sheet No. 18

or Transmission Owner to be not properly operating if Transmission Provider’s or
Transmission Owner’s review under Article 6 of this Agreement has disclosed irregular or
otherwise insufficient maintenance on such devices or that maintenance records do not
exist or are otherwise insufficient to demonstrate that adequate maintenance has been and
is being performed.

     5.12.4.3 Disconnection after Under-frequency Load Shed Event. NERC Planning Criteria
require the interconnected transmission system frequency be maintained between 59.95 Hz and
60.05 Hz. In case of an under-frequency system disturbance, the Transmission System is
designed to automatically activate a five-tier load shed program. The five load sheds occur
at 59.5, 59.3, 59.1, 58.9 and 58.7 Hz, respectively. For those Units that are determined by
Transmission Provider to be large enough to impact the Transmission Provider’s system
security, each such Unit shall be capable of under-frequency operation as specified in
Appendix 1 “Isolation of Generating Units” contained in ECAR Document No. 3 -Emergency
Operations, or a higher under-frequency set point if already in place upon execution of
this Agreement. Upon notice from Consumers and if the Transmission Provider or Transmission
Owner agrees, Consumers may implement a higher under-frequency relay set point if necessary
to protect its assets for a particular Unit or Units.

     5.12.5 Continuity of Service. Notwithstanding any other provision of this Agreement,
Transmission Provider shall not be obligated to accept, and Transmission Provider may require
Consumers to curtail, interrupt or reduce deliveries of energy if such delivery of energy impairs
Transmission Provider’s or Transmission Owner’s ability to construct, install, repair, replace or
remove any of its equipment or any part to its system or if Transmission Provider or Transmission
Owner determines that curtailment, interruption or reduction is necessary because of Emergencies,
forced outages, operating conditions on its system, or any reason otherwise permitted by
applicable rules or regulations promulgated by a regulatory agency having jurisdiction over such
matters. The Parties shall coordinate, and if necessary negotiate in good faith, the timing of such
curtailments, interruptions, reductions or deliveries with respect to maintenance, investigation or
inspection of Transmission Owner’s assets or system. Consumers reserves all rights under the
Federal Power Act and applicable other federal and state laws and regulations to commence a
complaint proceeding or other action with the Commission or other Governmental Authority with
appropriate jurisdiction over the Parties to enforce the provisions of this Subsection 5.12.5.

     5.12.6 Curtailment Notice. Except in case of Emergency, in order not to interfere
unreasonably with the other Party’s operations, the curtailing, interrupting or reducing Party
shall give the other Party reasonable prior notice of any curtailment, interruption or reduction,
the reason for its occurrence, and its probable duration.

5.13 Operating Expenses

     Consumers shall reimburse Transmission Owner for all direct and indirect costs and expenses
(including but not limited to telephone circuit charges, property taxes, insurance and assets
testing) incurred by Transmission Owner in operating Transmission Owner’s Interconnection Assets,
to the extent that Transmission Owner is not otherwise recovering such costs and expenses under an
existing tariff or rate schedule which has been filed by

 

 

Original Sheet No. 19

Transmission Provider or Transmission Owner and accepted by FERC. Such costs and expenses shall be
determined by Transmission Owner in accordance with the standard practices and policies followed by
Transmission Provider or Transmission Owner for the performance of work for others in effect at the
time such operation work is performed. Payment by Consumers shall be made in accordance with the
provisions of Article 12 hereof.

ARTICLE 6

MAINTENANCE

6.1 Transmission Owner’s Obligations

     Transmission Owner shall maintain its assets, to the extent they might reasonably be expected to
have an impact on the operation of the Unit (a) in a safe and reliable manner in accordance with
applicable operational and/or reliability criteria, protocols, and directives (which include those
of NERC and ECAR), (b) in accordance with the provisions of the Operating Agreement and (c) in
accordance with the provisions of this Agreement.

6.2 Consumers’ Obligations

     Consumers shall maintain its assets, to the extent they might reasonably be expected to have an
impact on the operation of the Transmission System (a) in a safe and reliable manner in accordance
with applicable operational and/or reliability criteria, protocols, and directives (which include
those of NERC and ECAR), (b) in accordance with the provisions of the Operating Agreement and (c)
in accordance with the provisions of this Agreement.

6.3 Jointly Owned Assets

     Maintenance of Jointly Owned Assets at the electric substations where Interconnection Facilities
are located will be under the direction and control of the Party with more than fifty percent (50%)
of the major equipment at each such location, unless otherwise agreed by the Parties hereto. Said
Party shall maintain the Jointly Owned Assets in a manner consistent with Good Utility Practice and
the provisions of Sections 6.1 and 6.2 above, as appropriate. Each Party’s respective share of
responsibility for the costs of maintenance of Jointly Owned Assets shall be the same percentage as
the percentage of major equipment owned by such Party in that substation, as set forth in Exhibit B
and its subsequent addendum. For purposes of this Agreement, major equipment is defined as set
forth in Section 5.4 hereto. Exhibit B shall be updated with an addendum at least annually by the
Transmission Owner, and approved in writing by Consumers, to show all changes in equipment and the
effects of such changes on the determination of Jointly Owned Asset percentages. In the case where
each Party hereto owns exactly fifty percent (50%) of the major equipment at any specific location,
the Transmission Owner shall assume the responsibility for direction and control of the maintenance
activities at such location.

6.4 Access Rights

     The Parties shall provide each other such access rights as may be necessary for either Party’s
performance of their respective maintenance and/or construction obligations under this Agreement;
provided that, notwithstanding anything stated herein, a Party performing

 

 

Original Sheet No. 20

maintenance and/or construction work within the boundaries of the other Party’s assets must abide
by the rules applicable to that site.

6.5 Maintenance Expenses

     Consumers shall reimburse Transmission Owner for all direct and indirect costs and expenses
(including but not limited to inspection, repair and replacement) incurred by Transmission Owner in
maintaining Transmission Owner’s Interconnection Assets, to the extent that Transmission Owner is
not otherwise recovering such costs and expenses under an existing tariff or rate schedule which
has been filed by Transmission Provider or Transmission Owner and accepted by FERC. Such costs and
expenses shall be determined by Transmission Owner in accordance with the standard practices and
policies followed by Transmission Provider or Transmission Owner for the performance of work for
others in effect at the time such operation work is performed. Payment by Consumers shall be made
in accordance with the provisions of Article 12 of this Agreement.

6.6 Coordination

     The Parties agree to confer regularly to coordinate the planning and scheduling of preventative and
corrective maintenance. Each Party shall conduct preventive and corrective maintenance activities
as planned and scheduled in accordance with this Section 6.5 and the Operating Agreement.

6.7 Inspections and Testing

     Each Party shall perform routine inspection and testing of its assets in accordance with Good
Utility Practice as may be necessary to ensure the continued interconnection of each Unit with the
Transmission System in a safe and reliable manner.

6.8 Right to Observe Testing

     Each Party shall, at its own expense, have the right to observe the testing of any of the other
Party’s assets whose performance may reasonably be expected to affect the reliability of the
observing Party’s assets. Each Party shall notify the other Party in advance of its performance of
tests of its assets, and the other Party may have a representative attend and be present during
such testing.

6.9 Secondary Systems

     Each Party agrees to cooperate with the other in the inspection, maintenance, and testing of those
Secondary Systems directly affecting the operation of a Party’s assets which may reasonably be
expected to impact the other Party. Each Party will provide advance notice to the other Party
before undertaking any work in these areas, especially in electrical circuits involving circuit
breaker trip and close contacts, current transformers, or potential transformers.

6.10 Observation of Deficiencies

 

 

Original Sheet No. 21

     If a Party observes any deficiencies or defects on, or becomes aware of a lack of scheduled
maintenance and testing with respect to, the other Party’s assets that might reasonably be expected
to adversely affect the observing Party’s assets, the observing Party shall either (a) provide
notice to the other Party that is prompt under the circumstance or (b) deem such observation an
Emergency to life or property and immediately disconnect the Unit pursuant to Subsection
5.12.4.2 of this Agreement, and the other Party shall make any corrections required in accordance
with Good Utility Practice.

ARTICLE 7

EMERGENCIES

7.1 Obligations

     Each Party agrees to comply with NERC and ECAR Emergency procedures and Transmission Provider,
Transmission Owner and Consumers Emergency procedures, as applicable, with respect to Emergencies.

7.2 Notice

     Transmission Provider or Transmission Owner shall provide Consumers with oral notification
that is prompt under the circumstances of an Emergency that may reasonably be expected to affect
Consumers’ operation of any or all of its Generation Resources, to the extent Transmission Provider
or Transmission Owner is aware of the Emergency. Consumers shall provide Transmission Provider and
Transmission Owner with oral notification that is prompt under the circumstances of an Emergency
that may reasonably be expected to affect the Transmission System, to the extent Consumers is aware
of the Emergency. In lieu of oral notification described in the preceding two sentences, the
Parties may agree in advance to use other electronic notification means. To the extent the Party
becoming aware of an Emergency is aware of the facts of the Emergency, such notification shall
describe the Emergency, the extent of the damage or deficiency, its anticipated duration, and the
corrective action taken and/or to be taken. Any such notification given pursuant to this Section
7.2 shall be followed as soon as practicable with written notice.

7.3 Immediate Action

     In case of an Emergency, the Party becoming aware of the Emergency may, in accordance with Good
Utility Practice, take such action as is reasonable and necessary to prevent, avoid, or mitigate
injury, danger, and loss, including disconnection pursuant to Subsection 5.12.4.2 of this
Agreement.

7.4 Transmission Provider’s and Transmission Owner’s Authority

     Transmission Provider or Transmission Owner may, consistent with Good Utility Practice, take
whatever actions with regard to the Transmission System as it may deem necessary during an
Emergency in order to (a) preserve public health and safety, (b) preserve the reliability of the
Transmission System, (c) limit or prevent damage and (d) expedite

 

 

Original Sheet No. 22

restoration of service. Transmission Provider or Transmission Owner shall use reasonable efforts
to minimize the effect of such actions on the Unit.

7.5 Consumers’ Authority

     Consumers may, consistent with Good Utility Practice, take whatever actions with regard to the Unit
as it may deem necessary during an Emergency in order to (a) preserve public health and safety, (b)
preserve the reliability of the Unit, (c) limit or prevent damage and (d) expedite restoration of
service. Consumers shall use reasonable efforts to minimize the effect of such actions on the
Transmission System.

7.6 Audit Rights

     Each Party shall keep and maintain records of actions taken during an
Emergency that may reasonably be expected to impact the other Party’s assets and make such records
available for third-party independent audit upon the request and expense of the party affected by
such action. Any such request for an audit will be no later than twelve (12) months following the
action taken.

ARTICLE 8

SAFETY

8.1 General

     The Parties agree that all work performed by a Party that may reasonably be expected to affect
another Party shall be performed in accordance with Good Utility Practice and all applicable laws,
regulations, and other requirements pertaining to the safety of persons or property. A Party
performing work within the boundaries of another Party’s assets must abide by the safety rules
applicable to the site.

8.2 Environmental Releases

     Each Party shall notify the other Parties, first orally and then in writing, of the release of any
Hazardous Substances or any type of remedial activities, such as asbestos or lead abatement, which
may reasonably be expected to affect another Party, as soon as possible but not later than
twenty-four (24) hours after the Party becomes aware of the occurrence, and shall promptly furnish
to the other Parties copies of any reports filed with any governmental agencies addressing such
events.

ARTICLE 9

METERING

9.1 General

     Transmission Owner shall provide, install, own and maintain Metering Assets necessary to meet its
obligations under this Agreement. Notwithstanding the foregoing sentence, Consumers, if mutually
agreed by the Parties, may provide and install some, or all,

 

 

Original Sheet No. 23

of said Metering Assets, as per Transmission Owner’s specifications. The Parties agree that, as to
all Connection Points in existence as of the effective date of this Agreement, no new Metering
Assets or arrangements shall be required. If necessary, Metering Assets shall be either located or
adjusted, at Transmission Provider’s or Transmission Owner’s option, in such manner to account for
(a) any transformation or interconnection losses between the location of the meter and the Point of
Receipt and (b) any station auxiliary power load of the generating unit. Metering quantities, in
analog and/or digital form, shall be provided to Consumers upon request. The Parties also agree
that Consumers shall continue to maintain records of the Megawatthour and Megavarhour values
collected from existing meters on the generating units and provide the information recorded to
Transmission Provider or Transmission Owner upon request.

9.2 Costs of Administering Metering Assets

     All costs associated with the administration of Metering Assets and the provision of metering data
to Consumers shall be born by Consumers. The costs of administration and of providing metering data
shall be separately itemized on Transmission Owner’s invoices to Consumers pursuant to Article 12
of this Agreement. All costs associated with changes to Metering Assets requested by Consumers,
shall be borne by Consumers and shall be invoiced pursuant to
Article 12 of this Agreement.

9.3 Testing of Metering Assets

     Transmission Owner shall, at Consumers’ expense, inspect and test all Metering Assets not less than
once every year, unless an extension of the testing cycle is agreed upon by the Parties. If
requested to do so by Consumers and at Consumers’ expense, Transmission Owner shall inspect or test
Metering Assets more frequently. Transmission Owner shall give reasonable notice of the time when
any inspection or test shall take place and Consumers may have representatives present at the test
or inspection. If Metering Assets is found to be inaccurate or defective, it shall be adjusted,
repaired or replaced at Consumers’ expense, in order to provide accurate metering. If Metering
Assets fails to register, or if the measurement made by Metering Assets during a test varies by
more than two percent (2%) from the measurement made by the standard Metering Assets used in the
test, adjustment shall be made correcting all measurements made by the inaccurate Metering Assets
for (a) the actual period during which inaccurate measurements were made, if the period can be
determined, or (b) a period equal to one-half of the elapsed time since the last test of the
Metering Assets.

9.4 Metering Data

     9.4.1 When the Metering Assets location is not at the Point of Receipt, Metering Assets
readings shall be adjusted to account for appropriate transformer and line losses, and when
applicable, the station auxiliary power load of the Unit.

     9.4.2 At Consumers’ expense, all metered data shall be telemetered to one or more locations
designated by Transmission Provider and one or more locations designated by Consumers.

 

 

Original Sheet No. 24

9.5 Communications

     9.5.1 At Consumers’ expense, Consumers shall maintain satisfactory operating communications
with System Operator or representative, as designated by Transmission Provider or Transmission
Owner. Consumers has provided standard voice and facsimile communications in the control room of
each of its Units through use of the public telephone system. Consumers has also provided a 4-wire,
full duplex data circuit (or circuits) operating at a minimum of 9600 baud, or at other baud rates
as reasonably specified by Transmission Provider or Transmission Owner. The data circuit(s) extend
from each Consumers’ Unit to a location, or locations, specified by Transmission Provider or
Transmission Owner. Any required maintenance of such communications assets shall be performed at
Consumers’ expense, and may be performed by Consumers or by Transmission Owner. Operational
communications shall be activated and maintained under, but not be limited to, the following
events: system paralleling or separation, scheduled and unscheduled shutdowns, equipment
clearances, and hourly and daily load data exchanges. To the extent required by applicable rules
and regulations, Consumers shall (a) request permission from the System Operator prior to opening
or closing circuit breakers that affect the Transmission System, (b) carry out switching orders
from the
System Operator in a timely manner and (c) keep the System Operator advised of the Unit’s
operational capabilities as required for reliable operation of the Transmission System.

     9.5.2 For all Units 1 MW or larger, a Remote Terminal Unit (“RTU”), or equivalent data
collection and transfer equipment acceptable to Consumers and Transmission Owner, has been
installed to gather accumulated and instantaneous data to be telemetered to a location, or
locations, designated by Transmission Owner through use of dedicated point-to-point data circuits
as indicated in Subsection 9.5.1 of this Agreement. Instantaneous bidirectional analog real power
and reactive power flow information, circuit breaker status information, instantaneous analog
voltage information, metering information, and disturbance monitoring information, as determined by
Transmission Provider or Transmission Owner, must be telemetered directly to the location, or
locations, specified by Transmission Provider or Transmission Owner.

ARTICLE 10

FORCE MAJEURE

     10.1 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 assets, 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.

     10.2 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 Consumers’ obligation under Section 5.11 of this
Agreement to provide protection while operating in parallel with the Transmission

 

 

Original Sheet No. 25

System 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.

     10.3 Any Party’s obligation to make payments already owing shall not be suspended by Force Majeure.

ARTICLE 11

INFORMATION REPORTING

     Each Party shall, in accordance with Good Utility Practice, promptly provide to the other Parties
all relevant information, documents, or data regarding the Party’s assets which may reasonably be
expected to pertain to the reliability of the other Parties’ assets and/or which has been
reasonably requested by the other Parties.

ARTICLE 12

PAYMENTS AND BILLING PROCEDURES

12.1 Invoices

     Any invoices for reimbursable services provided to another Party under this Agreement during the
preceding month 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 so that the
other Party will receive the funds by the 20th day following the date of such invoice,
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 another Party, or by wire transfer
to a bank named by the Party being paid, provided that payments expressly required by this
Agreement to be mailed shall be mailed in accordance with Section 12.2.

12.2 Payments

     Any payments to be made by Consumers under this Agreement shall be made to Transmission Owner at
the following address:

Michigan Electric Transmission Company, LLC

P.O. Box 673971

Detroit, Ml 48267-3971

Attn: Accounting Department

If paying by wire transfer, please see the wiring instructions on the invoice.

     Any payments to be made by Transmission Owner under this Agreement shall be made to Consumers at
the following address:

 

 

Original Sheet No. 26

Consumers Energy Company

One Energy Plaza

Jackson, Michigan 49201

Attn: Treasurer

     The Parties shall provide the names of appropriate contact personnel, as are set forth in this
Agreement or otherwise, to each other after this Agreement is executed and shall keep said listing
of names and addresses up to date.

12.3 Interest Charges

     Interest on any unpaid amounts shall be calculated in accordance with the methodology specified for
interest on refunds in the Commission’s regulations at 18 CFR. §35.19 (a)(2)(iii). Interest on
delinquent amounts shall be calculated from the due date of the invoice to the date of payment.
When payments are made by mail, invoices shall be considered as having been paid on the date of
receipt by Transmission Owner or Consumers, as the case may be.

12.4 Disputes

     In the event of a billing dispute between Transmission Owner and Consumers, the Parties shall
continue to provide services and pay all invoiced amounts not in dispute. 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 through the date
on which payment is made at the interest rate pursuant to Section 13.3. Payment shall be due within
ten (10) days of resolution.

ARTICLE 13

ASSIGNMENT

13.1 This Agreement shall inure to the benefit of and be binding upon the successors and
assigns of the respective parties hereto. This Agreement shall not be transferred or otherwise
alienated by any Party without the other Parties’ prior written consent, which consent shall not be
unreasonably withheld, provided that any assignee shall expressly assume assignor’s obligations
hereunder and, unless expressly agreed to by the other Parties, no assignment shall relieve the
assignor of its obligations hereunder in the event its assignee fails to perform. Any attempted
assignment, transfer or other alienation without such consent
shall be void and not merely voidable.

13.2 Notwithstanding the above, the Transmission Provider or Transmission Owner shall be
permitted to assign or otherwise transfer this Agreement, or its rights, duties and obligations
hereunder, in whole or in part, by operation of law or otherwise, without the prior written consent
of Consumers, to any successor to or transferee of the direct or indirect ownership or operation of
all or part of the transmission system to which the Generation Resources are connected. Upon the
assumption by any such permitted assignee of the assigning Transmission Provider’s or Transmission
Owner’s rights, duties and obligations hereunder, the

 

 

Original Sheet No. 27

assigning Transmission Provider or Transmission Owner shall be released and discharged therefrom to
the extent provided in the assignment agreement.

13.3 Notwithstanding the above, Consumers may assign this Agreement to a bank pursuant to the terms
of an Assignment and Security Agreement without the prior written consent of Transmission Provider
or Transmission Owner provided that such assignment shall not be effective as to Transmission
Provider or Transmission Owner until it receives a fully executed copy thereof.

ARTICLE 14

INDEMNITY AND INSURANCE

14.1 Indemnity

     The Parties shall at all times assume all liability for, and shall indemnify and save the other
Parties 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 assets or assets controlled by it, unless caused by the sole negligence, or
intentional wrongdoing, of another Party.

14.2 Insurance

     14.2.1 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.

     14.2.2 A Party may, at its option, [A] be an approved self-insurer 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.

     14.2.3 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

 

 

Original Sheet No. 28

any extensions) each Party shall provide to the other Parties 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 15

LIMITATION ON LIABILITY

     NO PARTY SHALL IN ANY EVENT BE LIABLE TO THE OTHER PARTIES FOR ANY SPECIAL, INCIDENTAL, EXEMPLARY,
PUNITIVE OR CONSEQUENTIAL DAMAGES SUCH AS, BUT NOT LIMITED TO, LOST PROFITS, REVENUE OR GOOD WILL,
INTEREST, LOSS BY REASON OF SHUTDOWN OR 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 16

BREACH, CURE AND DEFAULT

16.1 General

     A breach of this Agreement (“Breach”) shall occur upon the failure by a Party to perform or observe
any material term or condition of this Agreement. 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 the
provisions of Section 16.4 of this Agreement.

16.2 Events of Breach

     A Breach of this Agreement shall include:

     16.2.1 The failure to pay any amount when due;

     16.2.2 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;

 

 

Original Sheet No. 29

     16.2.3 If a Party: (a) becomes insolvent; (b) 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; (c) makes a general assignment for the
benefit of its creditors or (d) consents to the appointment of a receiver, trustee or liquidator;

     16.2.4 Assignment of this Agreement in a manner inconsistent with the terms of this Agreement;

     16.2.5 Failure of a Party to provide such access rights, or a Party’s attempt to revoke or
terminate such access rights, as provided under this Agreement; or

     16.2.6 Failure of a Party to provide information or data to the other Parties 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.

16.3 Continued Operation

     In the event of a Breach or Default by a Party, the Parties shall continue to operate and maintain,
as applicable, such DC power systems, protection and Metering Assets, Telemetering Assets, SCADA
equipment, transformers, Secondary Systems, communications assets, building assets, software,
documentation, structural components, and other assets and appurtenances that are reasonably
necessary for Transmission Provider or Transmission Owner to operate and maintain the Transmission
System and for Consumers to operate and maintain the Unit, in a safe and reliable manner.

16.4 Cure and Default

     Upon the occurrence of an event of Breach, the Party or Parties not in Breach (hereinafter 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 the Parties to this Agreement identify in
writing to the other Parties 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.

 

 

Original Sheet No. 30

16.5 Right to Compel Performance

     Notwithstanding the foregoing, upon the occurrence of an event of Default, the non-Defaulting Party
or Parties shall be entitled to: (a) 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 (b) exercise such other rights and remedies as it may have in
equity or at law.

ARTICLE 17

CONFIDENTIALITY

17.1 All information regarding a Party (the “Disclosing Party”) that is furnished directly or
indirectly to the another Party (the “Recipient”) pursuant to this Agreement and marked
“Confidential” shall be deemed “Confidential Information”. Notwithstanding the foregoing,
Confidential Information does not include information that (i) is rightfully received by Recipient
from a third party having an obligation of confidence to the Disclosing Party, (ii) is or becomes
in the public domain through no action on Recipient’s part in violation of this Agreement, (iii) is
already known by Recipient as of the date hereof, or (iv) is
developed by Recipient independent of any Confidential Information of the Disclosing Party.
Information that is specific as to certain data shall not be deemed to be in the public domain
merely because such information is embraced by more general disclosure in the public domain.

     17.1.1 Recipient shall keep all Confidential Information strictly confidential and not disclose
any Confidential Information to any third party for a period of two (2) years from the date the
Confidential Information was received by Recipient, except as otherwise provided herein.

     17.1.2 Recipient may disclose the Confidential Information to its affiliates and its affiliates’
respective directors, officers, employees, consultants, advisors, and agents who need to know the
Confidential Information for the purpose of assisting Recipient with respect to its obligations
under this Agreement. Recipient shall inform all such parties, in advance, of the confidential
nature of the Confidential Information. Recipient shall cause such parties to comply with the
requirements of this Agreement and shall be responsible for the actions, uses, and disclosures of
all such parties.

     17.1.3 If Recipient becomes legally compelled or required to disclose any of the Confidential
Information (including, without limitation, pursuant to the policies, methods, and procedures of
the FERC, including the OASIS Standards of Conduct, or other Regulatory Authority), Recipient will
provide the Disclosing Party with prompt written notice thereof so that the Disclosing Party may
seek a protective order or other appropriate remedy. Recipient will furnish only that portion of
the Confidential Information which its counsel considers legally required, and Recipient will
cooperate, at the Disclosing Party’s expense, with the Disclosing Party’s counsel to enable the
Disclosing Party to obtain a protective order or other reliable assurance that confidential
treatment will be accorded the Confidential Information. It is further agreed that, if, in the
absence of a protective order, Recipient is nonetheless required to disclose any Confidential
Information, Recipient will furnish only that portion of the Confidential Information which its
counsel considers legally required.

 

 

Original Sheet No. 31

ARTICLE 18

AUDIT RIGHTS

     Subject to the requirements of confidentiality under Article 17 of this Agreement, each Party
shall have the right, during normal business hours, and upon prior reasonable notice to another
Party, to audit one another’s accounts and records pertaining to the Party’s performance and/or
satisfaction of obligations arising under this Agreement. Said audit shall be performed at the
offices where such accounts and records are maintained and shall be limited to those portions of
such accounts and records that relate to obligations under this Agreement.

ARTICLE 19

DISPUTES

     The Dispute Resolution Procedures set forth in the Midwest ISO Tariff shall apply to all
disputes arising under this Agreement.

ARTICLE 20

NOTICES

20.1 Any notice, demand or request required or permitted to be given by a Party to another and any
instrument required or permitted to be tendered or delivered by a Party to another may be so given,
tendered or delivered, as the case may be, by depositing the same in any United States Post Office
with postage prepaid, for transmission by certified or registered mail, addressed to the Party, or
personally delivered to the Party, at the address set out below:

To Transmission Owner:

Michigan Electric Transmission Company, LLC

27175 Energy Way

Novi, Ml 48377

Attn: Legal Department — Contracts

To Consumers:

Consumers Energy Company

1945 W. Parnall Road

Jackson, Michigan 49201

Attn: Director of Staff — Generation

To Transmission Provider:

Midwest Independent Transmission System Operator, Inc.

Attn: Manager, Interconnection Planning

701 City Center Drive

Carmel, IN 46032

 

 

Original Sheet No. 32

20.2 The Parties shall use standard telephone circuits as the primary communication link for
generation dispatch communications, including with respect to dispatching energy in the event of an
Emergency and declaring unit capability. The Parties shall provide the names and telephone numbers
of appropriate contact personnel, as are set forth in this Agreement or otherwise, to each other
after this Agreement is executed and shall keep said listing of names and telephone numbers up to
date.

ARTICLE 21

MISCELLANEOUS

21.1 Amendments

     This Agreement may be amended by and only by a written instrument duly executed by the Parties
hereto. No change or modification as to any of the provisions hereof shall be binding on any Party
unless approved in writing and approved by the duly authorized officers of the Parties.
Notwithstanding the foregoing, nothing contained herein shall be construed as affecting in any way
the right of Transmission Provider, Transmission Owner or Consumers to unilaterally make
application to the Commission for a change in rates, terms or conditions of service under Sections
205 and 206 of the Federal Power Act and pursuant to the Commission’s Rules and Regulations
promulgated thereunder. Transmission Provider reserves the right to file rate schedules with the
Commission concerning any services Transmission Provider deems necessary for reliable and orderly
bulk power system management, including but not limited to any standby or related services that may
arise from a failure by Consumers to meet its schedule of deliveries across the assets covered by
this Agreement.

21.2 Binding Effect

     This Agreement and the rights and obligations hereof, shall be binding upon and shall inure
to the benefit of the successors and assigns of the Parties hereto.

21.3 Counterparts

     This Agreement may be executed in any number of counterparts, and each executed counterpart
shall have the same force and effect as an original instrument.

21.4 Entire Agreement

     This Agreement constitutes the entire agreement among the Parties hereto with reference to
the subject matter hereof and its execution superseded all previous agreements, discussions,
communications and correspondence with respect to said subject matter. The terms and conditions of
this Agreement and every Exhibit referred to herein shall be amended, as mutually agreed to by the
Parties, to comply with changes or alterations made necessary by a valid applicable order of any
governmental regulatory authority, or any court, having jurisdiction hereof.

21.5 Governing Law

 

 

Original Sheet No. 33

     The validity, interpretation and performance of this Agreement and each of its provisions
shall be governed by the applicable laws of the State of Michigan, exclusive of its conflict of
laws principles.

21.6 Headings Not To Affect Meaning

     The descriptive headings of the various Articles and Sections of this Agreement have been
inserted for convenience of reference only and shall in no way modify or restrict any of the terms
and provisions hereof.

21.7 Waivers

     Any waiver at any time by a Party of its rights with respect to a default under this
Agreement, or with respect to any other matters arising in connection with this Agreement, shall
not be deemed a waiver or continuing waiver with respect to any subsequent default or other
matter.

21.8 Termination of Predecessor Interconnection Agreement

     On the Effective Date, the July 24, 2008 Amendment and Restatement of the Generator
Interconnection Agreement between Transmission Provider, Transmission Owner and Consumers shall
terminate and be replaced by this Agreement with regard to the Units covered by this Agreement,
except insofar as necessary to resolve billing and related matters arising from service rendered
and other events occurring before the Effective Date.

     IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be duly executed by
their duly authorized officers.

	 	 	 	 	 

	MICHIGAN ELECTRIC TRANSMISSION COMPANY, LLC	 	 
	 
	 	 	 	 
	By

	 	/s/ Daniel J. Oginsky
	 	 
	 

	 	 	 	 
	 

	 	Daniel J. Oginsky	 	 
	Title

	 	Sr. V.P. & General Counsel	 	 
	 
	CONSUMERS ENERGY COMPANY	 	 
	 
	 	 	 	 
	By

	 	/s/ James R. Coddington
	 	1-20-2010
	 

	 	 	 	 
	 

	 	James R. Coddington	 	 
	Title

	 	V.P. Generation Ops.	 	APVD AS TO FORM
	 
	 	 	 	 
	MIDWEST INDEPENDENT TRANSMISSION SYSTEM OPERATOR, INC.	 	 
	 
	 	 	 	 
	By

	 	/s/ WILLIAM C. PHILLIPS	 	9-18-10
	 

	 	 	 	 
	 

	 	WILLIAM C. PHILLIPS	 	 
	Title

	 	Vice President	 	 
	 

	 	Standards Compliance & Strategy	 	 
	 
	 	 	 	 

 

 

     

					
	 
	 	EXHIBIT A — CONSUMERS GENERATION RESOURCES
	 	Original Sheet No. 34

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	Summer	 	Winter	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Nameplate	 	Net	 	Net	 	 	 	 	 	 	 	 	 	 	 	 	 	AGC	 	Black	 	 	 	 
	 	 	Rated	 	Demonstrated	 	Demonstrated	 	 	 	 	 	 	 	 	 	 	 	AGC	 	Ramp	 	Start	 	Synch	 	 
	Generating Unit	 	MVA (1)	 	MW Capability	 	MW Capability	 	Kilovolts	 	RPM	 	Cooling	 	Capable	 	MW/Min	 	Capable	 	Breaker(s)	 	Comments
	Campbell 1
	 	 	312.0	 	 	 	260.0	 	 	 	260.0	 	 	 	16.0	 	 	 	3,600	 	 	Hydrogen	 	Yes	 	 	1	 	 	No	 	 	199	 	 	 
	Campbell 2
	 	 	492.0	 	 	 	355.0	 	 	 	360.0	 	 	 	20.0	 	 	 	3,600	 	 	Water/Hydrogen	 	Yes	 	 	1	 	 	No	 	 	299	 	 	 
	Campbell A
	 	 	21.9	 	 	 	13.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	C16	 	 	 
	Cobb 1
	 	 	81.2	 	 	 	61.0	 	 	 	61.0	 	 	 	14.4	 	 	 	3,600	 	 	Hydrogen	 	No	 	 	0	 	 	No	 	 	199	 	 	Cobb 1-3 are capable of 68 MW each except that with 3 units running the combined output is boiler limited to 183 MW.
	Cobb 2
	 	 	81.2	 	 	 	61.0	 	 	 	61.0	 	 	 	14.4	 	 	 	3,600	 	 	Hydrogen	 	No	 	 	0	 	 	No	 	 	299	 	 	Cobb 1-3 are capable of 68 MW each except that with 3 units running the combined output is boiler limited to 183 MW.
	Cobb 3
	 	 	81.2	 	 	 	61.0	 	 	 	61.0	 	 	 	14.4	 	 	 	3,600	 	 	Hydrogen	 	No	 	 	0	 	 	No	 	 	399	 	 	Cobb 1-3 are capable of 68 MW each except that with 3 units running the combined output is boiler limited to 183 MW.
	Cobb 4
	 	 	184.0	 	 	 	158.0	 	 	 	160.0	 	 	 	18.0	 	 	 	3,600	 	 	Hydrogen	 	Yes	 	 	1	 	 	No	 	 	499	 	 	 
	Cobb 5
	 	 	184.0	 	 	 	158.0	 	 	 	160.0	 	 	 	18.0	 	 	 	3,600	 	 	Hydrogen	 	Yes	 	 	1	 	 	No	 	 	599	 	 	 
	Gaylord 1
	 	 	18.8	 	 	 	14.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	116	 	 	 
	Gaylord 2
	 	 	18.8	 	 	 	14.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	216	 	 	 
	Gaylord 3
	 	 	18.8	 	 	 	14.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	316	 	 	 
	Gaylord 4
	 	 	18.8	 	 	 	14.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	416	 	 	 
	Gaylord 5
	 	 	21.9	 	 	 	14.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	No	 	 	516	 	 	 
	Karn 1
	 	 	336.0	 	 	 	255.0	 	 	 	255.0	 	 	 	16.0	 	 	 	3,600	 	 	Hydrogen	 	No	 	 	0	 	 	No	 	 	199	 	 	 
	Karn 2
	 	 	320.0	 	 	 	260.0	 	 	 	260.0	 	 	 	16.0	 	 	 	3,600	 	 	Hydrogen	 	No	 	 	0	 	 	No	 	 	299	 	 	 
	Karn 3
	 	 	814.7	 	 	 	638.0	 	 	 	638.0	 	 	 	26.0	 	 	 	3,600	 	 	Water/Hydrogen	 	Yes	 	 	6	 	 	No	 	 	28R8/28H9	 	 	 
	Karn 4
	 	 	835.0	 	 	 	638.0	 	 	 	638.0	 	 	 	26.0	 	 	 	3,600	 	 	Water/Hydrogen	 	Yes	 	 	6	 	 	No	 	 	32F7/32H9	 	 	 
	Ludington 1 (gen)
	 	 	388.0	 	 	 	312.0	 	 	 	312.0	 	 	 	20.0	 	 	 	112.5	 	 	Air	 	Yes	 	 	9	 	 	No (2)	 	 	116	 	 	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
	Ludington 2 (gen)
	 	 	388.0	 	 	 	312.0	 	 	 	312.0	 	 	 	20.0	 	 	 	112.5	 	 	Air	 	Yes	 	 	9	 	 	Yes	 	 	216	 	 	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.
	Ludington 3 (gen)
	 	 	388.0	 	 	 	312.0	 	 	 	312.0	 	 	 	20.0	 	 	 	112.5	 	 	Air	 	Yes	 	 	9	 	 	Yes	 	 	316	 	 	NDC is 312 MW but can operate at 340 MWg (338 MW net) at full pond.

 

 

     

					
	 
	 	EXHIBIT A — CONSUMERS GENERATION RESOURCES
	 	Original Sheet No. 35

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	Summer	 	Winter	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Nameplate	 	Net	 	Net	 	 	 	 	 	 	 	 	 	 	 	 	 	AGC	 	Black	 	 	 	 
	 	 	Rated	 	Demonstrated	 	Demonstrated	 	 	 	 	 	 	 	 	 	 	 	AGC	 	Ramp	 	Start	 	Synch	 	 
	Generating Unit	 	MVA(1)	 	MW Capability	 	MW Capability	 	Kilovolts	 	RPM	 	Cooling	 	Capable	 	MW/Min	 	Capable	 	Breaker(s)	 	Comments
	Ludington 4 (gen)
	 	 	388.0	 	 	 	312.0	 	 	 	312.0	 	 	 	20.0	 	 	 	112.5	 	 	Air	 	Yes	 	 	9	 	 	No (2)	 	 	416	 	 	NDC is 312 MW but can operate at
340
 MWg (338 MW net) at full pond.
	Ludington 5 (gen)
	 	 	388.0	 	 	 	312.0	 	 	 	312.0	 	 	 	20.0	 	 	 	112.5	 	 	Air	 	Yes	 	 	9	 	 	Yes	 	 	516	 	 	NDC is 312 MW but can operate at
340
 MWg (338 MW  net) at full pond. 
	Ludington 6 (gen)
	 	 	388.0	 	 	 	312.0	 	 	 	312.0	 	 	 	20.0	 	 	 	112.5	 	 	Air	 	Yes	 	 	9	 	 	No (2)	 	 	616	 	 	NDC is 312 MW but can  operate at
340
 MWg (338 MW net) at full pond.
	Morrow A
	 	 	20.7	 	 	 	14.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	A16	 	 	 
	Morrow B
	 	 	20.7	 	 	 	14.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	B16	 	 	 
	Straits 1
	 	 	25.0	 	 	 	16.0	 	 	 	21.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	S16	 	 	 
	Thetford 1
	 	 	39.5	 	 	 	30.0	 	 	 	37.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	116	 	 	 
	Thetford 2
	 	 	39.5	 	 	 	29.0	 	 	 	37.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	216	 	 	 
	Thetford 3
	 	 	39.5	 	 	 	30.0	 	 	 	37.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	316	 	 	 
	Thetford 4
	 	 	39.5	 	 	 	30.0	 	 	 	37.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	416	 	 	 
	Thetford 5
	 	 	20.7	 	 	 	15.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	516	 	 	 
	Thetford 6
	 	 	20.7	 	 	 	15.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	616	 	 	 
	Thetford 7
	 	 	20.7	 	 	 	14.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	716	 	 	 
	Thetford 8
	 	 	20.7	 	 	 	15.0	 	 	 	18.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	816	 	 	 
	Thetford 9
	 	 	20.7	 	 	 	14.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	916	 	 	 
	Weadock 7
	 	 	202.0	 	 	 	155.0	 	 	 	155.0	 	 	 	18.0	 	 	 	3,600	 	 	Hydrogen	 	Yes	 	 	1	 	 	No	 	 	799	 	 	 
	Weadock 8
	 	 	184.0	 	 	 	155.0	 	 	 	155.0	 	 	 	18.0	 	 	 	3,600	 	 	Hydrogen	 	Yes	 	 	1	 	 	No	 	 	899	 	 	 
	Weadock A
	 	 	21.9	 	 	 	13.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	A16	 	 	 
	Whiting 1
	 	 	125.0	 	 	 	102.0	 	 	 	102.0	 	 	 	14.4	 	 	 	3,600	 	 	Hydrogen	 	Yes	 	 	1	 	 	No	 	 	199	 	 	 
	Whiting 2
	 	 	125.0	 	 	 	102.0	 	 	 	102.0	 	 	 	14.4	 	 	 	3,600	 	 	Hydrogen	 	Yes	 	 	1	 	 	No	 	 	299	 	 	 
	Whiting 3
	 	 	156.3	 	 	 	122.0	 	 	 	124.0	 	 	 	15.5	 	 	 	3,600	 	 	Hydrogen	 	Yes	 	 	1	 	 	No	 	 	399	 	 	 
	Whiting A
	 	 	21.9	 	 	 	13.0	 	 	 	17.0	 	 	 	13.8	 	 	 	3,600	 	 	Air	 	No	 	 	0	 	 	Yes	 	 	46A	 	 	 
	Alcona Hydro 1
	 	 	4.4	 	 	 	4.0	 	 	 	4.0	 	 	 	5.0	 	 	 	90	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/166	 	 	 
	Alcona Hydro 2
	 	 	4.4	 	 	 	4.0	 	 	 	4.0	 	 	 	5.0	 	 	 	90	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/166	 	 	 
	Calkins Bridge Hydro 1
	 	 	0.6	 	 	 	0.4	 	 	 	0.4	 	 	 	4.8	 	 	 	180	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/166	 	 	Also known as Allegan Hydro 
	Calkins Bridge Hydro 2
	 	 	1.1	 	 	 	0.9	 	 	 	0.9	 	 	 	4.8	 	 	 	120	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/166	 	 	Also known as Allegan Hydro
	Calkins Bridge Hydro 3
	 	 	1.5	 	 	 	1.2	 	 	 	1.2	 	 	 	4.8	 	 	 	113	 	 	Air	 	NA	 	NA	 	No	 	 	316/166	 	 	Also known as Allegan Hydro
	Cooke Hydro 1
	 	 	3.3	 	 	 	1.5	 	 	 	1.5	 	 	 	2.5	 	 	 	180	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/166	 	 	 
	Cooke Hydro 2
	 	 	3.3	 	 	 	3.0	 	 	 	3.0	 	 	 	2.5	 	 	 	180	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/166	 	 	 
	Cooke Hydro 3
	 	 	3.3	 	 	 	3.0	 	 	 	3.0	 	 	 	2.5	 	 	 	180	 	 	Air	 	NA	 	NA	 	Yes	 	 	316/166	 	 	 

 

 

     

					
	 
	 	EXHIBIT A — CONSUMERS GENERATION RESOURCES
	 	Original Sheet No. 36

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	Summer	 	Winter	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	Nameplate	 	Net	 	Net	 	 	 	 	 	 	 	 	 	 	 	 	 	AGC	 	Black	 	 	 	 
	 	 	Rated	 	Demonstrated	 	Demonstrated	 	 	 	 	 	 	 	 	 	 	 	AGC	 	 Ramp	 	 Start	 	Synch	 	 
	Generating Unit	 	MVA (1)	 	MW Capability	 	MW Capability	 	Kilovolts	 	RPM	 	Cooling	 	 Capable	 	MW/Min	 	Capable	 	Breaker(s)	 	Comments
	Croton Hydro 1
	 	 	3.8	 	 	 	2.9	 	 	 	2.9	 	 	 	7.2	 	 	 	225	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/246	 	 	 
	Croton Hydro 2
	 	 	3.8	 	 	 	2.9	 	 	 	2.9	 	 	 	7.2	 	 	 	225	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/246	 	 	 
	Croton Hydro 3
	 	 	1.4	 	 	 	1.3	 	 	 	1.3	 	 	 	7.2	 	 	 	150	 	 	Air	 	NA	 	NA	 	Yes	 	 	316/246	 	 	 
	Croton Hydro 4
	 	 	1.6	 	 	 	1.3	 	 	 	1.3	 	 	 	7.2	 	 	 	150	 	 	Air	 	NA	 	NA	 	Yes	 	 	416/246	 	 	 
	Five Channels 1
	 	 	3.3	 	 	 	3.2	 	 	 	3.2	 	 	 	2.5	 	 	 	150	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/166	 	 	 
	Five Channels 2
	 	 	3.3	 	 	 	3.2	 	 	 	3.2	 	 	 	2.5	 	 	 	150	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/166	 	 	 
	Foote Hydro 1
	 	 	3.3	 	 	 	3.3	 	 	 	3.3	 	 	 	5.0	 	 	 	90	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/366	 	 	 
	Foote Hydro 2
	 	 	3.3	 	 	 	3.3	 	 	 	3.3	 	 	 	5.0	 	 	 	90	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/366	 	 	 
	Foote Hydro 3
	 	 	3.3	 	 	 	3.3	 	 	 	3.3	 	 	 	5.0	 	 	 	90	 	 	Air	 	NA	 	NA	 	Yes	 	 	316/366	 	 	 
	Hodenpyl Hydro 1
	 	 	8.9	 	 	 	9.2	 	 	 	9.2	 	 	 	7.5	 	 	 	120	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/266	 	 	 
	Hodenpyl Hydro 2
	 	 	8.9	 	 	 	9.2	 	 	 	9.2	 	 	 	7.5	 	 	 	120	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/266	 	 	 
	Loud Hydro 1
	 	 	2.2	 	 	 	2.2	 	 	 	2.2	 	 	 	2.5	 	 	 	120	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/266	 	 	 
	Loud Hydro 2
	 	 	2.2	 	 	 	2.2	 	 	 	2.2	 	 	 	2.5	 	 	 	120	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/266	 	 	 
	Mio Hydro 1
	 	 	2.7	 	 	 	2.2	 	 	 	2.2	 	 	 	2.5	 	 	 	80	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/166	 	 	 
	Mio Hydro 2
	 	 	2.7	 	 	 	2.2	 	 	 	2.2	 	 	 	2.5	 	 	 	80	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/166	 	 	 
	Rogers Hydro 1
	 	 	1.9	 	 	 	1.5	 	 	 	1.5	 	 	 	7.5	 	 	 	150	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/166	 	 	 
	Rogers Hydro 2
	 	 	1.9	 	 	 	1.5	 	 	 	1.5	 	 	 	7.5	 	 	 	150	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/166	 	 	 
	Rogers Hydro 3
	 	 	1.9	 	 	 	1.5	 	 	 	1.5	 	 	 	7.5	 	 	 	150	 	 	Air	 	NA	 	NA	 	Yes	 	 	316/166	 	 	 
	Rogers Hydro 4
	 	 	1.9	 	 	 	1.5	 	 	 	1.5	 	 	 	7.5	 	 	 	150	 	 	Air	 	NA	 	NA	 	Yes	 	 	416/166	 	 	 
	Tippy Hydro 1
	 	 	7.1	 	 	 	7.0	 	 	 	7.0	 	 	 	7.5	 	 	 	109	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/266/126	 	 	 
	Tippy Hydro 2
	 	 	7.1	 	 	 	7.0	 	 	 	7.0	 	 	 	7.5	 	 	 	109	 	 	Air	 	NA	 	NA	 	Yes	 	 	216/266/126	 	 	 
	Tippy Hydro 3
	 	 	7.1	 	 	 	7.0	 	 	 	7.0	 	 	 	7.5	 	 	 	109	 	 	Air	 	NA	 	NA	 	Yes	 	 	316/266/126	 	 	 
	Webber Hydro 1
	 	 	3.3	 	 	 	2.3	 	 	 	2.3	 	 	 	7.2	 	 	 	164	 	 	Air	 	NA	 	NA	 	Yes	 	 	116/166	 	 	 
	Webber Hydro 2
	 	 	1.3	 	 	 	1.0	 	 	 	1.0	 	 	 	2.5	 	 	 	200	 	 	Air	 	NA	 	NA	 	Yes	 	 	216	 	 	 

 

			
	Notes:
	 
	(1)	 	Rated MVA represents generator machine capability limits. Turbine or main transformer limits
may be more restrictive.
	 
	(2)	 	Ludington units 1,4 and 6 need to have one of the other units on line before they can be
started.

 

 

Original Sheet No. 37

EXHIBIT B — INTERCONNECTION ASSETS

General

The Parties agree that certain assets located at each of the electrical Substations at which
Consumers’ Generation Resources are connected to the Transmission System are an integral part of
the assets required by the Parties to provide services under their respective charters and that the
physical partition would be impossible, impractical and wholly inconsistent with the purposes for
which this Agreement is made. Said assets are deemed to be Jointly Owned Assets. In general, said
assets include, but in some of the electrical Substations shall not be limited to, the following:

	 	 	 

	Foundations

	 	All foundations not identified as belonging to a specific piece of assets in the
Plant Accounting Records.
	 
	Structures

	 	All steel support structures.
	 
	Station wiring

	 	All buswork, control cables, batteries, battery chargers and ground grids.
	 
	Fencing

	 	All chain-link fencing surrounding or used within the specific electrical Substation.
	 
	Control house

	 	Any building located within the Substation used to house relaying, controls or
telemetry equipment beneficial to and used by both Parties.
	 
	Stone

	 	All stone used in the Substation yards, driveways and drains.

At each of the substations listed in this Exhibit B, an allocated percentage of the Jointly Owned
Assets is determined for each Party hereto, in accordance with the provisions of this Agreement

For each of the electrical Substations at which Consumers’ Generation Resources are connected to
the Transmission System, the specific assets allocated to and owned by Consumers are identified
below as Consumers’ Interconnection Assets. In certain 345 kV Substations, specific breakers and
associated assets that have been designated for operation by Consumers are also specifically
identified as Transmission Owner’s Interconnection Assets.

Some of the electrical Substations containing Interconnection Assets also contain Distribution
System assets owned by Consumers. Unless said Distribution System assets are directly involved in
the connection of Consumers’ Generation Resources to the Transmission System, they are not
described in the description of assets that follow.

The balance of the assets in each electrical Substation are allocated to and owned by the
Transmission Owner and considered a part of the Transmission System.

Wiring Diagrams (WDs) will be updated continuously in each Party’s Drawing Management System (DMS)
which is shared between the Parties and approved in writing by the Local Distribution Company to
show changes in ownership. For current ownership (reflecting ownership changes since July 24,
2008), see the WDs in the DMS.

 

 

Original Sheet No. 38

Exhibit B-Table 1

Jointly Owned Asset Ownership by Percent of Major Equipment

Addendum 1 — Final 01-01-10

Substations

Jointly Owned Assets

Percentage Split by Major Equipment Count

(Substations with 100% Ownership by Major Equipment Count Not Included)

	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Generation	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Owned by	 	 	 	 	 	 
	 	 	 	 	 	 	 	 	 	 	Local	 	 	 	 	 	Last
	 	 	 	 	 	 	 	 	 	 	Distribution	 	Third-Party	 	Revision
	Substation Name	 	Distribution	 	Transmission	 	Company	 	Assets	 	Date
	Campbell 138 kV
	 	 	0.00	 	 	 	69.23	 	 	 	30.25	 	 	 	0.51	 	 	 	01/01/10	 
	Cobb Plant
	 	 	47.22	 	 	 	25.00	 	 	 	27.78	 	 	 	 	 	 	 	04/29/02	 
	Gaylord
	 	 	44.44	 	 	 	44.44	 	 	 	11.12	 	 	 	 	 	 	 	01/01/10	 
	Karn Plant
	 	 	0.00	 	 	 	63.64	 	 	 	36.36	 	 	 	 	 	 	 	01/01/10	 
	Morrow 1
	 	 	66.67	 	 	 	23.33	 	 	 	6.67	 	 	 	3.33	 	 	 	01/01/10	 
	Thetford
	 	 	0.00	 	 	 	92.00	 	 	 	8.00	 	 	 	 	 	 	 	04/29/02	 
	Weadock
	 	 	35.14	 	 	 	24.32	 	 	 	40.54	 	 	 	 	 	 	 	01/01/10	 
	Whiting
	 	 	31.58	 	 	 	31.58	 	 	 	36.84	 	 	 	 	 	 	 	01/01/10	 

 

			
	1	 	 At 120kV and above, third-party related assets will be included as part of the Transmission
assets for purposes of making this calculation. Also, the third-party may share in the financial
responsibility associated with O&M activities.

Changes, relative to previous revisions (addendums), are shown in bold type. Major equipment is
defined in Section 5.4 of the GIA.

 

 

Original Sheet No. 39

Generator Connections located at Substations in the Transmission System 

Campbell 1&2 Plant

The Campbell 1&2 Plant consists of three generating Units, known as Unit 1 (consisting of
generators 1A and 1B), Unit 2 and Unit A. (The Campbell 3 Plant is located at the same site, but
has separate interconnection facilities and is covered by a separate generator interconnection
agreement.)

The Connection Point for Units 1,2 and A are in the Campbell 138 kV Substation (see Wiring Diagram
#93, Sheet 31 attached).

The Points of Receipt for all the Units in the Campbell 1&2 Plant are deemed to be the respective
Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Campbell 138 kV Substation (Wiring Diagram #93, Sheet
31):

	 	 	 

	Transformer Bank

	 	No. A (located outside of substation; not included in JOA calc)
	 
	Circuit Breakers

	 	Nos. 199, 299, 799, 899* and 16A (16A is rated < 23kV and not considered major
equipment per GIA definition).
	 
	Switches

	 	Nos. 99A, 195,196, 295, 296, 709, 793, 795, 796, 809*, 893*, 895* and 896*
	 
	 	 
	Circuit Connections

	 	All wire, cable or buswork electrically connecting the switches identified
above to the Circuit Breakers identified above and to the main or transfer buswork
	 
	 	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	Foundations

	 	All foundations supporting the Circuit Breakers identified above

 

			
	*	 	Jointly Owned asset with Michigan Public Power Agency (4.8%) and Wolverine Power Supply
Cooperative (1.8%)

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Campbell 138 kV Substation (Wiring Diagram #93,
Sheet 31):

	 	 	 

	Transformer Bank

	 	No. 5
	 
	Circuit Breakers

	 	Nos. 148, 188, 288, 388, 488, 500, 566 and 588
	 
	Switches

	 	Nos. 108, 144,145, 146, 184, 185, 186, 208, 284, 285, 286, 308, 384,
385, 386, 408,484,485,486, 505, 506, 508, 509, 545, 546, 584, 585,
586,594, 1020 and 1121

 

 

Original Sheet No. 40

	 	 	 

	Circuit Connections

	 	All wire, cable or bus work electrically connecting the switches identified
above to the Circuit Breakers identified above and to the main or transfer
bus work
	 
	Relay and Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	Foundations

	 	All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets — Percentage Split by Major Equipment Count

Campbell 138 kV Substation — See Exhibit B — Table 1

 

 

Original Sheet No. 41

CEII MATERIAL

 

 

Original Sheet No. 42

Cobb Generating Plant Complex

The Cobb Generating Plant Complex consists of five generating Units, known as Units 1 through 5,
respectively.

The Connection Points for Units 1 through 5 are in the BC Cobb Plant Substation (see Wiring Diagram
#240, Sheet 31 attached).

The Points of Receipt for all the Units in the Cobb Generating Plant Complex are deemed to be the
respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the BC Cobb Plant Substation (Wiring Diagram #240, Sheet
31):

	 	 	 

	Transformer Banks

	 	Nos. 1, 2, 3, 4, 5, 7 and 8
	 
	Capacitor Banks

	 	Nos. 1 and 2
	 
	Circuit Breakers

	 	Nos. 100, 188, 199, 288, 299, 399,499, 599, 766, 799, 866, 899, 1177,
1188,1288, 1388, 1488 and 1688
	 
	Switches

	 	Nos. 100,102,104, 152, 156, 184, 185, 186,193,195, 196, 200, 252,
256,284, 285, 286, 293, 295, 296, 393, 395, 396, 493, 495,496, 593,
595, and 596, 709, 762, 764, 765, 793, 795, 796, 809, 862, 864, 865,
893,895,896, 1171, 1173, 1175, 1182,1184, 1185, 1282, 1284, 1285,
1323,1382, 1384,1385,1482,1484, 1485,1588, 1682,1684, 1685,
1788,1888, 2333, 7732-1, 8826-2 and 8832-2
	 
	Circuit Connections

	 	All wire, cable or buswork electrically connecting the switches identified
above to the Circuit Breakers identified above and to the main buswork.
	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	Foundations

	 	All foundations supporting the Transformers and Circuit Breakers identified above
	 
	Auxiliary Power

	 	All 2400 Volt station power assets shown in the attached Wiring Diagram #240

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the BC Cobb Plant Substation (Wiring Diagram #240,
Sheet 31):

	 	 	 

	Circuit Breakers

	 	Nos. 148, 377, 488, 500, 588, 688, 788, 888 and 988
	 
	Switches

	 	Nos. 144, 145, 146, 307, 373, 375, 376, 408, 484, 485,486, 505,506,
508, 584, 585, 586, 608, 684, 685, 686, 708, 784, 785, 786, 808, 884,
885, 886, 908, 984, 985, 986, 1020,1021, 2030 and 2131
	 
	Circuit Connections

	 	All wire, cable or buswork electrically connecting the switches identified
above to the Circuit Breakers identified above and to the main buswork.
	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above

 

 

Original Sheet No. 43

	 	 	 

	Foundations

	 	All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets — Percentage Split by Major Equipment Count

Cobb Plant Substation -See Exhibit B — Table 1

 

 

Original Sheet No. 44

CEII MATERIAL

 

 

Original Sheet No. 45

Gaylord Generating Plant Complex

The Gaylord Generating Plant Complex consists of five combustion turbine generating Units, known as
Units 1 through 5, respectively.

The Connection Points for Units 1 through 5 are in the Gaylord Generating Substation (see Wiring
Diagram #495, Sheet 31 attached).

The Points of Receipt for all the Units in the Gaylord Generating Plant Complex are deemed to be
the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Gaylord Generating Substation (Wiring Diagram #495,
Sheet 31):

	 	 	 
	Transformer Banks

	 	Nos. 1, 2* and 3* (*located outside of substation; not included in JOA calc)
	 
	 	 
	Circuit Breakers

	 	Nos. A16*, 116*, 146, 166, 199, 216*, 316*, 416* and 1288 (*located outside of substation; not included in JOA calc)
	 
	 	 
	Switches

	 	Nos. 3, 142, 144, 145, 162, 164, 165, 191, 193, 195, 299, 399, 1282 and 1284
	 
	 	 
	Circuit Connections

	 	All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above
	 
	 	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	 	 
	Foundations

	 	All foundations supporting the Transformers and Circuit Breakers identified above
	 
	 	 
	Auxiliary Power

	 	All station power assets shown in the attached Wiring Diagram #495, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Gaylord Generating Substation (Wiring Diagram #495, Sheet 31):

	 	 	 
	Capacitor Bank

	 	No. 3
	 
	 	 
	Circuit Breakers

	 	Nos. 356, 377 and 477
	 
	 	 
	Switches

	 	Nos. 352, 371, 373, 375. 382, 384, 385, 471, 473, 475, 671, 673 and 675
	 
	 	 
	Circuit Connections

	 	All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above
	 
	 	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	 	 
	Foundations

	 	All foundations supporting the Circuit Breakers identified above

 

 

Original Sheet No. 46

Jointly Owned Assets — Percentage Split by Major Equipment Count

Gaylord Generating Substation — See Exhibit B — Table 1

 

 

Original Sheet No. 47

CEII MATERIAL

 

 

Original Sheet No. 48

Karn Generating Plant Complex

The Karn Generating Plant Complex consists of four generating Units, known as Units 1 (consisting
of generators 1A and 1B), Unit 2 (consisting of generators 2A and 2B, Unit 3 and Unit 4.

The Connection Point for Units 1 and 2 are in the DE Karn Plant 138 kV Substation (see Wiring
Diagram #695, Sheet 31 attached). The Connection Point for Units 3 and 4 are in the Hampton 345 kV
Substation (see Wiring Diagram #1327, Sheet 31 attached).

The Points of Receipt for all the Units in the DE Karn Generating Plant Complex are deemed to be
the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the DE Karn 138 kV Substation (Wiring Diagram #695, Sheet
31):

	 	 	 
	Transformer Banks

	 	Nos. 1 and 2 (located outside the substation; not included in JOA calc)
	 
	 	 
	Circuit Breakers

	 	Nos. 199, 299, 799 and 899
	 
	 	 
	Switches

	 	Nos. 136A, 136B, 195, 196, 236A, 236B, 295, 296, 793, 795, 796, 893, 895, and 896
	 
	 	 
	Circuit Connections

	 	All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the main or transfer buswork
	 
	 	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	 	 
	Foundations

	 	All foundations supporting the Circuit Breakers identified above
	 
	 	 
	Auxiliary Power

	 	All 480 Volt and 4160 Volt station power assets shown in the attached Wiring Diagram #695, Sheet 31

Transmission Owner’s Interconnection Assets

Transmission Owner owns the following assets at the DE Karn 138 kV Substation (Wiring Diagram #695,
Sheet 31):

	 	 	 
	Circuit Breakers

	 	Nos. 148, 188, 388, 488, 500, 588 and 988
	 
	 	 
	Switches

	 	Nos. 108, 144,145, 146, 184,185, 186, 308, 384, 385, 386,408,484, 485,486, 505, 506, 508, 584, 585, 586, 709, 809, 908, 984, 985, 986, 2038 and 2131
	 
	 	 
	Circuit Connections

	 	All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to adjacent buswork
	 
	 	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	 	 
	Foundations

	 	All foundations supporting the Circuit Breakers identified above

Jointly Owned Assets — Percentage Split by Major Equipment Count

Karn Plant Substation -
See Exhibit B — Table 1

 

 

Original Sheet No. 49

CEII MATERIAL

 

 

Original Sheet No. 50

CEII MATERIAL

 

 

Original Sheet No. 51

Ludington Pumped Storage Generating Plant Complex

Note: The Detroit Edison Company has a overall 49% ownership interest in the Ludington Generating
Plant and certain other related facilities and property.

The Ludington Pumped Storage Generating Plant Complex consists of six motor-generator Units, known
as Units 1 through 6, respectively.

The Connection Points for Units 1 through 6 are in the Ludington Substation (see Wiring Diagram
#1405, Sheet 31 attached).

The Points of Receipt for all the Units in the Ludington Pumped Storage Generating Plant Complex
are deemed to be the respective Connection Points.

Generator Interconnection Assets

Consumers Energy and Detroit Edison, as noted above, share ownership of the following assets at the
Ludington Site (Wiring Diagram #1405, Sheet 31):

	 	 	 
	Transformer Banks

	 	Nos. 1,2, and 3 (located outside the substation; not included in JOA calc)
	 
	 	 
	Reactors

	 	Nos. 1 and 2 (located outside the substation; not included in JOA calc)
	 
	 	 
	Circuit Breakers

	 	Nos. 115, 116, 216, 316, 416 516, 615 and 616 (all phase-reversing 3-pole breakers associated with the motor-generators) and Nos. 1116 and 6116 (breakers associated with Pony Motors Nos. 1 and 2) (located outside the substation; not included in JOA calc)
	 
	 	 
	Switches

	 	Nos. 105, 215, 315, 415, 515, 1099, 1112 and 6112
	 
	 	 
	Removable Links

	 	Nos. 111, 112, 113, 212, 213, 312, 313, 412, 413, 512, 513, 612 and 613
	 
	 	 
	Circuit Connections

	 	All 345 kV conductors connecting the 20/345 kV Transformer Banks to the 345 kV buswork in the Ludington Substation All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the 20
kV main and starting buswork
	 
	 	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	 	 
	Foundations

	 	All foundations supporting the Transformers and Circuit Breakers identified above
	 
	 	 
	Auxiliary Power

	 	All 480 Volt and 4160 Volt station power assets shown in the attached Wiring Diagram #1405, Sheet 31

Transmission Owner’s Interconnection Assets

Transmission Owner and Third Party share ownership of the following assets at the Ludington
Substation (Wiring Diagram #1405, Sheet 31):

	 	 	 
	Reactors

	 	Nos. 21 and 23
	 
	 	 
	Circuit Breakers

	 	Nos. 21F7, 21R8, 22F7, 22H9, 22R8, 23F7, 23R8, 24F7, 24H9, 24R8, 25F7, 25H9*, 25R8*, 26F7 and 26R8

 

 

Original Sheet No. 52

	 	 	 
	Switches

	 	Nos. 21F1, 21F3, 21R2, 21R4, 2156, 22F1,22F3, 22H5, 22H6, 22R2, 22R4,
23F1, 23F3, 23R2, 23R4, 2356, 24F1, 24F3, 24H5, 24H6, 24R2, 24R4, 25F1, 25F3, 25H5*, 25H6*, 25R2*, 25R4*,
26F1, 26H6, 26R2, and 26R4
	 
	 	 
	Circuit Connections

	 	All 345 kV conductors connecting the 20/345 kV Transformer Banks to the 345 kV buswork in the Ludington Substation All wire, cable or buswork electrically connecting the switches identified above to the Circuit Breakers identified above and to the 20 kV main and starting buswork
	 
	 	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	 	 
	Foundations

	 	All foundations supporting the Circuit Breakers identified above

 

			
	*	 	100% owned by Transmission Owner

	 	 	 
	Jointly Owned Assets -

	 	Percentage Split by Major Equipment Count
	 
	 	 
	Ludington Substation -

	 	Consumers (generation) = 0.00%; Consumers (distribution) = 0.00%;
	 

	 	Transmission Owner = 56.76%; Third Parties = 43.24%

 

 

Original Sheet No. 53

CEII MATERIAL

 

 

Original Sheet No. 54

Morrow Generating Plant Complex

The Morrow Generating Plant Complex consists of two combustion turbine generating Units, known as
Units A and B.

The Connection Points for both Units A and B are in the Morrow Substation (see Wiring Diagram #190,
Sheet 31, attached).

The Points of Receipt for the Units in the Morrow Generating Plant Complex are deemed to be the
Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Morrow Substation (Wiring Diagram #190, Sheet 31):

	 	 	 
	Transformer Banks

	 	No. 1, 2, 4 and 5
	 
	 	 
	Circuit Breakers

	 	Nos. 100, 156, 166, 199, 256, 266, 288, 299, 566, 499, 16A, 16B, 599, 1077, 1188, 1388,
1488, 1588, 1688 and 1788
	 
	 	 
	Switches

	 	Nos. 102, 104, 109, 162, 164, 165, 191, 193, 195, 196, 208, 209, 252, 262, 264,
265, 282, 284, 285, 286, 291, 293, 295,
296, 300, 495, 496, 509, 562, 564, 565, 591, 593, 595, 596, 1071, 1073, 1075, 1182, 1184, 1185, 1323, 1382, 1384, 1385,
1482, 1484, 1485, 1582, 1584, 1585, 1682, 1684, 1685, 1782, 1784, 1785 and 2333
	 
	Capacitors

	 	Nos. 1 and 2
	 
	 	 
	Circuit Connections

	 	All wire, cable or buswork electrically connecting the Transformers, Circuit Breakers and Switches identified above
	 
	 	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	 	 
	Foundations

	 	All foundations supporting the Transformers and Circuit Breakers identified above
	 
	 	 
	Auxiliary Power

	 	All 480 Volt station power assets shown in the attached Wiring Diagram #190, Sheet 31

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Morrow Substation (Wiring Diagram #190, Sheet
31):

	 	 	 
	Circuit Breakers

	 	Nos. 177, 377, 388, 500, 588, 677 and 988
	 
	 	 
	Switches

	 	Nos. 107, 173, 175, 176, 307, 308, 371, 373, 375, 376, 382, 384, 385, 386, 501, 502, 503, 504, 505, 506, 508, 582, 584, 585, 586, 607, 671, 673, 675, 676, 908, 982, 984, 985 and 986
	 
	 	 
	Circuit Connections

	 	All wire, cable or buswork electrically connecting the Circuit Breakers and Switches identified above
	 
	 	 
	Relay and Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	 	 
	Foundations

	 	All foundations supporting the Circuit Breakers identified above

 

 

Original Sheet No. 55

Third Party Owned Assets

Kalamazoo River Generation Station owns the following assets at the Morrow Substation (Wiring Diagram #190):

	 	 	 
	Circuit Breaker

	 	No. 888
	 
	Switches

	 	Nos. 882, 884, 885 and 886

Jointly Owned Assets — Percentage Split by Major Equipment Count

Morrow Substation — See Exhibit B — Table 1

 

 

Original Sheet No. 56

CEII MATERIAL

 

 

Original Sheet No. 57

Thetford Generating Plant Complex

The Thetford Generating Plant Complex consists of nine combustion turbine generating
Units, known as Units 1 through 9, respectively.

The Connection Points for Units 1 through 9 are in the Thetford Substation (see
Wiring Diagram #1000, Sheet 31 attached).

The Points of Receipt for all the Thetford Units are deemed to be the respective
Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Thetford Substation (Wiring Diagram #1000,
Sheet 31):

	 	 	 

	Transformer Banks

	 	Nos. 5, 6-1, 6-2 and 7
	 
	Circuit Breakers

	 	Nos. 13B7, 13W8, 116, 216, 316, 416, 516, 616, 716, 816 and 916
	 
	Switches

	 	Nos. 13B1, 13B3, 13M5, 13W2, 13W4, 591, 691-1, 691-2 and 791
	 
	Circuit
Connections

	 	All wire, cable or buswork electrically connecting the Transformer Banks, Circuit
Breakers and Switches identified above
	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	Foundations

	 	All foundations supporting the Transformers and Circuit Breakers identified
above

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the Thetford Substation (Wiring Diagram
#1000, Sheet #31):

	 	 	 

	Transformer Banks

	 	Nos. 3 and 4
	 
	Circuit Breakers

	 	Nos. 6B7, 6M9, 6W8, 7B7, 7M9, 7W8, 9B7, 9M9, 9W8, 11B7, 11M9,
11W8, 27F7, 27H9, 27R8, 31F7, 31H9, 31R8, 33F7, 33H9 and 33R8
	 
	Switches

	 	Nos. 6B1, 6B3, 6M5, 6M6, 6W2, 6W4, 7B1, 7B3, 7M5, 7M6, 7W2, 7W4,
9B1, 9B3, 9M5, 9M6, 9W2, 9W4, 11B1 , 11B3, 11M5, 11M6, 11W2,
11W4, 27F1, 27F3, 27H5, 27H6, 27R2, 27R4, 31F1, 31F3, 31H5, 31H6,
31R2, 31R4, 33F1 , 33F3, 33H5, 33H6, 33R2, 33R4 and 35R2
	 
	Circuit Connections

	 	All wire, cable or buswork electrically connecting the Transformer Banks, Circuit
Breakers and Switches identified above
	 
	Relay and Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	Foundations

	 	All foundations supporting the Transformers and Circuit Breakers identified
above

Jointly Owned Assets — Percentage Split by Major Equipment Count

Thetford Substation — See Exhibit B — Table 1

 

 

Original Sheet No. 58

CEII MATERIAL

 

 

Original Sheet No. 59

Weadock Generating Plant Complex

The Weadock Generating Plant Complex consists of three generating
Units, known as Units 7, 8 and A.

The Connection Points for Units 7, 8 and A1 are in the John C Weadock
Substation (see Wiring Diagram #195, Sheet 31 attached). These Units are
currently in service. In addition, there are six other units, known as
Units 1 through 6, which have been retired from service, but are still in
place. Those assets are also described below, should the Units be
restored to service in the future.

The Points of Receipt for all the Units currently in service at the
Weadock Generating Plant Complex are deemed
to be the respective Connection Points.

Consumers’ Interconnection Assets (for Units In Service)

Consumers owns the following assets at the John C Weadock Substation
(Wiring Diagram #195, Sheets 2 and 31):

	 	 	 

	Transformer Banks

	 	Nos. 1, 2, 7, 8, 9 and 10
	 
	Circuit Breakers

	 	Nos. 66A, 100, 136, 166, 199, 236, 266, 299, 300, 736C, 799, 899, 966,
999, 1066, 1088, 1099, 1188, 1288 and 1388
	 
	Switches

	 	Nos. 62A, 64A, 102, 104, 105, 106, 132, 134, 135, 152, 156, 162, 164,
165, 195, 196, 200, 232, 234, 235, 252, 256, 262, 264, 265, 295, 296,
302, 304, 306, 400, 732C, 734C, 735C, 736A, 736B, 795, 796, 836A,
836B, 895, 896, 962, 964, 965, 991, 993, 995, 996, 1062, 1064, 1065,
1082, 1084, 1085, 1091, 1093, 1095, 1096, 1182, 1184, 1185, 1282,
1284, 1285, 1382, 1384 and 1385
	 
	Capacitors

	 	1 and 2
	 
	Circuit
Connections

	 	All wire, cable or buswork electrically connecting the Switches identified above
to the Circuit Breakers identified above and to the main buswork.
	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	Foundations

	 	All foundations supporting the Transformer Banks and Circuit Breakers identified
above
	 
	Auxiliary Power

	 	All 480 Volt and 4160 Volt station power assets shown in the attached Wiring
Diagram #195, Sheet 31

Consumers’ Interconnection Assets (for Units Retired in Place)

Consumers owns the following assets at the John C Weadock Substation
(Wiring Diagram #195, Sheet 31):

	 	 	 

	Transformer Banks

	 	Nos. 5 and 6
	 
	Circuit Breakers

	 	Nos. 99A, 116, 216, 316, 336, 416 and 436
	 
	Switches

	 	Nos. 93A, 112, 114, 212, 214, 312, 314,
332, 412, 414, 432, 516, 536
and 616
	 
	Circuit
Connections

	 	All wire, cable or buswork electrically
connecting the Switches identified above to the
Circuit Breakers identified above and to the main
buswork.

 

 

Original Sheet No. 60

	 	 	 

	Relay & Controls

	 	All relays and controls
associated with the Circuit Breakers
identified above
	 
	Foundations

	 	All foundations supporting the
Transformer Banks and Circuit Breakers
identified above

Transmission Owner Interconnection Assets

Transmission Owner owns the following assets at the John C Weadock
Substation (Wiring Diagram #195, Sheet 31):

	 	 	 

	Circuit Breakers

	 	Nos. 148, 188, 288, 388, 488, 500, 588, 688 and 788
	 
	Switches

	 	Nos. 108, 142, 144, 145, 146, 182, 184, 185, 186, 208, 282, 284, 285,
286, 308, 382, 284, 385, 386, 408, 482, 484, 485, 486, 505, 506, 508,
582, 584, 585, 586, 608, 682, 684, 685, 686, 708, 782, 784, 785, 786,
900, 1020,1121, 2030, 2131, 3040, 3141, 4050 and 4151
	 
	Circuit
Connections

	 	All wire, cable or buswork electrically connecting the Switches identified above
to the Circuit Breakers identified above and to the main buswork
	 
	Relay & Controls

	 	All relays and controls associated with the Circuit Breakers identified above
	 
	Foundations

	 	All foundations supporting the Circuit Breakers identified above

Jointly
Owned Assets
 — Percentage Split
by Major Equipment
Count

John C
Weadock Substation
 — See Exhibit B -
Table 1

 

 

Original Sheet No. 61

CEII MATERIAL

 

 

Original Sheet No. 62

Whiting Generating Plant Complex

The Whiting Generating Plant Complex consists of four generating Units, known
as Units 1, 2, 3 and A.

The Connection Points for Units 1, 2, 3 and A are in the Whiting Substation (see
Wiring Diagram #400, Sheet 31 attached). Units 1, 2 and 3 are connected to the 138
kV buswork and Unit A is connected to the 46 kV buswork

The Points of Receipt for all the Units in the Whiting Generating Plant Complex are
deemed to be the respective Connection Points.

Consumers’ Interconnection Assets

Consumers owns the following assets at the Whiting Substation (Wiring Diagram #400,
Sheet 31):

	 	 	 

	Transformer Banks

	 	Nos. 1, 2, 3, 7 and A
(TB # A located outside of
substation; not included in
JOA calc)
	 
	Circuit Breakers

	 	Nos. 16A (located
outside switchyard; not
included in JOA calc), 46A,
199, 299, 399, 766, 799,
1188 and 1288
	 
	Switches

	 	Nos. 42A, 44A, 45A,
99A, 105, 156, 191, 193,
195, 196, 291, 293, 295,
296, 391, 393, 395, 396,
79T1, 762, 764, 765, 795,
796, 1182, 1184,
1185, 1282, 1284, 1285
	 
	Capacitor Bank

	 	No 1
	 
	Circuit Connections

	 	All wire, cable or
buswork electrically
connecting the Transformer
Banks, Circuit Breakers and
Switches identified above to
each other, as appropriate,
to the main buswork and to
the Auxiliary Power
assets
	 
	Relay & Controls

	 	All relays and controls
associated with the Circuit
Breakers identified
above
	 
	Foundations

	 	All foundations
supporting the Transformer
Banks and Circuit Breakers
identified above
	 
	Auxiliary Power

	 	All 480 Volt and 2400
Volt station power assets
shown in the attached Wiring
Diagram #400, Sheet 31

Transmission Owner
Interconnection Assets

Transmission Owner owns the following assets at the Whiting Substation
(Wiring Diagram #400, Sheet 31):

	 	 	 

	Transformer Bank

	 	No. 8
	 
	Circuit Breakers

	 	Nos. 500, 688, 788,899 and 988
	 
	Switches

	 	Nos. 501, 502, 503, 504, 505, 506, 608, 682,
684, 685, 686, 785, 786,
866, 895, 896, 908, 982, 984, 985 and 986
	 
	Circuit
Connections

	 	All wire, cable or buswork electrically
connecting the Transformer Banks, Circuit Breakers
and Switches identified above to each other, as
appropriate, to the main buswork

 

 

Original Sheet No. 63

	 	 	 

	Relay & Controls

	 	All relays and controls associated
with the Circuit Breakers identified
above
	 
	Foundations

	 	All foundations supporting the
Transformer Bank and Circuit Breakers
identified above

Jointly Owned
Assets — Percentage Split by
Major Equipment Count

Whiting
Substation — See Exhibit B -
Table 1

 

 

Original Sheet No. 64

CEII MATERIAL

 

 

Original Sheet No. 65

EXHIBIT C

Generator Connections located in Consumers’ Distribution System

The following Units are connected indirectly to the Transmission System and do not have specific
connection data listed herein.

Alcona Hydro Generating Plant, Units 1 and 2  

Calkins Bridge “Allegan” Hydro Generating Plant, Units 1, 2 and 3  

Cooke Hydro Generating Plant, Units 1, 2 and 3  

Croton Hydro Generating Plant, Units 1, 2, 3 and 4 

Five Channels Generating Plant, Units 1 and 2  

Foote Hydro Generating Plant, Units 1, 2 and 3  

Hodenpyl Hydro Generating Plant, Units 1 and 2  

Loud Hydro Generating Plant, Units 1 and 2  

Mio Hydro Generating Plant, Units 1 and 2  

Rogers Hydro Generating Plant, Units 1, 2, 3 and 4

Straits Combustion Turbine Generating Unit 1  

Tippy Hydro Generating Plant, Units 1, 2 and 3  

Webber Hydro Generating Plant, Units 1 and 2

Consumers Energy Generator Connections Covered under Other Interconnection Agreements

The following Units are covered under their own LGIAs and do not have specific connection data
listed herein.

Campbell Generating Plant, Unit 3.

Hardy Hydro Generating Plant, Units 1, 2 and 3.

Zeeland Power Plant

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